ARIZONA PUBLIC SERVICE CO (Form: 10-K, Received: 02/22/2013 08:07:00)

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission
File Number

Registrants; State of Incorporation;
Addresses; and Telephone Number

IRS Employer
Identification No.

1-8962

PINNACLE WEST CAPITAL CORPORATION

(An Arizona corporation)
400 North Fifth Street, P.O. Box 53999
Phoenix, Arizona 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, Arizona 85072-3999
(602) 250-1000

86-0011170

Securities registered pursuant to Section 12(b) of the Act:

	Title Of Each Class	Name Of Each Exchange On Which Registered
PINNACLE WEST CAPITAL CORPORATION	Common Stock, No Par Value	New York Stock Exchange
ARIZONA PUBLIC SERVICE COMPANY	None	None

Securities registered pursuant to Section 12(g) of the Act:

ARIZONA PUBLIC SERVICE COMPANY Common Stock, Par Value $2.50 per share

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

PINNACLE WEST CAPITAL CORPORATION	Yes x No o
ARIZONA PUBLIC SERVICE COMPANY	Yes x No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

PINNACLE WEST CAPITAL CORPORATION	Yes o No x
ARIZONA PUBLIC SERVICE COMPANY	Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

PINNACLE WEST CAPITAL CORPORATION	Yes x No o
ARIZONA PUBLIC SERVICE COMPANY	Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

PINNACLE WEST CAPITAL CORPORATION	Yes x No o
ARIZONA PUBLIC SERVICE COMPANY	Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or in any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

PINNACLE WEST CAPITAL CORPORATION
Large accelerated filer x	Accelerated filer o

Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

ARIZONA PUBLIC SERVICE COMPANY
Large accelerated filer o	Accelerated filer o

Non-accelerated filer x (Do not check if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x

State the aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of each registrant’s most recently completed second fiscal quarter:

PINNACLE WEST CAPITAL CORPORATION	$5,647,769,605 as of June 30, 2012
ARIZONA PUBLIC SERVICE COMPANY	$0 as of June 30, 2012

The number of shares outstanding of each registrant’s common stock as of February 15, 2013

PINNACLE WEST CAPITAL CORPORATION	109,756,391 shares
ARIZONA PUBLIC SERVICE COMPANY	Common Stock, $2.50 par value, 71,264,947 shares. Pinnacle West Capital Corporation is the sole holder of Arizona Public Service Company’s Common Stock.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Pinnacle West Capital Corporation’s definitive Proxy Statement relating to its Annual Meeting of Shareholders to be held on May 15, 2013 are incorporated by reference into Part III hereof.

Arizona Public Service Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.

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TABLE OF CONTENTS

		Page

GLOSSARY OF NAMES AND TECHNICAL TERMS		1

FORWARD-LOOKING STATEMENTS		2

PART I		3
Item 1.	Business	3
Item 1A.	Risk Factors	27
Item 1B.	Unresolved Staff Comments	39
Item 2.	Properties	40
Item 3.	Legal Proceedings	43
Item 4.	Mine Safety Disclosures	43
Executive Officers of Pinnacle West		44

PART II		46
Item 5.	Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	46
Item 6.	Selected Financial Data	48
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	50
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	76
Item 8.	Financial Statements and Supplementary Data	77
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	175
Item 9A.	Controls and Procedures	175
Item 9B.	Other Information	176

PART III		176
Item 10.	Directors, Executive Officers and Corporate Governance of Pinnacle West	176
Item 11.	Executive Compensation	176
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	176
Item 13.	Certain Relationships and Related Transactions, and Director Independence	178
Item 14.	Principal Accountant Fees and Services	178

PART IV		179
Item 15.	Exhibits and Financial Statement Schedules	179

SIGNATURES		224

This combined Form 10-K is separately filed by Pinnacle West and APS. Each registrant is filing on its own behalf all of the information contained in this Form 10-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. The information required with respect to each company is set forth within the applicable items. Item 8 of this report includes Consolidated Financial Statements of Pinnacle West and Consolidated Financial Statements of APS. Item 8 also includes Notes to Pinnacle West’s Consolidated Financial Statements, the majority of which also relates to APS, and Supplemental Notes, which only relate to APS’s Consolidated Financial Statements.

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GLOSSARY OF NAMES AND TECHNICAL TERMS

AC		Alternating Current
ACC		Arizona Corporation Commission
ADEQ		Arizona Department of Environmental Quality
AFUDC		Allowance for Funds Used During Construction
ANPP		Arizona Nuclear Power Project, also known as Palo Verde
APS		Arizona Public Service Company, a subsidiary of the Company
APSES		APS Energy Services Company, Inc., a subsidiary of the Company sold on August 19, 2011
Base Fuel Rate		The portion of APS’s retail base rates attributable to fuel and purchased power costs
BHP Billiton		BHP Billiton New Mexico Coal, Inc.
BNCC		BNP Navajo Coal Company
Cholla		Cholla Power Plant
CPUC		California Public Utility Commission
DC		Direct Current
DOE		United States Department of Energy
DOI		United States Department of the Interior
DSMAC		Demand side management adjustment charge
El Dorado		El Dorado Investment Company, a subsidiary of the Company
EPA		United States Environmental Protection Agency
FERC		United States Federal Energy Regulatory Commission
Four Corners		Four Corners Power Plant
GWh		Gigawatt-hour, one billion watts per hour
kV		Kilovolt, one thousand volts
kWh		Kilowatt-hour, one thousand watts per hour
LFCR		Lost Fixed Cost Recovery Mechanism
MMBtu		One million British Thermal Units
MW		Megawatt, one million watts
MWh		Megawatt-hour, one million watts per hour
Native Load		Retail and wholesale sales supplied under traditional cost-based rate regulation
Navajo Plant		Navajo Generating Station
NRC		United States Nuclear Regulatory Commission
OCI		Other comprehensive income
OSM		Office of Surface Mining Reclamation and Enforcement
Palo Verde		Palo Verde Nuclear Generating Station
Pinnacle West		Pinnacle West Capital Corporation (any use of the words “Company,” “we,” and “our” refer to Pinnacle West)
PSA		Power supply adjustor approved by the ACC to provide for recovery or refund of variations in actual fuel and purchased power costs compared with the Base Fuel Rate
RES		Arizona Renewable Energy Standard and Tariff
Salt River Project or SRP		Salt River Project Agricultural Improvement and Power District
SCE		Southern California Edison Company
SunCor		SunCor Development Company, a subsidiary of the Company
TCA		Transmission cost adjustor
VIE		Variable interest entity
West Phoenix		West Phoenix Power Plant

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FORWARD-LOOKING STATEMENTS

This document contains forward-looking statements based on current expectations. 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 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 outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Item 1A and in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” 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;

· volatile fuel and purchased power costs;

· fuel and water supply availability;

· our ability to achieve timely and adequate rate recovery of our costs, including returns on debt and equity capital;

· regulatory and judicial decisions, developments and proceedings;

· new legislation or regulation, including those relating to environmental requirements and nuclear plant operations;

· 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;

· competition in retail and wholesale power markets;

· the duration and severity of the economic decline in Arizona and current real estate market conditions;

· the cost of debt and equity capital and the ability to access capital markets when required;

· changes to our credit ratings;

· 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 the Risk Factors described in Item 1A of this report, which readers should review carefully before placing any reliance on our financial statements or disclosures. Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law.

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PART I

ITEM 1. BUSINESS

Pinnacle West

Pinnacle West is a holding company that conducts business through its subsidiaries. We derive essentially all of our revenues and earnings from our wholly-owned subsidiary, APS. APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the State of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.

Pinnacle West’s other remaining first-tier subsidiaries are SunCor and El Dorado. Additional information related to these businesses is provided later in this report.

Our reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities, and includes electricity generation, transmission and distribution.

BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY

APS currently provides electric service to approximately 1.1 million customers. We own or lease approximately 6,370 MW of regulated generation capacity and we hold a mix of both long-term and short-term purchased power agreements for additional capacity, including a variety of agreements for the purchase of renewable energy. During 2012, no single purchaser or user of energy accounted for more than 1.4% of our electric revenues.

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The following map shows APS’s retail service territory, including the locations of its generating facilities and principal transmission lines.

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Energy Sources and Resource Planning

To serve its customers, APS obtains power through its various generation stations and through purchased power agreements. Resource planning is an important function necessary to meet Arizona’s future energy needs. APS’s sources of energy by type during 2012 were as follows:

Generation Facilities

APS has ownership interests in or leases the coal, nuclear, gas, oil and solar generating facilities described below. For additional information regarding these facilities, see Item 2.

Coal-Fueled Generating Facilities

Four Corners — Four Corners is a 5-unit coal-fired power plant located in the northwestern corner of New Mexico. APS operates the plant and owns 100% of Four Corners Units 1, 2 and 3 and 15% of Units 4 and 5. APS has a total entitlement from Four Corners of 791 MW.

On November 8, 2010, APS and SCE entered into an asset purchase agreement (the “Asset Purchase Agreement”) providing for the purchase by APS of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. If consummated, APS would acquire 739 MW from SCE. The purchase price is $294 million, subject to certain adjustments. Completion of the purchase by APS is subject to the receipt of approvals by the ACC, the CPUC and the FERC. On March 29, 2012, the CPUC issued an order approving the sale. On April 18, 2012, the ACC voted to allow APS to move forward with the purchase. The Asset Purchase Agreement provides that the purchase price will be reduced by $7.5 million for each month between October 1, 2012 and the closing date. The ACC reserved the right to review the prudence of the transaction for cost recovery purposes in a future proceeding if the purchase closes. The ACC also authorized an accounting deferral of certain costs associated with the purchase until any such cost recovery proceeding concludes. The FERC application seeking authorization for the transaction was approved on November 27, 2012. The principal remaining condition to closing is the negotiation and execution of a new coal supply contract for Four Corners on terms reasonably acceptable to APS.

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On December 19, 2012, BHP Billiton, the parent company of BNCC, the coal supplier and operator of the mine that serves Four Corners, announced that it has entered into a Memorandum of Understanding with the Navajo Nation setting out the key terms under which full ownership of BNCC would be sold to the Navajo Nation. BHP Billiton would be retained by BNCC under contract as the mine manager and operator until July 2016. Key terms of the new coal supply contract are being finalized by the Navajo Nation and APS and the other Four Corners co-owners.

As a result of this proposed change in ownership of BNCC, APS now expects that a new coal supply contract would be executed upon completion of negotiations and following the endorsement of the transfer of ownership of the stock of BNCC to a new Navajo Nation commercial enterprise to be established by the Navajo Nation Tribal Council. The decision of the Tribal Council is currently expected to occur in the second quarter of 2013.

Pursuant to the Asset Purchase Agreement, either APS or SCE has a right to terminate the Agreement if satisfaction of the closing conditions had not occurred by December 31, 2012, unless the party seeking to terminate is then in breach of the Agreement.

The Four Corners plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation which extends the Four Corners leasehold interest from 2016 to 2041. The Navajo Nation approved these amendments in March 2011. The effectiveness of the amendments also requires the approval of the DOI, as does a related federal rights-of-way grant, which the Four Corners participants will pursue. A federal environmental review is underway as part of the DOI review process.

APS has announced that, if APS’s purchase of SCE’s interests in Units 4 and 5 at Four Corners is consummated, it will close Units 1, 2 and 3 at the plant. These events would change the plant’s overall generating capacity from 2,100 MW to 1,540 MW and APS’s entitlement from the plant from 791 MW to 970 MW.

APS cannot predict whether the mutual right to terminate in the Asset Purchase Agreement will be exercised by a party to that agreement in the future, whether BHP Billiton and the Navajo Nation will consummate the transfer of ownership of BNCC, or whether the coal supply contract will be finalized and executed, such that closing of APS’s purchase of SCE’s interest in Four Corners can occur.

Cholla — Cholla is a 4-unit coal-fired power plant located in northeastern Arizona. APS operates the plant and owns 100% of Cholla Units 1, 2 and 3. PacifiCorp owns Cholla Unit 4, and APS operates that unit for PacifiCorp. APS has a total entitlement from Cholla of 647 MW. APS purchases all of Cholla’s coal requirements from a coal supplier that mines all of the coal under long-term leases of coal reserves with the federal government and private landholders. The Cholla coal contract runs through 2024. APS believes that the current fuel contracts ensure the continued operation of Cholla for its useful life. In addition, APS has a long-term coal transportation contract.

Navajo Generating Station — The Navajo Plant is a 3-unit coal-fired power plant located in northern Arizona. Salt River Project operates the plant and APS owns a 14% interest in Navajo Units 1, 2 and 3. APS has a total entitlement from the Navajo Plant of 315 MW. The Navajo Plant’s coal requirements are purchased from a supplier with long-term leases from the Navajo Nation and the Hopi

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Tribe. The Navajo Plant is under contract with its coal supplier through 2019. The Navajo Plant site is leased from the Navajo Nation and is also subject to an easement from the federal government.

These coal-fueled plants face uncertainties, including those related to existing and potential legislation and regulation, that could significantly impact their economics and operations. See “Environmental Matters” below and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview and Capital Expenditures” in Item 7 for developments impacting these coal-fueled facilities. See Note 11 for information regarding APS’s coal mine reclamation obligations.

Nuclear

Palo Verde Nuclear Generating Station — Palo Verde is a 3-unit nuclear power plant located about 50 miles west of Phoenix, Arizona. APS operates the plant and owns 29.1% of Palo Verde Units 1 and 3 and about 17% of Unit 2. In addition, APS leases about 12.1% of Unit 2, resulting in a 29.1% combined ownership and leasehold interest in that Unit. APS has a total entitlement from Palo Verde of 1,146 MW.

Palo Verde Leases — In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back about 42% of its share of Palo Verde Unit 2 and certain common facilities. In accordance with the VIE accounting guidance, APS consolidates the lessor trust entities for financial reporting purposes, and eliminates lease accounting for these transactions. The agreements have terms of 29.5 years (expiring at the end of 2015) and contain options to renew the leases or to purchase the property for fair market value at the end of the lease terms. APS was required to give notice to the respective lessor trusts between December 31, 2010 and December 31, 2012 if it wished to retain the leased assets (without specifying whether it would purchase the leased assets or extend the leases) or return the leased assets to the lessor trusts. On December 31, 2012, APS gave notice to the respective lessor trusts informing them it will retain the leased assets. APS must give notice to the respective lessor trusts by June 30, 2014 notifying them which of the purchase or lease renewal options it will exercise. We are analyzing these options. See Note 20 for additional information regarding the Palo Verde Unit 2 sale leaseback transactions.

Palo Verde Operating Licenses — Operation of each of the three Palo Verde Units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987, and issued renewed operating licenses for each of the three units in April 2011, which extended the licenses for Units 1, 2 and 3 to June 2045, April 2046 and November 2047, respectively.

Palo Verde Fuel Cycle — The Palo Verde participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The fuel cycle for Palo Verde is comprised of the following stages:

· mining and milling of uranium ore to produce uranium concentrates;

· conversion of uranium concentrates to uranium hexafluoride;

· enrichment of uranium hexafluoride;

· fabrication of fuel assemblies;

· utilization of fuel assemblies in reactors; and

· storage and disposal of spent nuclear fuel.

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The Palo Verde participants have contracted for 100% of Palo Verde’s requirements for uranium concentrates through 2016, 95% of its requirements in 2017 and 80% of its requirements in 2018. The participants have also contracted for all of Palo Verde’s conversion services through 2016, 90% of its requirements in 2017 and 95% of its requirements in 2018; all of Palo Verde’s enrichment services through 2020; and all of Palo Verde’s fuel assembly fabrication services through 2016.

In late August 2012, one of Palo Verde’s suppliers that converts uranium concentrates to uranium hexafluoride invoked the force majeure provision in its contract when it shut down its conversion plant due to regulatory compliance issues. The Palo Verde participants have sufficient strategic reserves of enriched uranium such that they do not anticipate a short term impact on nuclear fuel supplies as a result of the force majeure declaration. The uranium conversion supplier has undertaken the necessary upgrades to its facility to address the regulatory compliance issues and anticipates resuming operations in a time frame that will not result in an adverse impact on Palo Verde’s ability to secure long-term conversion services. However, the participants are continuing to evaluate alternate long-term options for securing conversion services.

Spent Nuclear Fuel and Waste Disposal — The Nuclear Waste Policy Act of 1982 (“NWPA”) required the DOE to accept, transport, and dispose of spent nuclear fuel and high level waste generated by the nation’s nuclear power plants by 1998. The DOE’s obligations are reflected in a Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (“Standard Contract”) with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998, and APS (on behalf of itself and the other Palo Verde participants) filed a lawsuit for DOE’s breach of the Palo Verde Standard Contract in the U.S. Court of Federal Claims. The Court of Federal Claims ruled in favor of APS and in October 2010 awarded $30.2 million in damages to the Palo Verde participants for costs incurred through December 2006. On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE. This lawsuit seeks to recover APS’s damages incurred due to DOE’s failure to accept Palo Verde’s spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011.

The DOE had planned to meet its NWPA and Standard Contract disposal obligations by designing, licensing, constructing, and operating a permanent geologic repository at Yucca Mountain, Nevada. In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca Mountain construction authorization application that was pending before the NRC. Several interested parties have intervened in the NRC proceeding, and the proceeding has not been conclusively decided by the NRC or the courts. Additionally, a number of interested parties have filed a variety of lawsuits in different jurisdictions around the country challenging the DOE’s authority to withdraw the Yucca Mountain construction authorization application. None of these lawsuits have been conclusively decided by the courts.

On June 8, 2012, the U.S. Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”) issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel. The petitioners had challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision and temporary storage rule (“Waste Confidence Decision”).

The D.C. Circuit found that the agency’s 2010 Waste Confidence Decision update constituted a major federal action, which, consistent with the National Environmental Policy Act (“NEPA”), requires either an environmental impact statement or a finding of no significant impact from the

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agency’s actions. The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the 2010 Waste Confidence Decision update for further action consistent with NEPA.

On September 6, 2012, the NRC Commissioners issued a directive to the NRC staff to proceed directly with development of a generic environmental impact statement to support an updated Waste Confidence Decision. The Commission also directed the staff to establish a schedule to publish a final rule and environmental impact study within 24 months of September 6, 2012. Timely resolution of the remand by the Court of Appeals could have an adverse impact on certain NRC licensing actions.

Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation (“ISFSI”) to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, Palo Verde has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.

Nuclear Decommissioning Costs — APS currently relies on an external sinking fund mechanism to meet the NRC financial assurance requirements for decommissioning its interests in Palo Verde Units 1, 2 and 3. The decommissioning costs of Palo Verde Units 1, 2 and 3 are currently included in APS’s ACC jurisdictional rates. Decommissioning costs are recoverable through a non-bypassable system benefits charge (paid by all retail customers taking service from the APS system). See Note 22 for additional information about APS’s nuclear decommissioning trusts.

Palo Verde Liability and Insurance Matters — See “Palo Verde Nuclear Generating Station — Nuclear Insurance” in Note 11 for a discussion of the insurance maintained by the Palo Verde participants, including APS, for Palo Verde.

Impact of Earthquake and Tsunami in Japan on Nuclear Energy Industry — On March 11, 2011, an earthquake measuring 9.0 on the Richter Scale occurred off the coast of Japan. After the earthquake, the first of a series of seven tsunamis arrived at the Fukushima Daiichi Nuclear Power Station. As a result, the Fukushima Daiichi station experienced considerable damage.

Following the earthquake and tsunamis, the NRC established a task force (the “Near-Term Task Force”) to conduct a systematic and methodical review of NRC processes and regulations to determine whether the agency should make additional improvements to its regulatory system. On March 12, 2012, the NRC issued the first regulatory requirements based on the recommendations of the Near Term Task Force. With respect to Palo Verde, the NRC issued two orders requiring safety enhancements regarding: (1) mitigation strategies to respond to extreme natural events resulting in the loss of power at plants; and (2) enhancement of spent fuel pool instrumentation.

The NRC has issued a series of interim staff guidance documents regarding implementation of these requirements. Due to the developing nature of these requirements, we cannot predict the financial or operational impacts on Palo Verde or APS; however, Palo Verde continues to comply with regulatory requirements and related reporting to the NRC as specified in the March 12, 2012, and interim staff guidance documents.

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Natural Gas and Oil Fueled Generating Facilities

APS has six natural gas power plants located throughout Arizona, consisting of Redhawk, located near the Palo Verde Nuclear Generating Station; Ocotillo, located in Tempe; Sundance, located in Coolidge; West Phoenix, located in southwest Phoenix; Saguaro, located north of Tucson; and Yucca, located near Yuma. Several of the units at Saguaro and Yucca run on either gas or oil. APS has one oil-only power plant, Douglas, located in the town of Douglas, Arizona. APS owns and operates each of these plants with the exception of one oil-only combustion turbine unit and one oil and gas steam unit at Yucca that are operated by APS and owned by the Imperial Irrigation District. APS has a total entitlement from these plants of 3,389 MW. Gas for these plants is acquired through APS’s hedging program. APS has long-term gas transportation agreements with three different companies, some of which are effective through 2024. Fuel oil is acquired under short-term purchases delivered primarily to West Phoenix, where it is distributed to APS’s other oil power plants by truck.

Solar Facilities

To date, APS has begun operation of 69 MW of utility scale solar through its AZ Sun Program, discussed below. These facilities are owned by APS and are located in multiple locations throughout Arizona.

Additionally, APS owns and operates more than forty small solar systems around the state. Together they have the capacity to produce about 4 MW of renewable energy. This fleet of solar systems includes a 3 MW facility located at the Prescott Airport and 1 MW of small solar in various locations across Arizona. APS has also developed solar photovoltaic distributed energy systems installed as part of the Community Power Project in Flagstaff, Arizona. The Community Power Project, approved by the ACC on April 1, 2010, is a pilot program through which APS owns, operates and receives energy from approximately 1.5 MW of solar photovoltaic distributed energy systems located within a certain test area in Flagstaff, Arizona. Additionally, APS owns 7 MW of solar photovoltaic systems installed across Arizona through the ACC approved Schools and Government Program.

Purchased Power Contracts

In addition to its own available generating capacity, APS purchases electricity under various arrangements, including long-term contracts and purchases through short-term markets to supplement its owned or leased generation and hedge its energy requirements. A portion of APS’s purchased power expense is netted against wholesale sales on the Consolidated Statements of Income. (See Note 18.) APS continually assesses its need for additional capacity resources to assure system reliability.

Purchased Power Capacity — APS’s purchased power capacity under long-term contracts, including its renewable energy portfolio, is summarized in the table below. All capacity values are based on net capacity unless otherwise noted.

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Type	Dates Available	Capacity (MW)
Purchase Agreement (a)	Year-round through December 2014	104
Purchase Agreement (b)	Year-round through June 14, 2020	60
Exchange Agreement (c)	May 15 to September 15 annually through 2020	480
Tolling Agreement	Year-round through May 2017	500
Tolling Agreement	Summer seasons through October 2019	560
Day-Ahead Call Option Agreement	Summer seasons through September 2015	500
Day-Ahead Call Option Agreement	Summer seasons through summer 2016	150
Demand Response Agreement (d)	Summer seasons through 2024	100
Renewable Energy (e)	Various	349

(a) The capacity under this agreement varies by month, with a maximum capacity of 104 MW in 2012 and 90 MW in each of 2013 and 2014.

(b) Up to 60 MW of capacity is available; however, the amount of electricity available to APS under this agreement is based in large part on customer demand and is adjusted annually.

(c) This is a seasonal capacity exchange agreement under which APS receives electricity during the summer peak season (from May 15 to September 15) and APS returns a like amount of electricity during the winter season (from October 15 to February 15).

(d) The capacity under this agreement increases in phases over the first three years to reach the 100 MW level by the summer of 2012.

(e) Renewable energy purchased power agreements are described in detail below under “Current and Future Resources — Renewable Energy Standard — Renewable Energy Portfolio.”

Current and Future Resources

Current Demand and Reserve Margin

Electric power demand is generally seasonal. In Arizona, demand for power peaks during the hot summer months. APS’s 2012 peak one-hour demand on its electric system was recorded on August 8, 2012 at 7,207 MW, compared to the 2011 peak of 7,087 MW recorded on August 24, 2011. APS’s reserve margin at the time of the 2012 peak demand, calculated using system load serving capacity, was 22%. Excluding certain contractual rights to call on additional capacity on short notice, which APS may use in the event of unusual weather or unplanned outages, the 2012 reserve margin was 12%. APS anticipates the reserve margin for 2013 will be approximately 28%, or 19% excluding contractual rights to call on additional capacity. APS expects that our reserve margins will decrease over the next five years and that additional conventional resources will be needed around 2017.

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Future Resources and Resource Plan

Under the ACC’s resource planning rule, APS will file by April 1 of each even year its resource plans for the next fifteen-year period. APS filed its first resource plan pursuant to these rules on April 1, 2012. The rule requires the ACC to issue an order with its acknowledgment of APS’s resource plan within approximately ten months following its submittal. The deadline for the ACC to acknowledge APS’s resource plan has been extended from February 1, 2013 until April 1, 2013. The ACC’s acknowledgment of APS’s resource plan will consider factors such as the total cost of electric energy services, demand management, analysis of supply-side options, system reliability and risk management.

Renewable Energy Standard

In 2006, the ACC adopted the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. The renewable energy requirement is 4% of retail electric sales in 2013 and increases annually until it reaches 15% in 2025. In APS’s 2009 retail rate case settlement agreement, APS committed to have 1,700 GWh of new renewable resources in service by year-end 2015 in addition to its 2008 renewable resource commitments. Taken together, APS’s commitment is estimated to be approximately 12% of retail sales, by year-end 2015, which is more than double the RES target of 5% for that year. A component of the RES is focused on stimulating development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties, such as rooftop solar systems). Accordingly, under the RES, an increasing percentage of that requirement must be supplied from distributed energy resources. This distributed energy requirement is 30% of the overall RES requirement of 4% in 2013. The following table summarizes the RES requirement standard (not including the additional commitment required by the settlement agreement discussed above) and its timing:

	2013		2015		2020		2025
RES as a % of retail electric sales	4	%	5	%	10	%	15	%
Percent of RES to be supplied from distributed energy resources	30	%	30	%	30	%	30	%

Renewable Energy Portfolio. To date, APS has a diverse portfolio of existing and planned renewable resources totaling 1090 MW, including wind, geothermal, solar, biomass and biogas. Of this portfolio, 667 MW are currently in operation and 423 MW are under contract for development or are under construction. Renewable resources in operation include 81 MW of facilities owned by APS, 349 MW of long-term purchased power agreements, and an estimated 237 MW of customer-sited, third-party owned distributed energy resources.

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APS’s strategy to achieve its RES requirements includes executing purchased power contracts for new facilities, ongoing development of distributed energy resources and procurement of new facilities to be owned by APS. APS is developing owned solar resources through the AZ Sun Program. Under this program to date, APS has executed contracts for the development of 118 MW of new solar generation, representing an investment commitment of approximately $502 million. See Note 3 for additional details about the AZ Sun Program, including the related cost recovery.

The following table summarizes APS’s renewable energy sources currently in operation and under development. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the projects to the electric grid.

	Location	Actual/ Target Commercial Operation Date	Term (Years)	Net Capacity In Operation (MW AC)	Net Capacity Planned/Under Development (MW AC)
APS Owned
Solar:
AZ Sun Program:
Paloma	Gila Bend, AZ	2011		17
Cotton Center	Gila Bend, AZ	2011		17
Hyder Phase 1	Hyder, AZ	2011		11
Hyder Phase 2	Hyder, AZ	2012		5
Chino Valley	Chino Valley, AZ	2012		19
Foothills	Yuma, AZ	2013			35
Hyder II	Hyder, AZ	2013			14
Subtotal AZ Sun Program				69	49
Multiple Facilities	AZ	Various		4
Distributed Energy:
APS Owned (a)	AZ	Various		8
Total APS Owned				81	49

Purchased Power Agreements
Solar:
Solana (b)	Gila Bend, AZ	2013	30		250
RE Ajo	Ajo, AZ	2011	25	5
Sun E AZ 1	Prescott, AZ	2011	30	10
Saddle Mountain	Tonopah, AZ	2012	30	15
Solar 1 (c)	Tonopah, AZ	2013	30		15
Solar 2 (c)	Maricopa County, AZ	2013	30		15
Wind:
Aragonne Mesa	Santa Rosa, NM	2006	20	90
High Lonesome	Mountainair, NM	2009	30	100
Perrin Ranch Wind	Williams, AZ	2012	25	99
Geothermal:
Salton Sea	Imperial County, CA	2006	23	10
Biomass:
Snowflake	Snowflake, AZ	2008	15	14
Biogas:
Glendale Landfill	Glendale, AZ	2010	20	3
NW Regional Landfill	Surprise, AZ	2012	20	3
Total Purchased Power Agreements				349	280
Distributed Energy
Solar (d)
Third-party Owned (e)	AZ	various		204	94
Agreement 1	Bagdad, AZ	2011	25	15
Agreement 2	AZ	2011-2012	20-21	18
Total Distributed Energy				237	94
Total Renewable Portfolio				667	423

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(a) Includes Flagstaff Community Power Project and APS Schools and Government Program.

(b) Represents contracted capacity.

(d) Distributed generation is produced in DC and is converted to AC for reporting purposes.

(e) Achieved through incentive-based programs. Includes resources with production-based incentives that have terms of 10-20 years.

Demand Side Management

In recent years, Arizona regulators have placed an increased focus on energy efficiency and other demand side management programs to encourage customers to conserve energy, while incentivizing utilities to aid in these efforts that ultimately reduce the demand for energy. In December 2009, the ACC initiated its Energy Efficiency rulemaking, with a proposed Energy Efficiency Standard of 22% cumulative annual energy savings by 2020. This standard was adopted and became effective on January 1, 2011. This ambitious standard will likely impact Arizona’s future energy resource needs. (See Note 3 for energy efficiency and other demand side management obligations resulting from the settlement agreement related to APS’s 2008 retail rate case.)

Government Awards

Through the American Recovery and Reinvestment Act of 2009 (“ARRA”) and other DOE initiatives, the Federal government made a number of programs available for utilities to develop renewable resources, improve reliability and create jobs.

APS has received two awards from the DOE. The first is a $3 million non-ARRA award for a high penetration photovoltaic generation study related to the Community Power Project in Flagstaff, Arizona. This award will conclude on March 31, 2015 and is contingent upon APS meeting certain project milestones, including DOE-established budget parameters. Second, APS was a sub-recipient under a $3.4 million ARRA award received through the State of Arizona for the implementation of various distributed energy and energy efficiency programs in Arizona. This project concluded on April 30, 2012.

Competitive Environment and Regulatory Oversight

Retail

The ACC regulates APS’s retail electric rates and its issuance of securities. The ACC must also approve any significant transfer or encumbrance of APS’s property used to provide retail electric service and approve or receive prior notification of certain transactions between Pinnacle West, APS and their respective affiliates.

APS is subject to varying degrees of competition from other investor-owned electric and gas utilities in Arizona (such as Southwest Gas Corporation), as well as cooperatives, municipalities, electrical districts and similar types of governmental or non-profit organizations. In addition, some customers, particularly industrial and large commercial customers, may own and operate generation facilities to meet some or all of their own energy requirements. This practice is becoming more

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popular with customers installing or having installed products such as roof top solar panels to meet or supplement their energy needs.

On April 14, 2010, the ACC issued a decision holding that solar vendors that install and operate solar facilities for non-profit schools and governments pursuant to a specific type of contract that calculates payments based on the energy produced are not “public service corporations” under the Arizona Constitution, and are therefore not regulated by the ACC. A second matter is pending with the ACC to determine whether that ruling should extend to solar providers who serve a broader customer base under the same business model. Use of such products by customers within our territory would result in an increasing level of competition. APS cannot predict when, and the extent to which, additional electric service providers will enter or re-enter APS’s service territory.

In 1999, the ACC approved rules for the introduction of retail electric competition in Arizona. As a result, as of January 1, 2001, all of APS’s retail customers were eligible to choose alternate energy suppliers. However, there are currently no active retail competitors offering unbundled energy or other utility services to APS’s customers. In 2000, the Arizona Superior Court found that the rules were in part unconstitutional and in other respects unlawful, the latter finding being primarily on procedural grounds, and invalidated all ACC orders authorizing competitive electric services providers to operate in Arizona. In 2004, the Arizona Court of Appeals invalidated some, but not all of the rules and upheld the invalidation of the orders authorizing competitive electric service providers. In 2005, the Arizona Supreme Court declined to review the Court of Appeals’ decision.

To date, the ACC has taken no further or substantive action on either the rules or the prior orders authorizing competitive electric service providers in response to the final Court of Appeals’ decision. In 2008, the ACC directed the ACC staff to investigate whether such retail competition was in the public interest and what legal impediments remain to competition in light of the Court of Appeals’ decision referenced above. The ACC staff’s report on the results of its investigation was issued on August 12, 2010. The report stated that additional analysis, discussion and study of all aspects of the issue are required in order to perform a proper evaluation. While the report did not make any specific recommendations other than to conduct more workshops, the report did state that the current retail electric competition rules are incomplete and in need of modification.

Several ACC commissioners have publicly expressed interest in re-examining retail electric competition in 2013. APS cannot predict if or when this re-examination might occur.

Wholesale

The FERC regulates rates for wholesale power sales and transmission services. (See Note 3 for information regarding APS’s transmission rates.) During 2012, approximately 5.6% of APS’s electric operating revenues resulted from such sales and services. APS’s wholesale activity primarily consists of managing fuel and purchased power supplies to serve retail customer energy requirements. APS also sells, in the wholesale market, its generation output that is not needed for APS’s Native Load and, in doing so, competes with other utilities, power marketers and independent power producers. Additionally, subject to specified parameters, APS hedges both electricity and fuels. The majority of these activities are undertaken to mitigate risk in APS’s portfolio.

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Environmental Matters

Climate Change

Legislative Initiatives. There have been no recent attempts by Congress to pass legislation that would regulate greenhouse gas (“GHG”) emissions and, with its focus on other issues, such as economic recovery and job growth, it is unclear if and when the 113 th Congress will consider a climate change bill. In the event climate change legislation ultimately passes, the actual economic and operational impact of such legislation on APS depends on a variety of factors, none of which can be fully known until a law is enacted and the specifics of the resulting program are established. These factors include the terms of the legislation with regard to allowed emissions; whether any permitted emissions allowances will be allocated to source operators free of cost or auctioned; the cost to reduce emissions or buy allowances in the marketplace; and the availability of offsets and mitigating factors to moderate the costs of compliance.

In addition to federal legislative initiatives, state-specific initiatives may also impact our business. While Arizona has no pending legislation and no proposed agency rule regulating GHGs in Arizona, the California legislature enacted AB 32 and SB 1368 in 2006 to address GHG emissions. In October 2011, the California Air Resources Board approved final regulations that established a state-wide cap on GHG emissions beginning on January 1, 2013 and established a GHG allowance trading program under that cap. The first phase of the program, which applies to, among other entities, importers of electricity, commenced on January 1, 2013. Under the program, importers of electricity, including APS, must hold carbon allowances to cover GHG emissions associated with electricity imported into California from outside the state. APS is authorized to recover the cost of these carbon allowances through the PSA.

We are monitoring Arizona regulatory activities and other state legislative developments to understand the extent to which they may affect our business, including our sales into the impacted states or the ability of our out-of-state power plant participants to continue their participation in certain coal-fired power plants. In particular, SCE, a participant in Four Corners, has indicated that SB 1368 may prohibit it from making emission control expenditures at the plant. (See “Energy Sources and Resource Planning — Generation Facilities — Coal-Fueled Generating Facilities — Four Corners” above for details of the pending sale of SCE’s interest in Four Corners to APS.)

Regulatory Initiatives. In December 2009, EPA determined that GHG emissions endanger public health and welfare. This determination was made in response to a 2007 United States Supreme Court ruling that GHGs fit within the Clean Air Act’s broad definition of “air pollutant” and, as a result, EPA has the authority to regulate GHG emissions of new motor vehicles under the Clean Air Act. As a result of this “endangerment finding,” EPA determined that the Clean Air Act required new regulatory requirements for new and modified major GHG emitting sources, including power plants. On June 3, 2010, EPA issued a rule under the Clean Air Act, known as the “tailoring rule,” establishing new GHG emissions thresholds that determine when sources, including power plants, must obtain air operating permits or New Source Review permits. “New Source Review,” or “NSR,” is a pre-construction permitting program under the Clean Air Act that requires analysis of pollution controls prior to building a new stationary source or making major modifications to an existing stationary source. The tailoring rule became effective on August 2, 2010 and it became applicable to power plants on January 2, 2011. Several groups filed lawsuits challenging EPA’s endangerment finding and the tailoring rule, but on June 26, 2012, the United States Court of Appeals for the District of Columbia Circuit issued its decision upholding the rules.

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APS does not expect the tailoring rule to have a significant impact on its current operations. The rule will require APS to consider the impact of GHG emissions as part of its traditional New Source Review analysis for new sources and major modifications to existing plants.

On December 30, 2010, pursuant to its authority under the Clean Air Act, EPA finalized a GHG Federal Implementation Plan (“FIP”) for Arizona relating to pre-construction permits for construction of new sources or major modifications of existing sources. Subsequently, in March 2011, EPA and ADEQ entered into an agreement under which EPA delegated to ADEQ authority to issue GHG pre-construction permits and to modify existing GHG pre-construction permits. The GHG FIP will remain in place until such time as EPA approves a State Implementation Plan (“SIP”) that applies pre-construction permit requirements to GHG-emitting stationary sources in Arizona. APS does not expect the GHG FIP to have a significant impact on its current operations.

Pursuant to its authority under the Clean Air Act, on March 27, 2012, EPA proposed New Source Performance Standards (“NSPS”) for GHG emissions from new electric generating units. Once finalized, APS does not expect the GHG NSPS for new units to have an impact on its current operations. EPA has indicated that the rule will not apply to modified, reconstructed, or existing electric generating units. It is unclear when, or if, EPA will propose such standards, which could affect Four Corners, Cholla, and the Navajo Plant once promulgated.

At the present time, we cannot predict what other rules or regulations may ultimately result from EPA’s endangerment finding and what impact other potential rules or regulations will have on APS’s operations. If any emission reduction legislation or additional regulations are enacted, we will assess our compliance alternatives, which may include replacement of existing equipment, installation of additional pollution control equipment, purchase of allowances, retirement or suspension of operations at certain coal-fired facilities, or other actions. Although associated capital expenditures or operating costs resulting from GHG emission regulations or legislation could be material, we believe that we would be able to recover the costs of these environmental compliance initiatives through our regulated rates.

Company Response to Climate Change Initiatives . We have undertaken a number of initiatives to address emission concerns, including renewable energy procurement and development, promotion of programs and rates that promote energy conservation, renewable energy use and energy efficiency. (See “Energy Sources and Resource Planning — Current and Future Resources” above for details of these plans and initiatives.) APS currently has a diverse portfolio of renewable resources, including wind, geothermal, solar, biogas and biomass, and we are focused on increasing the percentage of our energy that is produced by renewable resources.

APS prepares an inventory of GHG emissions from its operations. This inventory is reported to EPA under the EPA GHG Reporting Program and is voluntarily communicated to the public in Pinnacle West’s annual Corporate Responsibility Report, which is available on our website ( www.pinnaclewest.com ). The report provides information related to the Company and its approach to sustainability and its workplace and environmental performance. The information on Pinnacle West’s website, including the Corporate Responsibility Report, is not incorporated by reference into this report.

Climate Change Lawsuit. In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in federal court in the Northern District of California against nine oil

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companies, fourteen power companies (including Pinnacle West), and a coal company, alleging that the defendants’ emissions of carbon dioxide contribute to global warming and constitute a public and private nuisance under both federal and state law. The plaintiffs also allege that the effects of global warming will require the relocation of the village, and they are seeking an unspecified amount of monetary damages. In June 2008, the defendants filed motions to dismiss the action, which were granted. The plaintiffs filed an appeal with the United States Court of Appeals for the Ninth Circuit in November 2009.

On September 21, 2012, a three-judge panel of the Ninth Circuit affirmed the district court’s dismissal of the Kivalina plaintiffs’ federal common law public nuisance action. The court declined to address any other issue raised by the parties, including the plaintiffs’ state nuisance law claim. On October 4, 2012, the plaintiffs filed a petition for rehearing by the entire Ninth Circuit, but on November 27, 2012, the court denied the plaintiffs’ petition. APS continues to believe the action in Kivalina is without merit and will continue to defend against both the federal and state claims.

EPA Environmental Regulation

Regional Haze Rules. Over a decade ago, EPA announced regional haze rules to reduce visibility impairment in national parks and wilderness areas. The rules require states (or, for sources located on tribal land, EPA) to determine what pollution control technologies constitute the “best available retrofit technology” (“BART”) for certain older major stationary sources. EPA subsequently issued the Clean Air Visibility Rule, which provides guidelines on how to perform a BART analysis.

The Four Corners and Navajo Plant participants’ obligations to comply with EPA’s final BART determinations (and Cholla’s obligations to comply with ADEQ’s and EPA’s determinations), coupled with the financial impact of potential future climate change legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of these plants or the ability of individual participants to continue their participation in these plants.

Cholla. In 2007, ADEQ required APS to perform a BART analysis for Cholla pursuant to the Clean Air Visibility Rule. APS completed the BART analysis for Cholla and submitted its BART recommendations to ADEQ on February 4, 2008. The recommendations include the installation of certain pollution control equipment that APS believes constitutes BART. ADEQ reviewed APS’s recommendations and submitted its proposed BART SIP for Cholla and other sources within the state on March 2, 2011.

On December 2, 2011, EPA provided notice of a proposed consent decree to address a lawsuit filed by a number of environmental organizations, which alleged that EPA failed to promulgate FIPs for states that have not yet submitted all or part of the required regional haze SIPs. In accordance with the consent decree, on December 5, 2012, EPA issued a final BART rule applicable to Cholla. EPA approved ADEQ’s BART emissions limits for sulfur dioxide (“SO 2 ”) and emissions of particulate matter (“PM”), but added an SO 2 removal efficiency requirement of 95%. In addition, EPA

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disapproved ADEQ’s BART determinations for oxides of nitrogen (“NO x ”) and promulgated a FIP establishing a new, more stringent “bubbled” NO x emissions rate applicable to the two BART-eligible Cholla units owned by APS and the other BART-eligible unit owned by PacifiCorp. In order to comply with this new rate, APS will be required to install selective catalytic reduction (“SCR”) technology on all three of the Cholla units. APS’s total costs for these post-combustion NO x controls would be approximately $187 million. This amount is not included in our current estimates for environmental capital expenditures in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Expenditures” in Item 7. Under the FIP, APS has five years from December 2012 to complete installation of the equipment and achieve the BART emissions limit for NO x .

APS believes that EPA’s final rule as it applies to Cholla is unsupported and that EPA had no basis for disapproving Arizona’s SIP and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program. Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit. The State of Arizona and three other utilities also filed similar petitions. On February 4, 2013, APS filed a Petition for Reconsideration and Stay of the final BART rule with EPA.

Four Corners . On August 6, 2012, EPA issued its final BART determination for Four Corners. The rule includes two compliance alternatives. The first emission control alternative finalized by EPA would require the installation of post-combustion controls on each of Units 1-5 at Four Corners to reduce NO x emissions. Current estimates indicate that APS’s share of total costs for Four Corners for these controls would be approximately $400 million. Under the second emission control alternative finalized by EPA, the owners of Four Corners would have the option to permanently close Units 1-3 by January 1, 2014 and install post-combustion NO x controls on each of Units 4 and 5 by July 31, 2018. APS’s share of total costs for these controls would be approximately $300 million. The majority of these costs are not included in the capital expenditure estimates in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Expenditures” in Item 7, since they would be incurred in years following 2015. For PM emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lb/mmBtu and Units 1-5 to meet a 20% opacity limit, both of which are achievable through operation of the existing baghouses. Because the Mercury and Air Toxics Standards will force the installation of baghouses on Units 1-3 if APS chooses not to close those units, EPA determined it is not necessary or appropriate to set new PM limits for Units 1-3 under the final Four Corners BART rule. (See “Mercury and other Hazardous Air Pollutants” for additional details of these standards.) Although unrelated to BART, the final BART rule also imposes a 20% opacity limitation on certain fugitive dust emissions from Four Corners’ coal and material handling operations. The Four Corners participants have until July 1, 2013 to notify EPA of which emission control approach Four Corners will follow.

On October 22, 2012, WildEarth Guardians filed a petition for review in the United States Court of Appeals for the Ninth Circuit alleging that EPA violated the Endangered Species Act (“ESA”) when it promulgated the final Four Corners BART FIP. On November 21, 2012, APS filed a motion for leave to intervene as a defendant, and the court granted that motion on December 10, 2012. EPA and APS have pending motions with the court to dismiss the petition or, in the alternative, transfer the case to the United States Court of Appeals for the Tenth Circuit, the circuit in which we believe the petition should have been filed. We cannot currently predict the outcome of this case or whether such outcome will have a material adverse impact on our financial position, results of operations, or cash flows.

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Navajo Plant . On January 18, 2013, EPA issued a proposed BART rule for the Navajo Plant, which would require installation of SCR technology in order to achieve a new, more stringent plantwide NO x emission limit. Under the proposal, the Navajo Plant participants would have up to five years after EPA issues its final determinations to achieve compliance with the BART requirements. APS’s total costs for post-combustion NO x controls could be up to approximately $158 million. The majority of these costs are not included in the capital expenditure estimates described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Expenditures” in Item 7, since they will be incurred in years following 2015. EPA’s proposal also includes an “Alternative to BART,” which would provide the Navajo Plant with additional time to install the SCR technology. Under this “better than BART” alternative, the Navajo Plant participants would be required to install SCR technology on one unit per year in 2021, 2022 and 2023. EPA is also requesting comments on other options that could set longer time frames for installing pollution controls if the Navajo Plant can achieve additional emission reductions. Comments are due to EPA by May 6, 2013.

Mercury and other Hazardous Air Pollutants. On December 16, 2011, EPA issued the final Mercury and Air Toxics Standards (“MATS”), which established maximum achievable control technology (“MACT”) standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired power plants. Generally, plants will have three years after the effective date of the rule to achieve compliance. In the case of Cholla, APS will have a total of four years after the MATS’ effective date to comply with the new MACT standards because on September 24, 2012, the permitting authority granted APS’s request for a one-year compliance date extension.

The MATS will require APS to install additional pollution control equipment. APS has installed certain of the equipment necessary to meet the anticipated standards. APS currently estimates that the cost for the remaining equipment necessary to meet these standards is approximately $124 million for Cholla Units 1-3. The estimated costs for Four Corners Units 1-3 are not included in our current environmental expenditure estimates since our estimates assume the consummation of APS’s purchase of SCE’s interest in Four Corners Units 4 and 5 and the subsequent shut down of Units 1-3. Cholla’s estimated costs for the next three years are included in our environmental expenditure estimates. (See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Expenditures” in Item 7 for details of our capital expenditure estimates). SRP, the operating agent for the Navajo Plant, is still evaluating compliance options under the MATS.

Cooling Water Intake Structures. EPA issued its proposed cooling water intake structures rule on April 20, 2011, which provides national standards applicable to certain cooling water intake structures at existing power plants and other facilities pursuant to Section 316(b) of the Clean Water Act. The proposed standards are intended to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures). To minimize impingement mortality, the proposed rule would require facilities, such as Four Corners and the Navajo Plant, to either demonstrate that impingement mortality at its cooling water intakes does not exceed a specified rate or reduce the flow at those structures to less than a specified velocity, and to take certain protective measures with respect to impinged fish. To minimize entrainment mortality, the proposed rule would also require these facilities to conduct a “structured site-specific analysis” to determine what site-specific controls, if any, should be required. Additional studies and a peer review process will also be required at these facilities.

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As proposed, existing facilities subject to the rule would have to comply with the impingement mortality requirements as soon as possible, but in no event later than eight years after the effective date of the rule, and would have to comply with the entrainment requirements as soon as possible under a schedule of compliance established by the permitting authority. APS is performing analyses to determine the costs of compliance with the proposed rule. EPA is working to finalize the standards by June 27, 2013.

Coal Combustion Waste. On June 21, 2010, EPA released its proposed regulations governing the handling and disposal of coal combustion residuals (“CCRs”), such as fly ash and bottom ash. APS currently disposes of CCRs in ash ponds and dry storage areas at Cholla and Four Corners, and also sells a portion of its fly ash for beneficial reuse as a constituent in concrete production. EPA proposes regulating CCRs as either non-hazardous waste or hazardous waste and requested comments on three different alternatives. The hazardous waste proposal would phase out the use of ash ponds for disposal of CCRs. The other two proposals would regulate CCRs as non-hazardous waste and impose performance standards for ash disposal. One of these proposals would require retrofitting or closure of currently unlined ash ponds, while the other proposal would not require the installation of liners or pond closures. EPA has not yet indicated a preference for any of the alternatives.

On April 5, 2012, a coalition of environmental groups filed suit to compel EPA to finalize its proposed CCR rule. Soon thereafter, coal ash recyclers filed similar lawsuits against EPA. Although we do not know when EPA will issue a final rule or by when compliance will ultimately be required, in an October 11, 2012 filing with the court, EPA took the position that it will need at least a year to finalize the rule. Motions and cross-motions for summary judgment are currently pending before the court. We cannot currently predict the outcome of the lawsuit or EPA’s actions or whether such actions will have a material adverse impact on our financial position, results of operations, or cash flows.

Effluent Limitation Guidelines. EPA is subject to a consent decree deadline to propose revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil-fired electric generating units by April 19, 2013, and to finalize the rule by May 22, 2014. EPA has indicated that it expects the revised standards to target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities and scrubber-related operations. If EPA requires such conversions under the final rule, Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change their waste disposal techniques. EPA may also revise standards for metals and other pollutants for wastewater streams not associated with ash handling. We cannot currently predict the shape of EPA’s final rule or whether this action will have a material adverse impact on our financial position, results of operations, or cash flows.

Ozone National Ambient Air Quality Standards. In March 2008, EPA adopted new, more stringent eight-hour ozone standards, known as national ambient air quality standards (“NAAQS”). In January 2010, EPA proposed to adopt even more stringent eight-hour ozone NAAQS. However, on September 2, 2011, President Obama decided to withdraw EPA’s revised ozone standards until at least 2013 when EPA would be required to review them as part of its five-year NAAQS review process. As ozone standards become more stringent, our fossil generation units may come under increasing pressure to reduce emissions of nitrogen oxides and volatile organic compounds and/or to generate emission offsets for new projects or facility expansions. At this time, APS is unable to predict what impact the adoption of these standards may have on its financial position, results of operations, or cash flows.

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New Source Review . On April 6, 2009, APS received a request from EPA under Section 114 of the Clean Air Act seeking detailed information regarding projects at and operations of Four Corners. This request is part of an enforcement initiative that EPA has undertaken under the Clean Air Act. EPA has taken the position that many utilities have made certain physical or operational changes at their plants that should have triggered additional regulatory requirements under the New Source Review provisions of the Clean Air Act. Other electric utilities have received and responded to similar Section 114 requests, and several of them have been the subject of notices of violation and lawsuits by EPA. APS responded to EPA’s request in August 2009 and is currently unable to predict the timing or content of EPA’s response, if any, or any resulting actions.

Clean Air Act Lawsuit . On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the New Source Review provisions of the Clean Air Act. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s NSPS program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss, which are pending. We are unable to determine a range of potential losses that are reasonably possible of occurring.

Endangered Species Act. On January 30, 2011, the Center for Biological Diversity, Diné Citizens Against Ruining Our Environment, and San Juan Citizens Alliance filed a lawsuit in the United States District Court for the District of Colorado against OSM and DOI, alleging that OSM failed to engage in mandatory ESA consultation with the Fish and Wildlife Service prior to authorizing the renewal of an operating permit for the mine that serves Four Corners. The lawsuit alleged that activities at the mine, including mining and the disposal of coal combustion residuals, would adversely affect several endangered species and their critical habitats. APS is not a party to the lawsuit but is monitoring it to determine its potential impact on APS’s operations. On March 14, 2012, the district court entered an order dismissing the plaintiffs’ lawsuit without prejudice. On May 14, 2012, the plaintiffs appealed the court’s order to the United States Court of Appeals for the Tenth Circuit.

Superfund. The Comprehensive Environmental Response, Compensation and Liability Act (“Superfund”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are potentially responsible parties (“PRPs”). PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52 nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study work plan. We estimate that our costs related to this investigation and study will be approximately $2 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.

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Manufactured Gas Plant Sites. Certain properties which APS now owns or which were previously owned by it or its corporate predecessors were at one time sites of, or sites associated with, manufactured gas plants. APS is taking action to voluntarily remediate these sites. APS does not expect these matters to have a material adverse effect on its financial position, results of operations or cash flows.

Navajo Nation Environmental Issues

Four Corners and the Navajo Plant are located on the Navajo Reservation and are held under easements granted by the federal government as well as leases from the Navajo Nation. See “Energy Sources and Resource Planning — Generation Facilities — Coal-Fueled Generating Facilities” above for additional information regarding these plants.

In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act, and the Navajo Nation Pesticide Act (collectively, the “Navajo Acts”). The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners and the Navajo Plant. On October 17, 1995, the Four Corners participants and the Navajo Plant participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, challenging the applicability of the Navajo Acts as to Four Corners and the Navajo Plant. The Court has stayed these proceedings pursuant to a request by the parties, and the parties are seeking to negotiate a settlement.

In April 2000, the Navajo Nation Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. APS believes the Navajo Nation exceeded its authority when it adopted the operating permit regulations. On July 12, 2000, the Four Corners participants and the Navajo Plant participants each filed a petition with the Navajo Supreme Court for review of these regulations. Those proceedings have been stayed, pending the settlement negotiations mentioned above. APS cannot currently predict the outcome of this matter.

On May 18, 2005, APS, Salt River Project, as the operating agent for the Navajo Plant, and the Navajo Nation executed a Voluntary Compliance Agreement to resolve their disputes regarding the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the courts granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the Clean Air Act. The agreement does not address or resolve any dispute relating to other Navajo Acts. APS cannot currently predict the outcome of this matter.

Water Supply

Assured supplies of water are important for APS’s generating plants. At the present time, APS has adequate water to meet its needs. However, the Four Corners region, in which Four Corners is located, has been experiencing drought conditions that may affect the water supply for the plants if adequate moisture is not received in the watershed that supplies the area. APS is continuing to work with area stakeholders to implement agreements to minimize the effect, if any, on future operations of the plant. The effect of the drought cannot be fully assessed at this time, and APS cannot predict the ultimate outcome, if any, of the drought or whether the drought will adversely affect the amount of power available, or the price thereof, from Four Corners.

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Conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions, which, in addition to future supply conditions, have the potential to impact APS operations.

San Juan River Adjudication. Both groundwater and surface water in areas important to APS’s operations have been the subject of inquiries, claims, and legal proceedings, which will require a number of years to resolve. APS is one of a number of parties in a proceeding, filed March 13, 1975, before the Eleventh Judicial District Court in New Mexico to adjudicate rights to a stream system from which water for Four Corners is derived. An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss.

Gila River Adjudication. A summons served on APS in early 1986 required all water claimants in the Lower Gila River Watershed in Arizona to assert any claims to water on or before January 20, 1987, in an action pending in Arizona Superior Court. Palo Verde is located within the geographic area subject to the summons. APS’s rights and the rights of the other Palo Verde participants to the use of groundwater and effluent at Palo Verde are potentially at issue in this action. As operating agent of Palo Verde, APS filed claims that dispute the court’s jurisdiction over the Palo Verde participants’ groundwater rights and their contractual rights to effluent relating to Palo Verde. Alternatively, APS seeks confirmation of such rights. Five of APS’s other power plants are also located within the geographic area subject to the summons. APS’s claims dispute the court’s jurisdiction over its groundwater rights with respect to these plants. Alternatively, APS seeks confirmation of such rights. In November 1999, the Arizona Supreme Court issued a decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. In addition, in September 2000, the Arizona Supreme Court issued a decision affirming the lower court’s criteria for resolving groundwater claims. Litigation on both of these issues has continued in the trial court. In December 2005, APS and other parties filed a petition with the Arizona Supreme Court requesting interlocutory review of a September 2005 trial court order regarding procedures for determining whether groundwater pumping is affecting surface water rights. The Court denied the petition in May 2007, and the trial court is now proceeding with implementation of its 2005 order. No trial date concerning APS’s water rights claims has been set in this matter.

Little Colorado River Adjudication. APS has filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County, Arizona, Superior Court, which was originally filed on September 5, 1985. APS’s groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and, therefore, is potentially at issue in the case. APS’s claims dispute the court’s jurisdiction over its groundwater rights. Alternatively, APS seeks confirmation of such rights. Other claims have been identified as ready for litigation in motions filed with the court. No trial date concerning APS’s water rights claims has been set in this matter.

Although the above matters remain subject to further evaluation, APS does not expect that the described litigation will have a material adverse impact on its financial position, results of operations, or cash flows.

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BUSINESS OF OTHER SUBSIDIARIES

The operations of our other first-tier subsidiaries (described below) are not expected to contribute in any material way to our future financial performance nor will they require any material amounts of capital over the next three years. We continue to focus on our core utility business and streamlining the Company.

El Dorado

El Dorado owns minority interests in several energy-related investments and Arizona community-based ventures. El Dorado’s short-term goal is to prudently realize the value of its existing investments. As of December 31, 2012, El Dorado had total assets of $19 million.

SunCor

SunCor was a developer of residential, commercial and industrial real estate projects in Arizona, Idaho, New Mexico and Utah. Due to the continuing distressed conditions in the real estate markets, in 2009 SunCor undertook a program to dispose of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to eliminate its outstanding debt. On February 24, 2012, SunCor filed for protection under the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Arizona to complete an orderly liquidation of its business. As of December 31, 2012, SunCor had no assets. All activities for SunCor are now reported as discontinued operations (see Note 21). SunCor’s loss in 2012 is primarily related to a contribution Pinnacle West expects to make to SunCor’s estate as part of a negotiated resolution to the bankruptcy. We do not expect SunCor’s bankruptcy to have a material impact on Pinnacle West’s financial position, results of operations or cash flows.

Financial Summary

	2012			2011			2010
	(dollars in millions)
Revenues (a)	$	—		$	1		$	30
Net loss attributable to common shareholders (b)	$	(10	)	$	(2	)	$	(10	)
Total assets at December 31	$	—		$	9		$	16

(a) All reported as discontinued operations on Pinnacle West’s Consolidated Statements of Income (see Note 21).

(b) In accordance with the tax sharing agreement, the parent company recognized tax benefits of $4 million in 2012, $1 million in 2011, and $4 million in 2010.

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OTHER INFORMATION

Pinnacle West, APS and Pinnacle West’s other operating first-tier subsidiary are all incorporated in the State of Arizona. Additional information for each of these companies is provided below:

	Principal Executive Office Address	Year of Incorporation	Approximate Number of Employees at December 31, 2012
Pinnacle West	400 North Fifth Street Phoenix, AZ 85004	1985	79

APS	400 North Fifth Street P.O. Box 53999 Phoenix, AZ 85072-3999	1920	6,534

El Dorado	400 North Fifth Street Phoenix, AZ 85004	1983	—
Total			6,613

The APS number includes employees at jointly-owned generating facilities (approximately 2,930 employees) for which APS serves as the generating facility manager. Approximately 1,877 APS employees are union employees. APS entered into a three-year collective bargaining agreement with union employees in the fossil generation, energy delivery and customer service business areas that expires in April 2014. In January 2013, the Palo Verde security officers voted to change their collective bargaining representative from the Security, Police and Fire Professionals of America to the United Security Professionals of America (“USPA”) and the National Labor Relations Board has certified the results. The Company is prepared to engage in good-faith negotiations with the USPA regarding the terms and conditions of their employment.

WHERE TO FIND MORE INFORMATION

We use our website www.pinnaclewest.com as a channel of distribution for material Company information. The following filings are available free of charge on our website as soon as reasonably practicable after they are electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”): Annual Reports on Form 10-K, definitive proxy statements for our annual shareholder meetings, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports. Our board and committee charters, Code of Ethics for Financial Executives, Code of Ethics and Business Practices and other corporate governance information is also available on the Pinnacle West website. Pinnacle West will post any amendments to the Code of Ethics for Financial Executives and Code of Ethics and Business Practices, and any waivers that are required to be disclosed by the rules of either the SEC or the New York Stock Exchange, on its website. The information on Pinnacle West’s website is not incorporated by reference into this report.

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You can request a copy of these documents, excluding exhibits, by contacting Pinnacle West at the following address: Pinnacle West Capital Corporation, Office of the Secretary, Station 8602, P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-4400).

ITEM 1A. RISK FACTORS

In addition to the factors affecting specific business operations identified in the description of these operations contained elsewhere in this report, set forth below are risks and uncertainties that could affect our financial results. Unless otherwise indicated or the context otherwise requires, the following risks and uncertainties apply to Pinnacle West and its subsidiaries, including APS.

REGULATORY RISKS

Our financial condition depends upon APS’s ability to recover costs in a timely manner from customers through regulated rates and otherwise execute its business strategy.

APS is subject to comprehensive regulation by several federal, state and local regulatory agencies that significantly influence its business, liquidity, results of operations and its ability to fully recover costs from utility customers in a timely manner. The ACC regulates APS’s retail electric rates and the FERC regulates rates for wholesale power sales and transmission services. The profitability of APS is affected by the rates it may charge and the timeliness of recovering costs incurred through its rates. Consequently, our financial condition and results of operations are dependent upon the satisfactory resolution of any APS rate proceedings and ancillary matters which may come before the ACC and the FERC. Arizona, like certain other states, has a statute that allows the ACC to reopen prior decisions and modify final orders under certain circumstances. The ACC must also approve APS’s issuance of securities and any transfer of APS property used to provide retail electric service, and must approve or receive prior notification of certain transactions between us, APS and our respective affiliates. Decisions made by the ACC or the FERC could have a material adverse impact on our financial condition, results of operations or cash flows.

APS’s ability to conduct its business operations and avoid fines and penalties depends upon compliance with federal, state or local statutes, regulations and ACC requirements, and obtaining and maintaining certain regulatory permits, approvals and certificates.

APS must comply in good faith with all applicable statutes, regulations, rules, tariffs, and orders of agencies that regulate APS’s business, including the FERC, the NRC, EPA, the ACC and state and local governmental agencies. These agencies regulate many aspects of APS’s utility operations, including safety and performance, emissions, siting and construction of facilities, customer service and the rates that APS can charge retail and wholesale customers. Failure to comply can subject APS to, among other things, fines and penalties. For example, under the Energy Policy Act of 2005, the FERC can impose penalties (up to one million dollars per day per violation) for failure to comply with mandatory electric reliability standards. In addition to penalties, APS may be unable to recover certain costs if, for example, it fails to implement any of its annual ACC-approved renewable implementation plans. APS is also required to have numerous permits, approvals and certificates from these agencies. APS believes the necessary permits, approvals and certificates have been obtained for its existing operations and that APS’s business is conducted in accordance with applicable laws in all material respects. However, changes in regulations or the imposition of new or revised laws or regulations could have an adverse impact on our results of operations. We are also unable to predict

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the impact on our business and operating results from pending or future regulatory activities of any of these agencies .

The operation of APS’s nuclear power plant exposes it to substantial regulatory oversight and potentially significant liabilities and capital expenditures.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. Events at nuclear facilities of other operators or impacting the industry generally may lead the NRC to impose additional requirements and regulations on all nuclear generation facilities, including Palo Verde. As a result of the March 2011 earthquake and tsunami that caused significant damage to the Fukushima Daiichi Nuclear Power Plant in Japan, various industry organizations are working to analyze information from the Japan incident and develop action plans for U.S. nuclear power plants. Additionally, the NRC is performing its own independent review of the events at Fukushima Daiichi, including a review of the agency’s processes and regulations in order to determine whether the agency should promulgate additional regulations and possibly make more fundamental changes to the NRC’s system of regulation. We cannot predict when or if the NRC will take formal action as a result of its review. The financial and/or operational impacts on Palo Verde and APS may be significant.

In the event of noncompliance with its requirements, the NRC has the authority to impose monetary civil penalties or a progressively increased inspection regime that could ultimately result in the shut-down of a unit, or both, depending upon the NRC’s assessment of the severity of the situation, until compliance is achieved. The increased costs resulting from penalties, a heightened level of scrutiny and implementation of plans to achieve compliance with NRC requirements may adversely affect APS’s financial condition, results of operations and cash flows.

APS is subject to numerous environmental laws and regulations, and changes in, or liabilities under, existing or new laws or regulations may increase APS’s cost of operations or impact its business plans.

APS is, or may become, subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, discharges of wastewater and streams originating from fly ash and bottom ash handling facilities, solid waste, hazardous waste, and coal combustion products, which consist of bottom ash, fly ash, and air pollution control wastes. These laws and regulations can result in increased capital, operating, and other costs, particularly with regard to enforcement efforts focused on power plant emissions obligations. These laws and regulations generally require APS to obtain and comply with a wide variety of environmental licenses, permits, and other approvals. If there is a delay or failure to obtain any required environmental regulatory approval, or if APS fails to obtain, maintain, or comply with any such approval, operations at affected facilities could be suspended or subject to additional expenses. In addition, failure to comply with applicable environmental laws and regulations could result in civil liability as a result of government enforcement actions or private claims or criminal penalties. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. APS cannot predict the outcome (financial or operational) of any related litigation that may arise.

Environmental Clean Up. APS has been named as a PRP for a Superfund site in Phoenix, Arizona and it could be named a PRP in the future for other environmental clean up at sites identified by a regulatory body. APS cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean up costs.

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There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

Regional Haze. APS has received final rulemaking imposing new requirements on Four Corners and Cholla and is currently awaiting a final rulemaking from EPA that could impose new requirements on the Navajo Plant. EPA and ADEQ will require these plants to install pollution control equipment that constitutes the best available retrofit technology to lessen the impacts of emissions on visibility surrounding the plants. The financial impact of installing and operating the required pollution control equipment could jeopardize the economic viability of these plants or the ability of individual participants to continue their participation in these plants.

Coal Ash. EPA released proposed regulations governing the disposal of CCRs, which are generated as a result of burning coal and consist of, among other things, fly ash and bottom ash. EPA proposed regulating CCRs as either non-hazardous or hazardous waste. APS currently disposes of CCRs in ash ponds and dry storage areas at Four Corners and Cholla, and also sells a portion of its fly ash for beneficial reuse as a constituent in concrete products. If EPA regulates CCRs as a hazardous solid waste or phases out APS’s ability to dispose of CCRs through the use of ash ponds, APS could incur significant costs for CCR disposal and may be unable to continue its sale of fly ash for beneficial reuse.

Effluent Limitation Guidelines. EPA is expected to propose revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil-fired electric generating units by April 19, 2013, and to promulgate a final rule by May 22, 2014. EPA has indicated that it expects the revised standards to target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities and scrubber-related operations. APS currently disposes of fly ash waste and bottom ash in ash ponds at Four Corners. Changes required by the rule could significantly increase ash disposal costs at Four Corners.

New Source Review. EPA has taken the position that many projects electric utilities have performed are major modifications that trigger New Source Review requirements under the Clean Air Act. The utilities generally have taken the position that these projects are routine maintenance and did not result in emissions increases, and thus are not subject to New Source Review. In 2009, APS received and responded to a request from EPA regarding projects and operations of Four Corners. An environmental organization filed suit against the Four Corners participants for alleged violations of New Source Review and the NSPS programs of the Clean Air Act. If EPA seeks to impose New Source Review requirements at Four Corners or any other APS plant, or if the citizens’ group prevails in its lawsuit, significant capital investments could be required to install new pollution control technologies. EPA could also seek civil penalties.

APS cannot assure that existing environmental regulations will not be revised or that new regulations seeking to protect the environment will not be adopted or become applicable to it. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs incurred by APS are not fully recoverable from APS’s customers, could have a material adverse effect on its financial condition, results of operations or cash flows. Due to current or potential future regulations or legislation, the economics of continuing to own certain resources, particularly coal facilities, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.

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APS faces physical and operational risks related to climate change, and potential financial risks resulting from climate change litigation and legislative and regulatory efforts to limit greenhouse gas emissions.

Concern over climate change, deemed by many to be induced by rising levels of greenhouse gases in the atmosphere, has led to significant legislative and regulatory efforts to limit CO 2 , which is a major byproduct of the combustion of fossil fuel, and other greenhouse gas emissions. In addition, lawsuits have been filed against companies that emit greenhouse gases, including a lawsuit filed by the Native Village of Kivalina and the City of Kivalina, Alaska against us and several other utilities seeking damages related to climate change.

Financial Risks — Potential Legislation and Regulation . It is possible that some form of legislation or EPA action to regulate domestic greenhouse gas emissions may occur in the future at the federal level. If the United States Congress, or individual states or groups of states in which APS operates, ultimately pass legislation, or if EPA promulgates additional regulations regulating the emissions of greenhouse gases from existing generation facilities, any resulting limitations on CO 2 and other greenhouse gas emissions could result in the creation of substantial additional capital expenditures and operating costs in the form of taxes, emissions allowances, or required equipment upgrades and could have a material adverse impact on all fossil-fuel-fired generation facilities (particularly coal-fired facilities, which constitute approximately 28% of APS’s generation capacity).

At the state level, the California legislature enacted legislation to address greenhouse gas emissions and the California Air Resources Board approved regulations that will establish a cap-and-trade program for greenhouse gas. This legislation, regulation and other state-specific initiatives may affect APS’s business, including sales into the impacted states or the ability of its out-of-state power plant participants to continue their participation in certain coal-fired power plants, including Four Corners following 2016.

Physical and Operational Risks. Weather extremes such as drought and high temperature variations are common occurrences in the Southwest’s desert area, and these are risks that APS considers in the normal course of business in the engineering and construction of its electric system. Large increases in ambient temperatures could require evaluation of certain materials used within its system and represent a greater challenge.

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Deregulation or restructuring of the electric industry may result in increased competition, which could have a significant adverse impact on APS’s business and its results of operations.

In 1999, the ACC approved rules for the introduction of retail electric competition in Arizona. Retail competition could have a significant adverse financial impact on APS due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. Although some very limited retail competition existed in APS’s service area in 1999 and 2000, there are currently no active retail competitors offering unbundled energy or other utility services to APS’s customers. As a result, APS cannot predict if, when, and the extent to which, additional competitors may re-enter APS’s service territory. Several ACC commissioners have publicly expressed interest in re-examining retail electric competition in 2013. APS cannot predict how and when this re-examination might take place.

In 2010, the ACC issued a decision holding that solar vendors that install and operate solar facilities for non-profit schools and governments pursuant to a specific type of contract that calculates payments based on the energy produced are not “public service corporations” under the Arizona Constitution, and are therefore not regulated by the ACC. A second matter is pending with the ACC to determine whether that ruling should extend to solar providers who serve a broader customer base under the same business model. The use of such products by customers within our territory would result in some level of competition. APS cannot predict whether the ACC will deem these vendors “public service corporations” subject to ACC regulation and when, and the extent to which, additional service providers will enter APS’s service territory, increasing the level of competition in the market.

OPERATIONAL RISKS

APS’s results of operations can be adversely affected by various factors impacting demand for electricity.

Weather Conditions. Weather conditions directly influence the demand for electricity and affect the price of energy commodities. Electric power demand is generally a seasonal business. In Arizona, demand for power peaks during the hot summer months, with market prices also peaking at that time. As a result, APS’s overall operating results fluctuate substantially on a seasonal basis. In addition, APS has historically sold less power, and consequently earned less income, when weather conditions are milder. As a result, unusually mild weather could diminish APS’s financial condition, results of operations and cash flows.

Higher temperatures may decrease the snowpack, which might result in lowered soil moisture and an increased threat of forest fires. Forest fires could threaten APS’s communities and electric transmission lines. Any damage caused as a result of forest fires could negatively impact APS’s financial condition, results of operations or cash flows.

Effects of Energy Conservation Measures and Distributed Energy. The ACC has enacted rules regarding energy efficiency that mandate a 22% annual energy savings requirement by 2020. This will likely increase participation by APS customers in energy efficiency and conservation programs and other demand-side management efforts, which in turn will impact the demand for electricity. The rules also include a requirement for the ACC to review and address financial disincentives, recovery of fixed costs and the recovery of net lost income/revenue that would result from lower sales due to increased energy efficiency requirements. To that end, the settlement agreement in APS’s recent retail rate case (the “Settlement Agreement”) includes a mechanism, the LFCR, to address these matters. The 2009

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retail rate case settlement agreement also established energy efficiency goals for APS that extended through 2012, subjecting APS to energy efficiency requirements slightly greater for the first two of those years than required under the rules described above.

APS must also meet certain distributed energy requirements. A portion of APS’s total renewable energy requirement must be met with an increasing percentage of distributed energy resources (generally, small scale renewable technologies located on customers’ properties). The distributed energy requirement was 25% of the overall RES requirement of 3% in 2011 and increased to 30% of the applicable RES requirement for 2012 and subsequent years. Customer participation in distributed energy programs would result in lower demand, since customers would be meeting some or all of their own energy needs.

Reduced demand due to these energy efficiency and distributed energy requirements, unless substantially offset through ratemaking mechanisms, could have a material adverse impact on APS’s financial condition, results of operations and cash flows. Additionally, higher than anticipated penetration of distributed energy may also cause portions of APS’s existing resource fleet, such as coal, to become uneconomic or operationally burdensome.

Customer and Sales Growth. For the three years 2010 through 2012, APS’s customer growth averaged 0.7% per year. We currently expect annual customer growth to average about 2% for 2013 through 2015 based on our assessment of modestly improving economic conditions, both nationally and in Arizona. For the three years 2010 through 2012, APS experienced annual declines in retail electricity sales averaging 0.1%, adjusted to exclude the effects of weather variations. We currently estimate that annual retail electricity sales in kilowatt-hours will remain about flat on average during 2013 through 2015, excluding the effects of weather variations. Actual customer and sales growth may differ from our projections as a result of numerous factors, such as economic conditions, customer growth and usage patterns, and the effects of energy efficiency and distributed energy programs and requirements. If our customer growth rate does not continue to improve as projected, or if it declines, or if the Arizona economy fails to improve, we may be unable to reach our estimated demand level and sales projections, which could have a negative impact on our financial condition, results of operations and cash flows.

The operation of power generation facilities and transmission systems involves risks that could result in reduced output or unscheduled outages, which could materially affect APS’s results of operations .

The operation of power generation, transmission and distribution facilities involves certain risks, including the risk of breakdown or failure of equipment, fuel interruption, and performance below expected levels of output or efficiency. Unscheduled outages, including extensions of scheduled outages due to mechanical failures or other complications, occur from time to time and are an inherent risk of APS’s business. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the larger transmission power grid, and the operation or failure of our facilities could adversely affect the operations of others. If APS’s facilities operate below expectations, especially during its peak seasons, it may lose revenue or incur additional expenses, including increased purchased power expenses.

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The inability to successfully develop or acquire generation resources to meet new or evolving standards and regulations could adversely impact our business.

Potential changes in regulatory standards, impacts of new and existing laws and regulations, including environmental laws and regulations, and the need to obtain certain regulatory approvals create uncertainty surrounding our generation portfolio. In addition, APS is required by the ACC to meet certain energy resource portfolio requirements and the RES. The development of any renewable generation facilities resulting from the RES is subject to many other risks, including risks related to financing, siting, permitting, technology, the construction of sufficient transmission capacity to support these facilities and stresses to generation and transmission resources from intermittent generation characteristics of renewable resources. APS’s inability to adequately develop or acquire the necessary generation resources to meet the required standards could have a material adverse impact on our business and results of operations.

The lack of access to sufficient supplies of water could have a material adverse impact on APS’s business and results of operations.

Assured supplies of water are important for APS’s generating plants. Water in the southwestern United States is limited and various parties have made conflicting claims regarding the right to access and use such limited supply of water. Both groundwater and surface water in areas important to APS’s generating plants have been and are the subject of inquiries, claims and legal proceedings. In addition, the region in which APS’s power plants are located is prone to drought conditions, which could potentially affect the plants’ water supplies. APS’s inability to access sufficient supplies of water could have a material adverse impact on our business and results of operations.

The ownership and operation of power generation and transmission facilities on Indian lands could result in uncertainty related to continued leases, easements and rights-of-way, which could have a significant impact on our business.

Certain APS power plants, including Four Corners, and portions of the transmission lines that carry power from these plants are located on Indian lands pursuant to leases, easements or other rights-of-way that are effective for specified periods. APS is currently unable to predict the final outcome of pending and future approvals by applicable governing bodies with respect to renewals of these leases, easements and rights-of-way.

There are inherent risks in the ownership and operation of nuclear facilities, such as environmental, health, fuel supply, spent fuel disposal, regulatory and financial risks and the risk of terrorist attack.

APS has an ownership interest in and operates, on behalf of a group of participants, Palo Verde, which is the largest nuclear electric generating facility in the United States. Palo Verde constitutes approximately 18% of our owned and leased generation capacity. Palo Verde is subject to environmental, health and financial risks such as the ability to obtain adequate supplies of nuclear fuel; the ability to dispose of spent nuclear fuel; the ability to maintain adequate reserves for decommissioning; potential liabilities arising out of the operation of these facilities; the costs of securing the facilities against possible terrorist attacks; and unscheduled outages due to equipment and other problems. APS maintains nuclear decommissioning trust funds and external insurance coverage to minimize its financial exposure to some of these risks; however, it is possible that damages could

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exceed the amount of insurance coverage. In addition, APS may be required under federal law to pay up to $118 million (but not more than $18 million per year) of liabilities arising out of a nuclear incident occurring not only at Palo Verde, but at any other nuclear power plant in the United States. Although we have no reason to anticipate a serious nuclear incident at Palo Verde, if an incident did occur, it could materially and adversely affect our results of operations and financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit and to promulgate new regulations that could require significant capital expenditures and/or increase operating costs.

The use of derivative contracts in the normal course of our business could result in financial losses that negatively impact our results of operations.

APS’s operations include managing market risks related to commodity prices. APS is exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas and coal to the extent that unhedged positions exist. We have established procedures to manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options, and swaps. As part of our overall risk management program, we enter into derivative transactions to hedge purchases and sales of electricity and fuels. The changes in market value of such contracts have a high correlation to price changes in the hedged commodity. To the extent that commodity markets are illiquid, we may not be able to execute our risk management strategies, which could result in greater unhedged positions than we would prefer at a given time and financial losses that negatively impact our results of operations.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), which was signed into law in July 2010, contains measures aimed at increasing the transparency and stability of the over-the counter, or OTC, derivative markets and preventing excessive speculation. The Dodd-Frank Act could restrict, among other things, trading positions in the energy futures markets, require different collateral or settlement positions, or increase regulatory reporting over derivative positions. Based on the provisions included in the Dodd-Frank Act and the implementation of regulations, these changes could, among other things, impact our ability to hedge commodity price and interest rate risk or increase the costs associated with our hedging programs.

We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We use a risk management process to assess and monitor the financial exposure of all counterparties. Despite the fact that the majority of APS’s trading counterparties are rated as investment grade by the rating agencies, there is still a possibility that one or more of these companies could default, which could result in a material adverse impact on our earnings for a given period.

Changes in technology could create challenges for APS’s existing business.

Research and development activities are ongoing to assess alternative technologies that produce power or reduce power consumption, including clean coal and coal gasification, renewable technologies including photovoltaic (solar) cells, customer-sited generation (solar) and efficiency technologies, and improvements in traditional technologies and equipment, such as more efficient gas turbines. Advances in these, or other technologies could reduce the cost of power production, making APS’s existing generating facilities less economical. In addition, advances in technology and equipment/appliance efficiency could reduce the demand for power supply, which could adversely affect APS’s business.

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APS is pursuing and implementing smart grid technologies, including advanced transmission and distribution system technologies, as well as digital meters enabling two-way communications between the utility and its customers. Many of the products and processes resulting from these and other alternative technologies have not yet been widely used or tested, and their use on large-scale systems is not as advanced and established as APS’s existing technologies and equipment. Uncertainties and unknowns related to these and other advancements in technology and equipment could adversely affect APS’s business if national standards develop that do not embrace the current technologies or if the technologies and equipment fail to perform as expected. In addition, widespread installation and acceptance of these devices could enable the entry of new market participants, such as technology companies, into the interface between APS and its customers.

We are subject to employee workforce factors that could adversely affect our business and financial condition.

Like most companies in the electric utility industry, our workforce is aging and a number of our employees will become eligible to retire within the next few years. Although we have undertaken efforts to recruit and train new employees, we may not be successful. We are subject to other employee workforce factors, such as the availability of qualified personnel, the need to negotiate collective bargaining agreements with union employees and potential work stoppages. Exposure to these or other employee workforce factors could negatively impact our business, financial condition or results of operations.

We are subject to information security risks and risks of unauthorized access to our systems .

In the regular course of our business we handle a range of sensitive security, customer and business systems information. We are subject to laws and rules issued by different agencies concerning safeguarding and maintaining the confidentiality of this information. A security breach of our information systems such as theft or the inappropriate release of certain types of information, including confidential customer, employee, financial or system operating information, could have a material adverse impact on our financial condition, results of operations or cash flows.

We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite implementation of security measures, our technology systems are vulnerable to disability, failures or unauthorized access. Our generation, transmission and distribution facilities, information technology systems and other infrastructure facilities and systems and physical assets could be targets of such unauthorized access. Failures or breaches of our systems could impact the reliability of our generation, transmission and distribution systems and also subject us to financial harm. If our technology systems were to fail or be breached and if we are unable to recover in a timely way, we may not be able to fulfill critical business functions and sensitive confidential data could be compromised, which could have a material adverse impact on our financial condition, results of operations or cash flows.

The implementation of security measures and cost of insurance addressing such activities could increase costs and have a material adverse impact on our financial results. These types of events could also require significant management attention and resources, and could adversely affect Pinnacle West’s and APS’s reputation with customers and the public.

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FINANCIAL RISKS

Financial market disruptions or new financial rules or regulations may increase our financing costs or limit our access to the credit markets, which may adversely affect our liquidity and our ability to implement our financial strategy.

We rely on access to credit markets as a significant source of liquidity and the capital markets for capital requirements not satisfied by cash flow from our operations. We believe that we will maintain sufficient access to these financial markets. However, certain market disruptions or rules or regulations may increase our cost of borrowing generally, and/or otherwise adversely affect our ability to access these financial markets.

In addition, the credit commitments of our lenders under our bank facilities may not be satisfied for a variety of reasons, including periods of financial distress or liquidity issues affecting our lenders, which could materially adversely affect the adequacy of our liquidity sources.

Changes in economic conditions, monetary policy or other factors could result in higher interest rates, which would increase our interest expense on our existing variable rate debt and new debt we expect to issue in the future, and thus reduce funds available to us for our current plans. Additionally, an increase in our leverage could adversely affect us by:

· causing a downgrade of our credit ratings;

· increasing the cost of future debt financing and refinancing;

· increasing our vulnerability to adverse economic and industry conditions; and

· requiring us to dedicate an increased portion of our cash flow from operations to payments on our debt, which would reduce funds available to us for operations, future business opportunities or other purposes.

A downgrade of our credit ratings could materially and adversely affect our business, financial condition and results of operations.

Our current ratings are set forth in “Liquidity and Capital Resources — Credit Ratings” in Item 7. We cannot be sure that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Any downgrade or withdrawal could adversely affect the market price of Pinnacle West’s and APS’s securities, limit our access to capital and increase our borrowing costs, which would diminish our financial results. We would be required to pay a higher interest rate for future financings, and our potential pool of investors and funding sources could decrease. In addition, borrowing costs under our existing credit facilities depend on our credit ratings. A downgrade would also require us to provide substantial additional support in the form of letters of credit or cash or other collateral to various counterparties. If our short-term ratings were to be lowered, it could severely limit access to the commercial paper market. We note that the ratings from rating agencies are not recommendations to buy, sell or hold our securities and that each rating should be evaluated independently of any other rating.

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Investment performance, changing interest rates and other economic factors could decrease the value of our benefit plan assets and nuclear decommissioning trust funds and increase the valuation of our related obligations, resulting in significant additional funding requirements. We are subject to risks related to the provision of employee healthcare benefits and recent healthcare reform legislation. Any inability to fully recover these costs in our utility rates would negatively impact our financial condition.

We have significant pension plan and other postretirement benefits plan obligations to our employees and retirees and legal obligations to fund nuclear decommissioning trusts for Palo Verde. We hold and invest substantial assets in these trusts that are designed to provide funds to pay for certain of these obligations as they arise. Declines in market values of the fixed income and equity securities held in these trusts may increase our funding requirements. Additionally, the valuation of liabilities related to our pension plan and other postretirement benefit plans are impacted by a discount rate, which is the interest rate used to discount future pension and other postretirement benefit obligations. Declining interest rates decrease the discount rate, increase the valuation of the plan liabilities and may result in increases in pension and other postretirement benefit costs, cash contributions, regulatory assets, and charges to other comprehensive income. Changes in demographics, including increased numbers of retirements or changes in life expectancy and changes in other actuarial assumptions, may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans. The minimum contributions required under these plans are impacted by federal legislation. Increasing liabilities or otherwise increasing funding requirements under these plans, resulting from adverse changes in legislation or otherwise, could result in significant cash funding obligations that could have a material impact on our financial position, results of operations or cash flows.

We recover most of the pension costs and other postretirement benefit costs and all of the nuclear decommissioning costs in our regulated rates. Any inability to fully recover these costs in a timely manner would have a material negative impact on our financial condition, results of operations or cash flows.

Employee healthcare costs in recent years have continued to rise. The Patient Protection and Affordable Care Act is expected to result in additional healthcare cost increases. Costs and other effects of the legislation, which may include the cost of compliance and potentially increased costs of providing for medical insurance for our employees, cannot be determined with certainty at this time. We will continue to monitor healthcare legislation and its impact on our plans and costs.

Our cash flow depends on the performance of APS.

Currently, we derive essentially all of our revenues and earnings from our wholly-owned subsidiary, APS. Accordingly, our cash flow and our ability to pay dividends on our common stock is dependent upon the earnings and cash flows of APS and its distributions to us. APS is a separate and distinct legal entity and has no obligation to make distributions to us.

APS’s debt agreements may restrict its ability to pay dividends, make distributions or otherwise transfer funds to us. In addition, an ACC financing order requires APS to maintain a common equity ratio of at least 40% and does not allow APS to pay common dividends if the payment would reduce its common equity below that threshold. The common equity ratio, as defined in the ACC order, is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.

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Pinnacle West’s ability to meet its debt service obligations could be adversely affected because its debt securities are structurally subordinated to the debt securities and other obligations of its subsidiaries.

Because Pinnacle West is structured as a holding company, all existing and future debt and other liabilities of our subsidiaries will be effectively senior in right of payment to our debt securities. The assets and cash flows of our subsidiaries will be available, in the first instance, to service their own debt and other obligations. Our ability to have the benefit of their cash flows, particularly in the case of any insolvency or financial distress affecting our subsidiaries, would arise only through our equity ownership interests in our subsidiaries and only after their creditors have been satisfied.

The market price of our common stock may be volatile.

The market price of our common stock could be subject to significant fluctuations in response to factors such as the following, some of which are beyond our control:

· variations in our quarterly operating results;

· operating results that vary from the expectations of management, securities analysts and investors;

· changes in expectations as to our future financial performance, including financial estimates by securities analysts and investors;

· developments generally affecting industries in which we operate, particularly the energy distribution and energy generation industries;

· announcements by us or our competitors of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments;

· announcements by third parties of significant claims or proceedings against us;

· favorable or adverse regulatory or legislative developments;

· our dividend policy;

· future sales by the Company of equity or equity-linked securities; and

· general domestic and international economic conditions.

In addition, the stock market in general has experienced volatility that has often been unrelated to the operating performance of a particular company. These broad market fluctuations may adversely affect the market price of our common stock.

Certain provisions of our articles of incorporation and bylaws and of Arizona law make it difficult for shareholders to change the composition of our board and may discourage takeover attempts.

These provisions, which could preclude our shareholders from receiving a change of control premium, include the following:

· restrictions on our ability to engage in a wide range of “business combination” transactions with an “interested shareholder” (generally, any person who owns 10% or more of our outstanding voting power or any of our affiliates or associates) or any affiliate or associate of an interested shareholder, unless specific conditions are met;

· anti-greenmail provisions of Arizona law and our bylaws that prohibit us from purchasing shares of our voting stock from beneficial owners of more than 5% of our outstanding shares unless specified conditions are satisfied;

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· the ability of the Board of Directors to increase the size of the Board and fill vacancies on the Board, whether resulting from such increase, or from death, resignation, disqualification or otherwise; and

· the ability of our Board of Directors to issue additional shares of common stock and shares of preferred stock and to determine the price and, with respect to preferred stock, the other terms, including preferences and voting rights, of those shares without shareholder approval.

While these provisions have the effect of encouraging persons seeking to acquire control of us to negotiate with our Board of Directors, they could enable the Board to hinder or frustrate a transaction that some, or a majority, of our shareholders might believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors.

SunCor’s continuing wind-down of its real estate business may give rise to various claims.

Since 2009, SunCor has been engaged in a program to dispose of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to eliminate its outstanding debt. SunCor is focusing on concluding an orderly wind-down of its business and, as of December 31, 2012, SunCor had no assets. This effort includes addressing contingent liabilities, such as warranty and construction claims that may be brought by property owners and potential funding obligations to local taxing districts that financed infrastructure at certain of its real estate developments.

Pinnacle West has not guaranteed any of SunCor’s obligations. In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business. Pinnacle West could be exposed to the uncertainties and complexities inherent for parent companies in such proceedings.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Neither Pinnacle West nor APS has received written comments regarding its periodic or current reports from the SEC staff that were issued 180 days or more preceding the end of its 2012 fiscal year and that remain unresolved.

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ITEM 2. PROPERTIES

Generation Facilities

APS’s portfolio of owned and leased generating facilities is provided in the table below:

Name	No. of Units	% Owned (a)		Principal Fuels Used	Primary Dispatch Type	Owned Capacity (MW)
*Nuclear:*
Palo Verde (b)	3	29.1	%	Uranium	Base Load	1,146
Total Nuclear						1,146

*Steam:*
Four Corners 1, 2, 3	3			Coal	Base Load	560
Four Corners 4, 5 (c)	2	15	%	Coal	Base Load	231
Cholla	3			Coal	Base Load	647
Navajo (d)	3	14	%	Coal	Base Load	315
Ocotillo	2			Gas	Peaking	220
Saguaro	2			Gas/Oil	Peaking	210
Total Steam						2,183

*Combined Cycle:*
Redhawk	2			Gas	Load Following	984
West Phoenix	5			Gas	Load Following	887
Total Combined Cycle						1,871

*Combustion Turbine:*
Ocotillo	2			Gas	Peaking	110
Saguaro 1, 2	2			Gas/Oil	Peaking	110
Saguaro 3	1			Gas	Peaking	79
Douglas	1			Oil	Peaking	16
Sundance	10			Gas	Peaking	420
West Phoenix	2			Gas	Peaking	110
Yucca 1, 2, 3	3			Gas/Oil	Peaking	93
Yucca 4	1			Oil	Peaking	54
Yucca 5, 6	2			Gas	Peaking	96
Total Combustion Turbine						1,088

*Solar:*
Cotton Center	1			Solar	As Available	17
Hyder	1			Solar	As Available	16
Paloma	1			Solar	As Available	17
Chino Valley	1			Solar	As Available	19
APS Owned Distributed Energy				Solar	As Available	8
Multiple facilities				Solar	As Available	4
Total Solar						81
Total Capacity						6,369

(a) 100% unless otherwise noted.

(b) See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Generation Facilities — Nuclear” in Item 1 for details regarding leased interests in Palo Verde. The other participants are Salt River Project (17.49%), SCE

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(15.8%), El Paso Electric Company (15.8%), Public Service Company of New Mexico (10.2%), Southern California Public Power Authority (5.91%), and Los Angeles Department of Water & Power (5.7%). The plant is operated by APS.

(c) The other participants are Salt River Project (10%), Public Service Company of New Mexico (13%), SCE (48%), Tucson Electric Power Company (7%) and El Paso Electric Company (7%). The plant is operated by APS. As discussed under “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Generation Facilities — Coal-Fueled Generating Facilities — Four Corners” in Item 1, APS and SCE have entered into an agreement by which APS would acquire SCE’s interest in Units 4 and 5, after which APS would close Units 1, 2 and 3.

(d) The other participants are Salt River Project (21.7%), Nevada Power Company (11.3%), the United States Government (24.3%), Tucson Electric Power Company (7.5%) and Los Angeles Department of Water & Power (21.2%). The plant is operated by Salt River Project.

See “Business of Arizona Public Service Company — Environmental Matters” in Item 1 with respect to matters having a possible impact on the operation of certain of APS’s generating facilities.

See “Business of Arizona Public Service Company” in Item 1 for a map detailing the location of APS’s major power plants and principal transmission lines.

Transmission and Distribution Facilities

Current Facilities . APS’s transmission facilities consist of approximately 5,883 pole miles of overhead lines and approximately 49 miles of underground lines, 5,660 miles of which are located in Arizona. APS’s distribution facilities consist of approximately 11,381 miles of overhead lines and approximately 17,572 miles of underground primary cable, all of which are located in Arizona. APS shares ownership of some of its transmission facilities with other companies. The following table shows APS’s jointly-owned interests in those transmission facilities recorded on the Consolidated Balance Sheets at December 31, 2012:

	Percent Owned (Weighted-Average)
Morgan — Pinnacle Peak System	64.1	%
Palo Verde — Estrella 500kV System	50.0	%
Round Valley System	50.0	%
ANPP 500kV System	33.3	%
Navajo Southern System	22.2	%
Four Corners Switchyards	37.0	%
Palo Verde — Yuma 500kV System	18.3	%
Phoenix — Mead System	17.1	%

Expansion. Each year APS prepares and files with the ACC a ten-year transmission plan. In APS’s 2013 plan, APS projects it will develop 275 miles of new lines over the next ten years. One significant project currently under development is a new 500kV path that will span from the Palo Verde Hub around the western and northern edges of the Phoenix metropolitan area and terminate at a bulk substation in the northeast part of Phoenix. The project consists of four phases. The first phase,

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Morgan to Pinnacle Peak 500kV, is currently in-service. The second phase, Delaney to Palo Verde 500kV, is under construction. The third and fourth phases, Delaney to Sun Valley 500kV and Morgan to Sun Valley 500kV, have been permitted and are in various stages of final design and development. In total, the projects consist of over 100 miles of new 500kV lines, with many of those miles constructed as capable of stringing a 230kV line as a second circuit.

APS continues to work with regulators to identify transmission projects necessary to support renewable energy facilities. Two such projects, which are included in APS’s 2013 transmission plan, are the Delaney to Palo Verde line and the North Gila to Hassayampa line, both of which are intended to support the transmission of renewable energy to Phoenix and California.

Plant and Transmission Line Leases and Rights-of-Way on Indian Lands

The Navajo Plant and Four Corners are located on land held under leases from the Navajo Nation and also under rights-of-way from the federal government. The right-of-way and lease for the Navajo Plant expire in 2019 and the right-of-way and lease for Four Corners expire in 2016. On March 7, 2011, the Navajo Nation Council signed a resolution approving a 25-year extension to the existing Four Corners lease term and providing Navajo Nation consent to renewal of the related rights-of-way. APS is filing applications for renewal of these rights-of-way with the DOI. Before it may approve the Four Corners lease extension and issue the renewed rights-of-way, the United States must complete an analysis under the federal National Environmental Policy Act, the ESA and related statutes.

Certain portions of the transmission lines that carry power from several of our power plants are located on Indian lands pursuant to rights-of-way that are effective for specified periods. Some of these rights-of-way have expired and our renewal applications have not yet been acted upon by the appropriate Indian tribes or federal agencies. Other rights expire at various times in the future and renewal action by the applicable tribe or federal agencies will be required at that time. The majority of our transmission lines residing on Indian lands are on the Navajo Nation. In March 2011, the Navajo Nation provided its consent to renew the rights-of-way for the transmission lines specified in the lease extension. However, some of our rights-of-way are not covered by the leases, or are granted by other Indian tribes or federal agencies. In recent negotiations with other utilities or companies for renewal of similar rights-of-way, certain of the affected Indian tribes have required payments substantially in excess of amounts that we have paid in the past for such rights-of-way. The ultimate cost of renewal of the rights-of-way for our transmission lines not addressed in the lease extension is uncertain. We are monitoring these right-of-way issues and have had extensive discussions with the respective tribes regarding the rights-of-way. We are currently unable to predict the outcome of this matter.

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ITEM 3. LEGAL PROCEEDINGS

See “Business of Arizona Public Service Company — Environmental Matters” in Item 1 with regard to pending or threatened litigation and other disputes.

See Note 3 for ACC and FERC-related matters.

See Note 11 for information regarding FERC proceedings on Pacific Northwest energy market issues, environmental and climate change matters, a Superfund matter and matters related to a September 2011 power outage.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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EXECUTIVE OFFICERS OF PINNACLE WEST

Pinnacle West’s executive officers are elected no less often than annually and may be removed by the Board of Directors at any time. The executive officers, their ages at February 22, 2013, current positions and principal occupations for the past five years are as follows:

Name	Age	Position	Period

Donald E. Brandt	58	Chairman of the Board and Chief Executive Officer of Pinnacle West; Chairman of the Board of APS	2009-Present
		President of Pinnacle West	2008-Present
		Chief Executive Officer of APS	2008-Present
		Chief Operating Officer of Pinnacle West	2008-2009
		President of APS	2006-2009
		Executive Vice President of Pinnacle West; Chief Financial Officer of APS	2003-2008
		Executive Vice President of APS	2003-2006
		Chief Financial Officer of Pinnacle West	2002-2008

Donald G. Robinson	59	President and Chief Operating Officer of APS	2009-Present
		Senior Vice President, Planning and Administration of APS	2007-2009

Denise R. Danner	57	Vice President, Controller and Chief Accounting Officer of Pinnacle West; Chief Accounting Officer of APS	2010-Present
		Vice President and Controller of APS	2009-Present
		Senior Vice President, Controller and Chief Accounting Officer of Allied Waste Industries, Inc.	2007-2008

Patrick Dinkel	49	Vice President, Resource Management	2012-Present
		Vice President, Power Marketing, Resource Planning and Acquisition	2011-2012
		Vice President, Power Marketing and Resource Planning	2010-2011
		General Manager, Strategic Planning and Resource Acquisition	2009-2010
		Director of Resource Acquisitions and Renewables	2007-2009

Randall K. Edington	59	Executive Vice President and Chief Nuclear Officer of APS	2007-Present
		Senior Vice President and Chief Nuclear Officer of APS	2007

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Name	Age	Position	Period

David P. Falck	59	Executive Vice President and General Counsel of Pinnacle West and APS	2009-Present
		Secretary of Pinnacle West and APS	2009-2012
		Senior Vice President — Law of Public Service Enterprise Group Inc.	2007-2009

Daniel T. Froetscher	51	Vice President, Energy Delivery	2008-Present
		General Manager of Rural Arizona Delivery	2007-2008

Jeffrey B. Guldner	47	Senior Vice President, Customers & Regulation	2012-Present
		Vice President, Rates & Regulation	2007-2012

James R. Hatfield	55	Executive Vice President of Pinnacle West and APS	2012-Present
		Chief Financial Officer of Pinnacle West and APS	2008-Present
		Senior Vice President of Pinnacle West and APS	2008-2012
		Treasurer of Pinnacle West and APS	2009-2010
		Senior Vice President and Chief Financial Officer of OGE Energy Corp.	1999-2008

John S. Hatfield	47	Vice President, Communications of APS	2010-Present
		Director, Corporate Communications of Southern California Edison	2004-2010

Tammy D. McLeod	51	Vice President and Chief Customer Officer	2007-Present

Lee R. Nickloy	46	Vice President and Treasurer of Pinnacle West and APS	2010-Present
		Assistant Treasurer and Director Corporate Finance of Ameren Corporation	2000-2010

Mark A. Schiavoni	57	Executive Vice President, Operations	2012-Present
		Senior Vice President, Fossil Operations of APS	2009-2012
		Senior Vice President of Exelon Generation and President of Exelon Power	2004-2009

Lori S. Sundberg	49	Senior Vice President, Human Resources and Ethics of APS	2011-Present
		Vice President, Human Resources and Ethics of APS	2010-2011
		Vice President, Human Resources of APS	2007-2010
		Vice President, Employee Relations, Safety, Compliance & Embrace of American Express Company	2007

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PART II

ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Pinnacle West’s common stock is publicly held and is traded on the New York Stock Exchange. At the close of business on February 15, 2013, Pinnacle West’s common stock was held of record by approximately 24,394 shareholders.

QUARTERLY STOCK PRICES AND DIVIDENDS PAID PER SHARE

STOCK SYMBOL: PNW

							Dividends
2012	High		Low		Close		Per Share

1 st Quarter	$	48.86	$	46.15	$	47.90	$	0.525
2 nd Quarter	52.30		45.95		51.74		0.525
3 rd Quarter	54.66		51.19		52.80		0.525
4 th Quarter	54.20		48.73		50.98		0.545

							Dividends
2011	High		Low		Close		Per Share

1 st Quarter	$	44.07	$	40.70	$	42.79	$	0.525
2 nd Quarter	45.64		41.93		44.58		0.525
3 rd Quarter	45.15		37.28		42.94		0.525
4 th Quarter	48.87		40.87		48.18		0.525

APS’s common stock is wholly-owned by Pinnacle West and is not listed for trading on any stock exchange. As a result, there is no established public trading market for APS’s common stock.

The chart below sets forth the dividends paid on APS’s common stock for each of the four quarters for 2012 and 2011.

Common Stock Dividends

(Dollars in Thousands)

Quarter	2012		2011
1 st Quarter	$	57,400	$	57,100
2 nd Quarter	47,500		57,200
3 rd Quarter	57,500		57,300
4 th Quarter	59,800		57,300

The sole holder of APS’s common stock, Pinnacle West, is entitled to dividends when and as declared out of legally available funds. As of December 31, 2012, APS did not have any outstanding preferred stock.

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Issuer Purchases of Equity Securities

The following table contains information about our purchases of our common stock during the fourth quarter of 2012.

Period	Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
October 1 — October 31, 2012	51,441	$	53.88	—	—
November 1 — November 30, 2012	—	—		—	—
December 1 — December 31, 2012	—	—		—	—

Total	51,441	$	53.88	—	—

(1) Represents shares of common stock withheld by Pinnacle West to satisfy tax withholding obligations upon the vesting of restricted stock and performance shares.

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ITEM 6. SELECTED FINANCIAL DATA

PINNACLE WEST CAPITAL CORPORATION — CONSOLIDATED

	2012			2011		2010		2009			2008
	(dollars in thousands, except per share amounts)
OPERATING RESULTS
Operating revenues:
Regulated electricity	$	3,293,481		$	3,237,194	$	3,180,678	$	3,149,187		$	3,127,383
Marketing and trading	—			—		—		—			66,897
Other revenues	8,323			4,185		8,521		4,469			2,253
Total operating revenues	$	3,301,804		$	3,241,379	$	3,189,199	$	3,153,656		$	3,196,533
Income from continuing operations	$	418,993		$	355,634	$	344,851	$	256,048		$	277,366
Income (loss) from discontinued operations — net of income taxes (a)	(5,829		)	11,306		25,358		(183,284		)	(17,746		)
Net income	413,164			366,940		370,209		72,764			259,620
Less: Net income attributable to noncontrolling interests	31,622			27,467		20,156		4,434			17,495
Net income attributable to common shareholders	$	381,542		$	339,473	$	350,053	$	68,330		$	242,125

COMMON STOCK DATA
Book value per share — year — end	$	36.20		$	34.98	$	33.86	$	32.69		$	34.16
Earnings per weighted-average common share outstanding:
Continuing operations attributable to common shareholders — basic	$	3.54		$	3.01	$	3.05	$	2.34		$	2.58
Net income attributable to common shareholders — basic	$	3.48		$	3.11	$	3.28	$	0.68		$	2.40
Continuing operations attributable to common shareholders — diluted	$	3.50		$	2.99	$	3.03	$	2.34		$	2.57
Net income attributable to common shareholders — diluted	$	3.45		$	3.09	$	3.27	$	0.67		$	2.40
Dividends declared per share	$	2.67		$	2.10	$	2.10	$	2.10		$	2.10
Weighted-average common shares outstanding — basic	109,510,296			109,052,840		106,573,348		101,160,659			100,690,838
Weighted-average common shares outstanding — diluted	110,527,311			109,864,243		107,137,785		101,263,795			100,964,920

BALANCE SHEET DATA
Total assets	$	13,379,615		$	13,111,018	$	12,392,998	$	12,035,253		$	11,780,876
Liabilities and equity:
Current liabilities	$	1,083,542		$	1,342,705	$	1,449,704	$	1,279,288		$	1,582,661
Long-term debt less current maturities	3,199,088			3,019,054		3,045,794		3,496,524			3,183,386
Deferred credits and other	4,994,696			4,818,673		4,122,274		3,831,437			3,443,860
Total liabilities	9,277,326			9,180,432		8,617,772		8,607,249			8,209,907
Total equity	4,102,289			3,930,586		3,775,226		3,428,004			3,570,969
Total liabilities and equity	$	13,379,615		$	13,111,018	$	12,392,998	$	12,035,253		$	11,780,876

(a) Amounts primarily related to SunCor and APSES discontinued operations (see Note 21).

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SELECTED FINANCIAL DATA

ARIZONA PUBLIC SERVICE COMPANY — CONSOLIDATED

	2012		2011		2010		2009		2008
	(dollars in thousands)
OPERATING RESULTS
Electric operating revenues	$	3,293,489	$	3,237,241	$	3,180,807	$	3,149,500	$	3,133,496
Fuel and purchased power costs	994,790		1,009,464		1,046,815		1,178,620		1,289,883
Other operating expenses	1,693,170		1,673,394		1,584,955		1,501,081		1,376,257
Operating income	605,529		554,383		549,037		469,799		467,356
Other income	16,358		24,974		20,138		13,893		836
Interest expense — net of allowance for borrowed funds	194,777		215,584		213,349		213,258		188,353
Net income	427,110		363,773		355,826		270,434		279,839
Less: Net income attributable to noncontrolling interests	31,613		27,524		20,163		19,209		17,495
Net income attributable to common shareholder	$	395,497	$	336,249	$	335,663	$	251,225	$	262,344

BALANCE SHEET DATA
Total assets	$	13,242,542	$	13,032,237	$	12,271,877	$	11,730,500	$	11,124,360

Liabilities and equity:
Total equity	$	4,222,483	$	4,051,406	$	3,916,037	$	3,527,679	$	3,416,751
Long-term debt less current maturities	3,035,219		2,828,507		2,948,991		3,180,406		2,850,242
Palo Verde sale leaseback lessor notes less current maturities	38,869		65,547		96,803		126,000		151,783
Total capitalization	7,296,571		6,945,460		6,961,831		6,834,085		6,418,776
Current liabilities	1,043,087		1,322,714		1,234,865		1,070,970		1,344,501
Deferred credits and other	4,902,884		4,764,063		4,075,181		3,825,445		3,361,083
Total liabilities and equity	$	13,242,542	$	13,032,237	$	12,271,877	$	11,730,500	$	11,124,360

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

The following discussion should be read in conjunction with Pinnacle West’s Consolidated Financial Statements and APS’s Consolidated Financial Statements and the related Notes that appear in Item 8 of this report. For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see “Forward-Looking Statements” at the front of this report and “Risk Factors” in Item 1A.

OVERVIEW

Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so.

Areas of Business Focus

Operational Performance, Reliability and Recent Developments.

Nuclear. APS operates and is a joint owner of Palo Verde. In 2012, Palo Verde achieved its best generation year ever, producing over 31 million megawatt-hours, with an overall station capacity factor of 92.3%. In 2012, Palo Verde successfully refueled both Unit 2 and Unit 3. APS management continues to work closely with regulators and others in the nuclear industry to analyze the lessons learned and address any rulemaking or improvements resulting from the March 2011 events impacting the Fukushima Daiichi Nuclear Power Station in Japan.

Coal and Related Environmental Matters. APS-operated coal plants, Four Corners and Cholla, achieved net capacity factors for APS of 71% and 75%, respectively, in 2012. These capacity factors were lower than in prior years primarily due to lower gas prices resulting in higher production from our gas fleet. APS is focused on the impacts on its coal fleet that may result from increased regulation and potential legislation concerning greenhouse gas emissions. Concern over climate change and other emission-related issues could have a significant impact on our capital expenditures and operating costs in the form of taxes, emissions allowances or required equipment upgrades for these plants. APS is closely monitoring its long-range capital management plans, understanding that any resulting regulation and legislation could impact the economic viability of certain plants, as well as the willingness or ability of power plant participants to fund any such equipment upgrades.

SCE, a participant in Four Corners, has indicated that certain California legislation may prohibit it from making emission control expenditures at the plant. On November 8, 2010, APS and SCE entered into the Asset Purchase Agreement, providing for the purchase by APS of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. The purchase price is $294 million, subject to certain adjustments. Completion of the purchase by APS is subject to the receipt of approvals by the ACC, the CPUC and the FERC. On March 29, 2012, the CPUC issued an order approving the sale. On April 18, 2012, the ACC voted to allow APS to move forward with the purchase. The Asset Purchase Agreement provides that the purchase price will be reduced by $7.5 million for each month between October 1,

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2012 and the closing date. The ACC reserved the right to review the prudence of the transaction for cost recovery purposes in a future proceeding if the purchase closes. The ACC also authorized an accounting deferral of certain costs associated with the purchase until any such cost recovery proceeding concludes. The FERC application seeking authorization for the transaction was approved on November 27, 2012. The principal remaining condition to closing is the negotiation and execution of a new coal supply contract on terms reasonably acceptable to APS.

APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation which extends the Four Corners leasehold interest from 2016 to 2041. The Navajo Nation approved these amendments in March 2011. The effectiveness of the amendments also requires the approval of the DOI, as does a related federal rights-of-way grant which the Four Corners participants will pursue. A federal environmental review is underway as part of the DOI review process.

APS has announced that, if APS’s purchase of SCE’s interests in Units 4 and 5 at Four Corners is consummated, it will close Units 1, 2 and 3 at the plant. APS owns 100% of Units 1-3. These events will change the plant’s overall generating capacity from 2,100 MW to 1,540 MW and APS’s entitlement from the plant from 791 MW to 970 MW. When the ACC approved APS moving forward with the purchase of Units 4 and 5, it also approved the recovery of any unrecovered costs associated with the closure of Units 1, 2 and 3. The Settlement Agreement in APS’s most recent retail rate case allows APS to seek a rate adjustment to reflect the Four Corners transaction should the transaction close (see Note 3).

Transmission and Delivery. APS is working closely with regulators to identify and plan for transmission needs resulting from the current focus on renewable energy. The capital expenditures table presented in the “Liquidity and Capital Resources” section below includes the next three years of new

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transmission projects along with other transmission costs for upgrades and replacements. APS is also working to establish and expand smart grid technologies throughout its service territory designed to provide long-term benefits both to APS and its customers. APS is piloting and deploying a variety of technologies that are intended to allow customers to better monitor their energy use and needs, minimize system outage durations as well as the number of customers that experience outages, and facilitate greater cost savings to APS through improved reliability and the automation of certain distribution functions, including remote meter reading and remote connects and disconnects.

Renewable Energy . The ACC approved the RES in 2006. The renewable energy requirement is 4% of retail electric sales in 2013 and increases annually until it reaches 15% in 2025. In the settlement agreement related to the 2008 retail rate case, APS agreed to exceed the RES standards, committing to 1,700 GWh of new renewable resources to be in service by year-end 2015 in addition to its 2008 renewable resource commitments. Taken together, APS’s commitment is estimated to be approximately 12% of APS’s estimated retail energy sales by year-end 2015, which is more than double the existing RES target of 5% for that year. A component of the RES is focused on stimulating development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties).

On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requesting 2013 RES funding of $97 million to $107 million. In a final order dated January 31, 2013, the ACC approved a budget of $103 million for APS’s 2013 RES plan. That budget includes $4 million for residential distributed energy incentives and $0.1 million for commercial distributed energy up-front incentives, but did not include any funds for commercial distributed energy production-based incentives. The ACC further ordered that a hearing take place to consider: (i) APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits; and (ii) removing retail sales to APS’s largest industrial customers when calculating APS’s compliance with the annual RES requirements.

APS has a diverse portfolio of existing and planned renewable resources totaling 1,090 MW, including solar, wind, geothermal, biomass and biogas. Of this portfolio, 667 MW are currently in operation and 423 MW are under contract for development or are under construction. Renewable resources in operation include 81 MW of solar facilities owned by APS, 349 MW of long-term purchased power agreements, and an estimated 237 MW of customer-sited, third-party owned distributed energy resources.

To achieve our RES requirements, as mentioned above, to date APS has entered into contracts for 423 MW of renewable resources that are planned, in development or under construction. APS’s strategy to procure these resources includes new facilities to be owned by APS, purchased power contracts for new facilities and ongoing development of distributed energy resources. Through the AZ Sun Program, APS has executed contracts for the development of 118 MW of new solar generation, representing an investment commitment of approximately $502 million. See Note 3 for additional details of the AZ Sun Program, including the related cost recovery. APS has also entered into long-term purchased power agreements for 280 MW from solar facilities currently planned, in development or under construction, and 94 MW from distributed energy resources. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the project to the electric grid.

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Demand Side Management. In recent years, Arizona regulators have placed an increased focus on energy efficiency and other demand side management programs to encourage customers to conserve energy, while incentivizing utilities to aid in these efforts that ultimately reduce the demand for energy. In December 2009, the ACC initiated an Energy Efficiency rulemaking, with a proposed Energy Efficiency Standard of 22% cumulative annual energy savings by 2020. The 22% figure represents the cumulative reduction in future energy usage through 2020 attributable to energy efficiency initiatives. This ambitious standard became effective on January 1, 2011 and will likely impact Arizona’s future energy resource needs. The ACC issued an order on April 4, 2012 approving recovery of approximately $72 million of APS’s energy efficiency and demand side management program costs over a twelve-month period beginning March 1, 2012. This amount does not include $10 million already being recovered in general retail base rates.

Rate Matters. APS needs timely recovery through rates of its capital and operating expenditures to maintain its financial health. APS’s retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. On June 1, 2011, APS filed a rate case with the ACC. APS and other parties to the retail rate case subsequently entered into a Settlement Agreement detailing the terms upon which the parties have agreed to settle the rate case. See Note 3 for details regarding the Settlement Agreement terms and for information on APS’s FERC rates.

APS has several recovery mechanisms in place that provide more timely recovery to APS of its fuel and transmission costs, and costs associated with the promotion and implementation of its demand side management and renewable energy efforts and customer programs. These mechanisms are described more fully in Note 3.

As part of APS’s proposed acquisition of SCE’s interest in Units 4 and 5 of Four Corners, APS and SCE agreed that upon closing of the acquisition (or in 2016 if the closing does not occur), the companies will terminate an existing agreement that provides transmission capacity for SCE to transmit its portion of the output from Four Corners to California. APS expects to file a request with FERC seeking authorization to cancel the existing agreement and defer a $40 million payment to be made by APS associated with the termination and recover the payment through amortization over a 29-year period. APS believes the costs associated with the termination of the existing agreement are recoverable, but cannot predict whether FERC will approve our request; however, if the recovery is disallowed by FERC, APS would record a charge to its results of operations at the time of the disallowance.

Financial Strength and Flexibility. Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities, and may readily access these facilities ensuring adequate liquidity for each company. Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.

Other Subsidiaries. The operations of El Dorado are not expected to have any material impact on our financial results, or to require any material amounts of capital, over the next three years. As a result of the continuing distressed conditions in the real estate markets, during 2009 our other first-tier subsidiary, SunCor, undertook a program to dispose of its homebuilding operations, master-planned

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communities, land parcels, commercial assets and golf courses in order to eliminate its outstanding debt and, as of December 31, 2012, SunCor had no assets. In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business. All activities of SunCor are now reported as discontinued operations (see Note 21). SunCor’s loss in 2012 is primarily related to a contribution Pinnacle West expects to make to SunCor’s estate as part of a negotiated resolution to the bankruptcy. We do not expect SunCor’s bankruptcy to have a material impact on Pinnacle West’s financial position, results of operations or cash flows.

Key Financial Drivers

In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below. We closely monitor these factors to plan for the Company’s current needs, and to adjust our expectations, financial budgets and forecasts appropriately.

Electric Operating Revenues. For the years 2010 through 2012, retail electric revenues comprised approximately 93% of our total electric operating revenues. Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms. Off-system sales of excess generation output, purchased power and natural gas are included in operating revenues and related fuel and purchased power because they are credited to APS’s retail customers through the PSA. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.

Customer and Sales Growth. Retail customer growth in APS’s service territory in 2012 was 1.1% compared with the comparable prior year. For the three years 2010 through 2012, APS’s customer growth averaged 0.7% per year. We currently expect annual customer growth to average about 2% for 2013 through 2015 based on our assessment of modestly improving economic conditions, both nationally and in Arizona. Retail electricity sales in kilowatt-hours, adjusted to exclude the effects of weather variations, increased 0.1% in 2012 compared with the prior year, reflecting the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, offset by mildly improving economic conditions. For the three years 2010 through 2012, APS experienced annual declines in retail electricity sales averaging 0.1%, adjusted to exclude the effects of weather variations. We currently estimate that annual retail electricity sales in kilowatt-hours will remain about flat on average during 2013 through 2015, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations. A failure of the Arizona economy to continue to improve could further impact these estimates.

Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns, impacts of energy efficiency programs and growth in distributed generation, and responses to retail price changes. Our experience indicates that a reasonable range of variation in our kilowatt-hour sales projection attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of up to $10 million.

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Weather. In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data. Historical extreme weather variations have resulted in annual variations in net income in excess of $20 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.

Fuel and Purchased Power Costs. Fuel and purchased power costs included on our Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, changes in our generation resource allocation, our hedging program for managing such costs and PSA deferrals and the related amortization.

Operations and Maintenance Expenses . Operations and maintenance expenses are impacted by growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, higher-trending pension and other postretirement benefit costs, renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors. In the settlement agreement related to the 2008 retail rate case, APS committed to operational expense reductions from 2010 through 2014 and received approval to defer certain pension and other postretirement benefit cost increases incurred in 2011 and 2012, which totaled $25 million, as a regulatory asset, until the most recent general retail rate case decision became effective on July 1, 2012. In July 2012, we began amortizing the regulatory asset over a 36-month period.

Depreciation and Amortization Expenses. Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates. See “Capital Expenditures” below for information regarding the planned additions to our facilities. As a result of the twenty-year extensions of the operating licenses for each of the Palo Verde units granted by the NRC in 2011, we decreased our pretax depreciation expense related to Palo Verde by approximately $34 million per year starting on January 1, 2012.

Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate in Arizona for APS, which owns essentially all of our property, was 9.6% of the assessed value for 2012, 9.0% for 2011, and 8.0% for 2010. We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units, transmission and distribution facilities. (See Note 3 for property tax deferrals contained in the Settlement Agreement).

Income Taxes . Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions and non-taxable items, such as AFUDC. In addition, income taxes may also be affected by the settlement of issues with taxing authorities.

Interest Expense. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (see Note 6). The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, equity issuances and internally generated cash flow. An allowance for borrowed funds used during construction offsets a portion of interest expense

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while capital projects are under construction. We stop accruing AFUDC on a project when it is placed in commercial operation.

RESULTS OF OPERATIONS

Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution.

APSES’s and SunCor’s operations have been classified as discontinued operations. Pinnacle West sold its investment in APSES in August 2011. In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business (see Note 21).

Operating Results — 2012 compared with 2011

Our consolidated net income attributable to common shareholders for the year ended December 31, 2012 was $382 million, compared with net income of $339 million for the prior year. The results reflect an increase of approximately $59 million for the regulated electricity segment primarily due to increases related to the retail regulatory settlement effective July 1, 2012 (see Note 3), higher retail transmission revenues, lower depreciation and amortization due to 20-year Palo Verde license extensions received in 2011, and lower net interest charges due to lower debt balances and lower interest rates in the current year.

The $17 million decrease in discontinued operations is primarily related to a contribution Pinnacle West expects to make to SunCor’s estate as part of a negotiated resolution to the bankruptcy (see Note 21) and absence of the 2011 gain on sale of our investment in APSES.

The following table presents net income attributable to common shareholders by business segment compared with the prior year:

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	Year Ended December 31,
	2012			2011			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses (a)	$	2,299		$	2,228		$	71
Operations and maintenance (a)	(885		)	(904		)	19
Depreciation and amortization	(404		)	(427		)	23
Taxes other than income taxes	(159		)	(148		)	(11		)
Other income (expenses), net	6			16			(10		)
Interest charges, net of allowance for borrowed funds used during construction	(200		)	(224		)	24
Income taxes	(237		)	(184		)	(53		)
Less income related to noncontrolling interests (Note 20)	(32		)	(28		)	(4		)
Regulated electricity segment net income	388			329			59

All other	—			(1		)	1
Income from Continuing Operations Attributable to Common Shareholders	388			328			60

Income (Loss) from Discontinued Operations Attributable to Common Shareholders (b)	(6		)	11			(17		)

Net Income Attributable to Common Shareholders	$	382		$	339		$	43

(a) Includes effects of 2011 settlement of certain transmission right-of-way costs, which did not affect net income, but increased both electric operating revenues and operations and maintenance expenses by $28 million. Costs related to the settlement were offset by related revenues from SCE, which leases the related transmission line from APS.

(b) Includes activities related to APSES and SunCor.

Operating revenues less fuel and purchased power expenses Regulated electricity segment operating revenues less fuel and purchased power expenses were $71 million higher for the year ended December 31, 2012 compared with the prior year. The following table summarizes the major components of this change:

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	Increase (Decrease)
	Operating revenues			Fuel and purchased power expenses			Net change
	(dollars in millions)

Impacts of retail regulatory settlement effective July 1, 2012	$	64		$	1		$	63
Higher retail transmission revenues	41			—			41
Lower fuel and purchased power costs, net of related deferrals and off-system sales	(11		)	(14		)	3
Lower demand-side management, renewable energy and similar regulatory surcharges	(3		)	4			(7		)
Settlement in 2011 of certain prior-period transmission right-of-way revenues	(28		)	—			(28		)
Miscellaneous items, net	(7		)	(6		)	(1		)
Total	$	56		$	(15	)	$	71

Operations and maintenance Operations and maintenance expenses decreased $19 million for the year ended December 31, 2012 compared with the prior year primarily because of:

· A decrease of $28 million related to settlement in 2011 of certain transmission right-of-way costs, which was offset in operating revenues;

· A decrease of $22 million related to costs for demand-side management, renewable energy and similar regulatory programs;

· A decrease of $15 million in generation costs, primarily related to lower nuclear generation costs;

· An increase of $21 million related to employee benefit costs, including approximately $12 million of pension and other postretirement costs;

· An increase of $9 million related to higher stock compensation costs resulting from an improved company stock price and estimated performance results;

· An increase of $7 million in information technology costs, primarily related to higher software maintenance; and

· An increase of $9 million due to other miscellaneous factors.

Depreciation and amortization Depreciation and amortization expenses were $23 million lower for the year ended December 31, 2012 compared with the prior year primarily due to the impacts of Palo Verde operating license extensions, partially offset by increased plant in service.

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Taxes other than income taxes Taxes other than income taxes increased $11 million for the year ended December 31, 2012 compared with the prior year primarily because of higher property tax rates in the current year.

Other income (expenses), net Other income (expenses), net, decreased $10 million for the year ended December 31, 2012 compared with the prior year primarily because of higher investment losses of approximately $2 million and other non-operating expenses of approximately $8 million in the current year.

Interest charges, net of allowance for borrowed funds used during construction Interest charges, net of allowance for borrowed funds used during construction, decreased $24 million for the year ended December 31, 2012 compared with the prior year primarily because of lower debt balances and lower interest rates in the current year.

Income taxes Income taxes were $53 million higher for the year ended December 31, 2012 compared with the prior year primarily due to higher pre-tax income in the current year and a lower effective tax rate in 2011.

Discontinued Operations

Results from discontinued operations decreased $17 million primarily due to a contribution Pinnacle West expects to make to SunCor’s estate as part of a negotiated resolution to the bankruptcy (see Note 21) and absence of a gain related to the sale of our investment in APSES in 2011.

Operating Results — 2011 compared with 2010

Our consolidated net income attributable to common shareholders for the year ended December 31, 2011 was $339 million, compared with net income of $350 million for the prior year. The $11 million net decrease consisted of a $14 million decrease in income from discontinued operations and a $3 million increase in income from continuing operations primarily related to the regulated electricity segment. Regulated electricity segment results reflect increased revenues related to weather and higher retail transmission charges and decreased operations and maintenance expenses. These positive factors were offset by higher depreciation and amortization due to increased plant in service, higher property taxes due to increased property tax rates and higher income taxes, including income tax benefits recognized in the prior year.

In addition, income from discontinued operations for the year ended December 31, 2011 included a gain of approximately $10 million after income taxes related to the sale of our investment in APSES. Income from discontinued operations in the prior year was due to a $25 million gain after income taxes related to the sale of APSES’s district cooling business (see Note 21).

The following table presents net income attributable to common shareholders by business segment compared with the prior year:

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	Year Ended December 31,
	2011			2010			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses (a) (b)	$	2,228		$	2,134		$	94
Operations and maintenance (a) (b)	(904		)	(870		)	(34		)
Depreciation and amortization	(427		)	(415		)	(12		)
Taxes other than income taxes	(148		)	(135		)	(13		)
Other income (expenses), net	16			18			(2		)
Interest charges, net of allowance for borrowed funds used during construction	(224		)	(226		)	2
Income taxes	(184		)	(161		)	(23		)
Less income related to noncontrolling interests (Note 20)	(28		)	(20		)	(8		)
Regulated electricity segment net income	329			325			4

All other	(1		)	—			(1		)
Income from Continuing Operations Attributable to Common Shareholders	328			325			3

Income from Discontinued Operations Attributable to Common Shareholders (c)	11			25			(14		)

Net Income Attributable to Common Shareholders	$	339		$	350		$	(11	)

(a) Includes effects of 2011 settlement of certain prior-period transmission rights-of-way related to Four Corners, which did not affect net income, but increased both electric operating revenues and operations and maintenance expenses by $28 million. Costs related to the settlement were offset by related revenues from SCE, which leases the related transmission line from APS.

(b) Operating revenues less fuel and purchased power expenses includes amounts related to demand-side management, renewable energy and similar regulatory surcharges, which were substantially offset in operations and maintenance.

Regulated electricity segment

This section includes a discussion of major variances in income and expense amounts for the regulated electricity segment.

Operating revenues less fuel and purchased power expenses Regulated electricity segment operating revenues less fuel and purchased power expenses were $94 million higher for the year ended December 31, 2011 compared with the prior year. The following table describes the major components of this change:

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	Increase (Decrease)
	Operating revenues			Fuel and purchased power expenses			Net change
	(dollars in millions)
Higher demand-side management, renewable energy and similar regulatory surcharges	$	29		$	1		$	28
Settlement of certain prior-period transmission rights-of-way	28			—			28
Effects of weather on usage per customer	33			13			20
Higher retail transmission charges	10			—			10
Higher line extension revenues (Note 3)	7			—			7
Higher usage per customer	8			6			2
Refund of PSA deferrals	(33		)	(40		)	7
Higher fuel and purchased power costs, net of off-system sales	(27		)	(24		)	(3		)
Miscellaneous items, net	2			7			(5		)
Total	$	57		$	(37	)	$	94

Operations and maintenance Operations and maintenance expenses increased $34 million for the year ended December 31, 2011 compared with the prior year primarily because of:

· An increase of $28 million related to settlement in 2011 of certain transmission rights-of-way costs, which was offset in operating revenues;

· An increase of $27 million related to costs for demand-side management, renewable energy, and similar regulatory programs, which were offset in operating revenues;

· A decrease of $16 million related to employee benefit costs; and

· A decrease of $5 million due to other miscellaneous factors.

Depreciation and amortization Depreciation and amortization expenses were $12 million higher for the year ended December 31, 2011 compared with the prior year primarily because of increased plant in service.

Taxes other than income taxes Taxes other than income taxes increased $13 million for the year ended December 31, 2011 compared with the prior year primarily because of higher property tax rates in the current period.

Income taxes Income taxes were $23 million higher for the year ended December 31, 2011 compared with the prior year. This increase was primarily due to the effects of higher pretax income in the current year and income tax benefits recognized in the prior year related to a reduction in the Company’s 2010 effective income tax rate.

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Discontinued Operations

Income from discontinued operations for year ended December 31, 2011 included a gain of $10 million related to the sale of our investment in APSES. Income from discontinued operations for the year ended December 31, 2010 included an after tax gain of $25 million related to the sale of APSES’s district cooling business (see Note 21).

LIQUIDITY AND CAPITAL RESOURCES

Overview

Pinnacle West’s primary cash needs are for dividends to our shareholders and principal and interest payments on our indebtedness. On December 19, 2012, the Pinnacle West Board of Directors declared a quarterly dividend of $0.545 per share of common stock, payable on March 1, 2013 to shareholders of record on February 1, 2013. During 2012, Pinnacle West increased its indicated annual dividend from $2.10 per share to $2.18 per share. The level of our common stock dividends and future dividend growth will be dependent on declaration by our Board of Directors based on a number of factors including our financial condition, payout ratio, free cash flow and other factors.

Our primary sources of cash are dividends from APS and external debt and equity issuances. An ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At December 31, 2012, APS’s common equity ratio, as defined, was 57%. Its total shareholder equity was approximately $4.1 billion, and total capitalization was approximately $7.2 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $2.9 billion, assuming APS’s total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.

APS’s capital requirements consist primarily of capital expenditures and maturities of long-term debt. APS funds its capital requirements with cash from operations and, to the extent necessary, external debt financing and equity infusions from Pinnacle West.

Many of APS’s current capital expenditure projects qualify for bonus depreciation. The American Taxpayer Relief Act of 2012, signed into law on January 2, 2013, includes provisions extending the eligibility for 50% bonus depreciation to qualified property placed in service in 2013. As a result of this provision, and the previously enacted bonus depreciation provisions provided for in the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010, total cash tax benefits of up to $400-$500 million are expected to be generated for APS through accelerated depreciation. The cash generated is an acceleration of the tax benefits that APS would have otherwise received over 20 years. It is anticipated that these cash benefits will be fully realized by APS by the end of 2013, with a majority of the benefit realized as of December 31, 2012.

Summary of Cash Flows

The following tables present net cash provided by (used for) operating, investing and financing activities for the years ended December 31, 2012, 2011 and 2010 (dollars in millions):

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Pinnacle West Consolidated

	2012			2011			2010
Net cash flow provided by operating activities	$	1,171		$	1,125		$	750
Net cash flow used for investing activities	(873		)	(782		)	(576		)
Net cash flow used for financing activities	(305		)	(420		)	(209		)
Net decrease in cash and cash equivalents	$	(7	)	$	(77	)	$	(35	)

Arizona Public Service Company

	2012			2011			2010
Net cash flow provided by operating activities	$	1,176		$	1,128		$	695
Net cash flow used for investing activities	(873		)	(834		)	(747		)
Net cash flow provided by (used for) financing activities	(319		)	(374		)	31
Net decrease in cash and cash equivalents	$	(16	)	$	(80	)	$	(21	)

Operating Cash Flows

2012 Compared with 2011 Pinnacle West’s consolidated net cash provided by operating activities was $1,171 million in 2012, compared to $1,125 million in 2011, an increase of $46 million in net cash provided. The increase is primarily related to a $77 million reduction of cash collateral posted and a decrease of $23 million in cash paid for interest in the current year, partially offset by a $26 million increase in property tax payments, a $65 million pension contribution in 2012 (approximately $12 million of which is reflected in capital expenditures) and other changes in working capital.

2011 Compared with 2010 Pinnacle West’s consolidated net cash provided by operating activities was $1,125 million in 2011, compared to $750 million in 2010, an increase of $375 million in net cash provided. The increase is primarily due to the $161 million change in collateral and margin posted, as a result of changes in commodity prices and expiration of prior hedge contracts, and a $200 million voluntary pension contribution in 2010 (approximately $40 million of which is reflected in capital expenditures). In addition, APS’s operating cash flows included income tax payments to the parent company of approximately $81 million in 2010.

Other Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. The requirements of the Employee Retirement Security Act of 1974 (“ERISA”) require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension benefit obligations. Under ERISA, the qualified pension plan was 105% funded as of January 1, 2012 and 101% funded as of January 1, 2013. The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made contributions to our pension plan totaling $65 million in 2012, zero in 2011 and $200 million in 2010. The minimum contributions for the pension plan due in 2013, 2014 and 2015 under the recently enacted Moving Ahead for Progress in the 21 st Century Act (MAP-21) are estimated to be zero, $89 million and $112 million, respectively. We expect to make voluntary contributions totaling $140 million to the pension plan in 2013, and contributions up to approximately $175 million in each of 2014 and 2015. With regard to contributions to our other postretirement benefit plans, we made a contribution of approximately $23 million in 2012, $19 million in 2011, and $17

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million in 2010. The contributions to our other postretirement benefit plans for 2013, 2014 and 2015 are expected to be approximately $20 million each year.

The $70 million long-term income tax receivable on the Consolidated Balance Sheets represents the anticipated refunds related to an APS tax accounting method change approved by the Internal Revenue Service (“IRS”) in the third quarter of 2009. This amount is classified as long-term, as there remains uncertainty regarding the timing of this cash receipt. Further clarification of the timing is expected from the IRS within the next twelve months.

Investing Cash Flows

2012 Compared with 2011 Pinnacle West’s consolidated net cash used for investing activities was $873 million in 2012, compared to $782 million in 2011, an increase of $91 million in net cash used. The increase in net cash used for investing activities is primarily due to the absence of $55 million in proceeds from the sale of life insurance policies in 2011 and the absence of $45 million in proceeds from the sale of Pinnacle West’s investment in APSES in 2011.

2011 Compared with 2010 Pinnacle West’s consolidated net cash used for investing activities was $782 million in 2011, compared to $576 million in 2010, an increase of $206 million in net cash used. The increase in net cash used for investing activities is primarily due to an increase of $131 million in capital expenditures and a decrease of $126 million in net proceeds from the sales of our non-utility businesses (see Note 21), partially offset by $55 million of proceeds from the sale of life insurance policies in 2011.

Capital Expenditures The following table summarizes the estimated capital expenditures for the next three years:

Capital Expenditures

(dollars in millions)

	Estimated for the Year Ended December 31,
	2013		2014		2015
APS
Generation:
Nuclear Fuel	$	58	$	82	$	83
Renewables	190		42		—
Environmental	21		86		187
Four Corners Units 4 and 5	253		—		—
Other Generation	142		246		340
Distribution	260		304		312
Transmission	152		204		200
Other (a)	45		69		66
Total APS	$	1,121	$	1,033	$	1,188

(a) Primarily information systems and facilities projects.

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Generation capital expenditures are comprised of various improvements to APS’s existing fossil and nuclear plants. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment, such as turbines, boilers and environmental equipment. For purposes of this table, we have assumed the consummation of APS’s purchase of SCE’s interest in Four Corners Units 4 and 5 and the subsequent shutdown of Units 1-3, as discussed in the “Overview” section above. As a result, we included the estimated $253 million purchase price under Generation and have not included environmental expenditures for Units 1-3. We have not included estimated costs for Cholla’s compliance with EPA’s Arizona regional haze rule since we have challenged the rule judicially and are considering our future options with respect to that plant if the rule is upheld. We are also monitoring the status of certain environmental matters, which, depending on their final outcome, could require modification to our environmental expenditures.

Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, and new customer construction. Examples of the types of projects included in the forecast include power lines, substations, and line extensions to new residential and commercial developments.

Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.

Financing Cash Flows and Liquidity

2012 Compared with 2011 Pinnacle West’s consolidated net cash used for financing activities was $305 million in 2012, compared to $420 million in 2011, a decrease of $115 million in net cash used. The decrease in net cash used for financing activities is primarily due to an increase of $92 million in APS’s short-term debt borrowings in 2012. In addition, APS had $56 million in higher issuances of long-term debt, partially offset by $99 million in higher repayments of long-term debt. Pinnacle West had $100 million in lower repayments of long-term debt partially offset by $50 million in lower debt issuances (see below).

2011 Compared with 2010 Pinnacle West’s consolidated net cash used for financing activities was $420 million in 2011, compared to $209 million in 2010, an increase of $211 million in net cash used. The increase in net cash used for financing activities is primarily due to $78 million of long-term debt repayments, net of issuances of long-term debt (see below), and proceeds of $253 million from the issuance of equity in April 2010 (which was infused into APS), partially offset by $121 million lower repayments of short-term borrowings at Pinnacle West.

APS’s net cash used for financing activities was $374 million in 2011, compared to net cash provided of $31 million in 2010, an increase of $405 million in net cash used. APS’s increase in net cash used for financing activities is primarily due to $107 million of long-term debt repayments, net of issuances of long-term debt (see below), and proceeds of $253 million from the infusion of equity from Pinnacle West in April 2010. In addition, APS increased its dividend payment to Pinnacle West by $47 million in 2011.

Significant Financing Activities During the year ended December 31, 2012, Pinnacle West’s total dividends paid per share of common stock was $2.12 per share, which resulted in dividend payments of $225 million.

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On January 13, 2012, APS issued $325 million of 4.50% unsecured senior notes that mature on April 1, 2042. The net proceeds from the sale were used along with other funds to repay at maturity APS’s $375 million aggregate principal amount of 6.50% senior notes on March 1, 2012.

On May 1, 2012, pursuant to the mandatory tender provision, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project), 2009 Series B, due 2029. On June 1, 2012 these bonds were remarketed. Currently, the interest rate on these bonds is reset daily by a remarketing agent. The daily rate at December 31, 2012 was 0.13% per annum. Additionally, the bonds are supported by a letter of credit. These bonds are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2012 and were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2011.

On June 1, 2012, pursuant to the mandatory tender provision, APS changed the interest rate mode for the approximately $38 million of Navajo County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series A. The new term rate period for these bonds commenced on June 1, 2012, and ends, subject to a mandatory tender, on May 29, 2014. During this time, the bonds will bear interest at a rate of 1.25% per annum. These bonds are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2012 and were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2011.

On November 1, 2012 APS redeemed at par all $90 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project) 2002 Series A, due 2029.

On November 29, 2012, Pinnacle West entered into a $125 million term loan that matures November 27, 2015. Pinnacle West used the proceeds of the loan to repay its existing term loan of $125 million. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings or, if unavailable, its long-term issuer ratings.

Available Credit Facilities Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs.

At December 31, 2012, Pinnacle West’s $200 million credit facility, which matures in November 2016, was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At December 31, 2012, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

At December 31, 2012, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in February 2015, and a $500 million facility that matures in November 2016. APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use these facilities to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings.

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The APS facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2012, APS had no outstanding borrowings under its revolving credit facilities or letters of credit. In addition, APS had commercial paper borrowings of $92 million at December 31, 2012.

See “Financial Assurances” in Note 11 for a discussion of APS’s separate outstanding letters of credit.

Other Financing Matters See Note 3 for information regarding the PSA approved by the ACC.

See Note 3 for information regarding the settlement related to the 2008 retail rate case, which includes ACC authorization and requirements of equity infusions into APS of at least $700 million by December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in 2010).

See Note 18 for information related to the change in our margin and collateral accounts.

Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant. For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2012, the ratio was approximately 46% for Pinnacle West and 45% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.

Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.

All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’s bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.

See Note 6 for further discussions of liquidity matters.

Credit Ratings

The ratings of securities of Pinnacle West and APS as of February 15, 2013 are shown below. We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings

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may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital. Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. At this time, we believe we have sufficient available liquidity resources to respond to a downward revision to our credit ratings.

	Moody’s	Standard & Poor’s	Fitch
Pinnacle West
Corporate credit rating	Baa2	BBB+	BBB
Commercial paper	P-3	A-2	F3
Outlook	Stable	Stable	Stable

APS
Corporate credit rating	Baa1	BBB+	BBB
Senior unsecured	Baa1	BBB+	BBB+
Secured lease obligation bonds	Baa1	BBB+	BBB+
Commercial paper	P-2	A-2	F3
Outlook	Stable	Stable	Stable

Off-Balance Sheet Arrangements

See Note 20 for a discussion of the impacts on our financial statements of consolidating certain VIEs.

Contractual Obligations

The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2012 (dollars in millions):

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	2013		2014- 2015		2016- 2017		Thereafter		Total
Long-term debt payments, including interest: (a)
APS	$	307	$	1,191	$	604	$	3,283	$	5,385
Pinnacle West	2		4		125		—		131
Total long-term debt payments, including interest	309		1,195		729		3,283		5,516
Fuel and purchased power commitments (b)	489		1,116		955		6,329		8,889
Renewable energy credits (c)	51		81		80		491		703
Purchase obligations (d)	96		29		14		221		360
Coal reclamation	1		74		27		17		119
Nuclear decommissioning funding requirements	17		36		4		67		124
Noncontrolling interests (e)	17		56		—		—		73
Operating lease payments	21		32		7		41		101
Total contractual commitments	$	1,001	$	2,619	$	1,816	$	10,449	$	15,885

(a) The long-term debt matures at various dates through 2042 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2012 (see Note 6).

(b) Our fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation (see Notes 3 and 11).

(d) These contractual obligations include commitments for capital expenditures and other obligations. These amounts do not include the purchase of SCE’s interest in Four Corners Units 4 and 5 due to additional approvals required. See discussion in “Overview.”

(e) Payments to the noncontrolling interests relate to the Palo Verde Sale Leaseback (see Note 20). We have committed to retain the assets relating to the noncontrolling interest beyond 2015 either through lease extensions or by purchasing the assets. If we elect to purchase the assets, the purchase price will be based on the fair value of the assets at the end of 2015, and such value is unknown at this time. If we elect to extend the leases, we will be required to make annual payments beginning in 2016 of approximately $23 million; however, the length of the lease extensions is unknown at this time as it must be determined through an appraisal process. Due to these uncertainties, amounts relating to the noncontrolling interests beyond 2015 have not been included in the table above.

This table excludes $135 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain. This table also excludes approximately zero, $89 million and $112 million in estimated minimum pension contributions for 2013, 2014 and 2015, respectively (see Note 8).

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CRITICAL ACCOUNTING POLICIES

In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.

Regulatory Accounting

Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers. Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. We had $1.2 billion of regulatory assets and $847 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2012.

Included in the balance of regulatory assets at December 31, 2012 is a regulatory asset of $780 million for pension and other postretirement benefits. This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future earnings.

See Notes 1 and 3 for more information.

Pensions and Other Postretirement Benefit Accounting

Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit liability and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.

The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2012 reported pension liability on the Consolidated Balance Sheets and our 2012 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):

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	Increase (Decrease)
Actuarial Assumption (a)	Impact on Pension Liability			Impact on Pension Expense
Discount rate:
Increase 1%	$	(330	)	$	(12	)
Decrease 1%	408			15
Expected long-term rate of return on plan assets:
Increase 1%	—			(9		)
Decrease 1%	—			9

(a) Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.

The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2012 reported other postretirement benefit obligation on the Consolidated Balance Sheets and our 2012 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):

	Increase (Decrease)
Actuarial Assumption (a)	Impact on Other Postretirement Benefit Obligation			Impact on Other Postretirement Benefit Expense
Discount rate:
Increase 1%	$	(149	)	$	(8	)
Decrease 1%	186			10
Health care cost trend rate (b):
Increase 1%	172			14
Decrease 1%	(136		)	(11		)
Expected long-term rate of return on plan assets — pretax:
Increase 1%	—			(3		)
Decrease 1%	—			3

(a) Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.

(b) This assumes a 1% change in the initial and ultimate health care cost trend rate.

See Note 8 for further details about our pension and other postretirement benefit plans.

Derivative Accounting

Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, determines whether we use

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accrual accounting (for derivative instruments designated as normal) or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in the fair value of derivative instruments are recognized in current earnings unless certain hedge criteria are met. Effective June 1, 2012, APS discontinued cash flow hedging for the significant majority of derivative contracts. APS now defers 100% of changes in fair value on these contracts for future rate treatment in accordance with the PSA (see Note 3).

See “Market Risks — Commodity Price Risk” below for quantitative analysis. See “Fair Value Measurements” below for additional information on valuation. See Note 1 for discussion on accounting policies and Note 18 for a further discussion on derivative accounting.

Fair Value Measurements

We account for derivative instruments, investments held in our nuclear decommissioning trust, certain cash equivalents and plan assets held in our retirement and other benefit plans at fair value on a recurring basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use inputs, or assumptions that market participants would use, to determine fair market value. The significance of a particular input determines how the instrument is classified in a fair value hierarchy. We utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The determination of fair value sometimes requires subjective and complex judgment. Our assessment of the inputs and the significance of a particular input to fair value measurement may affect the valuation of the instruments and their placement within a fair value hierarchy. Actual results could differ from our estimates of fair value. See Note 1 for discussion on accounting policies and Note 14 for further fair value measurement discussion.

OTHER ACCOUNTING MATTERS

See Note 2 for discussion regarding amended accounting guidance adopted during 2012 relating to fair value measurements and disclosures, and the presentation of comprehensive income.

MARKET AND CREDIT RISKS

Market Risks

Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust fund and benefit plan assets.

Interest Rate and Equity Risk

We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust fund (see Note 14 and Note 22) and benefit plan assets. The nuclear decommissioning trust fund and benefit plan assets also have risks associated with the changing market value of its equity and other non-fixed income investments. Nuclear decommissioning and benefit plan costs are recovered in regulated electricity prices.

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The tables below present contractual balances of our consolidated long-term and short-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2012 and 2011. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2012 and 2011 (dollars in thousands):

Pinnacle West — Consolidated

	Short-Term Debt				Variable-Rate Long-Term Debt				Fixed-Rate Long-Term Debt
	Interest				Interest				Interest
2012	Rates		Amount		Rates		Amount		Rates		Amount

2013	0.38	%	$	92,175	—		$	—	4.94	%	$	122,828
2014	—		—		—		—		5.58	%	540,424
2015	—		—		1.07	%	157,000		4.79	%	313,420
2016	—		—		0.15	%	43,580		6.15	%	314,000
2017	—		—		—		—		—		—
Years thereafter	—		—		—		—		6.21	%	1,840,150
Total			$	92,175			$	200,580			$	3,130,822
Fair value			$	92,175			$	200,268			$	3,674,958

	Variable-Rate Long-Term Debt				Fixed-Rate Long-Term Debt
	Interest				Interest
2011	Rates		Amount		Rates		Amount

2012	—		$	—	6.41	%	$	477,435
2013	—		—		4.94	%	122,828
2014	—		—		5.91	%	502,274
2015	1.79	%	125,000		4.79	%	313,420
2016	0.09	%	43,580		6.15	%	314,000
Years thereafter	—		—		6.49	%	1,605,150
Total			$	168,580			$	3,335,107
Fair value			$	167,018			$	3,758,811

The tables below present contractual balances of APS’s long-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2012 and 2011. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2012 and 2011 (dollars in thousands):

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APS — Consolidated

	Short-Term Debt				Variable-Rate Long-Term Debt				Fixed-Rate Long-Term Debt
	Interest				Interest				Interest
2012	Rates		Amount		Rates		Amount		Rates		Amount

2013	0.38	%	$	92,175	—		$	—	4.94	%	$	122,828
2014	—		—		—		—		5.58	%	540,424
2015	—		—		0.13	%	32,000		4.79	%	313,420
2016	—		—		0.15	%	43,580		6.15	%	314,000
2017	—		—		—		—		—		—
Years thereafter	—		—		—		—		6.21	%	1,840,150
Total			$	92,175			$	75,580			$	3,130,822
Fair value			$	92,175			$	75,580			$	3,674,958

	Variable-Rate Long-Term Debt				Fixed-Rate Long-Term Debt
	Interest				Interest
2011	Rates		Amount		Rates		Amount

2012	—		$	—	6.41	%	$	477,435
2013	—		—		4.94	%	122,828
2014	—		—		5.91	%	502,274
2015	—		—		4.79	%	313,420
2016	0.09	%	43,580		6.15	%	314,000
Years thereafter	—		—		6.49	%	1,605,150
Total			$	43,580			$	3,335,107
Fair value			$	43,580			$	3,758,811

Commodity Price Risk

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. Our risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities to ensure compliance with our stated energy risk management policies. We manage risks associated with these market fluctuations by utilizing various commodity instruments that may qualify as derivatives, including futures, forwards, options and swaps. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity and fuels. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.

The following table shows the net pretax changes in mark-to-market of our derivative positions in 2012 and 2011 (dollars in millions):

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	2012			2011
Mark-to-market of net positions at beginning of year	$	(222	)	$	(239	)
Recognized in earnings (a):
Change in mark-to-market gains (losses) for future period deliveries	1			(4		)
(Increase) decrease in regulatory asset	37			(1		)
Recognized in OCI:
Change in mark-to-market losses for future period deliveries (b)	(37		)	(95		)
Mark-to-market losses realized during the period	99			117
Change in valuation techniques	—			—
Mark-to-market of net positions at end of year	$	(122	)	$	(222	)

(a) Represents the amounts reflected in income after the effect of PSA deferrals.

(b) The changes in mark-to-market recorded in OCI are due primarily to changes in forward natural gas prices.

The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at December 31, 2012 by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement. See Note 1, “Derivative Accounting” and “Fair Value Measurements,” for more discussion of our valuation methods.

Source of Fair Value	2013			2014			2015			2016			2017			Years thereafter			Total fair value
Observable prices provided by other external sources	$	(53	)	$	(20	)	$	(1	)	$	—		$	—		$	—		$	(74	)
Prices based on unobservable inputs	(10		)	(9		)	(11		)	(8		)	(4		)	(6		)	(48		)
Total by maturity	$	(63	)	$	(29	)	$	(12	)	$	(8	)	$	(4	)	$	(6	)	$	(122	)

The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Consolidated Balance Sheets at December 31, 2012 and 2011 (dollars in millions):

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	December 31, 2012 Gain (Loss)					December 31, 2011 Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Earnings (a)
Natural gas	$	—	$	—		$	1	$	(1	)
Regulatory asset (liability) or OCI (b)
Electricity	7		(7		)	5		(5		)
Natural gas	25		(25		)	27		(27		)
Total	$	32	$	(32	)	$	33	$	(33	)

(a) Represents the amounts reflected in income after the effect of PSA deferrals.

(b) These contracts are economic hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.

Credit Risk

We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 18 for a discussion of our credit valuation adjustment policy.

ITEM 7A. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

See “Market and Credit Risks” in Item 7 above for a discussion of quantitative and qualitative disclosures about market risk.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS AND

FINANCIAL STATEMENT SCHEDULES

		Page
Management’s Report on Internal Control Over Financial Reporting (Pinnacle West Capital Corporation)		78
Report of Independent Registered Public Accounting Firm		79
Pinnacle West Consolidated Statements of Income for 2012, 2011 and 2010		81
Pinnacle West Consolidated Statements of Comprehensive Income for 2012, 2011, and 2010		82
Pinnacle West Consolidated Balance Sheets as of December 31, 2012 and 2011		83
Pinnacle West Consolidated Statements of Cash Flows for 2012, 2011 and 2010		85
Pinnacle West Consolidated Statements of Changes in Equity for 2012, 2011 and 2010		86
Notes to Pinnacle West’s Consolidated Financial Statements		87

Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)		154
Report of Independent Registered Public Accounting Firm		155
APS Consolidated Statements of Income for 2012, 2011 and 2010		157
APS Consolidated Statements of Comprehensive Income for 2012, 2011, and 2010		158
APS Consolidated Balance Sheets as of December 31, 2012 and 2011		159
APS Consolidated Statements of Cash Flows for 2012, 2011 and 2010		161
APS Consolidated Statements of Changes in Equity for 2012, 2011 and 2010		162
Supplemental Notes to APS’s Consolidated Financial Statements		164

Financial Statement Schedules for 2012, 2011 and 2010
Pinnacle West Schedule I — Condensed Statements of Comprehensive Income for 2012, 2011 and 2010		170
Pinnacle West Schedule I — Condensed Balance Sheets as of December 31, 2012 and 2011		171
Pinnacle West Schedule I — Condensed Statements of Cash Flows for 2012, 2011 and 2010		172
Pinnacle West Schedule II — Reserve for Uncollectibles for 2012, 2011 and 2010		173
APS Schedule II — Reserve for Uncollectibles for 2012, 2011 and 2010		174

See Note 13 and S-2 for the selected quarterly financial data (unaudited) required to be presented in this Item.

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MANAGEMENT’S REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

(PINNACLE WEST CAPITAL CORPORATION)

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Pinnacle West Capital Corporation. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2012. The effectiveness of our internal control over financial reporting as of December 31, 2012 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s consolidated financial statements.

February 22, 2013

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Pinnacle West Capital Corporation
Phoenix, Arizona

We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the “Company”) as of December 31, 2012 and 2011 and the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedules listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Pinnacle West Capital Corporation and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in Note 2 to the consolidated financial statements, the Company has changed its method of presenting comprehensive income in 2012 due to the adoption of amended guidance on the presentation of comprehensive income. The change in presentation has been applied retrospectively to all periods presented.

/s/ Deloitte & Touche LLP

Phoenix, Arizona

February 22, 2013

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PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(dollars and shares in thousands, except per share amounts)

	Year Ended December 31,
	2012			2011			2010

OPERATING REVENUES	$	3,301,804		$	3,241,379		$	3,189,199

OPERATING EXPENSES
Fuel and purchased power	994,790			1,009,464			1,046,815
Operations and maintenance	884,769			904,286			870,185
Depreciation and amortization	404,336			427,054			414,479
Taxes other than income taxes	159,323			147,408			135,328
Other expenses	6,831			6,659			7,509
Total	2,450,049			2,494,871			2,474,316
OPERATING INCOME	851,755			746,508			714,883
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction (Note 1)	22,436			23,707			22,066
Other income (Note 19)	1,606			3,111			6,387
Other expense (Note 19)	(19,842		)	(10,451		)	(9,921		)
Total	4,200			16,367			18,532
INTEREST EXPENSE
Interest charges	214,616			241,995			244,174
Allowance for borrowed funds used during construction (Note 1)	(14,971		)	(18,358		)	(16,479		)
Total	199,645			223,637			227,695
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	656,310			539,238			505,720
INCOME TAXES (Note 4)	237,317			183,604			160,869
INCOME FROM CONTINUING OPERATIONS	418,993			355,634			344,851
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $(3,813), $7,418 and $16,260 (Note 21)	(5,829		)	11,306			25,358
NET INCOME	413,164			366,940			370,209
Less: Net income attributable to noncontrolling interests (Note 20)	31,622			27,467			20,156
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	381,542		$	339,473		$	350,053
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	109,510			109,053			106,573
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	110,527			109,864			107,138

EARNINGS PER WEIGHTED — AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	3.54		$	3.01		$	3.05
Net income attributable to common shareholders — basic	3.48			3.11			3.28
Income from continuing operations attributable to common shareholders — diluted	3.50			2.99			3.03
Net income attributable to common shareholders — diluted	3.45			3.09			3.27

DIVIDENDS DECLARED PER SHARE	$	2.67		$	2.10		$	2.10

AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	387,380		$	328,110		$	324,688
Discontinued operations, net of tax	(5,838		)	11,363			25,365
Net income attributable to common shareholders	$	381,542		$	339,473		$	350,053

See Notes to Pinnacle West’s Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)

	Year Ended December 31,
	2012			2011			2010

NET INCOME	$	413,164		$	366,940		$	370,209

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $14,900, $37,389 and $61,348 (Note 18)	(22,763		)	(57,271		)	(93,939		)
Reclassification of net realized loss, net of tax benefit of $39,120, $46,288 and $48,453 (Note 18)	59,887			70,902			74,287
Pension and other postretirement benefits activity, net of tax (expense) benefit of $(651), $3,935 and $5,608 (Note 8)	1,031			(6,026		)	(8,528		)
Total other comprehensive income (loss)	38,155			7,605			(28,180		)

COMPREHENSIVE INCOME	451,319			374,545			342,029
Less: Comprehensive income attributable to noncontrolling interests	31,622			27,467			20,156

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	419,697		$	347,078		$	321,873

See Notes to Pinnacle West’s Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	December 31,
	2012			2011
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	26,202		$	33,583
Customer and other receivables	277,225			284,183
Accrued unbilled revenues	94,845			125,239
Allowance for doubtful accounts	(3,340		)	(3,748		)
Materials and supplies (at average cost)	218,096			204,387
Fossil fuel (at average cost)	31,334			22,000
Deferred income taxes (Note 4)	152,191			130,571
Income tax receivable (Note 4)	2,423			6,466
Assets from risk management activities (Note 18)	25,699			30,264
Deferred fuel and purchased power regulatory asset (Note 3)	72,692			27,549
Other regulatory assets (Note 3)	71,257			69,072
Other current assets	37,102			26,904
Total current assets	1,005,726			956,470

INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 18)	35,891			49,322
Nuclear decommissioning trust (Notes 14 and 22)	570,625			513,733
Other assets	62,694			64,588
Total investments and other assets	669,210			627,643

PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 10)
Plant in service and held for future use	14,346,367			13,753,971
Accumulated depreciation and amortization	(4,929,613		)	(4,709,991		)
Net	9,416,754			9,043,980
Construction work in progress	565,716			496,745
Palo Verde sale leaseback, net of accumulated depreciation of $222,055 and $218,186 (Note 20)	128,995			132,864
Intangible assets, net of accumulated amortization of $411,543 and $373,706	162,150			170,571
Nuclear fuel, net of accumulated amortization of $133,950 and $113,375	122,778			118,098
Total property, plant and equipment	10,396,393			9,962,258

DEFERRED DEBITS
Regulatory assets (Notes 1, 3 and 4)	1,099,900			1,352,079
Income tax receivable (Note 4)	70,389			68,633
Other	137,997			143,935
Total deferred debits	1,308,286			1,564,647

TOTAL ASSETS	$	13,379,615		$	13,111,018

See Notes to Pinnacle West’s Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	December 31,
	2012			2011
LIABILITIES AND EQUITY

CURRENT LIABILITIES
Accounts payable	$	221,312		$	326,987
Accrued taxes (Note 4)	124,939			120,289
Accrued interest	49,380			54,872
Common dividends payable	59,789			—
Short-term borrowings (Note 5)	92,175			—
Current maturities of long-term debt (Note 6)	122,828			477,435
Customer deposits	79,689			72,176
Liabilities from risk management activities (Note 18)	73,741			53,968
Regulatory liabilities (Note 3)	88,116			88,362
Other current liabilities	171,573			148,616
Total current liabilities	1,083,542			1,342,705

LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)
Long-term debt less current maturities	3,160,219			2,953,507
Palo Verde sale leaseback lessor notes less current maturities (Note 20)	38,869			65,547
Total long-term debt less current maturities	3,199,088			3,019,054

DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)	2,151,371			1,925,388
Regulatory liabilities (Notes 1, 3 and 4)	759,201			737,332
Liability for asset retirements (Note 12)	357,097			279,643
Liabilities for pension and other postretirement benefits (Note 8)	1,058,755			1,268,910
Liabilities from risk management activities (Note 18)	85,264			82,495
Customer advances	109,359			116,805
Coal mine reclamation	118,860			117,896
Unrecognized tax benefits (Note 4)	71,135			72,270
Other	283,654			217,934
Total deferred credits and other	4,994,696			4,818,673

COMMITMENTS AND CONTINGENCIES (SEE NOTES)

EQUITY (Note 7)
Common stock, no par value; authorized 150,000,000 shares, issued 109,837,957 at end of 2012 and 109,356,974 at end of 2011	2,466,923			2,444,247
Treasury stock at cost; 95,192 shares at end of 2012 and 111,161 at end of 2011	(4,211		)	(4,717		)
Total common stock	2,462,712			2,439,530
Retained earnings	1,624,102			1,534,483
Accumulated other comprehensive loss:
Pension and other postretirement benefits (Note 8)	(64,416		)	(65,447		)
Derivative instruments (Note 18)	(49,592		)	(86,716		)
Total accumulated other comprehensive loss	(114,008		)	(152,163		)
Total shareholders’ equity	3,972,806			3,821,850
Noncontrolling interests (Note 20)	129,483			108,736
Total equity	4,102,289			3,930,586

TOTAL LIABILITIES AND EQUITY	$	13,379,615		$	13,111,018

See Notes to Pinnacle West’s Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

	Year Ended December 31,
	2012			2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	413,164		$	366,940		$	370,209
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sale of energy-related products and services business	—			(10,404		)	—
Gain on sale of district cooling business	—			—			(41,973		)
Depreciation and amortization including nuclear fuel	481,262			493,784			472,807
Deferred fuel and purchased power	71,573			69,166			93,631
Deferred fuel and purchased power amortization	(116,716		)	(155,157		)	(122,481		)
Allowance for equity funds used during construction	(22,436		)	(23,707		)	(22,066		)
Real estate impairment charges	—			—			16,731
Gain on real estate debt restructuring	—			—			(16,755		)
Deferred income taxes	228,602			176,192			260,411
Change in derivative instruments fair value	(749		)	4,064			2,688
Changes in current assets and liabilities:
Customer and other receivables	14,587			40,626			(67,943		)
Accrued unbilled revenues	30,394			(21,947		)	7,679
Materials, supplies and fossil fuel	(23,043		)	(23,398		)	12,276
Other current assets	(27,352		)	(3,079		)	9,375
Accounts payable	(96,600		)	58,346			9,125
Accrued taxes and income tax receivable — net	8,693			12,068			24,222
Other current liabilities	23,869			20,358			2,921
Change in margin and collateral accounts — assets	2,216			33,349			(9,937		)
Change in margin and collateral accounts — liabilities	137,785			29,731			(88,315		)
Change in long term income tax receivable	(1,756		)	(3,530		)	—
Change in unrecognized tax benefits	(2,583		)	8,410			(73,621		)
Change in other regulatory liabilities	13,539			37,009			56,801
Change in other long-term assets	6,872			(41,722		)	(47,940		)
Change in other long-term liabilities	29,801			58,484			(97,388		)
Net cash flow provided by operating activities	1,171,122			1,125,583			750,457

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(889,551		)	(884,350		)	(748,374		)
Contributions in aid of construction	49,876			38,096			32,754
Allowance for borrowed funds used during construction	(14,971		)	(18,358		)	(16,778		)
Proceeds from sale of district cooling business	—			—			100,300
Proceeds from sale of energy-related products and services business	—			45,111			—
Proceeds from nuclear decommissioning trust sales	417,603			497,780			560,469
Investment in nuclear decommissioning trust	(434,852		)	(513,799		)	(584,885		)
Proceeds from sale of commercial real estate investments	—			1,375			72,038
Proceeds from sale of life insurance policies	—			55,444			—
Other	(1,099		)	(3,306		)	8,576
Net cash flow used for investing activities	(872,994		)	(782,007		)	(575,900		)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	476,081			470,353			—
Repayment of long-term debt	(654,286		)	(655,169		)	(106,572		)
Short-term borrowings and payments — net	92,175			(16,600		)	(137,115		)
Dividends paid on common stock	(225,075		)	(221,728		)	(216,979		)
Common stock equity issuance	15,955			15,841			255,971
Distributions to noncontrolling interests	(10,529		)	(10,210		)	(11,403		)
Other	170			(2,668		)	6,351
Net cash flow used for financing activities	(305,509		)	(420,181		)	(209,747		)

NET DECREASE IN CASH AND CASH EQUIVALENTS	(7,381		)	(76,605		)	(35,190		)

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	33,583			110,188			145,378

CASH AND CASH EQUIVALENTS AT END OF YEAR	$	26,202		$	33,583		$	110,188

See Notes to Pinnacle West’s Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(dollars in thousands)

	Year Ended December 31,
	2012			2011			2010
COMMON STOCK (Note 7)
Balance at beginning of year	$	2,444,247		$	2,421,372		$	2,153,295
Issuance of common stock	22,676			22,875			268,077
Balance at end of year	2,466,923			2,444,247			2,421,372

TREASURY STOCK (Note 7)
Balance at beginning of year	(4,717		)	(2,239		)	(3,812		)
Purchase of treasury stock	(4,607		)	(3,720		)	(82		)
Reissuance of treasury stock used for stock compensation	5,113			1,242			1,655
Balance at end of year	(4,211		)	(4,717		)	(2,239		)

RETAINED EARNINGS
Balance at beginning of year	1,534,483			1,423,961			1,298,213
Net income attributable to common shareholders	381,542			339,473			350,053
Common stock dividends	(291,923		)	(228,951		)	(224,305		)
Balance at end of year	1,624,102			1,534,483			1,423,961

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Balance at beginning of year	(152,163		)	(159,767		)	(131,587		)
Other comprehensive income (loss) attributable to common shareholders	38,155			7,604			(28,180		)
Balance at end of year	(114,008		)	(152,163		)	(159,767		)

NONCONTROLLING INTERESTS
Balance at beginning of year	108,736			91,899			111,895
Net income attributable to noncontrolling interests	31,622			27,467			20,156
Net capital activities by noncontrolling interests	(10,875		)	(10,630		)	(40,152		)
Balance at end of year	129,483			108,736			91,899

TOTAL EQUITY	$	4,102,289		$	3,930,586		$	3,775,226

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
Net income attributable to common shareholders	$	381,542		$	339,473		$	350,053
Other comprehensive income (loss)	38,155			7,605			(28,180		)
Comprehensive income attributable to common shareholders	$	419,697		$	347,078		$	321,873

See Notes to Pinnacle West’s Consolidated Financial Statements.

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1. Summary of Significant Accounting Policies

Description of Business and Basis of Presentation

Pinnacle West is a holding company that conducts business through its subsidiaries; APS and El Dorado, and formerly SunCor and APSES. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so. SunCor was a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico, Idaho and Utah but in 2009 and 2010, essentially all of these assets were sold. In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business. All activities for SunCor are now reported as discontinued operations (see Note 21). APSES provided energy-related projects to commercial and industrial retail customers in competitive markets in the western United States. APSES was sold in 2011 and is now reported as discontinued operations (see Note 21). El Dorado is an investment firm.

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS and El Dorado, and formerly SunCor and APSES. APS’s consolidated financial statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback. Intercompany accounts and transactions between the consolidated companies have been eliminated.

We consolidate VIEs for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. In performing our primary beneficiary analysis we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity. We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments. We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities (see Note 20).

Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented.

Accounting Records and Use of Estimates

Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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Regulatory Accounting

APS is regulated by the ACC and the FERC. The accompanying financial statements reflect the rate-making policies of these commissions. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers.

Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to APS or other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.

See Note 3 for additional information.

Electric Revenues

We derive electric revenues primarily from sales of electricity to our regulated Native Load customers. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.

Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called a “book-out” and usually occurs for contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and fuel and purchased power costs.

For the period January 1, 2010 through June 30, 2012, electric revenues also include proceeds for line extension payments for new or upgraded service in accordance with the 2009 retail rate case settlement agreement (see Note 3). Effective July 1, 2012, as a result of the 2011 rate case settlement agreement, these amounts are now recorded as contributions in aid of construction and are not included in electric revenues.

Some of our cost recovery mechanisms are alternative revenue programs. For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed.

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Allowance for Doubtful Accounts

The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including accrued utility revenues. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment.

Utility Plant and Depreciation

Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes:

· material and labor;

· contractor costs;

· capitalized leases;

· construction overhead costs (where applicable); and

· allowance for funds used during construction.

We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 12.

APS records a regulatory liability on its regulated assets for the difference between the amount that has been recovered in regulated rates and the amount calculated in accordance with guidance on accounting for asset retirement obligations. APS believes it can recover in regulated rates the costs capitalized in accordance with this accounting guidance.

We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2012 were as follows:

· Fossil plant — 16 years;

· Nuclear plant — 27 years;

· Other generation — 26 years;

· Transmission — 39 years;

· Distribution — 35 years; and

· Other — 7 years.

APS applied for twenty-year extensions of its operating licenses for each of the three Palo Verde units in December 2008. On April 21, 2011, the NRC approved the extensions of the Palo Verde licenses. The nuclear plant remaining life takes into consideration an ACC decision which authorizes the new Palo Verde Nuclear plant lives, effective January 1, 2012.

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For the years 2010 through 2012, the depreciation rates ranged from a low of 0.45% to a high of 12.08%. The weighted-average rate was 2.71% for 2012, 2.98% for 2011, and 2.98% for 2010.

Allowance for Funds Used During Construction

AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant. Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statement of Income. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.

AFUDC was calculated by using a composite rate of 8.60% for 2012, 10.25% for 2011, and 9.2% for 2010. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

Materials and Supplies

APS values materials, supplies and fossil fuel inventory using a weighted-average cost method. APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.

Fair Value Measurements

We account for derivative instruments, investments held in our nuclear decommissioning trust, certain cash equivalents and plan assets held in our retirement and other benefit plans at fair value on a recurring basis. Due to the short-term nature of net accounts receivable, accounts payable, and short-term borrowings, the carrying values of these instruments approximate fair value. Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments. We also disclose fair value information for our long-term debt, which is carried at amortized cost (see Note 6).

Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date. Inputs to fair value may include observable and unobservable data. We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available. When actively quoted prices are not available for the identical instruments we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources. For options, long-term contracts and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value.

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The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods.

See Note 14 for additional information about fair value measurements.

Derivative Accounting

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emission allowances and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial instruments including futures, forwards, options and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. We also enter into derivative instruments for economic hedging purposes. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power expenses in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.

We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities. Transactions with counterparties that have master netting arrangements are reported net on the balance sheet. See Note 18 for additional information about our derivative instruments.

Loss Contingencies and Environmental Liabilities

Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business. Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Retirement Plans and Other Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries. We also sponsor another postretirement benefit plan for the employees of Pinnacle West and our subsidiaries that provide medical and life insurance benefits to retired employees. Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually. See Note 8 for additional information on pension and other postretirement benefits.

Nuclear Fuel

APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production method is based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of

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thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.

APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charges APS $0.001 per kWh of nuclear generation. See Note 11 for information on spent nuclear fuel disposal costs.

Income Taxes

Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes. We file our federal income tax return on a consolidated basis and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures (see Note 4).

Cash and Cash Equivalents

We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.

The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):

	Years ended December 31,
	2012		2011		2010

Cash paid during the period for:
Income taxes, net of (refunds)	$	2,543	$	10,324	$	(23,447	)
Interest, net of amounts capitalized	200,923		217,789		221,728
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	26,208	$	27,245	$	19,226
Dividends declared but not paid	59,789		—		—

Intangible Assets

We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’s software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives. Amortization expense was $50 million in 2012, $47 million in 2011, and $45 million in 2010. Estimated amortization expense on existing intangible assets over the next five years is $45 million in 2013, $37 million in 2014, $28 million in 2015, $20 million in 2016, and $12 million in 2017. At December 31, 2012, the weighted-average remaining amortization period for intangible assets was 6 years.

Investments

El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership).

Our investments in the nuclear decommissioning trust fund are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities. See Note 14 and Note 22 for more information on these investments.

2. New Accounting Standards

During 2012, we adopted amended guidance intended to converge fair value measurement and disclosure requirements for GAAP and international financial reporting standards (“ IFRS”). The

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amended guidance clarifies how certain fair value measurement principles should be applied and requires enhanced fair value disclosures. The adoption of this new guidance resulted in additional fair value disclosures (see Note 14), but did not impact our financial statement results.

During 2012, we also adopted amended guidance on the presentation of comprehensive income. As a result of the amended guidance, we have changed our format for presenting comprehensive income. Previously, components of comprehensive income were presented within changes in equity. Due to the amended guidance, we now present comprehensive income in a new financial statement titled “Consolidated Statements of Comprehensive Income”. The adoption of this guidance changed our format for presenting comprehensive income, but did not impact our financial statement results.

3. Regulatory Matters

Retail Rate Case Filing with the Arizona Corporation Commission

On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million. APS requested that the increase become effective July 1, 2012. The request would have increased the average retail customer bill approximately 6.6%. On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties agreed to settle the rate case. On May 15, 2012, the ACC approved the Settlement Agreement without material modifications.

Settlement Agreement

The Settlement Agreement provides for a zero net change in base rates, consisting of: (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the Base Fuel Rate for fuel and purchased power costs from $0.03757 to $0.03207 per kWh; and (3) the transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates in an estimated amount of $36.8 million.

APS also agreed not to file its next general rate case before May 31, 2015, and not to request that its next general retail rate increase be effective prior to July 1, 2016. The Settlement Agreement allows APS to request a change to its base rates during the stay-out period in the event of an extraordinary event that, in the ACC’s judgment, requires base rate relief in order to protect the public interest. Nor is APS precluded from seeking rate relief, or any other party to the Settlement Agreement precluded from petitioning the ACC to examine the reasonableness of APS’s rates, in the event of significant regulatory developments that materially impact the financial results expected under the terms of the Settlement Agreement.

Other key provisions of the Settlement Agreement include the following:

· An authorized return on common equity of 10.0%;

· A capital structure comprised of 46.1% debt and 53.9% common equity;

· A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012;

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· Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows:

· Deferral of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and

· Deferral of 100% in all years if Arizona property tax rates decrease;

· A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s proposed acquisition (should it be consummated) of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners;

· Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation;

· Modifications to the Environmental Improvement Surcharge (“EIS”) to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually;

· Modifications to the PSA, including the elimination of the current 90/10 sharing provision;

· A limitation on the use of the RES surcharge and the DSMAC to recoup capital expenditures not required under the terms of the 2008 rate case settlement agreement discussed below;

· Allowing a negative credit that currently exists in the PSA rate to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;

· Modification of the TCA to streamline the process for future transmission-related rate changes; and

· Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS.

The Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012. This accomplished a goal set by the parties to the 2008 rate case settlement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occur within 30 days after the filing of a rate case.

2008 General Retail Rate Case On-Going Impacts

On December 30, 2009, the ACC issued an order approving a settlement agreement entered into by APS and twenty-one other parties in APS’s prior general retail rate case, which was originally filed

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in March 2008. The settlement agreement contains certain on-going requirements, commitments and authorizations that will survive the 2012 Settlement Agreement, including the following:

· A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014;

· Authorization and requirements of equity infusions into APS of at least $700 million during the period beginning June 1, 2009 through December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in the second quarter of 2010); and

· Various modifications to the existing energy efficiency, demand side management and renewable energy programs that require APS to, among other things, expand its conservation and demand side management programs through 2012 and its use of renewable energy through 2015, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand side management costs and incentives.

Cost Recovery Mechanisms

APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.

Renewable Energy Standard. In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.

On July 1, 2011, APS filed its annual RES implementation plan, covering the 2012-2016 timeframe and requested 2012 RES funding of $129 million to $152 million. On December 14, 2011, the ACC voted to approve APS’s 2012 RES Plan and authorized a total 2012 RES budget of $110 million. Within that budget, the ACC authorized APS to, among other items, own up to an additional 100 MW under its AZ Sun Program, for a total potential program amount of up to 200 MW. The AZ Sun program, originally approved by the ACC in March 2010, contemplates the development of photovoltaic solar plants which APS will own. Under this program to date, APS has executed contracts for the development of 118 MW of new solar generation, representing an investment commitment of approximately $502 million.

On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requested 2013 RES funding of $97 million to $107 million. In a final order dated January 31, 2013, the ACC approved a budget of $103 million for APS’s 2013 RES plan. That budget includes $4 million for residential distributed energy incentives and $0.1 million for commercial distributed energy up-front incentives, but did not include any funds for commercial distributed energy production-based incentives. The ACC further ordered that a hearing take place to consider: (i) APS’s

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proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits; and (ii) removing retail sales to APS’s largest industrial customers when calculating APS’s compliance with the annual RES requirements.

Demand Side Management Adjustor Charge. The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan for review by and approval of the ACC. In 2010, the DSMAC was modified to recover estimated amounts for use on certain demand side management programs over the current year. Previously, the DSMAC allowed for such recovery only on a historical or after-the-fact basis. The surcharge allows for the recovery of energy efficiency program expenses and any earned incentives.

The ACC previously approved recovery of all 2009 program costs plus incentives. The change from program cost recovery on a historical basis to recovery on a concurrent basis, as authorized in the 2008 retail rate case settlement agreement, resulted in this one-time need to address two years (2009 and 2010) of cost recovery. As requested by APS, 2009 program cost recovery was amortized over a three-year period, which ended in 2012.

On June 1, 2011, APS filed its 2012 Demand Side Management Implementation Plan consistent with the ACC’s Electric Energy Efficiency Standards, which became effective January 1, 2011. The 2012 requirement under such standards is for cumulative energy efficiency savings of 3% of APS retail sales for the prior year. This energy savings requirement is slightly higher than the goal established by the 2008 retail rate case settlement agreement (2.75% of total energy resources for the same two-year period). The ACC issued an order on April 4, 2012 approving recovery of approximately $72 million of APS’s energy efficiency and demand side management program costs over a twelve-month period beginning March 1, 2012. This amount does not include $10 million already being recovered in general retail base rates.

On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan. In 2013, the standards will require APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales. Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million. Although this proposed budget is approximately $5.6 million more than the approved 2012 budget, the expiration of the three-year amortization of 2009 costs and prior year credits would result in a small decrease in the DSMAC. APS expects to receive a decision from the ACC in the second quarter of 2013.

PSA Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:

· APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;

· an adjustment to the PSA rate is made annually each February 1 st (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;

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· the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);

· the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and

· the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2012 and 2011 (dollars in millions):

	Twelve Months Ended December 31,
	2012			2011
Beginning balance	$	28		$	(58	)
Deferred fuel and purchased power costs — current period	(72		)	(69		)
Amounts credited to customers	117			155
Ending balance	$	73		$	28

The PSA rate for the PSA year beginning February 1, 2013 is $0.0013 per kWh as compared to ($0.0042) per kWh for the prior year. This represents a $0.0055 per kWh increase over the 2012 PSA charge. This new rate is comprised of a forward component of ($0.0010) per kWh and a historical component of $0.0023 per kWh. The Settlement Agreement allowed APS to exceed the $0.004 per kWh cap to PSA rate changes in this instance. Any uncollected (overcollected) deferrals during the 2013 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2014.

Transmission Rates and Transmission Cost Adjustor . In July 2008, FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the Settlement Agreement (discussed above), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 beginning in 2013 and will go into effect automatically unless suspended by the ACC.

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The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may be calculated to account for previously over-collected amounts.

Effective June 1, 2011, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $44 million for the twelve-month period beginning June 1, 2011 in accordance with the FERC-approved formula as a result of higher costs and lower revenues reflected in the formula. Approximately $38 million of this revenue increase relates to Retail Transmission Charges. The ACC approved the related increase of APS’s TCA rate on June 21, 2011 and it became effective on July 1, 2011.

Effective June 1, 2012, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $16 million for the twelve-month period beginning June 1, 2012 in accordance with the FERC-approved formula. Because of higher relative system demand by APS’s retail customers, the approximately $16 million increase reflects roughly a $2 million decrease for wholesale customers and an $18 million increase for APS retail customers.

On May 14, 2012, APS filed an application with the ACC to implement the FERC-approved transmission rates for retail customers discussed above. On July 18, 2012, the ACC approved the application authorizing the implementation of the FERC-approved transmission rates for retail customers, which became effective August 2012.

Lost Fixed Cost Recovery Mechanism . The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by the Company in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as roof-top solar arrays. The fixed costs recoverable by the LFCR mechanism were established in the recent rate case and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. The kWh’s lost from energy efficiency are based on a third-party evaluation of the

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Company’s energy efficiency programs. Distributed generation sales losses are determined from the metered output from the distributed generation units or if metering is unavailable, through accepted estimating techniques.

APS filed its first LFCR adjustment on January 15, 2013 and will file for its LFCR adjustment every January thereafter. On February 12, 2013, the ACC approved an LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the Settlement Agreement went into effect on July 1, 2012.

Regulatory Assets and Liabilities

The detail of regulatory assets is as follows (dollars in millions):

	Remaining Amortization	December 31, 2012				December 31, 2011
	Period	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	(a)	$	—	$	780	$	—	$	1,023
Income taxes — AFUDC equity	2042	4		92		3		81
Deferred fuel and purchased power — mark-to-market (Note 18)	2016	19		21		43		34
Transmission vegetation management	2016	9		23		9		32
Coal reclamation	2026	8		24		2		35
Palo Verde VIEs (Note 20)	2046	—		38		—		35
Deferred compensation	2036	—		34		—		33
Deferred fuel and purchased power (b) (c)	2013	73		—		28		—
Tax expense of Medicare subsidy	2024	2		17		2		18
Loss on reacquired debt	2034	2		18		1		19
Income taxes — investment tax credit basis adjustment	2042	1		26		—		15
Pension and other postretirement benefits deferral	2015	8		13		—		12
Other	Various	18		14		9		15
Total regulatory assets (d)		$	144	$	1,100	$	97	$	1,352

(a) This asset represents the future recovery of under-funded pension and other postretirement benefits obligation through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues.

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(b) See “Cost Recovery Mechanisms” discussion above.

(d) There are no regulatory assets for which the ACC has allowed recovery of costs but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates and Transmission Cost Adjustor.”

The detail of regulatory liabilities is as follows (dollars in millions):

	Remaining Amortization	December 31, 2012				December 31, 2011
	Period	Current		Non-Current		Current		Non-Current
Removal costs	(a)	$	27	$	321	$	22	$	349
Asset retirement obligations	(a)	—		256		—		225
Renewable energy standard (b)	2013	43		—		54		—
Income taxes — change in rates	2042	—		66		—		59
Spent nuclear fuel	2047	10		36		5		44
Deferred gains on utility property	2019	2		12		2		14
Income taxes- deferred investment tax credit	2042	2		52		1		30
Other	Various	4		16		4		16
Total regulatory liabilities		$	88	$	759	$	88	$	737

(a) In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal (see Note 12).

(b) See “Cost Recovery Mechanisms” discussion above.

4. Income Taxes

Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the currently enacted income tax rates.

APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations. The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction and pension and other postretirement benefits. The regulatory liabilities primarily relate to deferred taxes resulting from investment tax credits (“ITC”) and the change in income tax rates.

In accordance with regulatory requirements, APS investment tax credits are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the statement of income.

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The $70 million long-term income tax receivable on the Consolidated Balance Sheets represents the anticipated refunds related to an APS tax accounting method change approved by the IRS in the third quarter of 2009. This amount is classified as long-term, as there remains uncertainty regarding the timing of this cash receipt. Further clarification of the timing is expected from the IRS within the next twelve months.

Net income associated with the Palo Verde sale leaseback variable interest entities is not subject to tax (see Note 20). As a result, there is no income tax expense associated with the VIEs recorded on the Consolidated Statements of Income.

During the first quarter of 2010, the Company reached a settlement with the IRS with regard to the examination of tax returns for the years ended December 31, 2005 through 2007. As a result of this settlement, net uncertain tax positions decreased $62 million, including approximately $3 million which decreased our effective tax rate. Additionally, the settlement resulted in the recognition of net interest benefits of approximately $4 million through the effective tax rate.

The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):

	2012			2011			2010
Total unrecognized tax benefits, January 1	$	136,005		$	127,595		$	201,216
Additions for tax positions of the current year	5,167			10,915			7,551
Reductions for tax positions of prior years for:
Changes in judgment	(7,729		)	(1,555		)	(11,017		)
Settlements with taxing authorities	—			(124		)	(62,199		)
Lapses of applicable statute of limitations	(21		)	(826		)	(7,956		)
Total unrecognized tax benefits, December 31	$	133,422		$	136,005		$	127,595

Included in the balances of unrecognized tax benefits at December 31, 2012, 2011 and 2010 were approximately $10 million, $8 million and $7 million, respectively, of tax positions that, if recognized, would decrease our effective tax rate.

As of the balance sheet date, the tax year ended December 31, 2008 and all subsequent tax years remain subject to examination by the IRS. With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2008.

It is reasonably possible that within the next twelve months the IRS will finalize the examination of tax returns for the years ended December 31, 2008 and 2009. At this time, a reasonable estimate of the range of possible change in the uncertain tax position cannot be made. However, we do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations.

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We reflect interest and penalties, if any, on unrecognized tax benefits in the Consolidated Statements of Income as income tax expense. The amount of interest recognized in the Consolidated Statements of Income related to unrecognized tax benefits was a pre-tax expense of $4 million for 2012, a pre-tax expense of $3 million for 2011 and a pre-tax benefit of $2 million for 2010.

The total amount of accrued liabilities for interest recognized in the Consolidated Balance Sheets related to unrecognized tax benefits was $13 million as of December 31, 2012, $9 million as of December 31, 2011 and $6 million as of December 31, 2010. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, as of December 31, 2012, we have recognized $5 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

The components of income tax expense are as follows (dollars in thousands):

	Year Ended December 31,
	2012			2011			2010
Current:
Federal	$	(3,493	)	$	(310	)	$	(108,827	)
State	8,395			15,140			25,545
Total current	4,902			14,830			(83,282		)
Deferred:
Federal	200,322			159,566			260,236
State	28,280			16,626			10,911
Discontinued operations	—			—			(10,736		)
Total deferred	228,602			176,192			260,411
Total income tax expense	233,504			191,022			177,129
Less: income tax expense (benefit) on discontinued operations	(3,813		)	7,418			16,260
Income tax expense — continuing operations	$	237,317		$	183,604		$	160,869

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The following chart compares pretax income from continuing operations at the 35% federal income tax rate to income tax expense — continuing operations (dollars in thousands):

	Year Ended December 31,
	2012			2011			2010

Federal income tax expense at 35% statutory rate	$	229,709		$	188,733		$	177,002
Increases (reductions) in tax expense resulting from: State income tax net of federal income tax benefit	23,819			19,594			17,485
Credits and favorable adjustments related to prior years resolved in current year	—			—			(17,300		)
Medicare Subsidy Part-D	483			823			1,311
Allowance for equity funds used during construction (see Note 1)	(6,158		)	(6,881		)	(6,563		)
Palo Verde VIE noncontrolling interest (see Note 20)	(11,065		)	(9,636		)	(7,057		)
Other	529			(9,029		)	(4,009		)
Income tax expense — continuing operations	$	237,317		$	183,604		$	160,869

The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):

	December 31,
	2012			2011
Current asset	$	152,191		$	130,571
Long-term liability	(2,151,371		)	(1,925,388		)
Deferred income taxes — net	$	(1,999,180	)	$	(1,794,817	)

On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four year phase-in of corporate income tax rate reductions beginning in 2014. As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in Arizona. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2012, APS has recorded a regulatory liability of $69 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

The American Taxpayer Relief Act of 2012, signed into law on January 2, 2013, includes provisions making qualified property placed into service in 2013 eligible for 50% bonus depreciation for federal income tax purposes. Full recognition of the cash benefit of this provision would delay realization of approximately $79 million in federal general business income tax credit carryforwards which are classified as current assets as of December 31, 2012.

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The components of the net deferred income tax liability were as follows (dollars in thousands):

	December 31,
	2012			2011
DEFERRED TAX ASSETS
Risk management activities	$	72,243		$	117,765
Regulatory liabilities:
Asset retirement obligation and removal costs	238,669			236,739
Renewable energy standard	—			19,722
Unamortized investment tax credits	53,837			31,460
Other	33,764			33,155
Pension and other postretirement liabilities	408,764			501,202
Renewable energy incentives	66,941			57,901
Credit and loss carryforwards	139,022			171,915
Other	68,844			73,759
Total deferred tax assets	1,082,084			1,243,618
DEFERRED TAX LIABILITIES
Plant-related	(2,584,166		)	(2,446,908		)
Risk management activities	(23,940		)	(30,171		)
Regulatory assets:
Allowance for equity funds used during construction	(37,899		)	(33,347		)
Deferred fuel and purchased power	(28,858		)	(10,884		)
Deferred fuel and purchased power — mark-to-market	(15,796		)	(30,559		)
Pension and other postretirement benefits	(316,757		)	(408,716		)
Other	(68,170		)	(73,087		)
Other	(5,678		)	(4,763		)
Total deferred tax liabilities	(3,081,264		)	(3,038,435		)
Deferred income taxes — net	$	(1,999,180	)	$	(1,794,817	)

As of December 31, 2012, the deferred tax assets for credit and loss carryforwards relate to federal general business credits of $111 million and federal net operating losses of $21 million, both of which first begin to expire in 2031, and other federal and state loss carryforwards of $7 million which first begin to expire in 2017.

5. Lines of Credit and Short-Term Borrowings

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2012 (dollars in millions):

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Credit Facility	Expiration	Amount Committed		Unused Amount (a)		Commitment Fees
Pinnacle West Revolving Credit Facility	November 2016	$	200	$	200	0.225	%

APS Revolving Credit Facility	November 2016	500		408		0.175	%

APS Revolving Credit Facility	February 2015	500		500		0.20	%
Total		$	1,200	$	1,108

(a) At December 31, 2012, APS had $92 million of outstanding commercial paper. Accordingly, at such date the total combined amount available under its two $500 million credit facilities was $908 million.

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs.

Pinnacle West

At December 31, 2012, the Pinnacle West credit facility, which terminates in November 2016, was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At December 31, 2012, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit and no commercial paper borrowings.

APS

APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use these facilities to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings.

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2012, APS had no outstanding borrowings or letters of credit under its revolving credit facilities. In addition, APS had commercial paper borrowings of $92 million at December 31, 2012.

See “Financial Assurances” in Note 11 for discussion of APS’s separate outstanding letters of credit.

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2011 (dollars in millions):

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Credit Facility	Expiration	Amount Committed		Unused Amount (a)		Commitment Fees
Pinnacle West Revolving Credit Facility	November 2016	$	200	$	200	0.275	%

APS Revolving Credit Facility	November 2016	500		500		0.225	%

APS Revolving Credit Facility	February 2015	500		500		0.250	%
Total		$	1,200	$	1,200

(a) These facilities were also fully available as of December 31, 2011.

Pinnacle West

On November 4, 2011, Pinnacle West refinanced its $200 million revolving credit facility that would have matured in February 2013, with a new $200 million facility. The new revolving credit facility terminates in November 2016. Interest rates are based on Pinnacle West senior unsecured debt credit ratings.

At December 31, 2011, the Pinnacle West credit facility was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program. At December 31, 2011, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit and no commercial paper borrowings.

APS

On February 14, 2011, APS refinanced its $489 million revolving credit facility that would have matured in September 2011, and increased the size of the facility to $500 million. The new revolving credit facility terminates in February 2015. APS will use the facility to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings.

On November 4, 2011, APS refinanced its $500 million revolving credit facility that would have matured in February 2013, with a new $500 million facility. The new revolving credit facility terminates in November 2016. APS may increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use the facility to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings.

The facilities described above are available to support its $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2011, APS had no borrowings outstanding under any of its credit facilities and no outstanding commercial paper.

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See “Financial Assurances” in Note 11 for discussion of APS’s separate outstanding letters of credit.

Debt Provisions

Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On February 6, 2013, the ACC issued a financing order in which it, subject to specified parameters and procedures, (a) approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power), (b) approved an increase in APS’s long-term debt authorization from $4.2 billion to $5.1 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs, and (c) authorized APS to enter into derivative financial instruments for the purpose of managing interest rate risk associated with its long- and short-term debt. This financing order is set to expire on December 31, 2017.

6. Long-Term Debt and Liquidity Matters

All of Pinnacle West’s and APS’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2012 and 2011 (dollars in thousands):

	Maturity	Interest	December 31,
	Dates (a)	Rates	2012			2011
APS
Pollution Control Bonds:
Variable	2029-2038	(b)	$	75,580		$	43,580
Fixed	2024-2034	1.25%-6.00%	490,275			522,275
Pollution control bonds with senior notes		5.05%	—			90,000
Total Pollution Control Bonds			565,855			655,855
Senior unsecured notes	2014-2042	4.50%-8.75%	2,575,000			2,625,000
Palo Verde sale leaseback lessor notes	2015	8.00%	65,547			96,803
Capitalized lease obligations		(c)	—			1,029
Unamortized discount			(9,486		)	(7,198		)
Total APS long-term debt			3,196,916			3,371,489
Less current maturities			122,828			477,435
Total APS long-term debt less current maturities			3,074,088			2,894,054
Pinnacle West
Term loan	2015	(d)	125,000			125,000
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES			$	3,199,088		$	3,019,054

(a) This schedule does not reflect the timing of redemptions that may occur prior to maturities.

(b) The weighted-average rate for the variable rate pollution control bonds was 0.13%-0.15% at December 31, 2012 and 0.09% at December 31, 2011.

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(d) The weighted-average interest rate was 1.312% at December 31, 2012 and 1.794% at December 31, 2011.

The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in millions):

Year	Consolidated Pinnacle West		Consolidated APS
2013	$	123	$	123
2014	540		540
2015	470		345
2016	358		358
2017	—		—
Thereafter	1,840		1,840
Total	$	3,331	$	3,206

Debt Fair Value

Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within level 2 of the fair value hierarchy. Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

	As of December 31, 2012				As of December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Pinnacle West	$	125	$	125	$	125	$	123
APS	3,197		3,750		3,371		3,803
Total	$	3,322	$	3,875	$	3,496	$	3,926

Credit Facilities and Debt Issuances

Pinnacle West

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APS

See Lines of Credit and Short-Term Borrowings in Note 5 and “Financial Assurances” in Note 11 for discussion of APS’s other letters of credit.

Debt Provisions

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An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At December 31, 2012, APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $4.1 billion, and total capitalization was approximately $7.2 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $2.9 billion, assuming APS’s total capitalization remains the same. Since APS was in compliance with this common equity ratio requirement, this restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

7. Common Stock and Treasury Stock

Our common stock and treasury stock activity during each of the three years 2012, 2011 and 2010 is as follows (dollars in thousands):

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	Common Stock			Treasury Stock
	Shares	Amount		Shares		Amount
Balance at December 31, 2009	101,527,937	$	2,153,295	(93,239	)	$	(3,812	)

Common stock issuance (a)	7,292,130	268,077		—		—
Purchase of treasury stock (b)	—	—		(1,994	)	(82		)
Reissuance of treasury stock for stock compensation	—	—		44,823		1,655
Balance at December 31, 2010	108,820,067	2,421,372		(50,410	)	(2,239		)

Common stock issuance	536,907	22,875		—		—
Purchase of treasury stock (b)	—	—		(88,440	)	(3,720		)
Reissuance of treasury stock for stock compensation	—	—		27,689		1,242
Balance at December 31, 2011	109,356,974	2,444,247		(111,161	)	(4,717		)

Common stock issuance	480,983	22,676		—		—
Purchase of treasury stock (b)	—	—		(89,629	)	(4,607		)
Reissuance of treasury stock for stock compensation	—	—		105,598		5,113
Balance at December 31, 2012	109,837,957	$	2,466,923	(95,192	)	$	(4,211	)

(a) In April 2010, Pinnacle West issued 6,900,000 shares of common stock at an offering price of $38.00 per share, resulting in net proceeds of approximately $253 million. Pinnacle West contributed all of the net proceeds from this offering into APS in the form of equity infusions. APS has used these contributions to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes.

(b) Primarily represents shares of common stock withheld from certain stock awards for tax purposes.

At December 31, 2012, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $25, $50 and $100 par values, none of which was outstanding.

8. Retirement Plans and Other Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan (The Pinnacle West Capital Corporation Retirement Plan) and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. All new employees participate in the account balance plan. Defined benefit plans specify the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated

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employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. Generally, we calculate the benefits based on age, years of service and pay.

Pinnacle West also sponsors another postretirement benefit plan (Pinnacle West Capital Corporation Group Life and Medical Plan) for the employees of Pinnacle West and its subsidiaries. This plan provides medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plan, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits.

Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date. See Note 14 for discussion of how fair values are determined. Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods.

A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and therefore is recoverable in rates. Accordingly, these changes are recorded as a regulatory asset. In its 2009 retail rate case settlement, APS received approval to defer a portion of pension and other postretirement benefit cost increases incurred in 2011 and 2012. We deferred pension and other postretirement benefit costs of approximately $14 million in 2012 and $11 million in 2011. Pursuant to an ACC regulatory order, we began amortizing the regulatory asset over 3 years beginning in July 2012. We amortized approximately $4 million during 2012.

On March 23, 2010, the President signed into law comprehensive health care reform legislation under the Patient Protection and Affordable Care Act (the “Act”). One feature of the Act is the elimination of the tax deduction for prescription drug costs that are reimbursed as part of the Medicare Part D subsidy. Although this tax increase does not take effect until 2013, we are required to recognize the full accounting impact in our financial statements in the period in which the Act is signed. In accordance with accounting for regulated companies, the loss of this deduction is substantially offset by a regulatory asset that will be recovered through future electric revenues. In the first quarter of 2010, Pinnacle West charged regulatory assets for a total of $42 million, with a corresponding increase in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged to the regulatory asset) (dollars in thousands):

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	Pension									Other Benefits
	2012			2011			2010			2012			2011			2010
Service cost-benefits earned during the period	$	63,502		$	57,605		$	59,064		$	27,163		$	21,856		$	19,236
Interest cost on benefit obligation	119,586			124,727			122,724			46,467			46,807			42,428
Expected return on plan assets	(140,979		)	(133,678		)	(124,161		)	(45,793		)	(41,536		)	(39,257		)
Amortization of:
Transition obligation	—			—			—			452			452			452
Prior service cost (credit)	1,143			1,400			1,705			(179		)	(179		)	(539		)
Net actuarial loss	44,250			25,956			18,833			20,233			15,015			10,317
Net periodic benefit cost	$	87,502		$	76,010		$	78,165		$	48,343		$	42,415		$	32,637
Portion of cost charged to expense	$	36,333		$	29,312		$	37,933		$	19,321		$	15,208		$	15,839

The following table shows the plans’ changes in the benefit obligations and funded status for the years 2012 and 2011 (dollars in thousands):

	Pension						Other Benefits
	2012			2011			2012			2011
Change in Benefit Obligation
Benefit obligation at January 1	$	2,699,126		$	2,345,060		$	1,047,094		$	827,897
Service cost	63,502			57,605			27,163			21,856
Interest cost	119,586			124,727			46,467			46,807
Benefit payments	(113,632		)	(104,257		)	(26,279		)	(24,877		)
Actuarial (gain) loss	82,264			275,991			(104,027		)	171,674
Plan amendments	—			—			—			3,737
Benefit obligation at December 31	2,850,846			2,699,126			990,418			1,047,094

Change in Plan Assets
Fair value of plan assets at January 1	1,850,550			1,775,596			608,663			567,410
Actual return on plan assets	259,363			162,042			83,567			58,367
Employer contributions	65,000			—			22,707			18,769
Benefit payments	(95,732		)	(87,088		)	(30,716		)	(35,883		)
Fair value of plan assets at December 31	2,079,181			1,850,550			684,221			608,663
Funded Status at December 31	$	(771,665	)	$	(848,576	)	$	(306,197	)	$	(438,431	)

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The following table shows the projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets as of December 31, 2012 and 2011 (dollars in thousands):

	2012		2011
Projected benefit obligation	$	2,850,846	$	2,699,126
Accumulated benefit obligation	2,646,306		2,396,575
Fair value of plan assets	2,079,181		1,850,550

The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2012 and 2011 (dollars in thousands):

	Pension						Other Benefits
	2012			2011			2012			2011
Current liability	$	(19,107	)	$	(18,097	)	$	—		$	—
Noncurrent liability	(752,558		)	(830,479		)	(306,197		)	(438,431		)
Net amount recognized	$	(771,665	)	$	(848,576	)	$	(306,197	)	$	(438,431	)

The following table shows the details related to accumulated other comprehensive loss as of December 31, 2012 and 2011 (dollars in thousands):

	Pension						Other Benefits
	2012			2011			2012			2011
Net actuarial loss	$	644,239		$	724,605		$	238,862		$	400,892
Prior service cost (credit)	3,169			4,312			(475		)	(655		)
Transition obligation	—			—			—			452
APS’s portion recorded as a regulatory asset	(550,471		)	(632,099		)	(230,020		)	(390,521		)
Income tax benefit	(38,303		)	(38,243		)	(2,585		)	(3,296		)
Accumulated other comprehensive loss	$	58,634		$	58,575		$	5,782		$	6,872

The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2012 (dollars in thousands):

	Pension		Other Benefits
Net actuarial loss	$	37,574	$	12,236
Prior service cost (credit)	1,097		(179		)
Total amounts estimated to be amortized from accumulated other comprehensive loss and regulatory assets in 2013	$	38,671	$	12,057

The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:

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	Benefit Obligations As of December 31,				Benefit Costs For the Years Ended December 31,
	2012		2011		2012		2011		2010
Discount rate-pension	4.01	%	4.42	%	4.42	%	5.31	%	5.90	%
Discount rate-other benefits	4.20	%	4.59	%	4.59	%	5.49	%	6.00	%
Rate of compensation increase	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%
Expected long-term return on plan assets	N/A		N/A		7.75	%	7.75	%	8.25	%
Initial health care cost trend rate	7.50	%	7.50	%	7.50	%	8.00	%	8.00	%
Ultimate health care cost trend rate	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%
Number of years to ultimate trend rate	4		4		4		4		4

In selecting the pretax expected long-term rate of return on plan assets we consider past performance and economic forecasts for the types of investments held by the plan. For the year 2013, we are assuming a 7.0% long-term rate of return on plan assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

Assumed health care cost trend rates above have a significant effect on the amounts reported for the health care plans. In selecting our health care trend rates, we consider past performance and forecasts of health care costs. A one percentage point change in the assumed initial and ultimate health care cost trend rates would have the following effects (dollars in millions):

	1% Increase		1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	$	14	$	(11	)
Effect on service and interest cost components of net periodic other postretirement benefit costs	17		(13		)
Effect on the accumulated other postretirement benefit obligation	172		(136		)

Plan Assets

The Board of Directors has delegated oversight of the pension and other postretirement benefit plans’ assets to an Investment Management Committee (“Committee”). The Committee has adopted investment policy statements (“IPS”) for the pension and the other postretirement benefit plans’ assets. The investment strategies for these plans include external management of plan assets, and prohibition of investments in Pinnacle West securities.

The overall strategy of the pension plan’s IPS is to achieve an adequate level of trust assets relative to the benefit obligations. To achieve this objective, the plan’s investment policy provides for

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mixes of investments including long-term fixed income assets and return-generating assets. The target allocation between return-generating and long-term fixed income assets is defined in the IPS and is a function of the plan’s funded status. The plan’s funded status is reviewed on at least a monthly basis.

Long-term fixed income assets, also known as liability-hedging assets, are designed to offset changes in the benefit obligations due to changes in interest rates. Long-term fixed income assets consist primarily of fixed income debt securities issued by the U.S. Treasury, other government agencies, and corporations. Long-term fixed income assets may also include interest rate swaps, U.S. Treasury futures and other instruments.

Return-generating assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility. Return-generating assets are composed of U.S. equities, international equities, and alternative investments. International equities include investments in both developed and emerging markets. Alternative investments primarily include investments in real estate, but may also include private equity and various other strategies. The plan may hold investments in return-generating assets by holding securities in common and collective trusts.

Based on the IPS, and given the pension plan’s funded status at year-end 2012, the long-term fixed income assets and the return generating assets each had a target allocation of 50%. The return-generating assets have additional target allocations, as a percent of total plan assets, of 30% equities in U.S. and other developed markets, 6% equities in emerging markets, and 14% in alternative investments. The pension plan IPS does not provide for a specific mix of long-term fixed income assets, but does expect the average credit quality of such assets to be investment grade. As of December 31, 2012, long-term fixed income assets represented 44% of total pension plan assets, and return-generating assets represented 56% of total pension plan assets.

The asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for an asset allocation target mix of at least 25% of fixed income assets and 55% or less of non-fixed income assets. This asset allocation target mix does not vary with the plan’s funded status. As of December 31, 2012, investment in fixed income assets represented 45% of the other postretirement benefit plan total assets, and non-fixed income assets represent 55% of the other postretirement benefit plan’s assets. Fixed income assets are primarily invested in corporate bonds of investment-grade U.S. issuers, and U.S. Treasuries. Non-fixed income assets are primarily invested in large cap U.S. equities in diverse industries, and international equities in both emerging and developed markets.

See Note 14 for a discussion on the fair value hierarchy and how fair value methodologies are applied. The plans invest directly in fixed income and equity securities, in addition to investing indirectly in equity securities and real estate through the use of common and collective trusts. Equity securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades, and are classified as Level 1. Fixed income securities issued by the U.S. Treasury held directly by the plans are valued using quoted active market prices, and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies are primarily valued using quoted inactive market prices, or quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield, maturity and credit quality. These instruments are classified as Level 2.

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The common and collective trusts, which are similar to mutual funds, are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 index). The common and collective equity trusts are valued using the concept of net asset value (“NAV”), which is a value derived from the quoted active market prices of the underlying securities. The plans’ common and collective real estate trust is valued using NAV, which is derived from the appraised values of the trust’s underlying real estate assets. As of December 31, 2012 the plans were able to transact in the common and collective trusts at NAV and accordingly classify these investments as Level 2. Because the trust’s shares are offered to a limited group of investors, they are not considered to be traded in an active market.

The plans’ trustee provides valuation of our plan assets by using pricing services that utilize methodologies described to determine fair market value. We have internal control procedures to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes.

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2012, by asset category, are as follows (dollars in thousands):

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	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Other (c)			Balance at December 31, 2012
Pension Plan:
Assets:
Cash and cash equivalents	$	579	$	—	$	—		$	—		$	579
Fixed Income Securities:
Corporate	—		607,749		—			—			607,749
U.S. Treasury	232,161		—		—			—			232,161
Other (b)	—		67,992		—			—			67,992
Equities:
U.S. Companies	531,291		—		—			—			531,291
International Companies	43,848		—		—			—			43,848
Common and collective trusts:
U.S. Equities	—		176,694		—			—			176,694
International Equities	—		271,735		—			—			271,735
Real estate	—		117,854		—			—			117,854
Short-term investments and other	—		26,922		2,419		(a)	(63		)	29,278

Total Pension Plan	$	807,879	$	1,268,946	$	2,419		$	(63	)	$	2,079,181
Other Benefits:
Assets:
Cash and cash equivalents	$	60	$	—	$	—		$	—		$	60
Fixed Income Securities:
Corporate	—		163,306		—			—			163,306
U.S. Treasury	112,558		—		—			—			112,558
Other (b)	—		33,998		—			—			33,998
Equities:
U.S. Companies	205,714		—		—			—			205,714
International Companies	14,412		—		—			—			14,412
Common and collective trusts:
U.S. Equities	—		60,038		—			—			60,038
International Equities	—		76,969		—			—			76,969
Real Estate	—		9,378		—			—			9,378
Short-term investments and other	402		6,340		—			1,046			7,788

Total Other Benefits	$	333,146	$	350,029	$	—		$	1,046		$	684,221

(a) Represents investments in a partnership that invests in privately held portfolio companies.

(b) This category consists primarily of debt securities issued by municipalities.

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The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2011, by asset category, are as follows (dollars in thousands):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Other (a)		Balance at December 31, 2011
Pension Plan:
Assets:
Cash and cash equivalents	$	1,441	$	—	$	—	$	1,441
Fixed Income Securities:
Corporate	—		584,619		—		584,619
U.S. Treasury	207,862		—		—		207,862
Other (b)	—		62,906		—		62,906
Equities:
U.S. Companies	436,393		—		—		436,393
International Companies	118,263		—		—		118,263
Common and collective trusts:
U.S. Equities	—		139,321		—		139,321
International Equities	—		156,407		—		156,407
Real estate	—		106,147		—		106,147
Short-term investments and other	—		29,913		7,278		37,191

Total Pension Plan	$	763,959	$	1,079,313	$	7,278	$	1,850,550
Other Benefits:
Assets:
Cash and cash equivalents	$	160	$	—	$	—	$	160
Fixed Income Securities:
Corporate	—		148,417		—		148,417
U.S. Treasury	103,321		—		—		103,321
Other (b)	—		30,105		—		30,105
Equities:
U.S. Companies	179,235		—		—		179,235
International Companies	22,486		—		—		22,486
Common and collective trusts:
U.S. Equities	—		52,507		—		52,507
International Equities	—		53,504		—		53,504
Real Estate	—		8,446		—		8,446
Short-term investments and other	—		8,516		1,966		10,482

Total Other Benefits	$	305,202	$	301,495	$	1,966	$	608,663

(a) Represents plan receivables and payables.

(b) This category consists primarily of debt securities issued by municipalities.

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The following table shows the changes in fair value for assets that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the year ended December 31, 2012 (dollars in thousands):

Short-Term Investments and Other	Pension
Beginning balance at January 1, 2012	$	—
Actual return on assets still held at December 31, 2012	(668		)
Purchases, sales, and settlements	3,087
Transfers in and/or out of Level 3	—
Ending balance at December 31, 2012	$	2,419

Contributions

We made contributions to our pension plan totaling $65 million in 2012, zero in 2011 and $200 million in 2010. The minimum contributions for the pension plan due in 2013, 2014 and 2015 under the recently enacted Moving Ahead for Progress in the 21 st Century Act (MAP-21) are estimated to be zero, $89 million and $112 million, respectively. We expect to make voluntary contributions totaling $140 million to the pension plan in 2013, and contributions up to approximately $175 million in each of 2014 and 2015. With regard to contributions to our other postretirement benefit plans, we made a contribution of approximately $23 million in 2012, $19 million in 2011, and $17 million in 2010. The contributions to our other postretirement benefit plans for 2013, 2014 and 2015 are expected to be approximately $20 million each year. APS and other subsidiaries fund their share of the contributions. APS’s share of the pension plan contribution was $64 million in 2012, zero in 2011, and $195 million in 2010. APS’s share of the contributions to the other postretirement benefit plan was $22 million in 2012, $19 million in 2011, and $16 million in 2010.

Estimated Future Benefit Payments

Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter are estimated to be as follows (dollars in thousands):

Year	Pension		Other Benefits
2013	$	126,091	$	26,934
2014	135,602		29,870
2015	145,438		32,929
2016	155,774		35,893
2017	165,535		38,765
Years 2018-2022	971,362		235,170

Electric plant participants contribute to the above amounts in accordance with their respective participation agreements.

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Employee Savings Plan Benefits

Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2012, costs related to APS’s employees represented 99% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. Pinnacle West recorded expenses for this plan of approximately $8 million for 2012, $8 million for 2011 and $9 million for 2010.

9. Leases

We lease certain vehicles, land, buildings, equipment and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates.

Total lease expense recognized in the Consolidated Statements of Income was $19 million in 2012, $21 million in 2011, and $23 million in 2010. APS’s lease expense was $16 million in 2012, $18 million in 2011, and $19 million in 2010.

Estimated future minimum lease payments for Pinnacle West’s and APS’s operating leases, excluding purchased power agreements, are approximately as follows (dollars in millions):

Year	Pinnacle West Consolidated		APS
2013	$	21	$	18
2014	17		15
2015	15		12
2016	4		4
2017	3		3
Thereafter	41		40
Total future lease commitments	$	101	$	92

In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. These lessor trust entities have been deemed variable interest entities for which APS is the primary beneficiary. As the primary beneficiary APS consolidated these lessor trust entities. The above lease disclosures exclude the impacts of these sale leaseback transactions, as lease accounting for these agreements is eliminated upon consolidation. See Note 20 for a discussion of VIEs.

10. Jointly-Owned Facilities

APS shares ownership of some of its generating and transmission facilities with other companies. We are responsible for our share of operating costs, as well as providing our own financing. Our share of operating expenses and utility plant costs related to these facilities is accounted for using

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proportional consolidation. The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2012 (dollars in thousands):

	Percent Owned		Plant in Service		Accumulated Depreciation		Construction Work in Progress
Generating facilities:
Palo Verde Units 1 and 3	29.1	%	$	1,717,970	$	1,006,615	$	15,122
Palo Verde Unit 2 (a)	16.8	%	555,132		324,063		4,125
Palo Verde Common	28.0	%(b)	516,950		223,632		83,365
Palo Verde Sale Leaseback		(a)	351,050		222,055		—
Four Corners Units 4 and 5	15.0	%	167,390		36,311		3,040
Four Corners Common	38.4	%(b)	58,810		17,930		1,512
Navajo Generating Station Units 1, 2 and 3	14.0	%	269,792		141,914		2,368
Cholla common facilities (c)	63.3	% (b)	146,571		43,815		1,680
Transmission facilities:
ANPP 500kV System	33.3	%(b)	82,490		31,511		1,607
Navajo Southern System	22.2	%(b)	55,427		15,815		561
Palo Verde — Yuma 500kV System	18.3	%(b)	11,761		4,493		797
Four Corners Switchyards	37.0	%(b)	20,874		6,033		1,466
Phoenix — Mead System	17.1	%(b)	39,772		11,553		—
Palo Verde — Estrella 500kV System	50.0	%(b)	85,643		13,309		4,137
Morgan — Pinnacle Peak System	64.1	%(b)	133,073		3,751		331
Round Valley System	50.0	%(b)	488		261		—

(a) See Note 20.

(b) Weighted-average of interests.

(c) PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned.

11. Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a breach of contract lawsuit against the DOE in the U.S. Court of Federal Claims. The lawsuit seeks to recover APS’s damages incurred due to DOE’s breach of the Standard Contract for failing to accept Palo Verde spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.

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APS currently estimates it will incur $122 million over the current life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At December 31, 2012, APS had a regulatory liability of $46 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

Nuclear Insurance

Liability for incidents at nuclear power plants is governed by the Price-Anderson Act, which limits the liability of nuclear reactor owners to the amount of insurance available from both private sources and an industry retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to $12.6 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by commercial insurance carriers. The remaining balance of $12.2 billion of liability coverage is provided through a mandatory industry wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $118 million, subject to an annual limit of $18 million per incident, to be periodically adjusted for inflation. Based on APS’s interest in the three Palo Verde units, APS’s maximum potential retrospective assessment per incident for all three units is approximately $103 million, with an annual payment limitation of approximately $15 million.

The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $18 million for each retrospective assessment declared by NEIL’s Board of Directors due to losses. In addition, NEIL policies contain rating triggers that would result in APS providing approximately $48 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Fuel and Purchased Power Commitments and Purchase Obligations

APS is party to purchase obligations and various fuel and purchased power contracts with terms expiring between 2013 and 2043 that include required purchase provisions. APS estimates the contract requirements to be approximately $585 million in 2013; $589 million in 2014; $556 million in 2015; $522 million in 2016; $447 million in 2017; and $6.6 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.

Of the various fuel and purchased power contracts mentioned above, some of those contracts have take-or-pay provisions. The contracts APS has for its coal supply include take-or-pay provisions. The current take-or-pay coal contracts have terms that expire in 2024.

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The following table summarizes our estimated coal take-or-pay commitments (dollars in millions):

	Years Ended December 31,
	2013		2014		2015		2016		2017		Thereafter
Coal take-or-pay commitments (a)	$	90	$	93	$	96	$	63	$	27	$	121

(a) Total take-or-pay commitments are approximately $490 million. The total net present value of these commitments is approximately $375 million.

APS spends more to meet its actual fuel requirements than the minimum purchase obligations in our coal take-or-pay contracts. The following table summarizes the actual amounts purchased under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in millions):

	Year Ended December 31,
	2012		2011		2010
Total purchases	$	196	$	191	$	156

Renewable Energy Credits

APS has entered into contracts to purchase renewable energy credits to comply with the RES. APS estimates the contract requirements to be approximately $51 million in 2013; $40 million in 2014; $41 million in 2015; $40 million in 2016; $40 million in 2017; and $491 million thereafter. These amounts do not include purchases of renewable energy credits that are bundled with energy. Also, these amounts do not include purchases of renewable energy credits that are associated with purchased power contracts.

Coal Mine Reclamation Obligations

APS must reimburse certain coal providers for amounts incurred for final and contemporaneous coal mine reclamation. We account for contemporaneous reclamation costs as part of the cost of the delivered coal. We utilize site-specific studies of costs expected to be incurred in the future to estimate our final reclamation obligation. These studies utilize various assumptions to estimate the future costs. Based on the most recent reclamation studies, APS has recorded a final coal mine reclamation obligation of approximately $119 million at December 31, 2012 and $118 million at December 31, 2011. Under our current coal supply agreements, we expect to make payments to certain coal providers for the final mine reclamation as follows: $1 million in 2013; $25 million in 2014; $49 million in 2015; $25 million in 2016; $2 million in 2017; and $17 million thereafter. Any amendments to current coal supply agreements may change the timing of the reimbursement.

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FERC Market Issues

On July 25, 2001, the FERC ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest. The FERC affirmed the administrative law judge’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision was appealed to the U.S. Court of Appeals for the Ninth Circuit and ultimately remanded to the FERC for further consideration. On October 3, 2011, the FERC ordered an evidentiary, trial-type hearing before an administrative law judge to address possible activity that may have influenced prices in the Pacific Northwest spot market during the period from December 25, 2000 through June 20, 2001.

The first phase of the hearing is currently expected to commence in April 2013. However, APS and Pinnacle West have entered into settlement agreements with all claimants with direct claims against us. The last of these settlement agreements was filed with FERC on December 5, 2012 and is currently pending FERC approval. Thus, we do not expect the outcome of the hearing to have a material adverse impact on our financial position, results of operations or cash flows.

Superfund

Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52 nd Street Superfund Site, OU3 in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study work plan. We estimate that our costs related to this investigation and study will be approximately $2 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.

Climate Change Lawsuit

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in federal court in the Northern District of California against nine oil companies, fourteen power companies (including Pinnacle West), and a coal company, alleging that the defendants’ emissions of carbon dioxide contribute to global warming and constitute a public and private nuisance under both federal and state law. The plaintiffs also allege that the effects of global warming will require the relocation of the village, and they are seeking an unspecified amount of monetary damages. In June 2008, the defendants filed motions to dismiss the action, which were granted. The plaintiffs filed an appeal with the United States Court of Appeals for the Ninth Circuit in November 2009.

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October 4, 2012, the plaintiffs filed a petition for rehearing by the entire Ninth Circuit, but on November 27, 2012, the court denied plaintiffs’ petition. APS continues to believe the action in Kivalina is without merit and will continue to defend against both the federal and state claims.

Southwest Power Outage

On September 8, 2011 at approximately 3:30PM, a 500 kV transmission line running between the Hassayampa and North Gila substations in southwestern Arizona tripped out of service due to a fault that occurred at a switchyard operated by APS. At the time, an APS employee at the North Gila substation was performing a procedure to remove from service a capacitor bank that was believed not to be operating properly. Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service.

Within the same time period that APS’s Yuma customers lost service, a series of transmission and generation disruptions occurred across the systems of several utilities that resulted in outages affecting portions of southern Arizona, southern California and northern Mexico. A total of approximately 7,900 MW of firm load and 2.7 million customers were reported to have been affected. Service to all affected APS customers was restored by 9:15PM on September 8. Service to customers affected by the wider regional outages was restored by approximately 3:25AM on September 9.

The FERC and the North American Electric Reliability Corporation (“NERC”) conducted a joint inquiry into the outages and, on May 1, 2012, they issued a report (the “Joint Report”) with their analysis and conclusions as to the causes of the events. The report includes recommendations to help industry operators prevent similar outages in the future, including increased data sharing and coordination among the western utilities and entities responsible for bulk electric system reliability coordination. The Joint Report does not address potential reliability violations or an assessment of responsibility of the parties involved. APS continues to analyze business practices and procedures related to the September 8 events.

APS cannot predict the timing, results or potential impacts of enforcement actions that may be brought against APS relating to the September 8 events, or any claims that may be made as a result of the outages. If violations of NERC Reliability Standards are ultimately determined to have occurred, FERC has the legal authority to assert a possible fine of up to $1 million per violation per day that a violation is found to have been in existence.

Clean Air Act Lawsuit

On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the New Source Review provisions of the Clean Air Act. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s NSPS program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the

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other Four Corners participants filed motions to dismiss, which are pending. We are unable to determine a range of potential losses that are reasonably possible of occurring.

Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, wastewater discharges, solid waste, hazardous waste, and CCR. These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates, but cannot predict whether it will obtain such recovery. The following proposed and final rules involve material compliance costs to APS.

Regional Haze Rules. APS has received final rulemaking imposing new requirements on Four Corners and Cholla and is currently awaiting a final rulemaking from EPA that could impose new requirements on the Navajo Plant. EPA and ADEQ will require these plants to install pollution control equipment that constitutes the best available retrofit technology to lessen the impacts of emissions on visibility surrounding the plants. Based on EPA’s final standards, APS’s share of its total costs for Four Corners (assuming the consummation of its purchase of SCE’s interest in Units 4 and 5 and subsequent shut down of Units 1-3) could be approximately $300 million. APS’s share of costs for upgrades at Navajo, based on EPA’s FIP proposal, could be up to approximately $158 million. APS has filed a Petition for Review of EPA’s rule as it applies to Cholla, which, if not successful, will require installation of controls with a cost to APS of approximately $187 million.

Mercury and Other Hazardous Air Pollutants. In 2011, EPA issued rules establishing maximum achievable control technology standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired plants. APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $124 million for Cholla Units 1-3. Estimated costs for Four Corners Units 1-3 are not included in our current environmental expenditure estimates since our estimates assume the consummation of APS’s purchase of SCE’s interest in Four Corners Units 4 and 5 and the subsequent shut down of Units 1-3. SRP, the operating agent for the Navajo Plant, is still evaluating compliance options under the rules.

Other future environmental rules that could involve material compliance costs include those related to cooling water intake structures, coal combustion waste, effluent limitations, ozone national ambient air quality, greenhouse gas emissions and other rules or matters involving the Clean Air Act, Endangered Species Act, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with these and other future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.

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Regional Haze Rules — Cholla

Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2012, approximately $76 million of letters of credit were outstanding to support existing pollution control bonds of a similar amount. The letters of credit are available to fund the payment of principal and interest of such debt obligations. One of these letters of credit expires in 2015 and two expire in 2016. APS has also entered into letters of credit to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 20 for further details on the Palo Verde sale leaseback transactions). These letters of credit will expire December 31, 2015, and totaled approximately $42 million at December 31, 2012. Additionally, APS has issued letters of credit to support collateral obligations under certain risk management arrangements including certain natural gas tolling contracts entered into with third parties. At December 31, 2012, $65 million of such letters of credit were outstanding that will expire in 2013 and 2015.

We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements; most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.

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Pinnacle West has issued parental guarantees and surety bonds for APS which were not material at December 31, 2012.

12. Asset Retirement Obligations

APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant. In the first quarter of 2011, a new decommissioning study with updated cash flow estimates was completed for Palo Verde. This study reflects the twenty-year license extension approved by the NRC on April 21, 2011, which extends the commencement of decommissioning to 2045.

The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term. The Four Corners coal-fired power plant asset retirement obligation relates to final plant decommissioning, including ash pond closures. In the fourth quarter of 2012, a new study related to ash pond closure was completed which updated the total cost estimates and related cash flow estimates.

Some of APS’s transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such distribution and transmission assets.

Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites.

The following schedule shows the change in our asset retirement obligations for 2012 and 2011 (dollars in millions):

	2012		2011
Asset retirement obligations at the beginning of year	$	280	$	329
Changes attributable to:
Accretion expense	19		19
Estimated cash flow revisions	58		(68		)
Asset retirement obligations at the end of year	$	357	$	280

In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 3.

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13. Selected Quarterly Financial Data (Unaudited)

Consolidated quarterly financial information for 2012 and 2011 is as follows (dollars in thousands, except per share amounts):

	2012 Quarter Ended									2012
	March 31,			June 30,		Sept. 30,		Dec. 31,		Total

Operating revenues	$	620,631		$	878,576	$	1,109,475	$	693,122	$	3,301,804
Operations and maintenance	210,663			216,236		220,729		237,141		884,769
Operating income	48,007			254,489		447,970		101,289		851,755
Income taxes	(4,645		)	76,689		147,116		18,157		237,317
Income from continuing operations	284			130,930		252,874		34,905		418,993
Net income (loss) attributable to common shareholders	(8,257		)	122,345		244,823		22,631		381,542

Earnings Per Share:
Income (loss) from continuing operations attributable to common shareholders — Basic	$	(0.07	)	$	1.12	$	2.23	$	0.24	$	3.54
Net income (loss) attributable to common shareholders — Basic	(0.08		)	1.12		2.23		0.21		3.48
Income (loss) from continuing operations attributable to common shareholders — Diluted	(0.07		)	1.12		2.21		0.24		3.50
Net income (loss) attributable to common shareholders — Diluted	(0.08		)	1.11		2.21		0.20		3.45

	2011 Quarter Ended									2011
	March 31,			June 30,		Sept. 30,		Dec. 31,		Total

Operating revenues	$	648,847		$	799,799	$	1,124,841	$	667,892	$	3,241,379
Operations and maintenance	255,029			210,590		210,035		228,632		904,286
Operating income	35,784			196,992		435,017		78,715		746,508
Income taxes	(6,005		)	50,818		131,416		7,375		183,604
Income (loss) from continuing operations	(10,368		)	93,185		253,273		19,544		355,634
Net income (loss) attributable to common shareholders	(15,135		)	86,685		255,359		12,564		339,473

Earnings Per Share:
Income (loss) from continuing operations attributable to common shareholders — Basic	$	(0.15	)	$	0.79	$	2.25	$	0.11	$	3.01
Net income (loss) attributable to common shareholders — Basic	(0.14		)	0.80		2.34		0.12		3.11
Income (loss) from continuing operations attributable to common shareholders — Diluted	(0.15		)	0.78		2.24		0.11		2.99
Net income (loss) attributable to common shareholders — Diluted	(0.14		)	0.79		2.32		0.11		3.09

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14. Fair Value Measurements

We classify our assets and liabilities that are carried at fair value within the fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are:

Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis. This category includes exchange-traded equities, exchange-traded derivative instruments, cash equivalents, and investments in U.S. Treasury securities.

Level 2 — Utilizes quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable (such as yield curves). This category includes non-exchange traded contracts such as forwards, options, swaps and certain investments in fixed income securities. This category also includes investments in common and collective trusts and commingled funds that are redeemable and valued based on NAV.

Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

Recurring Fair Value Measurements

We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans. See Note 8 for the fair value discussion of plan assets held in our retirement and other benefit plans.

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Cash Equivalents

Cash equivalents represent short-term investments with original maturities of three months or less in exchange traded money market funds that are valued using quoted prices in active markets.

Risk Management Activities — Derivative Instruments

Exchange traded commodity contracts are valued using unadjusted quoted prices. For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged. The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. We maintain credit policies that management believes minimize overall credit risk.

Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near term portion and unobservable valuations for the long-term portions of the transaction. We rely primarily on broker quotes to value these instruments. When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance. These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity. When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.

Option contracts are primarily valued using a Black-Scholes option valuation model which utilizes both observable and unobservable inputs such as broker quotes, interest rates and price volatilities.

When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions and the use of option valuation models with significant unobservable inputs.

Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies. We have a risk control function that is responsible for valuing our derivative commodity instruments in accordance with established policies and procedures. The risk control function reports to the chief financial officer’s organization.

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Investments Held in our Nuclear Decommissioning Trust

The nuclear decommissioning trust invests in fixed income securities and equity securities. Equity securities are held indirectly through commingled funds. The commingled funds are valued based on the concept of NAV, which is a value primarily derived from the quoted active market prices of the underlying equity securities. We may transact in these commingled funds on a semi-monthly basis at the NAV, and accordingly classify these investments as Level 2. The commingled funds, which are similar to mutual funds, are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 index. Because the commingled fund shares are offered to a limited group of investors, they are not considered to be traded in an active market.

Cash equivalents reported within Level 2 represent investments held in a short-term investment commingled fund, valued using NAV, which invests in U.S. government fixed income securities. We may transact in this commingled fund on a daily basis at the NAV.

Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies including mortgage-backed instruments are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves. These instruments are classified as Level 2. Whenever possible multiple market quotes are obtained which enables a cross-check validation. A primary price source is identified based on asset type, class, or issue of securities.

Our trustee provides valuation of our nuclear decommissioning trust assets by using pricing services that utilize the valuation methodologies described to determine fair market value. We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes. See Note 22 for additional discussion about our nuclear decommissioning trust.

Fair Value Tables

The following table presents the fair value at December 31, 2012 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

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	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other			Balance at December 31, 2012
Assets
Cash equivalents	$	16	$	—		$	—		$	—		$	16
Risk management activities — derivative instruments:
Commodity Contracts	—		22			62			(22		)(b)	62
Nuclear decommissioning trust:
U.S. commingled equity funds	—		204			—			—			204
Fixed income securities:
U.S. Treasury	104		—			—			—			104
Cash and cash equivalent funds	6		13			—			(4		)(c)	15
Corporate debt	—		80			—			—			80
Mortgage-backed securities	—		83			—			—			83
Municipality bonds	—		74			—			—			74
Other	—		11			—			—			11
Subtotal nuclear decommissioning trust	110		465			—			(4		)	571
Total	$	126	$	487		$	62		$	(26	)	$	649

Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(96	)	$	(110	)	$	47	(b)	$	(159	)

(a) Primarily consists of heat rate options and other long-dated electricity contracts.

(b) Represents counterparty netting, margin and collateral. See Note 18.

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The following table presents the fair value at December 31, 2011 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other			Balance at December 31, 2011
Assets
Risk management activities-derivative instruments:
Commodity contracts	$	—	$	70		$	74		$	(64	)(b)	$	80
Nuclear decommissioning trust:
U.S. commingled equity funds	—		175			—			—			175
Fixed income securities:
U.S. Treasury	69		—			—			—			69
Cash and cash equivalent funds	—		9			—			(1		)(c)	8
Corporate debt	—		73			—			—			73
Mortgage-backed securities	—		78			—			—			78
Municipality bonds	—		90			—			—			90
Other	—		21			—			—			21
Subtotal nuclear decommissioning trust	69		446			—			(1		)	514
Total	$	69	$	516		$	74		$	(65	)	$	594

Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(241	)	$	(125	)	$	229	(b)	$	(137	)

(a) Primarily consists of heat rate options and other long-dated electricity contracts.

(b) Represents counterparty netting, margin and collateral. See Note 18.

Fair Value Measurements Classified as Level 3

The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long term nature of the quote and option model inputs. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements. Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 3).

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Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts. Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.

Our option contracts classified as Level 3 primarily relate to purchase heat rate options. The significant unobservable inputs for these instruments include electricity prices, gas prices and implied volatilities. If electricity prices and electricity price implied volatilities increase we would expect the fair value of these options to increase, and if these valuation inputs decrease we would expect the fair value of these options to decrease. If natural gas prices and natural gas price implied volatilities increase we would expect the fair value of these options to decrease, and if these inputs decrease we would expect the fair value of the options to increase. The commodity prices and implied volatilities do not always move in corresponding directions. The options’ fair values are impacted by the net changes of these various inputs.

Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.

The following table provides information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments:

	December 31, 2012 Fair Value (millions)				Valuation	Significant		Weighted-
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range	Average
Electricity:
Forward Contracts (a)	$	57	$	82	Discounted cash flows	Electricity forward price (per MWh)	$23.06 - $64.20	$	43.16

Option Contracts	—		27		Option model	Electricity forward price (per MWh)	$36.66 - $92.19	$	60.97
						Natural gas forward price (per mmbtu)	$4.10 - $4.25	$	4.20
						Implied electricity price volatilities	15% - 66%	39		%
						Implied natural gas price volatilities	17% - 36%	23		%
Natural Gas:
Forward Contracts (a)	5		1		Discounted cash flows	Natural gas forward price (per mmbtu)	$3.25 - $4.44	$	3.93
Total	$	62	$	110

(a) Includes swaps and physical and financial contracts.

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The following table shows the changes in fair value for our risk management activities assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the years ended December 31, 2012 and 2011 (dollars in millions):

	Year Ended December 31,
Commodity Contracts	2012			2011
Net derivative balance at beginning of period	$	(51	)	$	(38	)
Total net gains (losses) realized/unrealized:
Included in earnings	2			2
Included in OCI	(3		)	(5		)
Deferred as a regulatory asset or liability	7			(10		)
Settlements	(5		)	11
Transfers into Level 3 from Level 2	(2		)	(4		)
Transfers from Level 3 into Level 2	4			(7		)
Net derivative balance at end of period	$	(48	)	$	(51	)

Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	1

Amounts included in earnings are recorded in either operating revenues or fuel and purchased power depending on the nature of the underlying contract.

Transfers reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period. We had no significant Level 1 transfers to or from any other hierarchy level. Transfers in or out of Level 3 are typically related to our heat rate options and long-dated energy transactions that extend beyond available quoted periods.

Financial Instruments Not Carried at Fair Value

The carrying value of our net accounts receivable, accounts payable and short-term borrowings approximate fair value. Our short-term borrowings are classified within Level 2 of the fair value hierarchy. For our long-term debt fair values see Note 6.

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15. Earnings Per Share

The following table presents earnings attributable to common shareholders per weighted-average common share outstanding for the years ended December 31, 2012, 2011 and 2010:

	2012			2011		2010
Basic earnings per share:
Income from continuing operations attributable to common shareholders	$	3.54		$	3.01	$	3.05
Income (loss) from discontinued operations	(0.06		)	0.10		0.23
Earnings per share — basic	$	3.48		$	3.11	$	3.28
Diluted earnings per share:
Income from continuing operations attributable to common shareholders	$	3.50		$	2.99	$	3.03
Income (loss) from discontinued operations	(0.05		)	0.10		0.24
Earnings per share — diluted	$	3.45		$	3.09	$	3.27

Dilutive stock options and performance shares (which are contingently issuable) increased average common shares outstanding by approximately 1,017,000 shares in 2012, 811,000 shares in 2011 and 565,000 shares in 2010. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 110,527,311 shares in 2012, 109,864,243 shares in 2011 and 107,137,785 shares in 2010.

For the years ended 2012 and 2011, there were no common stock options that were excluded from the computation of diluted earnings per share as a result of the options’ exercise prices being greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted earnings per share were 192,542 during 2010.

16. Stock-Based Compensation

Pinnacle West grants long-term incentive awards under the 2012 long-term incentive plan (“2012 Plan”) in the form of Stock Grants, Restricted Stock Units and Performance Shares and may grant restricted stock, stock units, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights. The 2012 Plan, effective May 16, 2012, provides 4,595,500 common shares to be available for grant to eligible employees and members of the Board of Directors. Awards made in 2012 were issued under the 2012 Plan, prior awards from 2007 to 2011 were issued under the 2007 long-term incentive plan (“2007 Plan”).

Restricted Stock Unit Awards and Stock Grants

Stock grants issued to non-officer members of the Board of Directors (“Directors”) in 2012, 2011 and 2010, provided Directors the option to elect to receive a stock grant, or to defer receipt until a later date and receive restricted stock units in lieu of the stock grant. Directors who elect to defer may elect to receive payment in either stock, or 50% in cash and 50% in stock. The Director may elect to receive payments either as of the last business day of the month following the month

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in which they separate from service on the Board, or as of a specified date, which must be after December 31 of the year in which the grant was received. The deferred restricted stock units accrue dividend rights equal to the amount of dividends the Director would have received had they directly owned stock equal to the number of vested restricted stock units from the date of grant to the date of payment plus interest compounded quarterly. The dividends and interest are paid, based on the Director’s election, in either stock, or 50% in cash and 50% in stock.

Restricted stock units were granted to officers and key employees in each year since 2007. From 2007 through 2009, officers and key employees elected to receive payment in either cash or in fully transferable shares of stock, in exchange for each restricted stock unit on pre-established valuation dates. In 2010, 2011 and 2012, officers and key employees elected to receive payment in either stock, or 50% cash and 50% stock.

Restricted stock unit awards vest and settle over a four-year period. In addition, officers and key employees accrue dividend rights on the vested restricted stock units, equal to the amount of dividends that they would have received had they directly owned stock equal to the number of vested restricted stock units from the date of grant to the date of payment plus interest compounded quarterly. The dividends and interest for the 2007 through 2009 awards are paid in cash. The dividends and interest for the 2010, 2011 and 2012 awards are paid in the same form as the restricted stock unit payment election. Restricted stock unit awards are accounted for as a liability award, with compensation cost initially calculated on the date of grant using the Company’s closing stock price, and remeasured at each balance sheet date. Compensation expense for retirement eligible participants is recognized immediately.

On December 19, 2012, the Company granted a retention award of 50,617 restricted stock units to the Chairman of the Board, President, and Chief Executive Officer of Pinnacle West. The award will vest and will be paid in shares of common stock on December 31, 2016 provided that he remains employed with the Company until the vesting date. The award can be increased up to an additional 33,745 restricted stock units payable in stock if certain performance requirements are met.

A grant of restricted stock unit awards was made to officers of the company on February 15, 2011, payable solely in shares of common stock upon the officer’s retirement or other separation of employment. This award will vest 50% on February 15, 2013, 25% on February 15, 2014 and 25% on February 15, 2015, provided that the officer remains employed on such date. The officers will also accrue notional dividends equal to the amount of dividends that an officer would have received if the officer had directly owned one share of Pinnacle West common stock for each restricted stock unit held by the officer from the grant date to each dividend payment date. Each additional restricted stock unit will proportionally vest on the same remaining vesting schedule that applies to the original restricted stock unit.

The following table is a summary of granted restricted stock units and stock grants and the weighted-average fair value for the three years ended 2012, 2011 and 2010:

	2012		2011		2010
Units granted	202,278		292,242		202,341
Grant date fair value (a)	$	49.31	$	41.98	$	37.47

(a) Weighted-average grant date fair value

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The following table is a summary of the status of restricted stock units and stock grants, as of December 31, 2012 and changes during the year. This table represents only the stock portion of restricted stock units, per the election on payment discussed in the paragraph above:

Nonvested shares	Shares	Weighted-Average Grant-Date Fair Value
Nonvested at January 1, 2012	416,231	$	39.61
Granted	202,278	49.31
Vested	126,959	39.76
Forfeited	10,797	42.63
Nonvested at December 31, 2012	480,753	43.58

The amount of cash required to settle the payments on restricted stock units is (dollars in millions):

Year	2012		2011		2010
2007 Grant	$	—	$	1.0	$	0.9
2008 Grant	1.9		1.6		1.5
2009 Grant	1.7		1.5		1.4
2010 Grant	0.6		0.6		—
2011 Grant	0.7		—		—

Performance Share Awards

Performance share awards were granted to officers and key employees under the 2012 Plan in 2012 and under the 2007 Plan from 2008 to 2011. Performance share awards contain two performance element criteria that affect the number of shares received after the end of a three-year performance period if performance criteria conditions are met.

The 2012, 2011 and 2010 performance share grant criteria is based 50% upon the percentile ranking of Pinnacle West’s total shareholder return at the end of the three-year performance period as compared with the total shareholder return of all relevant companies in a specified utility index and the other 50% based upon six non-financial separate performance metrics. The exact number of shares issued will vary from 0% to 200% of the target award. Shares received include dividend rights paid in stock equal to the amount of dividends that they would have received had they directly owned stock equal to the number of vested performance shares from the date of grant to the date of payment plus interest compounded quarterly.

Performance share awards are accounted for as liability awards, with compensation cost initially calculated on the date of grant using the Company’s closing stock price, and remeasured at each balance sheet date. Compensation expense for retirement eligible participants is recognized immediately. Management also evaluates the probability of meeting the performance criteria at each balance sheet date. If the performance criteria are not achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed.

The following table is a summary of the performance shares granted and the weighted-average fair value for the three years ended 2012, 2011 and 2010:

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	2012		2011		2010
Units granted (a)	185,878		175,072		178,722
Grant date fair value (b)	$	47.40	$	41.71	$	37.57

(a) Reflects the target payout level.

(b) Weighted-average grant date fair value.

The following table is a summary of the status of performance shares, as of December 31, 2012 and changes during the year:

Nonvested shares (a)	Shares	Weighted-Average Grant-Date Fair Value
Nonvested at January 1, 2012	347,946	$	39.64
Granted	185,878	47.40
Increase in performance factor	87,037	37.57
Vested	257,127	37.57
Forfeited	16,044	42.53
Nonvested at December 31, 2012	347,690	44.67

(a) Nonvested shares are reflected at the target payout level. The increase or decrease in the number of shares from the target level to the estimated actual payout level is included in the increase for performance factor amounts in the year the award vests.

Retention Units

The retention unit awards have fully vested and settled on January 4, 2010; for any employee that was eligible to retire before that date, the employee’s retention units vested by retirement date and the compensation expense was recognized by retirement eligibility. Retention unit awards were granted to key employees in 2006 and 2007. Each retention unit award represented the right to receive a cash payment equal to the fair market value of one share of Pinnacle West’s common stock, determined on pre-established valuation dates. Each retention unit award vested and settled in equal annual installments over a four-year period. In addition, the employee received a cash payment equal to the amount of dividends that the employee would have received if the employee had owned the stock from the date of grant to the date of payment plus interest. As this award was accounted for as a liability award, compensation costs, initially measured based on the Company’s stock price on the grant date, were remeasured at each balance sheet date, using Pinnacle West’s closing stock price.

The amount of cash to settle the payment on the first business day of 2010 was $1.3 million.

Stock Options

The Company has not granted stock options since 2004. Outstanding stock option grant terms cannot be longer than 10 years and options cannot be repriced during their terms.

The following table summarizes the option activity under prior equity incentive plans for the year ended December 31, 2012:

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Options	Shares	Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (Years)	Aggregate Intrinsic Value (dollars in thousands)
Outstanding at January 1, 2012	22,958	$	34.75
Exercised	15,033	36.05
Forfeited or expired	—	—
Outstanding at December 31, 2012	7,925	32.29		.21	$	148
Exercisable at December 31, 2012	7,925	32.29		.21	$	148

Cash received from options exercised under our share-based payment arrangements was $0.5 million for 2012, $1.8 million for 2011, and $4.6 million for 2010. The tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements were immaterial for all years.

The intrinsic value of options exercised was immaterial for all years.

As of December 31, 2012, there was $17 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the plans. That cost is expected to be recognized over a weighted-average period of 2.0 years. The total fair value of shares vested during 2012 was $19 million, 2011 was $14 million, and 2010 was $11 million.

The compensation cost that has been charged against Pinnacle West’s income for share-based compensation plans was $32 million in 2012, $23 million in 2011, and $15 million in 2010. The compensation cost that Pinnacle West has capitalized is immaterial for all years. Pinnacle West’s total income tax benefit recognized in the Consolidated Statements of Income for share-based compensation arrangements was $13 million in 2012, $9 million in 2011, and $6 million in 2010. APS’s share of compensation cost that has been charged against income was $32 million in 2012, $22 million in 2011, and $15 million in 2010.

Pinnacle West’s current policy is to issue new shares to satisfy share requirements for stock compensation plans and it does not expect to repurchase any shares except to satisfy tax withholding obligations upon the vesting of restricted stock units and performance shares.

17. Business Segments

Financial data for 2012, 2011 and 2010 is provided as follows (dollars in millions):

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	Business Segments for the Year Ended December 31, 2012
	Regulated Electricity Segment			All other (a)			Total
Operating revenues	$	3,294		$	8		$	3,302
Fuel and purchased power costs	995			—			995
Other operating expenses	1,047			4			1,051
Operating margin	1,252			4			1,256
Depreciation and amortization	404			—			404
Interest expense	200			—			200
Other expense (income)	(9		)	5			(4		)
Income (loss) from continuing operations before income taxes	657			(1		)	656
Income taxes	238			(1		)	237
Income from continuing operations	419			—			419
Loss from discontinued operations — net of income tax benefit of $(4) million (see Note 21)	—			(6		)	(6		)
Net income	419			(6		)	413
Less: Net income attributable to noncontrolling interests	31			—			31
Net income attributable to common shareholders	$	388		$	(6	)	$	382
Total assets	$	13,347		$	33		$	13,380
Capital expenditures	$	836		$	—		$	836

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	Business Segments for the Year Ended December 31, 2011
	Regulated Electricity Segment			All other (a)			Total
Operating revenues	$	3,237		$	4		$	3,241
Fuel and purchased power costs	1,009			—			1,009
Other operating expenses	1,055			3			1,058
Operating margin	1,173			1			1,174
Depreciation and amortization	427			—			427
Interest expense	224			—			224
Other expense (income)	(19		)	3			(16		)
Income (loss) from continuing operations before income taxes	541			(2		)	539
Income taxes	184			(1		)	183
Income (loss) from continuing operations	357			(1		)	356
Income from discontinued operations — net of income tax expense of $7 million (see Note 21)	—			11			11
Net income	357			10			367
Less: Net income attributable to noncontrolling interests	28			—			28
Net income attributable to common shareholders	$	329		$	10		$	339
Total assets	$	13,068		$	43		$	13,111
Capital expenditures	$	885		$	—		$	885

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	Business Segments for the Year Ended December 31, 2010
	Regulated Electricity Segment			All other (a)		Total
Operating revenues	$	3,181		$	8	$	3,189
Fuel and purchased power costs	1,047			—		1,047
Other operating expenses	1,009			4		1,013
Operating margin	1,125			4		1,129
Depreciation and amortization	415			—		415
Interest expense	226			2		228
Other expense (income)	(22		)	2		(20		)
Income from continuing operations before income taxes	506			—		506
Income taxes	161			—		161
Income from continuing operations	345			—		345
Income from discontinued operations — net of income tax expense of $16 million (see Note 21)	—			25		25
Net income	345			25		370
Less: Net income attributable to noncontrolling interests	20			—		20
Net income attributable to common shareholders	$	325		$	25	$	350
Total assets	$	12,285		$	108	$	12,393
Capital expenditures	$	666		$	4	$	670

(a) All other activities relate to SunCor, APSES and El Dorado. Loss from discontinued operations in 2012 is primarily related to a contribution Pinnacle West expects to make to SunCor’s estate as part of a negotiated resolution to the bankruptcy (see Note 21). Income from discontinued operations for 2011 is primarily related to the sale of our investment in APSES. Income from discontinued operations for 2010 is primarily related to the APSES sale of its district cooling business. None of these segments is a reportable business segment.

18. Derivative Accounting

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels. Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. We also enter into derivative instruments for economic hedging purposes. While we

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believe the economic hedges mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.

On June 1, 2012, we elected to discontinue cash flow hedge accounting treatment for the significant majority of our contracts that had previously been designated as cash flow hedges. This discontinuation is due to changes in PSA recovery (see Note 3), which now allows for 100% deferral of the unrealized gains and losses relating to these contracts. For those contracts that were de-designated, all changes in fair value after May 31, 2012 are no longer recorded through OCI, but are deferred through the PSA. The amounts previously recorded in accumulated OCI relating to these instruments will remain in accumulated OCI, and will transfer to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if we determine it is probable that the forecasted transaction will not occur. Cash flow hedge accounting treatment will continue for a limited number of contracts that are not subject to PSA recovery.

Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value; see Note 14 for a discussion of fair value measurements. Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value of the derivative instrument contract and the hedged item over time. We assess hedge effectiveness both at inception and on a continuing basis. These assessments exclude the time value of certain options. For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of OCI and reclassified into earnings in the same period during which the hedged transaction affects earnings. We recognize in current earnings, subject to the PSA, the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment. As cash flow hedge accounting has been discontinued for the significant majority of our contracts, effective June 1, 2012, effectiveness testing is no longer being performed for these contracts.

Prior to the Settlement Agreement, for its regulated operations, APS deferred for future rate treatment approximately 90% of unrealized gains and losses on certain derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Due to the Settlement Agreement, for its regulated operations, APS now defers for future rate treatment 100% of the unrealized gains and losses for delivery periods after June 30, 2012 on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 3). Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

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As of December 31, 2012, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

Commodity	Quantity
Power	8,045	gigawatt hours
Gas	139	Bcfs (a)

(a) “Bcf” is Billion Cubic Feet.

Gains and Losses from Derivative Instruments

The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the years ended December 31, 2012, 2011 and 2010 (dollars in thousands):

	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2012			2011			2010

Loss Recognized in OCI on Derivative Instruments (Effective Portion)	Other comprehensive loss — derivative instruments	$	(37,663	)	$	(94,660	)	$	(155,287	)
Loss Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion Realized) (a)	Fuel and purchased power	(99,007		)	(117,189		)	(122,740		)
Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Fuel and purchased power	117			(211		)	3,680

(a) During the year ended December 31, 2012, we had $1.8 million of losses reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges. There were no amounts reclassified in the 2011 and 2010 periods related to discontinued cash flow hedges.

During the next twelve months, we estimate that a net loss of $44 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, substantially all of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2012, 2011 and 2010 (dollars in thousands):

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	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2012			2011			2010

Net Gain (Loss) Recognized in Income	Operating revenues	$	103		$	(27	)	$	1,436

Net Loss Recognized in Income	Fuel and purchased power	(2,747		)	(52,113		)	(107,690		)
Total		$	(2,644	)	$	(52,140	)	$	(106,254	)

Fair Values of Derivative Instruments in the Consolidated Balance Sheets

The following table provides information about the fair value of our risk management activities reported on a gross basis. Transactions with counterparties that have master netting arrangements are reported net on the Consolidated Balance Sheets. These amounts are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets. Amounts are as of December 31, 2012 (dollars in thousands):

Commodity Contracts	Designated as Hedging Instruments			Not Designated as Hedging Instruments			Margin and Collateral Provided to Counterparties		Collateral Provided from Counterparties (a)			Other (b)			Total
Current Assets	$	—		$	42,495		$	61	$	—		$	(16,857	)	$	25,699
Investments and Other Assets	—			41,563			—		—			(5,672		)	35,891
Total Assets	—			84,058			61		—			(22,529		)	61,590

Current Liabilities	(1,147		)	(104,177		)	39,249		(25,463		)	17,797			(73,741		)
Deferred Credits and Other	(4,332		)	(96,654		)	10,051		—			5,671			(85,264		)
Total Liabilities	(5,479		)	(200,831		)	49,300		(25,463		)	23,468			(159,005		)
Total	$	(5,479	)	$	(116,773	)	$	49,361	$	(25,463	)	$	939		$	(97,415	)

(a) Collateral relates to non-derivative instruments or derivative instruments that qualify for a scope exception.

(b) Other represents derivative instrument netting, option premiums, and other risk management contracts.

The following table provides information about the fair value of our risk management activities reported on a gross basis at December 31, 2011 (dollars in thousands):

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Commodity Contracts	Designated as Hedging Instruments			Not Designated as Hedging Instruments			Margin and Collateral Provided to Counterparties		Collateral Provided from Counterparties (a)			Other (b)			Total
Current Assets	$	7,287		$	76,162		$	1,630	$	—		$	(54,815	)	$	30,264
Investments and Other Assets	3,804			58,273			—		—			(12,755		)	49,322
Total Assets	11,091			134,435			1,630		—			(67,570		)	79,586

Current Liabilities	(82,195		)	(124,028		)	107,228		(11,145		)	56,172			(53,968		)
Deferred Credits and Other	(68,137		)	(92,880		)	65,768		—			12,754			(82,495		)
Total Liabilities	(150,332		)	(216,908		)	172,996		(11,145		)	68,926			(136,463		)
Total Derivative Instruments	$	(139,241	)	$	(82,473	)	$	174,626	$	(11,145	)	$	1,356		$	(56,877	)

(a) Collateral relates to non-derivative instruments or derivative instruments that qualify for a scope exception.

(b) Other represents derivative instrument netting, option premiums, and other risk management contracts.

Credit Risk and Credit Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management contracts with many counterparties, including two counterparties for which our exposure represents approximately 86% of Pinnacle West’s $62 million of risk management assets as of December 31, 2012. This exposure relates to long-term traditional wholesale contracts with counterparties that have high credit quality. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).

The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2012 (dollars in millions):

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	December 31, 2012
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	206
Cash Collateral Posted	49
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)	120

(a) This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.

We also have energy related non-derivative instrument contracts with investment grade credit-related contingent features which could also require us to post additional collateral of approximately $183 million if our debt credit ratings were to fall below investment grade.

19. Other Income and Other Expense

The following table provides detail of other income and other expense for 2012, 2011 and 2010 (dollars in thousands):

	2012			2011			2010
Other income:
Interest income	$	1,239		$	1,850		$	3,255
Investment gains — net	—			1,165			2,797
Miscellaneous	367			96			335
Total other income	$	1,606		$	3,111		$	6,387

Other expense:
Non-operating costs	$	(7,777	)	$	(7,037	)	$	(6,831	)
Investment loss — net	(2,453		)	—			—
Miscellaneous	(9,612		)	(3,414		)	(3,090		)
Total other expense	$	(19,842	)	$	(10,451	)	$	(9,921	)

20. Palo Verde Sale Leaseback Variable Interest Entities

In 1986, APS entered into agreements with three separate VIE lessor trusts in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will pay approximately $49 million per year for the years 2013 to 2015 related to these leases. The lease agreements include fixed rate renewal periods which give APS the ability to utilize the asset for a significant portion of the asset’s economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance. Predominately due to the fixed rate renewal periods, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

On December 31, 2012, APS notified the lessor trust entities that APS will retain the assets beyond 2015 by either exercising the fixed rate lease renewals or by purchasing the assets. If APS elects to purchase the assets, the purchase price will be based on the fair market value of the assets at

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the end of 2015. If APS elects to extend the leases, we will be required to make payments beginning in 2016 of approximately $23 million annually. The length of the lease extensions is unknown at this time as it must be determined through an appraisal process. APS must give notice to the lessor trusts by June 30, 2014 notifying them which of these two options (lease renewal or purchasing the assets) it will exercise. The December 31, 2012 notification does not impact APS’s consolidation of the VIEs, as APS continues to be deemed the primary beneficiary of the VIEs.

As a result of consolidation, we eliminate rent expense and recognize depreciation and interest expense, resulting in an increase in net income for 2012, 2011 and 2010 of $32 million, $28 million and $20 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders remains the same. Consolidation of these VIEs also results in changes to our Consolidated Statements of Cash Flows, but does not impact net cash flows.

Our Consolidated Balance Sheets at December 31, 2012 and December 31, 2011 include the following amounts relating to the VIEs (in millions):

	December 31, 2012		December 31, 2011
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	129	$	133
Current maturities of long term-debt	27		31
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	39		66
Equity-Noncontrolling interests	129		108

Assets of the VIEs are restricted and may only be used to settle the VIEs’ debt obligations and for payment to the noncontrolling interest holders. Other than the VIEs’ assets reported on our consolidated financial statements, the creditors of the VIEs have no other recourse to the assets of APS or Pinnacle West, except in certain circumstances such as a default by APS under the lease.

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Unit 2 interests which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2012, APS would have been required to pay the noncontrolling equity participants approximately $139 million and assume $66 million of debt. Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Consolidated Balance Sheets.

For regulatory ratemaking purposes the leases continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.

21. Discontinued Operations

SunCor — In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business. We do not expect SunCor’s bankruptcy to have a material impact on Pinnacle West’s financial position, results of operations, or cash flows.

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

APSES — On August 19, 2011, Pinnacle West sold its investment in APSES. The sale resulted in an after-tax gain from discontinued operations of approximately $10 million. In June 2010, APSES sold its district cooling business. As a result of that sale, we recorded an after-tax gain from discontinued operations of approximately $25 million. Prior period income statement amounts related to these sales and the associated revenues and costs are reflected in discontinued operations.

The following table provides revenue, income (loss) before income taxes and income (loss) after taxes classified as discontinued operations in Pinnacle West’s Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010 (dollars in millions):

	2012			2011			2010
Revenue:
SunCor	$	—		$	1		$	30
APSES	—			36			127
Total revenue	$	—		$	37		$	157

Income (loss) before taxes:
SunCor	$	(10	)	$	(2	)	$	(10	)
APSES	—			21			51
Total income (loss) before taxes	$	(10	)	$	19		$	41

Income (loss) after taxes:
SunCor	$	(6	)	$	(1	)	$	(6	)
APSES	—			12			31
Total income (loss) after taxes	$	(6	)	$	11		$	25

22. Nuclear Decommissioning Trusts

To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. Third-party investment managers are authorized to buy and sell securities per their stated investment guidelines. The trust funds are invested in fixed income securities and equity securities. APS classifies investments in decommissioning trust funds as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Consolidated Balance Sheets. See Note 14 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities . The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at December 31, 2012 and December 31, 2011 (dollars in millions):

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2012
Equity securities	$	204		$	67	$	—
Fixed income securities	371			24		—
Net payables (a)	(4		)	—		—
Total	$	571		$	91	$	—

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2011
Equity securities	$	175		$	44	$	(1	)
Fixed income securities	340			23		(1		)
Net payables (a)	(1		)	—		—
Total	$	514		$	67	$	(2	)

(a) Net payables relate to pending securities sales and purchases.

The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):

	Year Ended December 31,
	2012			2011			2010

Realized gains	$	7		$	8		$	17
Realized losses	(4		)	(5		)	(4		)
Proceeds from the sale of securities (a)	418			498			560

(a) Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2012 is as follows (dollars in millions):

	Fair Value
Less than one year	$	14
1 year — 5 years	97
5 years — 10 years	109
Greater than 10 years	151
Total	$	371

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MANAGEMENT’S REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

(ARIZONA PUBLIC SERVICE COMPANY)

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Arizona Public Service Company. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2012. The effectiveness of our internal control over financial reporting as of December 31, 2012 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s financial statements.

February 22, 2013

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Arizona Public Service Company

Phoenix, Arizona

We have audited the accompanying consolidated balance sheets of Arizona Public Service Company and subsidiary (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company’s internal control over financial reporting based on our audits.

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In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Arizona Public Service Company and subsidiary as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ Deloitte & Touche LLP

Phoenix, Arizona
February 22, 2013

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ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(dollars in thousands)

	Year Ended December 31,
	2012			2011			2010

ELECTRIC OPERATING REVENUES	$	3,293,489		$	3,237,241		$	3,180,807

OPERATING EXPENSES
Fuel and purchased power	994,790			1,009,464			1,046,815
Operations and maintenance	873,916			895,917			860,712
Depreciation and amortization	404,242			426,958			414,336
Income taxes (Notes 4 and S-1)	256,600			204,066			175,440
Taxes other than income taxes	158,412			146,453			134,467
Total	2,687,960			2,682,858			2,631,770

OPERATING INCOME	605,529			554,383			549,037

OTHER INCOME (DEDUCTIONS)
Income taxes (Notes 4 and S-1)	12,204			11,524			4,975
Allowance for equity funds used during construction (Note 1)	22,436			23,707			22,066
Other income (Note S-3)	2,868			5,071			8,956
Other expense (Note S-3)	(21,150		)	(15,328		)	(15,859		)
Total	16,358			24,974			20,138

INTEREST EXPENSE
Interest on long-term debt	198,398			218,981			217,002
Interest on short-term borrowings	7,135			10,345			8,267
Debt discount, premium and expense	4,215			4,616			4,559
Allowance for borrowed funds used during construction (Note 1)	(14,971		)	(18,358		)	(16,479		)
Total	194,777			215,584			213,349

NET INCOME	427,110			363,773			355,826

Less: Net income attributable to noncontrolling interests (Note 20)	31,613			27,524			20,163

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	395,497		$	336,249		$	335,663

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Consolidated Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)

	Year Ended December 31,
	2012			2011			2010

NET INCOME	$	427,110		$	363,773		$	355,826

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $14,888, $37,397 and $61,358 (Note 18)	(22,775		)	(57,262		)	(93,929		)
Reclassification of net realized loss, net of tax benefit of $39,119, $46,298 and $48,462 (Note 18)	59,888			70,891			74,278
Pension and other postretirement benefits activity, net of tax benefit of $408, $1,910 and $4,493 (Note 8)	(617		)	(2,925		)	(6,848		)
Total other comprehensive income (loss)	36,496			10,704			(26,499		)

COMPREHENSIVE INCOME	463,606			374,477			329,327
Less: Comprehensive income attributable to noncontrolling interests	31,613			27,524			20,163

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	431,993		$	346,953		$	309,164

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Consolidated Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	December 31,
	2012			2011
ASSETS

PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 10)
Plant in service and held for future use	$	14,342,501		$	13,750,105
Accumulated depreciation and amortization	(4,925,990		)	(4,706,462		)
Net	9,416,511			9,043,643

Construction work in progress	565,716			496,745
Palo Verde sale leaseback, net of accumulated depreciation of $222,055 and $218,186 (Note 20)	128,995			132,864
Intangible assets, net of accumulated amortization of $411,543 and $372,573	161,995			170,416
Nuclear fuel, net of accumulated amortization of $133,950 and $113,375	122,778			118,098
Total property, plant and equipment	10,395,995			9,961,766

INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 14 and 22)	570,625			513,733
Assets from risk management activities (Note 18)	35,891			49,322
Other assets	31,650			30,551
Total investments and other assets	638,166			593,606

CURRENT ASSETS
Cash and cash equivalents	3,499			19,873
Customer and other receivables	274,815			280,100
Accrued unbilled revenues	94,845			125,239
Allowance for doubtful accounts	(3,340		)	(3,748		)
Materials and supplies (at average cost)	218,096			204,387
Fossil fuel (at average cost)	31,334			22,000
Assets from risk management activities (Note 18)	25,699			30,264
Deferred fuel and purchased power regulatory asset (Note 3)	72,692			27,549
Other regulatory assets (Note 3)	71,257			69,072
Deferred income taxes (Notes 4 and S-1)	74,420			111,503
Other current assets	37,666			29,355
Total current assets	900,983			915,594

DEFERRED DEBITS
Regulatory assets (Notes 1, 3, 4 and S-1)	1,099,900			1,352,079
Income tax receivable (Notes 4 and S-1)	70,784			69,028
Unamortized debt issue costs	22,492			21,181
Other	114,222			118,983
Total deferred debits	1,307,398			1,561,271

TOTAL ASSETS	$	13,242,542		$	13,032,237

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Consolidated Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	December 31,
	2012			2011
LIABILITIES AND EQUITY

CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital	2,379,696			2,379,696
Retained earnings	1,624,237			1,510,740
Accumulated other comprehensive (loss):
Pension and other postretirement benefits (Note 8)	(39,503		)	(38,886		)
Derivative instruments (Note 18)	(49,592		)	(86,705		)
Total shareholder equity	4,093,000			3,943,007
Noncontrolling interests (Note 20)	129,483			108,399
Total equity	4,222,483			4,051,406
Long-term debt less current maturities (Note 6)	3,035,219			2,828,507
Palo Verde sale leaseback lessor notes less current maturities (Notes 6 and 20)	38,869			65,547
Total capitalization	7,296,571			6,945,460

CURRENT LIABILITIES
Commercial paper (Note 5)	92,175			—
Current maturities of long-term debt (Note 6)	122,828			477,435
Accounts payable	215,577			322,047
Accrued taxes (Notes 4 and S-1)	116,700			113,930
Accrued interest	49,135			54,611
Common dividends payable	59,800			—
Customer deposits	79,689			72,176
Liabilities from risk management activities (Note 18)	73,741			53,968
Regulatory liabilities (Note 3)	88,116			88,362
Other current liabilities	145,326			140,185
Total current liabilities	1,043,087			1,322,714

DEFERRED CREDITS AND OTHER
Deferred income taxes (Notes 4 and S-1)	2,133,976			1,952,608
Regulatory liabilities (Notes 1, 3, 4, and S-1)	759,201			737,332
Liability for asset retirements (Note 12)	357,097			279,643
Liabilities for pension and other postretirement benefits (Note 8)	1,017,556			1,222,542
Liabilities from risk management activities (Note 18)	85,264			82,495
Customer advances	109,359			116,805
Coal mine reclamation	118,860			117,896
Unrecognized tax benefits (Notes 4 and S-1)	70,932			72,073
Other	250,639			182,669
Total deferred credits and other	4,902,884			4,764,063

COMMITMENTS AND CONTINGENCIES (SEE NOTES)

TOTAL LIABILITIES AND EQUITY	$	13,242,542		$	13,032,237

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Consolidated Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

	Year Ended December 31,
	2012			2011			2010

CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	427,110		$	363,773		$	355,826
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	481,168			493,653			471,226
Deferred fuel and purchased power	71,573			69,166			93,631
Deferred fuel and purchased power amortization	(116,716		)	(155,157		)	(122,481		)
Allowance for equity funds used during construction	(22,436		)	(23,707		)	(22,066		)
Deferred income taxes	243,738			168,805			224,095
Change in derivative instruments fair value	(749		)	4,064			2,688
Changes in current assets and liabilities:
Customer and other receivables	12,914			34,913			(49,956		)
Accrued unbilled revenues	30,394			(21,947		)	7,679
Materials, supplies and fossil fuel	(23,043		)	(23,398		)	12,276
Other current assets	(27,745		)	(5,473		)	4,718
Accounts payable	(97,395		)	73,369			18,066
Accrued taxes and income tax receivable — net	5,050			5,103			(51,620		)
Other current liabilities	6,070			18,762			(2,853		)
Change in margin and collateral accounts — assets	2,216			33,349			(9,937		)
Change in margin and collateral accounts — liabilities	137,785			29,731			(88,315		)
Change in long-term regulatory liabilities	13,539			37,009			56,801
Change in long-term income tax receivable	(1,756		)	(3,530		)	—
Change in unrecognized tax benefits	(2,583		)	9,125			(73,189		)
Change in other long-term assets	1,391			(41,788		)	(46,118		)
Change in other long-term liabilities	34,854			61,990			(85,136		)
Net cash flow provided by operating activities	1,175,379			1,127,812			695,335
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(889,551		)	(878,546		)	(747,967		)
Contributions in aid of construction	49,876			38,096			32,754
Allowance for borrowed funds used during construction	(14,971		)	(18,358		)	(16,479		)
Proceeds from nuclear decommissioning trust sales	417,603			497,780			560,469
Investment in nuclear decommissioning trust	(434,852		)	(513,799		)	(584,885		)
Proceeds from sale of life insurance policies	—			44,183			—
Other	(1,099		)	(3,306		)	8,576
Net cash flow used for investing activities	(872,994		)	(833,950		)	(747,532		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	351,081			295,353			—
Repayment of long-term debt	(529,286		)	(430,169		)	(27,694		)
Short-term borrowings and payments — net	92,175			—			—
Equity infusion	—			—			252,833
Dividends paid on common stock	(222,200		)	(228,900		)	(182,400		)
Noncontrolling interests	(10,529		)	(10,210		)	(11,403		)
Net cash flow provided by (used for) financing activities	(318,759		)	(373,926		)	31,336
NET DECREASE IN CASH AND CASH EQUIVALENTS	(16,374		)	(80,064		)	(20,861		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	19,873			99,937			120,798
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	3,499		$	19,873		$	99,937
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Income taxes, net of refunds	$	1,196		$	25,975		$	81,339
Interest, net of amounts capitalized	$	196,038		$	210,995		$	208,251
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	26,208		$	27,245		$	19,226
Dividends declared but not paid	$	59,800		$	—		$	—

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Consolidated Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(dollars in thousands)

	Year Ended December 31,
	2012			2011			2010

COMMON STOCK	$	178,162		$	178,162		$	178,162

ADDITIONAL PAID-IN CAPITAL
Balance at beginning of year	2,379,696			2,379,696			2,126,863
Equity infusion	—			—			252,833
Balance at end of year	2,379,696			2,379,696			2,379,696

RETAINED EARNINGS
Balance at beginning of year	1,510,740			1,403,390			1,250,126
Net income attributable to common shareholder	395,497			336,249			335,663
Dividends on common stock	(282,000		)	(228,900		)	(182,400		)
Other	—			1			1
Balance at end of year	1,624,237			1,510,740			1,403,390

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Balance at beginning of year	(125,591		)	(136,295		)	(109,796		)
Other comprehensive income (loss) attributable to common shareholder	36,496			10,704			(26,499		)
Balance at end of year	(89,095		)	(125,591		)	(136,295		)

NONCONTROLLING INTERESTS
Balance at beginning of year	108,399			91,084			82,324
Net income attributable to noncontrolling interests	31,613			27,524			20,163
Net capital activities by noncontrolling interests	(10,529		)	(10,209		)	(11,403		)
Balance at end of year	129,483			108,399			91,084

TOTAL EQUITY	$	4,222,483		$	4,051,406		$	3,916,037

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER
Net income attributable to common shareholder	$	395,497		$	336,249		$	335,663
Other comprehensive income (loss)	36,496			10,704			(26,499		)
Total comprehensive income attributable to common shareholder	$	431,993		$	346,953		$	309,164

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Consolidated Financial Statements.

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Certain notes to Arizona Public Service Company’s consolidated financial statements are combined with the notes to Pinnacle West Capital Corporation’s consolidated financial statements. Listed below are the consolidated notes to Pinnacle West Capital Corporation’s consolidated financial statements, the majority of which also relate to Arizona Public Service Company’s consolidated financial statements. In addition, listed below are the supplemental notes which are required disclosures for Arizona Public Service Company and should be read in conjunction with Pinnacle West Capital Corporation’s Consolidated Notes.

	Consolidated Footnote Reference	APS’s Supplemental Footnote Reference
Summary of Significant Accounting Policies	Note 1	—
New Accounting Standards	Note 2	—
Regulatory Matters	Note 3	—
Income Taxes	Note 4	Note S-1
Lines of Credit and Short-Term Borrowings	Note 5	—
Long-Term Debt and Liquidity Matters	Note 6	—
Common Stock and Treasury Stock	Note 7	—
Retirement Plans and Other Benefits	Note 8	—
Leases	Note 9	—
Jointly-Owned Facilities	Note 10	—
Commitments and Contingencies	Note 11	—
Asset Retirement Obligations	Note 12	—
Selected Quarterly Financial Data (Unaudited)	Note 13	Note S-2
Fair Value Measurements	Note 14	—
Earnings Per Share	Note 15	—
Stock-Based Compensation	Note 16	—
Business Segments	Note 17	—
Derivative Accounting	Note 18	—
Other Income and Other Expense	Note 19	Note S-3
Palo Verde Sale Leaseback Variable Interest Entities	Note 20	—
Discontinued Operations	Note 21	—
Nuclear Decommissioning Trusts	Note 22	—

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

S-1. Income Taxes

APS is included in Pinnacle West’s consolidated tax return. However, when Pinnacle West allocates income taxes to APS, it is done based upon APS’s taxable income computed on a stand-alone basis, in accordance with the tax sharing agreement.

In accordance with regulatory requirements, APS investment tax credits are deferred and are amortized over the life of the related property, with such amortization applied as a credit to reduce current income tax expense in the statement of income.

The $71 million long-term income tax receivable on APS’s Consolidated Balance Sheets represents the anticipated refunds related to an APS tax accounting method change approved by the IRS in the third quarter of 2009. This amount is classified as long-term, as there remains uncertainty regarding the timing of this cash receipt. Further clarification of the timing is expected from the IRS within the next twelve months.

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	2012			2011			2010
Total unrecognized tax benefits, January 1	$	135,824		$	126,698		$	199,887
Additions for tax positions of the current year	5,167			10,915			7,551
Reductions for tax positions of prior years for:
Changes in judgment	(7,729		)	(1,555		)	(10,964		)
Settlements with taxing authorities	—			(124		)	(61,820		)
Lapses of applicable statute of limitations	(21		)	(110		)	(7,956		)
Total unrecognized tax benefits, December 31	$	133,241		$	135,824		$	126,698

Included in the balance of unrecognized tax benefits at December 31, 2012, 2011 and 2010 were approximately $10 million, $8 million and $6 million, respectively, of tax positions that, if recognized, would decrease our effective tax rate.

As of the balance sheet date, the tax year ended December 31, 2008 and all subsequent tax years remain subject to examination by the IRS. With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2008.

We reflect interest and penalties, if any, on unrecognized tax benefits in the Statements of Income as income tax expense. The amount of interest recognized in the Statements of Income related to unrecognized tax benefits was a pre-tax expense of $4 million for 2012, a pre-tax expense of $3 million for 2011 and a pre-tax benefit of $2 million for 2010.

The total amount of accrued liabilities for interest recognized in the Balance Sheets related to unrecognized tax benefits was $13 million as of December 31, 2012, $9 million as of December 31, 2011 and $6 million as of December 31, 2010. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, as of December 31, 2012, we have recognized $5 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

The components of APS’s income tax expense are as follows (dollars in thousands):

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Year Ended December 31,
	2012			2011		2010
Current:
Federal	$	(11,650	)	$	4,633	$	(71,036	)
State	12,308			19,104		17,406
Total current	658			23,737		(53,630		)
Deferred:
Federal	216,367			154,632		207,334
State	27,371			14,173		16,761
Total deferred	243,738			168,805		224,095
Total income tax expense	$	244,396		$	192,542	$	170,465

On the APS Statements of Income, federal and state income taxes are allocated between operating income and other income.

The following chart compares APS’s pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Year Ended December 31,
	2012			2011			2010

Federal income tax expense at 35% statutory rate	$	235,027		$	194,710		$	184,202
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	25,379			21,139			19,186
Credits and favorable adjustments related to prior years resolved in current year	—			—			(17,300		)
Medicare Subsidy Part-D	483			823			889
Allowance for equity funds used during construction (see Note 1)	(6,158		)	(6,880		)	(6,563		)
Palo Verde VIE noncontrolling interest (see Note 20)	(11,065		)	(9,633		)	(7,057		)
Other	730			(7,617		)	(2,892		)
Income tax expense	$	244,396		$	192,542		$	170,465

The following table shows the net deferred income tax liability recognized on the APS Balance Sheets (dollars in thousands):

	December 31,
	2012			2011
Current asset	$	74,420		$	111,503
Long-term liability	(2,133,976		)	(1,952,608		)
Deferred income taxes — net	$	(2,059,556	)	$	(1,841,105	)

The American Taxpayer Relief Act of 2012, signed into law on January 2, 2013, includes provisions making qualified property placed into service in 2013 eligible for 50% bonus depreciation for federal income tax purposes. Full recognition of the cash benefit of this provision would delay realization of approximately $4 million in federal general business income tax credit carryforwards which are classified as current assets as of December 31, 2012.

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The components of the net deferred income tax liability were as follows (dollars in thousands):

	December 31,
	2012			2011
DEFERRED TAX ASSETS
Regulatory liabilities:
Asset retirement obligation and removal costs	$	238,669		$	236,739
Renewable energy standard	—			19,722
Unamortized investment tax credits	53,837			31,460
Other	33,764			33,155
Risk management activities	72,243			117,765
Pension and other postretirement liabilities	392,486			494,744
Renewable energy incentives	66,941			57,901
Credit and loss carryforwards	52,441			106,668
Other	111,327			99,176
Total deferred tax assets	1,021,708			1,197,330
DEFERRED TAX LIABILITIES
Plant-related	(2,584,166		)	(2,446,908		)
Risk management activities	(23,940		)	(30,171		)
Regulatory assets:
Allowance for equity funds used during construction	(37,899		)	(33,347		)
Deferred fuel and purchased power	(28,858		)	(10,884		)
Deferred fuel and purchased power — mark-to-market	(15,796		)	(30,559		)
Pension and other postretirement benefits	(316,757		)	(408,716		)
Other	(68,170		)	(73,087		)
Other	(5,678		)	(4,763		)
Total deferred tax liabilities	(3,081,264		)	(3,038,435		)
Deferred income taxes — net	$	(2,059,556	)	$	(1,841,105	)

As of December 31, 2012, the deferred tax assets for credit and loss carryforwards relate to federal general business credits ($50 million) which first begin to expire in 2031 and other federal and state loss carryforwards ($2 million) which first begin to expire in 2017.

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

S-2. Selected Quarterly Financial Data (Unaudited)

Quarterly financial information for 2012 and 2011 is as follows (dollars in thousands):

	2012 Quarter Ended,									2012
	March 31,			June 30,		September 30,		December 31,		Total

Operating revenues	$	620,248		$	877,587	$	1,108,623	$	687,031	$	3,293,489
Operations and maintenance	208,447			213,746		218,403		233,320		873,916
Operating income	53,995			176,821		296,945		77,768		605,529
Net income (loss) attributable to common shareholder	(4,105		)	124,928		247,831		26,843		395,497

	2011 Quarter Ended,									2011
	March 31,			June 30,		September 30,		December 31,		Total

Operating revenues	$	647,994		$	798,686	$	1,124,057	$	666,504	$	3,237,241
Operations and maintenance	252,607			208,597		207,967		226,746		895,917
Operating income	45,574			145,400		292,783		70,626		554,383
Net income (loss) attributable to common shareholder	(12,081		)	87,705		246,333		14,292		336,249

S-3. Other Income and Other Expense

The following table provides detail of APS’s other income and other expense for 2012, 2011 and 2010 (dollars in thousands):

	2012			2011			2010
Other income:
Interest income	$	310		$	406		$	668
Investment gains — net	—			1,418			2,334
Miscellaneous	2,558			3,247			5,954
Total other income	$	2,868		$	5,071		$	8,956

Other expense:
Non-operating costs (a)	$	(8,706	)	$	(8,810	)	$	(9,855	)
Asset dispositions	(1,511		)	(1,352		)	(612		)
Miscellaneous	(10,933		)	(5,166		)	(5,392		)
Total other expense	$	(21,150	)	$	(15,328	)	$	(15,859	)

(a) As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).

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PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

	Year Ended December 31,
	2012			2011			2010

Operating revenues	$	6,133		$	1,034		$	2,810
Operating expenses	12,125			8,811			9,880

Operating loss	(5,992		)	(7,777		)	(7,070		)

Other
Equity in earnings of subsidiaries	391,528			335,859			358,527
Other expense	(2,001		)	(1,481		)	(588		)
Total	389,527			334,378			357,939

Interest expense	4,868			8,053			14,346

Income from continuing operations	378,667			318,548			336,523
Income tax benefit	(7,079		)	(8,938		)	(9,596		)

Income from continuing operations — net of income taxes	385,746			327,486			346,119
Income (loss) from discontinued operations — net of income taxes	(4,204		)	11,987			3,934

Net income attributable to common shareholders	$	381,542		$	339,473		$	350,053

Other comprehensive income (loss) — attributable to common shareholders	38,155			7,605			(28,180		)
Total comprehensive income — attributable to common shareholders	$	419,697		$	347,078		$	321,873

See Notes to Pinnacle West’s Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED BALANCE SHEETS

(in thousands)

	December 31,
	2012			2011
ASSETS

Current assets
Cash and cash equivalents	$	22,679		$	12,710
Customer and other receivables	92,906			62,418
Current deferred income taxes	77,771			19,068
Income tax receivable	3,350			1,804
Other current assets	25			55
Total current assets	196,731			96,055

Investments and other assets
Investments in subsidiaries	4,223,301			4,026,289
Deferred income taxes	—			27,220
Other assets	13,833			16,898
Total investments and other assets	4,237,134			4,070,407

Total Assets	$	4,433,865		$	4,166,462

LIABILITIES AND EQUITY

Current liabilities
Accounts payable	$	5,735		$	4,811
Accrued taxes	8,239			9,795
Common dividends payable	59,789			—
Other current liabilities	41,000			28,295
Total current liabilities	114,763			42,901

Long-term debt less current maturities	125,000			125,000

Deferred credits and other
Deferred income taxes	17,395			—
Pension and other postretirement liabilities	41,199			32,513
Other	33,219			35,462
Total deferred credits and other	91,813			67,975

Common stock equity
Common stock	2,462,712			2,439,530
Accumulated other comprehensive loss	(114,008		)	(152,163		)
Retained earnings	1,624,102			1,534,483
Total Pinnacle West Shareholders’ equity	3,972,806			3,821,850
Noncontrolling interests	129,483			108,736
Total Equity	4,102,289			3,930,586
Total Liabilities and Equity	$	4,433,865		$	4,166,462

See Notes to Pinnacle West’s Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2012			2011			2010

Cash flows from operating activities
Net income	$	381,542		$	339,473		$	350,053
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries — net	(391,528		)	(335,859		)	(358,527		)
Depreciation and amortization	94			97			143
Gain on sale of energy-related business	—			(10,404		)	—
Deferred income taxes	(15,135		)	7,387			40,342
Customer and other receivables	28,763			(24,201		)	(18,175		)
Accounts payable	879			(2,677		)	7,468
Accrued taxes and income tax receivables — net	(3,103		)	7,512			59,640
Dividends received from subsidiaries	222,200			228,900			207,000
Other	(4,589		)	19,270			423
Net cash flow provided by operating activities	219,123			229,498			288,367

Cash flows from investing activities
Investments in subsidiaries	—			—			(183,544		)
Repayments of loans from subsidiaries	996			61,143			98,406
Proceeds from sale of energy-related products and services business	—			45,111			—
Advances of loans to subsidiaries	(1,200		)	(64,970		)	(119,293		)
Proceeds from sale of life insurance policies	—			9,357			—
Net cash flow provided by (used for) investing activities	(204		)	50,641			(204,431		)

Cash flows from financing activities
Issuance of long-term debt	125,000			175,000			—
Short-term borrowings and payments — net	—			(16,600		)	(132,487		)
Dividends paid on common stock	(225,075		)	(221,728		)	(216,979		)
Repayment of long-term debt	(125,000		)	(225,000		)	—
Common stock equity issuance	15,955			15,841			255,971
Other	170			(2,667		)	—
Net cash flow used for financing activities	(208,950		)	(275,154		)	(93,495		)

Net increase (decrease) in cash and cash equivalents	9,969			4,985			(9,559		)

Cash and cash equivalents at beginning of year	12,710			7,725			17,284

Cash and cash equivalents at end of year	$	22,679		$	12,710		$	7,725

See Notes to Pinnacle West’s Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION

SCHEDULE II — RESERVE FOR UNCOLLECTIBLES

(dollars in thousands)

Column A	Column B		Column C				Column D		Column E
			Additions
Description	Balance at beginning of period		Charged to cost and expenses		Charged to other accounts		Deductions		Balance at end of period

Reserve for uncollectibles:
2012	$	3,748	$	5,290	$	—	$	5,698	$	3,340
2011	4,709		5,672		—		6,633		3,748
2010	4,573		6,905		—		6,769		4,709

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ARIZONA PUBLIC SERVICE COMPANY

SCHEDULE II — RESERVE FOR UNCOLLECTIBLES

(dollars in thousands)

Column A	Column B		Column C				Column D		Column E
			Additions
Description	Balance at beginning of period		Charged to cost and expenses		Charged to other accounts		Deductions		Balance at end of period

Reserve for uncollectibles:
2012	$	3,748	$	5,290	$	—	$	5,698	$	3,340
2011	4,376		5,751		—		6,379		3,748
2010	4,483		6,756		—		6,863		4,376

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

(a) Disclosure Controls and Procedures

The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934 (the “Exchange Act”) (15 U.S.C. 78a et seq .) is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of December 31, 2012. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.

APS’s management, with the participation of APS’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’s disclosure controls and procedures as of December 31, 2012 Based on that evaluation, APS’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’s disclosure controls and procedures were effective.

(b) Management’s Annual Reports on Internal Control Over Financial Reporting

Reference is made to “Management’s Report on Internal Control Over Financial Reporting (Pinnacle West Capital Corporation)” on page 78 of this report and “Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)” on page 154 of this report.

Reference is made to “Report of Independent Registered Public Accounting Firm” on page 79 of this report and “Report of Independent Registered Public Accounting Firm” on page 155 of this report on the internal control over financial reporting of Pinnacle West and APS, respectively.

(d) Changes In Internal Control Over Financial Reporting

The term “internal control over financial reporting” (defined in SEC Rule 13a-15(f)) refers to the process of a company that is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

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No change in Pinnacle West’s or APS’s internal control over financial reporting occurred during the fiscal quarter ended December 31, 2012 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS

AND CORPORATE GOVERNANCE OF PINNACLE WEST

Reference is hereby made to “Information About Our Board and Corporate Governance,” “Proposal 1 — Election of Directors” and to “Section 16(a) Beneficial Ownership Reporting Compliance” in the Pinnacle West Proxy Statement relating to the Annual Meeting of Shareholders to be held on May 15, 2013 (the “2013 Proxy Statement”) and to the “Executive Officers of Pinnacle West” section in Part I of this report.

Pinnacle West has adopted a Code of Ethics for Financial Executives that applies to financial executives including Pinnacle West’s Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Controller, Treasurer, and persons holding substantially equivalent positions at Pinnacle West’s subsidiaries. The Code of Ethics for Financial Executives is posted on Pinnacle West’s website at www.pinnaclewest.com . Pinnacle West intends to satisfy the requirements under Item 5.05 of Form 8-K regarding disclosure of amendments to, or waivers from, provisions of the Code of Ethics for Financial Executives by posting such information on Pinnacle West’s website.

ITEM 11. EXECUTIVE COMPENSATION

Reference is hereby made to “Directors’ Compensation,” “Report of the Human Resources Committee,” “Executive Compensation,” and “Human Resources Committee Interlocks and Insider Participation” in the 2013 Proxy Statement.

ITEM 12. SECURITY OWNERSHIP OF

CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

AND RELATED STOCKHOLDER MATTERS

Reference is hereby made to “Shares of Pinnacle West Stock Owned by Management and Large Shareholders” in the 2013 Proxy Statement.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table sets forth information as of December 31, 2012 with respect to the 2012 Plan, the 2007 Plan and the 2002 Long-Term Incentive Plan (the “2002 Plan”) under which our equity securities are outstanding or currently authorized for issuance.

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Equity Compensation Plan Information

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted- average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)

Equity compensation plans approved by security holders	1,807,219	$	32.29	3,986,496
Equity compensation plans not approved by security holders	—	—		—
Total	1,807,219	$	32.29	3,986,496

(a) This amount includes shares subject to outstanding options as well as shares subject to outstanding performance share awards and restricted stock unit awards at the maximum amount of shares issuable under such awards. However, payout of the performance share awards is contingent on the Company reaching certain levels of performance during a three-year performance period. If the performance criteria for these awards are not fully satisfied, the award recipient will receive less than the maximum number of shares available under these grants and may receive nothing from these grants.

(b) The weighted-average exercise price in this column does not take performance share awards or restricted stock unit awards into account, as those awards have no exercise price.

(c) Awards under the 2012 Plan can take the form of options, stock appreciation rights, restricted stock, performance shares, performance share units, performance cash, stock grants, stock units, dividend equivalents, and restricted stock units. Additional shares cannot be awarded under either the 2002 Plan or the 2007 Plan. However, if an award under the 2012 Plan or an award that was outstanding under either the 2002 Plan or the 2007 Plan on or after December 31, 2011 is forfeited, terminated or cancelled or expires, the shares subject to such award, to the extent of the forfeiture, termination, cancellation or expiration, may be added back to the shares available for issuance under the 2012 Plan.

Equity Compensation Plans Approved By Security Holders

Amounts in column (a) in the table above include shares subject to awards outstanding under three equity compensation plans that were previously approved by our shareholders: (a) the 2002 Plan, which was approved by our shareholders at our 2002 annual meeting of shareholders and under which no new stock awards may be granted, (b) the 2007 Plan, which was approved by our shareholders at our 2007 annual meeting of shareholders and under which no new stock awards may

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be granted, and (c) the 2012 Plan, which was approved by our shareholders at our 2012 annual meeting of shareholders. See Note 16 of the Notes to Consolidated Financial Statements for additional information regarding these plans.

Equity Compensation Plans Not Approved by Security Holders

The Company does not have any equity compensation plans under which shares can be issued that have not been approved by the shareholders.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED

TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Reference is hereby made to “Information About Our Board and Corporate Governance” and “Related Party Transactions” in the 2013 Proxy Statement.

ITEM 14. PRINCIPAL ACCOUNTANT

FEES AND SERVICES

Pinnacle West

Reference is hereby made to “Accounting and Auditing Matters — Audit Fees and — Pre-Approval Policies” in the 2013 Proxy Statement.

APS

The following fees were paid to APS’s independent registered public accountants, Deloitte & Touche LLP, for the last two fiscal years:

Type of Service	2011		2012
Audit Fees (1)	$	1,547,722	$	1,659,087
Audit-Related Fees (2)	183,091		174,310

(1) The aggregate fees billed for services rendered for the audit of annual financial statements and for review of financial statements included in Reports on Form 10-Q.

(2) The aggregate fees billed for assurance services that are reasonably related to the performance of the audit or review of the financial statements that are not included in Audit Fees reported above, which primarily consist of fees for employee benefit plan audits performed in 2012 and 2011.

Pinnacle West’s Audit Committee pre-approves each audit service and non-audit service to be provided by APS’s registered public accounting firm. The Audit Committee has delegated to the Chairman of the Audit Committee the authority to pre-approve audit and non-audit services to be performed by the independent public accountants if the services are not expected to cost more than $50,000. The Chairman must report any pre-approval decisions to the Audit Committee at its next scheduled meeting. All of the services performed by Deloitte & Touche LLP for APS were pre-approved by the Audit Committee.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Financial Statements and Financial Statement Schedules

See the Index to Financial Statements and Financial Statement Schedule in Part II, Item 8.

Exhibits Filed

The documents listed below are being filed or have previously been filed on behalf of Pinnacle West or APS and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith.

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

3.1	Pinnacle West	Articles of Incorporation, restated as of May 21, 2008	3.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-8962	8-7-08

3.2	Pinnacle West	Pinnacle West Capital Corporation Bylaws, amended as of May 19, 2010	3.1 to Pinnacle West/APS June 30, 2010 Form 10-Q Report, File No. 1-8962	8-3-10

3.3	APS	Articles of Incorporation, restated as of May 25, 1988	4.2 to APS’s Form 18 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473	9-29-93

3.3.1	APS	Amendment to the Articles of Incorporation of Arizona Public Service Company, amended May 16, 2012	3.1 to Pinnacle West/APS May 22, 2012 Form 8-K Report, File Nos. 1-8962 and 1-4473	5-22-12

3.4	APS	Arizona Public Service Company Bylaws, amended as of December 16, 2008	3.4 to Pinnacle West/APS December 31, 2008 Form 10-K, File No. 1-4473	2-20-09

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Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

4.1	Pinnacle West	Specimen Certificate of Pinnacle West Capital Corporation Common Stock, no par value	4.1 to Pinnacle West June 28, 2011 Form 8-K Report, File No. 1-8962	6-28-11

4.2	Pinnacle West APS	Indenture dated as of January 1, 1995 among APS and The Bank of New York Mellon, as Trustee	4.6 to APS’s Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report, File No. 1-4473	1-11-95

4.2a	Pinnacle West APS	First Supplemental Indenture dated as of January 1, 1995	4.4 to APS’s Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report, File No. 1-4473	1-11-95

4.3	Pinnacle West APS	Indenture dated as of November 15, 1996 between APS and The Bank of New York, as Trustee	4.5 to APS’s Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333- 15379 by means of November 19, 1996 Form 8-K Report, File No. 1-4473	11-22-96

4.3a	Pinnacle West APS	First Supplemental Indenture dated as of November 15, 1996	4.6 to APS’s Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report, File No. 1-4473	11-22-96

4.3b	Pinnacle West APS	Second Supplemental Indenture dated as of April 1, 1997	4.10 to APS’s Registration Statement Nos. 33-55473, 33-64455 and 333-15379 by means of April 7, 1997 Form 8-K Report, File No. 1-4473	4-9-97

4.3c	Pinnacle West APS	Third Supplemental Indenture dated as of November 1, 2002	10.2 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962	5-15-03

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Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

4.4	Pinnacle West	Indenture dated as of December 1, 2000 between the Company and The Bank of New York, as Trustee, relating to Senior Unsecured Debt Securities	4.1 to Pinnacle West’s Registration Statement No. 333-52476	12-21-00

4.5	Pinnacle West	Indenture dated as of December 1, 2000 between the Company and The Bank of New York, as Trustee, relating to Subordinated Unsecured Debt Securities	4.2 to Pinnacle West’s Registration Statement No. 333-52476	12-21-00

4.6	Pinnacle West APS	Indenture dated as of January 15, 1998 between APS and The Bank of New York Mellon Trust Company N.A. (successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank), as Trustee	4.10 to APS’s Registration Statement Nos. 333-15379 and 333-27551 by means of January 13, 1998 Form 8-K Report, File No. 1-4473	1-16-98

4.6c	Pinnacle West APS	Seventh Supplemental Indenture dated as of May 1, 2003	4.1 to APS’s Registration Statement No. 333-90824 by means of May 7, 2003 Form 8-K Report, File No. 1-4473	5-9-03

181

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

4.6d	Pinnacle West APS	Eighth Supplemental Indenture dated as of June 15, 2004	4.1 to APS’s Registration Statement No. 333-106772 by means of June 24, 2004 Form 8-K Report, File No. 1-4473	6-28-04

4.6e	Pinnacle West APS	Ninth Supplemental Indenture dated as of August 15, 2005	4.1 to APS’s Registration Statements Nos. 333-106772 and 333-121512 by means of August 17, 2005 Form 8-K Report, File No. 1-4473	8-22-05

4.6f	APS	Tenth Supplemental Indenture dated as of August 1, 2006	4.1 to APS’s July 31, 2006 Form 8-K Report, File No. 1-4473	8-3-06

4.6g	Pinnacle West APS	Eleventh Supplemental Indenture dated as of February 26, 2009	4.1 to Pinnacle West/APS February 23, 2009 Form 8-K Report, File Nos. 1-8962 and 1-4473	2-25-09

4.6h	Pinnacle West APS	Twelfth Supplemental Indenture dated as of August 25, 2011	4.1 to Pinnacle West/APS August 22, 2011 Form 8-K Report, File Nos. 1-8962 and 1-4473	8-24-11

4.6i	Pinnacle West APS	Thirteenth Supplemental Indenture dated as of January 13, 2012	4.1 to Pinnacle West/APS January 10, 2012 Form 8-K Report, File Nos. 1-8962 and 1-4473	1-12-12

4.7	Pinnacle West	Second Amended and Restated Pinnacle West Capital Corporation Investors Advantage Plan dated as of June 23, 2004	4.4 to Pinnacle West’s June 23, 2004 Form 8-K Report, File No. 1-8962	8-9-04

182

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

4.7a	Pinnacle West	Third Amended and Restated Pinnacle West Capital Corporation Investors Advantage Plan dated as of November 25, 2008	4.1 to Pinnacle West’s Form S-3 Registration Statement No. 333-155641, File No. 1-8962	11-25-08

4.8	Pinnacle West	Agreement, dated March 29, 1988, relating to the filing of instruments defining the rights of holders of long-term debt not in excess of 10% of the Company’s total assets	4.1 to Pinnacle West’s 1987 Form 10-K Report, File No. 1-8962	3-30-88

4.8a	Pinnacle West APS	Agreement, dated March 21, 1994, relating to the filing of instruments defining the rights of holders of APS long-term debt not in excess of 10% of APS’s total assets	4.1 to APS’s 1993 Form 10-K Report, File No. 1-4473	3-30-94

10.1.1	Pinnacle West APS	Two separate Decommissioning Trust Agreements (relating to PVNGS Units 1 and 3, respectively), each dated July 1, 1991, between APS and Mellon Bank, N.A., as Decommissioning Trustee	10.2 to APS’s September 30, 1991 Form 10-Q Report, File No. 1-4473	11-14-91

10.1.1a	Pinnacle West APS	Amendment No. 1 to Decommissioning Trust Agreement (PVNGS Unit 1), dated as of December 1, 1994	10.1 to APS’s 1994 Form 10-K Report, File No. 1-4473	3-30-95

183

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.1.1b	Pinnacle West APS	Amendment No. 1 to Decommissioning Trust Agreement (PVNGS Unit 3), dated as of December 1, 1994	10.2 to APS’s 1994 Form 10-K Report, File No. 1-4473	3-30-95

10.1.1c	Pinnacle West APS	Amendment No. 2 to APS Decommissioning Trust Agreement (PVNGS Unit 1) dated as of July 1, 1991	10.4 to APS’s 1996 Form 10-K Report , File No. 1-4473	3-28-97

10.1.1d	Pinnacle West APS	Amendment No. 2 to APS Decommissioning Trust Agreement (PVNGS Unit 3) dated as of July 1, 1991	10.6 to APS’s 1996 Form 10-K Report, File No. 1-4473	3-28-97

10.1.1e	Pinnacle West APS	Amendment No. 3 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of March 18, 2002	10.2 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962	5-15-02

10.1.1f	Pinnacle West APS	Amendment No. 3 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of March 18, 2002	10.4 to Pinnacle West’s March 2002 Form 10-Q Report, File No. 1-8962	5-15-02

10.1.1g	Pinnacle West APS	Amendment No. 4 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of December 19, 2003	10.3 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	3-15-04

10.1.1h	Pinnacle West APS	Amendment No. 4 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of December 19, 2003	10.5 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	3-15-04

184

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.1.1i	Pinnacle West APS	Amendment No. 5 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of May 1, 2007	10.1 to Pinnacle West/APS March 31, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473	5-9-07

10.1.1j	Pinnacle West APS	Amendment No. 5 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of May 1, 2007	10.2 to Pinnacle West/APS March 31, 2007 Form 10-Q Report, File Nos. 1-8962 and 104473	5-9-07

10.1.2	Pinnacle West APS	Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992, among APS, Mellon Bank, N.A., as Decommissioning Trustee, and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee under two separate Trust Agreements, each with a separate Equity Participant, and as Lessor under two separate Facility Leases, each relating to an undivided interest in PVNGS Unit 2	10.1 to Pinnacle West’s 1991 Form 10-K Report, File No. 1-8962	3-26-92

10.1.2a	Pinnacle West APS	First Amendment to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1992	10.2 to APS’s 1992 Form 10-K Report, File No. 1-4473	3-30-93

185

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.1.2b	Pinnacle West APS	Amendment No. 2 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1994	10.3 to APS’s 1994 Form 10-K Report, File No. 1-4473	3-30-95

10.1.2c	Pinnacle West APS	Amendment No. 3 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of June 20, 1996	10.1 to APS’s June 30, 1996 Form 10-Q Report, File No. 1-4473	8-9-96

10.1.2d	Pinnacle West APS	Amendment No. 4 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of December 16, 1996	APS 10.5 to APS’s 1996 Form 10-K Report, File No. 1-4473	3-28-97

10.1.2e	Pinnacle West APS	Amendment No. 5 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of June 30, 2000	10.1 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962	5-15-02

10.1.2f	Pinnacle West APS	Amendment No. 6 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of March 18, 2002	10.3 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962	5-15-02

10.1.2g	Pinnacle West APS	Amendment No. 7 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of December 19, 2003	10.4 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	3-15-04

186

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.1.2h	Pinnacle West APS	Amendment No. 8 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of April 1, 2007	10.1.2h to Pinnacle West’s 2007 Form 10-K Report, File No. 1-8962	2-27-08

10.2.1 b	Pinnacle West APS	Arizona Public Service Company Deferred Compensation Plan, as restated, effective January 1, 1984, and the second and third amendments thereto, dated December 22, 1986, and December 23, 1987, respectively	10.4 to APS’s 1988 Form 10-K Report, File No. 1-4473	3-8-89

10.2.1a b	Pinnacle West APS	Third Amendment to the Arizona Public Service Company Deferred Compensation Plan, effective as of January 1, 1993	10.3A to APS’s 1993 Form 10-K Report, File No. 1-4473	3-30-94

10.2.1b b	Pinnacle West APS	Fourth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective as of May 1, 1993	10.2 to APS’s September 30, 1994 Form 10-Q Report, File No. 1-4473	11-10-94

10.2.1c b	Pinnacle West APS	Fifth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective January 1, 1997	10.3A to APS’s 1996 Form 10-K Report, File No. 1-4473	3-28-97

187

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.2.1d b	Pinnacle West APS	Sixth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective January 1, 2001	10.8A to Pinnacle West’s 2000 Form 10-K Report, File No. 1-8962	3-14-01

10.2.2 b	Pinnacle West APS	Arizona Public Service Company Directors’ Deferred Compensation Plan, as restated, effective January 1, 1986	10.1 to APS’s June 30, 1986 Form 10-Q Report, File No. 1-4473	8-13-86

10.2.2a b	Pinnacle West APS	Second Amendment to the Arizona Public Service Company Directors’ Deferred Compensation Plan, effective as of January 1, 1993	10.2A to APS’s 1993 Form 10-K Report, File No. 1-4473	3-30-94

10.2.2b b	Pinnacle West APS	Third Amendment to the Arizona Public Service Company Directors’ Deferred Compensation Plan, effective as of May 1, 1993	10.1 to APS’s September 30, 1994 Form 10-Q Report, File No. 1-4473	11-10-94

10.2.2c b	Pinnacle West APS	Fourth Amendment to the Arizona Public Service Company Directors Deferred Compensation Plan, effective as of January 1, 1999	10.8A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00

188

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.2.3 b	Pinnacle West APS	Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans dated August 1, 1996	10.14A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00

10.2.3a b	Pinnacle West APS	First Amendment dated December 7, 1999 to the Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans	10.15A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00

10.2.4 b	Pinnacle West APS	Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan as amended and restated effective January 1, 1996	10.10A to APS’s 1995 Form 10-K Report, File No. 1-4473	3-29-96

189

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.2.4a b	Pinnacle West APS	First Amendment effective as of January 1, 1999, to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	10.7A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00

10.2.4b b	Pinnacle West APS	Second Amendment effective January 1, 2000 to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	10.10A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00

10.2.4c b	Pinnacle West APS	Third Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan, effective as of January 1, 2002	10.3 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962	5-15-03

190

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.2.4d b	Pinnacle West APS	Fourth Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan, effective January 1, 2003	10.64 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06

10.2.5 b	Pinnacle West APS	Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates	10.2.6 to Pinnacle West/APS 2008 Form 10-K Report, File Nos. 1-8962 and 1-4473	2-20-09

10.2.5a b	Pinnacle West APS	First Amendment to the Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates	10.2.6a to Pinnacle West/APS 2009 Form 10-K Report, File Nos. 1-8962 and 1-4473	2-19-10

10.2.5b b	Pinnacle West APS	Second Amendment to the Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates	10.2.5b to Pinnacle West/APS 2011 Form 10-K Report, File Nos. 1-8962 and 1-4473	2-24-12

10.3.1 b	Pinnacle West APS	Pinnacle West Capital Corporation Supplement Excess Benefit Retirement Plan, amended and restated as of January 1, 2003	10.7A to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	3-15-04

191

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.3.1a b	Pinnacle West APS	Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan, as amended and restated, dated December 18, 2003	10.48b to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06

10.3.2 b	Pinnacle West APS	Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan of 2005	10.3.2 to Pinnacle West/APS 2008 Form 10-K Report, File Nos. 1-8962 and 1-4473	2-20-09

10.4.1 b	APS	Letter Agreement dated December 20, 2006 between APS and Randall K. Edington	10.78 to Pinnacle West/APS 2006 Form 10-K Report, File Nos. 1-8962 and 1-4473	2-28-07

10.4.2 b	APS	Letter Agreement dated July 22, 2008 between APS and Randall K. Edington	10.3 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-4473	8-07-08

10.4.3 b	Pinnacle West APS	Letter Agreement dated June 17, 2008 between Pinnacle West/APS and James R. Hatfield	10.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8-07-08

10.4.4 b	APS	Supplemental Agreement dated December 26, 2008 between APS and Randall K. Edington	10.4.10 to Pinnacle West/APS 2008 Form 10-K Report, File No. 1-4473	2-20-09

10.4.5 b	APS	Description of 2010 Palo Verde Specific Compensation Opportunity for Randall K. Edington	10.4.13 to Pinnacle West/APS 2009 Form 10-K Report, File Nos. 1-8962 and 1-4473	2-19-10

192

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.4.6 b	Pinnacle West	Letter Agreement dated May 21, 2009, between Pinnacle West Capital Corporation and David P. Falck	10.4 to Pinnacle West/APS March 31, 2010 Form 10-Q Report, File No. 1-8962	5-6-10

10.4.7 b	APS	Supplemental Agreement dated June 19, 2012 between APS and Randall K. Edington	10.1 to Pinnacle West/APS June 30, 2012 Form 10-Q Report File Nos. 1-8962 and 1-4473	8-2-12

10.4.8 b	APS	Description of 2013 Palo Verde Specific Compensation Opportunity for Randall K. Edington	Pinnacle West/APS December 24, 2012 Form 8-K Report, File No. 1-4473	12-26-12

10.5.1 bd	Pinnacle West APS	Key Executive Employment and Severance Agreement between Pinnacle West and certain executive officers of Pinnacle West and its subsidiaries	10.77 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06

10.5.1a bd	Pinnacle West APS	Form of Amended and Restated Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries	10.4 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473	11-6-07

10.5.2 bd	Pinnacle West APS	Form of Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries	10.3 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473	11-6-07

193

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.5.3 bd	Pinnacle West APS	Form of Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries	10.5.3 to Pinnacle West/APS 2009 Form 10-K Report, File Nos. 1-8962 and 1-4473	2-19-10

10.5.4 bd	Pinnacle West APS	Form of Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries

10.6.1 b	Pinnacle West APS	Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.5A to Pinnacle West’s 2002 Form 10-K Report	3-31-03

10.6.1a bd	Pinnacle West APS	Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.1 to Pinnacle West/APS December 9, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473	12-15-05

10.6.1b bd	Pinnacle West APS	Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.1 to Pinnacle West/APS December 31, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473	2-1-06

10.6.1c bd	Pinnacle West APS	Performance Accelerated Stock Option Agreement under Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.98 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05

194

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.6.1d bd	Pinnacle West APS	Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.91 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06

10.6.2 b	Pinnacle West	Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan	Appendix B to the Proxy Statement for Pinnacle West’s 2007 Annual Meeting of Shareholders, File No. 1-8962	4-20-07

10.6.2a b	Pinnacle West	First Amendment to the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan	10.2 to Pinnacle West/APS April 18, 2007 Form 8-K Report, File No. 1-8962	4-20-07

10.6.2b bd	Pinnacle West APS	Performance Share Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan	10.3 to Pinnacle West/APS March 31, 2009 Form 10-Q Report, File Nos. 1-8962 and 1-4473	5-5-09

10.6.2c bd	Pinnacle West	Form of Performance Share Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan	10.1 to Pinnacle West/APS June 30, 2010 Form 10-Q Report, File No. 1-8962	8-3-10

10.6.2d bd	Pinnacle West	Form of Restricted Stock Unit Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan	10.2 to Pinnacle West/APS June 30, 2010 Form 10-Q Report, File No. 1-8962	8-3-10

10.6.2e bd	Pinnacle West	Form of Performance Share Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan	10.4 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File No. 1-8962	4-29-11

195

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.6.2f bd	Pinnacle West	Form of Restricted Stock Unit Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan	10.5 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File No. 1-8962	4-29-11

10.6.2g bd	Pinnacle West	Form of Restricted Stock Unit Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan (Supplemental 2010 Award)	10.6 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File No. 1-8962	4-29-11

10.6.3 b	Pinnacle West	Description of Annual Stock Grants to Non-Employee Directors	10.1 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File No. 1-8962	11-6-07

10.6.4 b	Pinnacle West	Description of Stock Grant to W. Douglas Parker	10.2 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File No. 1-8962	11-6-07

10.6.5 b	Pinnacle West	Description of Annual Stock Grants to Non-Employee Directors	10.2 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-8962	8-07-08

10.6.6 bd	Pinnacle West APS	Summary of 2013 CEO Variable Incentive Plan and Officer Variable Incentive Plan

10.6.7	Pinnacle West	Description of Restricted Stock Unit Grant to Donald E. Brandt	Pinnacle West/APS December 24, 2012 Form 8-K Report, File No. 1-8962	12-26-12

10.6.8 b	Pinnacle West APS	Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan	Appendix A to the Proxy Statement for Pinnacle West’s 2012 Annual Meeting of Shareholders, File No. 1-8962	3-29-12

196

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.6.8a bd	Pinnacle West	Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan	10.1 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473	5-3-12

10.6.8b bd	Pinnacle West	Form of Restricted Stock Unit Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan	10.2 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473	5-3-12

10.6.8c bd	Pinnacle West	Master Amendment to Performance Share Agreements	10.3 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473	5-3-12

10.6.8d bd	Pinnacle West	Master Amendment to Restricted Stock Unit Agreements	10.4 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473	5-3-12

10.7.1	Pinnacle West APS	Indenture of Lease with Navajo Tribe of Indians, Four Corners Plant	5.01 to APS’s Form S-7 Registration Statement, File No. 2-59644	9-1-77

10.7.1a	Pinnacle West APS	Supplemental and Additional Indenture of Lease, including amendments and supplements to original lease with Navajo Tribe of Indians, Four Corners Plant	5.02 to APS’s Form S-7 Registration Statement, File No. 2-59644	9-1-77

197

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.7.1b	Pinnacle West APS	Amendment and Supplement No. 1 to Supplemental and Additional Indenture of Lease Four Corners, dated April 25, 1985	10.36 to Pinnacle West’s Registration Statement on Form 8-B Report, File No. 1-8962	7-25-85

10.7.1c	Pinnacle West APS	Amendment and Supplement No. 2 to Supplemental and Additional Indenture of Lease with the Navajo Nation dated March 7, 2011	10.1 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File Nos. 1-8962 and 1-4473	4-29-11

10.7.1d	Pinnacle West APS	Amendment and Supplement No. 3 to Supplemental and Additional Indenture of Lease with the Navajo Nation dated March 7, 2011	10.2 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File Nos. 1-8962 and 1-4473	4-29-11

10.7.2	Pinnacle West APS	Application and Grant of multi-party rights-of-way and easements, Four Corners Plant Site	5.04 to APS’s Form S-7 Registration Statement, File No. 2-59644	9-1-77

10.7.2a	Pinnacle West APS	Application and Amendment No. 1 to Grant of multi-party rights-of-way and easements, Four Corners Power Plant Site dated April 25, 1985	10.37 to Pinnacle West’s Registration Statement on Form 8-B, File No. 1-8962	7-25-85

10.7.3	Pinnacle West APS	Application and Grant of Arizona Public Service Company rights- of-way and easements, Four Corners Plant Site	5.05 to APS’s Form S-7 Registration Statement, File No. 2-59644	9-1-77

198

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.7.3a	Pinnacle West APS	Application and Amendment No. 1 to Grant of Arizona Public Service Company rights-of-way and easements, Four Corners Power Plant Site dated April 25, 1985	10.38 to Pinnacle West’s Registration Statement on Form 8-B, File No. 1-8962	7-25-85

10.7.4	Pinnacle West APS	Four Corners Project Co-Tenancy Agreement Amendment No. 6	10.7 to Pinnacle West’s 2000 Form 10-K Report, File No. 1-8962	3-14-01

10.8.1	Pinnacle West APS	Indenture of Lease, Navajo Units 1, 2, and 3	5(g) to APS’s Form S-7 Registration Statement, File No. 2-36505	3-23-70

10.8.2	Pinnacle West APS	Application of Grant of rights-of-way and easements, Navajo Plant	5(h) to APS Form S-7 Registration Statement, File No. 2-36505	3-23-70

10.8.3	Pinnacle West APS	Water Service Contract Assignment with the United States Department of Interior, Bureau of Reclamation, Navajo Plant	5(l) to APS’s Form S-7 Registration Statement, File No. 2-394442	3-16-71

199

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.8.4	Pinnacle West APS	Navajo Project Co-Tenancy Agreement dated as of March 23, 1976, and Supplement No. 1 thereto dated as of October 18, 1976, Amendment No. 1 dated as of July 5, 1988, and Amendment No. 2 dated as of June 14, 1996; Amendment No. 3 dated as of February 11, 1997; Amendment No. 4 dated as of January 21, 1997; Amendment No. 5 dated as of January 23, 1998; Amendment No. 6 dated as of July 31, 1998	10.107 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06

10.8.5	Pinnacle West APS	Navajo Project Participation Agreement dated as of September 30, 1969, and Amendment and Supplement No. 1 dated as of January 16, 1970, and Coordinating Committee Agreement No. 1 dated as of September 30, 1971	10.108 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06

200

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.9.1	Pinnacle West APS	Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles, and amendments 1-12 thereto	10. 1 to APS’s 1988 Form 10-K Report, File No. 1-4473	3-8-89

10.9.1a	Pinnacle West APS	Amendment No. 13, dated as of April 22, 1991, to Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles	10.1 to APS’s March 31, 1991 Form 10-Q Report, File No. 1-4473	5-15-91

201

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.9.1b	Pinnacle West APS	Amendment No. 14 to Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles	99.1 to Pinnacle West’s June 30, 2000 Form 10-Q Report, File No. 1-8962	8-14-00

10.9.1c	Pinnacle West APS	Amendment No. 15, dated November 29, 2010, to Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles	10.9.1c to Pinnacle West/APS 2010 Form 10-K Report, File Nos. 1-8962 and 1-4473	2-18-11

202

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.10.1	Pinnacle West APS	Asset Purchase and Power Exchange Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990 and as of July 18, 1991	10.1 to APS’s June 30, 1991 Form 10-Q Report, File No. 1-4473	8-8-91

10.10.2	Pinnacle West APS	Long-Term Power Transaction Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990, and as of July 8, 1991	10.2 to APS’s June 30, 1991 Form 10-Q Report, File No. 1-4473	8-8-91

10.10.2a	Pinnacle West APS	Amendment No. 1 dated April 5, 1995 to the Long-Term Power Transaction Agreement and Asset Purchase and Power Exchange Agreement between PacifiCorp and APS	10.3 to APS’s 1995 Form 10-K Report, File No. 1-4473	3-29-96

10.10.3	Pinnacle West APS	Restated Transmission Agreement between PacifiCorp and APS dated April 5, 1995	10.4 to APS’s 1995 Form 10-K Report, File No. 1-4473	3-29-96

10.10.4	Pinnacle West APS	Contract among PacifiCorp, APS and United States Department of Energy Western Area Power Administration, Salt Lake Area Integrated Projects for Firm Transmission Service dated May 5, 1995	10.5 to APS’s 1995 Form 10-K Report, File No. 1-4473	3-29-96

203

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.10.5	Pinnacle West APS	Reciprocal Transmission Service Agreement between APS and PacifiCorp dated as of March 2, 1994	10.6 to APS’s 1995 Form 10-K Report, File No. 1-4473	3-29-96

10.11.1	Pinnacle West APS	Five-Year Credit Agreement dated as of November 4, 2011 between APS, as Borrower, Barclays Bank PLC, as Agent, and the lenders and other parties thereto	10.11.1 to Pinnacle West/APS 2011 Form 10-K Report, File Nos. 1-8962 and 1-4473	2-24-12

10.11.2	Pinnacle West	Term Loan Agreement dated as of November 29, 2012 among Pinnacle West Capital Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Agent, and the lenders and other parties thereto

10.11.3	Pinnacle West	Five-Year Credit Agreement dated as of November 4, 2011 among Pinnacle West Capital Corporation, as Borrower, Barclays Bank PLC, as Agent, and the lenders and other parties thereto	10.11.3 to Pinnacle West/APS 2011 Form 10-K Report, File Nos. 1-8962 and 1-4473	2-24-12

204

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.11.4	APS	$500,000,000 Four-Year Credit Agreement dated as of February 14, 2011 among Arizona Public Service Company as Borrower, Barclays Bank PLC, as Agent and Issuing Bank, Credit Suisse Securities (USA) LLC, as Syndication Agent, Credit Suisse AG, Cayman Islands Branch, as Issuing Bank, Bank of America, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents and the other parties thereto	10.11.4 to Pinnacle West/APS 2010 Form 10-K Report, File Nos. 1-8962 and 1-4473	2-18-11

10.11.5	Pinnacle West APS	Reimbursement Agreement among APS, the Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, dated as of April 16, 2010	10.2 to Pinnacle West/APS March 31, 2010 Form 10-Q Report, File Nos. 1-8962 and 1-4473	5-6-10

10.11.5a	Pinnacle West APS	Amendment No. 1 to the Reimbursement Agreement among APS, the Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, dated December 22, 2011	10.11.5a to Pinnacle West/APS 2011 Form 10-K Report, File Nos. 1-8962 and 1-4473	2-24-12

205

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.11.6	Pinnacle West APS	Reimbursement Agreement among APS, the Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, dated as of April 16, 2010	10.3 to Pinnacle West/APS March 31, 2010 Form 10-Q Report, File Nos. 1-8962 and 1-4473	5-6-10

10.11.6a	Pinnacle West APS	Amendment No. 1 to the Reimbursement Agreement among APS, the Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, dated December 22, 2011	10.11.6a to Pinnacle West/APS 2011 Form 10-K Report, File Nos. 1-8962 and 1-4473	2-24-12

10.12.1 c	Pinnacle West APS	Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee	4.3 to APS’s Form 18 Registration Statement, File No. 33-9480	10-24-86

206

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.12.1a c	Pinnacle West APS	Amendment No. 1, dated as of November 1, 1986, to Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee	10.5 to APS’s September 30, 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473	12-4-86

10.12.1b c	Pinnacle West APS	Amendment No. 2 dated as of June 1, 1987 to Facility Lease dated as of August 1, 1986 between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee	10.3 to APS’s 1988 Form 10-K Report, File No. 1-4473	3-8-89

10.12.1c c	Pinnacle West APS	Amendment No. 3, dated as of March 17, 1993, to Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee	10.3 to APS’s 1992 Form 10-K Report, File No. 1-4473	3-30-93

207

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.12.2	Pinnacle West APS	Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee	10.1 to APS’s November 18, 1986 Form 8-K Report, File No. 1-4473	1-20-87

10.12.2a	Pinnacle West APS	Amendment No. 1, dated as of August 1, 1987, to Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee	4.13 to APS’s Form 18 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report, File No. 1-4473	8-24-87

10.12.2b	Pinnacle West APS	Amendment No. 2, dated as of March 17, 1993, to Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee	10.4 to APS’s 1992 Form 10-K Report, File No. 1-4473	3-30-93

208

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.13.1	Pinnacle West APS	Agreement between Pinnacle West Energy Corporation and Arizona Public Service Company for Transportation and Treatment of Effluent by and between Pinnacle West Energy Corporation and APS dated as of the 10 th day of April, 2001	10.102 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05

10.13.2	Pinnacle West APS	Agreement for the Transfer and Use of Wastewater and Effluent by and between APS, SRP and PWE dated June 1, 2001	10.103 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05

10.13.3	Pinnacle West APS	Agreement for the Sale and Purchase of Wastewater Effluent dated November 13, 2000, by and between the City of Tolleson, Arizona, APS and SRP	10.104 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05

10.13.4	Pinnacle West APS	Operating Agreement for the Co-Ownership of Wastewater Effluent dated November 16, 2000 by and between APS and SRP	10.105 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05

209

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.13.5	Pinnacle West APS	Municipal Effluent Purchase and Sale Agreement dated April 29, 2010, by and between City of Phoenix, City of Mesa, City of Tempe, City of Scottsdale, City of Glendale, APS and Salt River Project Agricultural Improvement and Power District	10.1 to Pinnacle West/APS March 31, 2010 Form 10-Q Report, File Nos. 1-8962 and 1-4473	5-6-10

10.14.1	Pinnacle West APS	Contract, dated July 21, 1984, with DOE providing for the disposal of nuclear fuel and/or high-level radioactive waste, ANPP	10.31 to Pinnacle West’s Form S-14 Registration Statement, File No. 2-96386	3-13-85

10.15.1	Pinnacle West APS	Territorial Agreement between APS and Salt River Project	10.1 to APS’s March 31, 1998 Form 10-Q Report, File No. 1-4473	5-15-98

10.15.2	Pinnacle West APS	Power Coordination Agreement between APS and Salt River Project	10.2 to APS’s March 31, 1998 Form 10-Q Report, File No. 1-4473	5-15-98

10.15.3	Pinnacle West APS	Memorandum of Agreement between APS and Salt River Project	10.3 to APS’s March 31, 1998 Form 10-Q Report, File No. 1-4473	5-15-98

10.15.3a	Pinnacle West APS	Addendum to Memorandum of Agreement between APS and Salt River Project dated as of May 19, 1998	10.2 to APS’s May 19, 1998 Form 8-K Report, File No. 1-4473	6-26-98

210

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

10.16	Pinnacle West APS	Purchase and Sale Agreement dated November 8, 2010 by and between Southern California Edison Company and APS	10.1 to Pinnacle West/APS November 8, 2010 Form 8-K Report, File Nos. 1-8962 and 1-4473	11-8-10

10.17	Pinnacle West APS	Proposed Settlement Agreement dated January 6, 2012 by and among APS and certain parties to its retail rate case (approved by ACC Order No. 73183)	10.17 to Pinnacle West/APS 2011 Form 10-K Report, File Nos. 1-8962 and 1-4473	2-24-12

12.1	Pinnacle West	Ratio of Earnings to Fixed Charges

12.2	APS	Ratio of Earnings to Fixed Charges

12.3	Pinnacle West	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements

21.1	Pinnacle West	Subsidiaries of Pinnacle West

23.1	Pinnacle West	Consent of Deloitte & Touche LLP

23.2	APS	Consent of Deloitte & Touche LLP

211

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

31.1	Pinnacle West	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.2	Pinnacle West	Certificate of James R. Hatfield, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.3	APS	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.4	APS	Certificate of James R. Hatfield, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

32.1 e	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

212

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

32.2 e	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

99.1	Pinnacle West APS	Collateral Trust Indenture among PVNGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee	4.2 to APS’s 1992 Form 10-K Report, File No. 1-4473	3-30-93

99.1a	Pinnacle West APS	Supplemental Indenture to Collateral Trust Indenture among PVNGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee	4.3 to APS’s 1992 Form 10-K Report, File No. 1-4473	3-30-93

213

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

99.2 c	Pinnacle West APS	Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein	28.1 to APS’s September 30, 1992 Form 10-Q Report, File No. 1-4473	11-9-92

214

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

99.2a c	Pinnacle West APS	Amendment No. 1 dated as of November 1, 1986, to Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein	10.8 to APS’s September 30, 1986 Form 10-Q Report by means of Amendment No. 1, on December 3, 1986 Form 8, File No. 1-4473	12-4-86

99.2b c	Pinnacle West APS	Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein	28.4 to APS’s 1992 Form 10-K Report, File No. 1-4473	3-30-93

215

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

99.3 c	Pinnacle West APS	Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	4.5 to APS’s Form 18 Registration Statement, File No. 33-9480	10-24-86

99.3a c	Pinnacle West APS	Supplemental Indenture No. 1, dated as of November 1, 1986 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	10.6 to APS’s September 30, 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473	12-4-86

216

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

99.3b c	Pinnacle West APS	Supplemental Indenture No. 2 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Lease Indenture Trustee	4.4 to APS’s 1992 Form 10-K Report, File No. 1-4473	3-30-93

99.4 c	Pinnacle West APS	Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	28.3 to APS’s Form 18 Registration Statement, File No. 33-9480	10-24-86

99.4a c	Pinnacle West APS	Amendment No. 1, dated as of November 1, 1986, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	10.10 to APS’s September 30, 1986 Form 10-Q Report by means of Amendment No. l on December 3, 1986 Form 8, File No. 1-4473	12-4-86

217

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

99.4b c	Pinnacle West APS	Amendment No. 2, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	28.6 to APS’s 1992 Form 10-K Report, File No. 1-4473	3-30-93

99.5	Pinnacle West APS	Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Report Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee under a Trust Indenture, APS, and the Owner Participant named therein	28.2 to APS’s September 30, 1992 Form 10-Q Report, File No. 1-4473	11-9-92

218

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

99.5 a	Pinnacle West APS	Amendment No. 1, dated as of August 1, 1987, to Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Corp., Inc. as Funding Corporation, State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, Chemical Bank, as Indenture Trustee, APS, and the Owner Participant named therein	28.20 to APS’s Form 18 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report, File No. 1-4473	8-10-87

99.5 b	Pinnacle West APS	Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Owner Participant named therein	28.5 to APS’s 1992 Form 10-K Report, File No. 1-4473	3-30-93

219

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

99.6	Pinnacle West APS	Trust Indenture, Mortgage Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	10.2 to APS’s November 18, 1986 Form 10-K Report, File No. 1-4473	1-20-87

99.6 a	Pinnacle West APS	Supplemental Indenture No. 1, dated as of August 1, 1987, to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	4.13 to APS’s Form 18 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report, File No. 1-4473	8-24-87

220

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

99.6 b	Pinnacle West APS	Supplemental Indenture No. 2 to Trust Indenture Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Lease Indenture Trustee	4.5 to APS’s 1992 Form 10-K Report, File No. 1-4473	3-30-93

99.7	Pinnacle West APS	Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	10.5 to APS’s November 18, 1986 Form 8-K Report, File No. 1-4473	1-20-87

99.7 a	Pinnacle West APS	Amendment No. 1, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	28.7 to APS’s 1992 Form 10-K Report, File No. 1-4473	3-30-93

221

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

99.8 c	Pinnacle West APS	Indemnity Agreement dated as of March 17, 1993 by APS	28.3 to APS’s 1992 Form 10-K Report, File No. 1-4473	3-30-93

99.9	Pinnacle West APS	Extension Letter, dated as of August 13, 1987, from the signatories of the Participation Agreement to Chemical Bank	28.20 to APS’s Form 18 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report, File No. 1-4473	8-10-87

99.10	Pinnacle West APS	Arizona Corporation Commission Order, Decision No. 61969, dated September 29, 1999, including the Retail Electric Competition Rules	10.2 to APS’s September 30, 1999 Form 10-Q Report, File No. 1-4473	11-15-99

99.11	Pinnacle West	Purchase Agreement by and among Pinnacle West Energy Corporation and GenWest, L.L.C. and Nevada Power Company, dated June 21, 2005	99.5 to Pinnacle West/APS June 30, 2005 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8-9-05

101.INS e	Pinnacle West APS	XBRL Instance Document

101.SCH e	Pinnacle West APS	XBRL Taxonomy Extension Schema Document

101.CAL e	Pinnacle West APS	XBRL Taxonomy Extension Calculation Linkbase Document

222

Table of Contents

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed

101.LAB e	Pinnacle West APS	XBRL Taxonomy Extension Label Linkbase Document

101.PRE e	Pinnacle West APS	XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF e	Pinnacle West APS	XBRL Taxonomy Definition Linkbase Document

a Reports filed under File No. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.

b Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 15(b) of Form 10-K.

c An additional document, substantially identical in all material respects to this Exhibit, has been entered into, relating to an additional Equity Participant. Although such additional document may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates of execution), there are no material details in which such document differs from this Exhibit.

d Additional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional persons. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit.

e Furnished herewith as an Exhibit.

223

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	PINNACLE WEST CAPITAL CORPORATION
	(Registrant)


Date: February 22, 2013	/s/ Donald E. Brandt
	(Donald E. Brandt, Chairman of the Board of Directors, President and Chief Executive Officer)

Power of Attorney

We, the undersigned directors and executive officers of Pinnacle West Capital Corporation, hereby severally appoint James R. Hatfield and David P. Falck, and each of them, our true and lawful attorneys with full power to them and each of them to sign for us, and in our names in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date


/s/ Donald E. Brandt	Principal Executive Officer and Director	February 22, 2013
(Donald E. Brandt, Chairman	Principal Executive Officer and Director
of the Board of Directors, President
and Chief Executive Officer)


/s/ James R. Hatfield	Principal Financial Officer	February 22, 2013
(James R. Hatfield,
Executive Vice President and
Chief Financial Officer)

/s/ Denise R. Danner	Principal Accounting Officer	February 22, 2013
(Denise R. Danner,
Vice President, Controller and
Chief Accounting Officer)

224

Table of Contents

/s/ Edward N. Basha, Jr.	Director	February 22, 2013
(Edward N. Basha, Jr.)


/s/ Susan Clark-Johnson	Director	February 22, 2013
(Susan Clark-Johnson)


/s/ Denis A. Cortese	Director	February 22, 2013
(Denis A. Cortese)


/s/ Michael L. Gallagher	Director	February 22, 2013
(Michael L. Gallagher)


/s/ Roy A. Herberger, Jr.	Director	February 22, 2013
(Roy A. Herberger, Jr.)


/s/ Dale E. Klein	Director	February 22, 2013
(Dale E. Klein)


/s/ Humberto S. Lopez	Director	February 22, 2013
(Humberto S. Lopez)


/s/ Kathryn L. Munro	Director	February 22, 2013
(Kathryn L. Munro)


/s/ Bruce J. Nordstrom	Director	February 22, 2013
(Bruce J. Nordstrom)

225

Table of Contents

SIGNATURES

	ARIZONA PUBLIC SERVICE COMPANY
	(Registrant)


Date: February 22, 2013	/s/ Donald E. Brandt
	(Donald E. Brandt, Chairman of the Board of Directors and Chief Executive Officer)

Power of Attorney

We, the undersigned directors and executive officers of Arizona Public Service Company, hereby severally appoint James R. Hatfield and David P. Falck, and each of them, our true and lawful attorneys with full power to them and each of them to sign for us, and in our names in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission.

Signature	Title	Date


/s/ Donald E. Brandt	Principal Executive Officer	February 22, 2013
(Donald E. Brandt, Chairman	and Director
of the Board of Directors and
Chief Executive Officer)


/s/ James R. Hatfield	Principal Financial Officer	February 22, 2013
(James R. Hatfield,
Executive Vice President and
Chief Financial Officer)

/s/ Denise R. Danner	Principal Accounting Officer	February 22, 2013
(Denise R. Danner,
Vice President, Controller and
Chief Accounting Officer)

226

Table of Contents

/s/ Edward N. Basha, Jr.	Director	February 22, 2013
(Edward N. Basha, Jr.)


/s/ Susan Clark-Johnson	Director	February 22, 2013
(Susan Clark-Johnson)


/s/ Denis A. Cortese	Director	February 22, 2013
(Denis A. Cortese)


/s/ Michael L. Gallagher	Director	February 22, 2013
(Michael L. Gallagher)


/s/ Roy A. Herberger, Jr.	Director	February 22, 2013
(Roy A. Herberger, Jr.)


/s/ Dale E. Klein	Director	February 22, 2013
(Dale E. Klein)


/s/ Humberto S. Lopez	Director	February 22, 2013
(Humberto S. Lopez)


/s/ Kathryn L. Munro	Director	February 22, 2013
(Kathryn L. Munro)


/s/ Bruce J. Nordstrom	Director	February 22, 2013
(Bruce J. Nordstrom)

227

ARTICLE I	DEFINITIONS AND ACCOUNTING TERMS	1

Section 1.01	Certain Defined Terms	1
Section 1.02	Other Interpretive Provisions	14
Section 1.03	Accounting Terms	14
Section 1.04	Rounding	15
Section 1.05	Times of Day	15

ARTICLE II	AMOUNTS AND TERMS OF THE LOANS	15

Section 2.01	The Loans	15
Section 2.02	Making the Loans	15
Section 2.03	Agent’s Fees	17
Section 2.04	Repayment of Loans	17
Section 2.05	Interest on Loans	17
Section 2.06	Interest Rate Determination	18
Section 2.07	Optional Conversion of Loans	19
Section 2.08	Prepayments of Loans	19
Section 2.09	Increased Costs	20
Section 2.10	Illegality	21
Section 2.11	Payments and Computations	21
Section 2.12	Taxes	22
Section 2.13	Sharing of Payments, Etc.	26
Section 2.14	Evidence of Debt	27
Section 2.15	Use of Proceeds	28
Section 2.16	Affected Lenders	28
Section 2.17	Replacement of Lenders	28

ARTICLE III	CONDITIONS PRECEDENT	29

Section 3.01	Conditions Precedent to Effectiveness	29
Section 3.02	Determinations Under Section 3.01	30

ARTICLE IV	REPRESENTATIONS AND WARRANTIES	31

Section 4.01	Representations and Warranties of the Borrower	31

ARTICLE V	COVENANTS OF THE BORROWER	34

Section 5.01	Affirmative Covenants	34
Section 5.02	Negative Covenants	37
Section 5.03	Financial Covenant	38

ARTICLE VI	EVENTS OF DEFAULT	38

Section 6.01	Events of Default	38

ARTICLE VII	THE AGENT	40

Section 7.01	Appointment and Authority	40
Section 7.02	Rights as a Lender	41
Section 7.03	Exculpatory Provisions	41
Section 7.04	Reliance by Agent	42
Section 7.05	Delegation of Duties	42
Section 7.06	Resignation of Agent	42
Section 7.07	Non-Reliance on Agent and Other Lenders	43
Section 7.08	No Other Duties, Etc.	43

ARTICLE VIII	MISCELLANEOUS	43

Section 8.01	Amendments, Etc.	43
Section 8.02	Notices, Etc.	44
Section 8.03	No Waiver; Cumulative Remedies; Enforcement	46
Section 8.04	Costs and Expenses; Indemnity; Damage Waiver	46
Section 8.05	Right of Set-off	48
Section 8.06	Effectiveness; Binding Effect	48
Section 8.07	Successors and Assigns	49
Section 8.08	Confidentiality	52
Section 8.09	Governing Law	53
Section 8.10	Counterparts; Integration	53
Section 8.11	Jurisdiction, Etc.	53
Section 8.12	Payments Set Aside	53
Section 8.13	Patriot Act	54
Section 8.14	Waiver of Jury Trial	54
Section 8.15	No Advisory or Fiduciary Responsibility	54
Section 8.16	Survival of Representations and Warranties	55
Section 8.17	Severability	55

Schedules

Schedule 1.01	Commitments and Ratable Shares
Schedule 4.01(j)	Subsidiaries
Schedule 4.01(k)	Existing Indebtedness
Schedule 8.02	Certain Addresses for Notices

Exhibits

Exhibit A	Form of Note
Exhibit B	Form of Notice of Initial Borrowing
Exhibit C	Form of Assignment and Assumption
Exhibit D	Form of Interest Election Request

Public Debt Rating S&P/Moody’s	Base Rate Loan		Eurodollar Rate Loan
Level 1 > A-/A3	0.000	%	0.875	%
Level 2 < Level 1 but > BBB+/Baa1	0.000	%	1.000	%
Level 3 < Level 2 but > BBB/Baa2	0.100	%	1.100	%
Level 4 < Level 3 but > BBB-/Baa3	0.250	%	1.250	%
Level 5 < Level 4	0.500	%	1.500	%

PINNACLE WEST CAPITAL CORPORATION


By:	/s/ Lee R. Nickloy

	Name:	Lee R. Nickloy
	Title:	Vice President and Treasurer

ADMINISTRATIVE AGENT:	JPMORGAN CHASE BANK, N.A., as Agent


	By:	/s/ Nancy R. Barwig

		Name:	Nancy R. Barwig
		Title:	Credit Executive

LENDERS:	JPMORGAN CHASE BANK, N.A., as a Lender


	By:	/s/ Nancy R. Barwig

		Name:	Nancy R. Barwig
		Title:	Credit Executive

SUNTRUST BANK, as a Lender


By:	/s/ Andrew Johnson

	Name:	Andrew Johnson
	Title:	Director

U.S. BANK NATIONAL ASSOCIATION, as a Lender


By:	/s/ Holland H. Williams

	Name:	Holland H. Williams
	Title:	AVP & Portfolio Manager

UMB BANK ARIZONA, N.A., as a Lender


By:	/s/ James S. Patterson, Jr.

	Name:	James S. Patterson, Jr.
	Title:	Chief Executive Officer

NATIONAL BANK OF ARIZONA, as a Lender


By:	/s/ Gary J. Naquin

	Name:	Gary J. Naquin
	Title:	Senior Vice President

Lender	Commitment		Ratable Share

JPMorgan Chase Bank, N.A.	$	50,000,000.00	40.00	%

SunTrust Bank	$	25,000,000.00	20.00	%

U.S. Bank National Association	$	25,000,000.00	20.00	%

UMB Bank Arizona, N.A.	$	15,000,000.00	12.00	%

National Bank of Arizona	$	10,000,000.00	8.00	%

TOTAL	$	125,000,000.00	100.00	%

BORROWER:

	Pinnacle West Capital Corporation
	400 North Fifth Street
	Mail Station 9040
	Phoenix, AZ 85004
	Attention:	Treasurer
	Telephone:	(602) 250-3300
	Telecopier:	(602) 250-3902
	Electronic	Lee.Nickloy@PinnacleWest.com

AGENT :

Notices relating to Borrowing requests or Interest Election Requests:

	JPMorgan Chase Bank, N.A.
	10 S. Dearborn St.
	Mail Code IL1-0010
	Chicago, IL 60603
	Facsimile No.: (888) 292-9533
	Telephone No.: (312) 385-7080
	Attention: Darren Cunningham
	Email: darren.cunningham@jpmchase.com

Notices other than with respect to Borrowing requests or Interest Election Requests:

	JPMorgan Chase Bank, N.A.
	10 S. Dearborn St.
	Mail Code IL1-0090
	Chicago, IL 60603
	Facsimile No.: (312) 732-1762
	Telephone No.: (312) 732-1838
	Attention: Nancy Barwig
	Email: nancy.r.barwig@jpmorgan.com

With a copy to the Portfolio Management Administration:

	JPMorgan Chase Bank, N.A.
	10 S. Dearborn St.
	Mail Code IL1-0874
	Chicago, IL 60603
	Facsimile No.: (312) 325-3150
	Telephone No.: (312) 325-3238
	Attention: Lisa Tverdek
	Email: lisa.tverdek@jpmorgan.com

1) GenWest, LLC	} now under PWCC
2) APACS Holdings, LLC	} now under PWCC

	/s/ Donald E. Brandt
	Donald E. Brandt
	Chairman, President and
	Chief Executive Officer

	/s/ Donald E. Brandt
	Donald E. Brandt
	Chairman and Chief Executive Officer