10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2013

OR

oTRANSITION 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.x

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	Smaller reporting company o
(Do not check if a smaller reporting company)

ARIZONA PUBLIC SERVICE COMPANY
Large accelerated filer o	Accelerated filer o
Non-accelerated filer x	Smaller reporting company o
(Do not check if a smaller reporting company)

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	$6,078,967,225 as of June 30, 2013
ARIZONA PUBLIC SERVICE COMPANY	$0 as of June 30, 2013

The number of shares outstanding of each registrant’s common stock as of February 14, 2014

PINNACLE WEST CAPITAL CORPORATION	110,194,366 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 21, 2014 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.

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	42
Item 4.	Mine Safety Disclosures	42
Executive Officers of Pinnacle West		43
PART II		45
Item 5.	Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	45
Item 6.	Selected Financial Data	47
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	75
Item 8.	Financial Statements and Supplementary Data	76
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		222

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	BHP Navajo Coal Company
Cholla	Cholla Power Plant
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
El Paso	El Paso Electric 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
NTEC	Navajo Transitional Energy Company, LLC
OCI	Other comprehensive income
Palo Verde	Palo Verde Nuclear Generating Station or PVNGS
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
TCA	Transmission cost adjustor
VIE	Variable interest entity
West Phoenix	West Phoenix Power Plant

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;

·competition in retail and wholesale power markets;

·regulatory and judicial decisions, developments and proceedings;

·new legislation or regulation, including those relating to environmental requirements, nuclear plant operations and potential deregulation of retail electric markets;

·fuel and water supply availability;

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

·our ability to meet renewable energy and energy efficiency mandates and recover related costs;

·risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty;

·current and future economic conditions in Arizona, particularly in real estate markets;

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

·environmental and other concerns surrounding coal-fired generation;

·volatile fuel and purchased power costs;

·the investment performance of the assets of our nuclear decommissioning trust, pension, and other postretirement benefit plans and the resulting impact on future funding requirements;

·the liquidity of wholesale power markets and the use of derivative contracts in our business;

·potential shortfalls in insurance coverage;

·new accounting requirements or new interpretations of existing requirements;

·generation, transmission and distribution facility and system conditions and operating costs;

·the ability to meet the anticipated future need for additional baseload generation and associated transmission facilities in our region;

·the willingness or ability of our counterparties, power plant participants and power plant land owners to meet contractual or other obligations or extend the rights for continued power plant operations;

·technological developments affecting the electric industry; and

·restrictions on dividends or other provisions in our credit agreements and ACC orders.

These and other factors are discussed in 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 operating subsidiary is El Dorado.  Additional information related to this business 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 1.2 million customers.  We own or lease 6,394 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 2013, no single purchaser or user of energy accounted for more than 1.1% 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 2013 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 63% of Four Corners Units 4 and 5 following the acquisition of SCE’s interest in Units 4 and 5 described below.  As of December 30, 2013, APS retired Units 1, 2 and 3.  APS has a total entitlement from Four Corners of 970 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, allowing APS to acquire 739 MW from SCE.  On December 30, 2013, APS and SCE closed this transaction.  The final purchase price for SCE’s interest was approximately $182 million, subject to certain minor post-closing adjustments.

In connection with APS’s most recent retail rate case with the ACC, the ACC reserved the right to review the prudence of the Four Corners transaction for cost recovery purposes upon the closing of the transaction.  On December 30, 2013, APS filed an application with the ACC to request rate adjustments prior to its next general rate case related to APS’s acquisition of SCE’s interest in Four Corners.  If approved, these would result in an average bill impact to residential customers of approximately 2%.  APS cannot predict the outcome of this request.

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Concurrently with the closing of the SCE transaction, BHP Billiton, the parent company of BNCC, the coal supplier and operator of the mine that serves Four Corners, transferred its ownership of BNCC to NTEC, a company formed by the Navajo Nation to own the mine and develop other energy projects.  BHP Billiton will be retained by NTEC under contract as the mine manager and operator until July 2016.  Also occurring concurrently with the closing, the Four Corners’ co-owners executed a long-term agreement for the supply of coal to Four Corners from July 2016, when the current coal supply agreement expires, through 2031 (the “2016 Coal Supply Agreement”).  El Paso, a 7% owner in Units 4 and 5 of Four Corners, did not sign the 2016 Coal Supply Agreement.  Under the 2016 Coal Supply Agreement, APS has agreed to assume the 7% shortfall obligation.  When APS ultimately acquires a right to EPE’s interest in Four Corners, by agreement or operation of law, NTEC will have an option to purchase the interest within a certain timeframe pursuant to an option granted by APS to NTEC.  The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% shortfall obligations in the event NTEC does not exercise its option.

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 are pursuing.  A federal environmental review is underway as part of the DOI review process.  APS will also require a Prevention of Significant Deterioration (“PSD”) permit from EPA to install selective catalytic reduction (“SCR”) control technology at Four Corners, as described below under “Environmental Matters — EPA Environmental Regulation.”  APS cannot predict whether these federal approvals will be granted, and if so on a timely basis, or whether any conditions that may be attached to them will be acceptable to the Four Corners owners.

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 and state governments and private landholders.  The Cholla coal contract runs through 2024.  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 Tribe.  The Navajo Plant is under contract with its coal supplier through 2019, with extension rights through 2026.  The Navajo Plant site is leased from the Navajo Nation and is also subject to an easement from the federal government.  The current lease expires in 2019.

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.

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Nuclear

Palo Verde Nuclear Generating Station — Palo Verde is a 3-unit nuclear power plant located approximately 50 miles west of Phoenix, Arizona.  APS operates the plant and owns 29.1% of Palo Verde Units 1 and 3 and approximately 17% of Unit 2.  In addition, APS leases approximately 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 approximately 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 expire 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 currently analyzing these options.  See Note 19 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.

The Palo Verde participants have contracted for 100% of Palo Verde’s requirements for uranium concentrates through 2017, 90% of its requirements in 2018 and 45% of its requirements in 2019-2020.  The participants have also contracted for all of Palo Verde’s conversion services through 2016, 95% of its requirements in 2017-2018 and 45% of its requirements in 2019-2020; all of Palo Verde’s enrichment services through 2020; and all of Palo Verde’s fuel assembly fabrication services through 2016.

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

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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 (the “Standard Contract”) with each nuclear power plant.  The DOE failed to begin accepting spent nuclear fuel by 1998.  APS is directly and indirectly involved in several legal proceedings related to DOE’s failure to meet its statutory and contractual obligations regarding acceptance of spent nuclear fuel and high level waste.

APS Lawsuit for Breach of Standard Contract — In December 2003, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a lawsuit against DOE in the U.S. Court of Federal Claims for damages incurred due to DOE’s breach of the Standard Contract.  The Court of Federal Claims ruled in favor of APS and the Palo Verde participants in October 2010 and awarded $30.2 million in damages to APS and 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 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.  That lawsuit is presently pending in the Court of Federal Claims.

The One-Mill Fee — In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per kWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual obligations under the Standard Contract.  This fee is recovered by APS in its retail rates.  In June 2012, the U.S. Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”) held that DOE failed to conduct a sufficient fee analysis in making the 2010 determination.  The D.C. Circuit remanded the 2010 determination to the Secretary of the DOE (“Secretary”) with instructions to conduct a new fee adequacy determination within six months.  In February 2013, upon completion of DOE’s revised one-mill fee adequacy determination, the D.C. Circuit reopened the proceedings.  On November 19, 2013, the D.C. Circuit ordered the Secretary to notify Congress of his intent to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators, as he is required to do pursuant to the NWPA and the D.C. Circuit’s order.  On January 3, 2014, the Secretary notified Congress of his intention to suspend collection of the one-mill fee, subject to Congress’ disapproval.

DOE’s Construction Authorization Application for Yucca Mountain — 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 June 2008, the DOE submitted its Yucca Mountain construction authorization application to the NRC, but in March 2010, the DOE filed a motion to dismiss with prejudice the Yucca Mountain construction authorization application.  Several interested parties have also intervened in the NRC proceeding.  Additionally, a number of interested parties filed a variety of lawsuits in different jurisdictions around the country challenging the DOE’s authority to withdraw the Yucca Mountain construction authorization application and NRC’s cessation of its review of the Yucca Mountain construction authorization application.  The cases have been consolidated into one matter at the D.C. Circuit.  In August 2013, the D.C. Circuit ordered the NRC to resume its review of the application with available appropriated funds.

Waste Confidence — On June 8, 2012, 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

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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 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 NRC Commissioners also directed the staff to establish a schedule to publish a final rule and environmental impact study within 24 months of September 6, 2012.  In September 2013, the NRC issued its draft environmental impact statement to support an updated Waste Confidence Decision.  In October 2013, the NRC began a series of nationwide public meetings to receive stakeholder input on the draft environmental impact statement.  The NRC’s meeting schedule was completed in December 2013.  The NRC Commissioners have instructed the staff to issue the final generic environmental impact statement and rule by no later than September 2014.  Untimely resolution by the NRC of the remand from the D.C. Circuit could have an adverse impact on certain NRC licensing actions.  Currently, Palo Verde does not have any licensing actions pending with the NRC.

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 20 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 causing a series of seven tsunamis.  As a result, the Fukushima Daiichi Nuclear Power Station experienced damage.

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Following the earthquake and tsunamis, the NRC established a 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 ultimate financial or operational impacts on Palo Verde or APS; however, the NRC has directed nuclear power plants to implement the first tier recommendations of the NRC’s Near Term Task Force.  In response to these recommendations, Palo Verde expects to spend approximately $100 million for capital enhancements to the plant over the next several years (APS’s share is 29.1%).

Natural Gas and Oil Fueled Generating Facilities

APS has six natural gas power plants located throughout Arizona, consisting of Redhawk, located near Palo Verde; Ocotillo, located in Tempe (discussed below); 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 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 3,179 MW.  Gas for these plants is financially hedged up to three years in advance of purchasing and the gas is generally purchased one month prior to delivery.  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.

Ocotillo is a 330 MW 4-unit gas plant.  In early 2014, APS announced a roughly $600-$700 million project to modernize the plant, which will involve retiring two older 110 MW steam units, adding five 102 MW combustion turbines and maintaining two existing 55 MW combustion turbines.  In total, this will increase the capacity of the site by 290 MW, to 620 MW, with completion targeted for summer 2018.

Solar Facilities

To date, APS has begun operation of 118 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 approximately 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 MW of solar photovoltaic distributed energy systems located within a certain test area in Flagstaff, Arizona.  Additionally, APS owns 14 MW of

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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 17.)  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.

Type	Dates Available	Capacity (MW)
Purchase Agreement (a)	Year-round through December 2014	90
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	514
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	25
Renewable Energy (e)	Various	629

(a)The capacity under this agreement varies by month, with a maximum capacity of 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 may be increased in 5 MW increments in each of 2014, 2015 and 2016 and 10 MW increments in years 2017 through 2024, up to a maximum of 50 MW.

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

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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 2013 peak one-hour demand on its electric system was recorded on July 8, 2013 at 6,927 MW, compared to the 2012 peak of 7,207 MW recorded on August 8, 2012.  APS’s reserve margin at the time of the 2013 peak demand, calculated using system load serving capacity, was 27%.  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 2013 reserve margin was 17%.  APS anticipates the reserve margin for 2014 will be approximately 34% or 24% excluding contractual rights to call on additional capacity.  APS expects that our reserve margins will decrease over the next three years and that additional conventional resources will be needed around 2017.

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.  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 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.  APS will be filing its next resource plan by April 1, 2014.

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 4.5% of retail electric sales in 2014 and increases annually until it reaches 15% in 2025.  In APS’s 2009 retail rate case settlement agreement (the “2009 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 4.5% in 2014.  The following table summarizes the RES requirement standard (not including the additional commitment required by the 2009 Settlement Agreement) and its timing:

	2014		2015		2020		2025
RES as a % of retail electric sales	4.5	%	5	%	10	%	15	%
Percent of RES to be supplied from distributed energy resources	30	%	30	%	30	%	30	%

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Renewable Energy Portfolio.  To date, APS has a diverse portfolio of existing and planned renewable resources totaling 1175 MW, including solar, wind, geothermal, biomass and biogas.  Of this portfolio, 1074 MW are currently in operation and 101 MW are under contract for development or are under construction.  Renewable resources in operation include 137 MW of facilities owned by APS, 629 MW of long-term purchased power agreements, and an estimated 308 MW of customer-sited, third-party owned distributed energy resources.

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 estimates its investment commitment will be approximately $695 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.

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	Location	Actual/Target Commercial Operation Date	Term (Years)	NetCapacityIn Operation (MW AC)	Net CapacityPlanned/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
Hyder II	Hyder, AZ	2013		14
Foothills	Yuma, AZ	2013		35
Gila Bend	Gila Bend, AZ	2014			32
Subtotal AZ Sun Program (a)				118	32
Multiple Facilities	AZ	Various		4
Distributed Energy:
APS Owned (b)	AZ	Various		15
Total APS Owned				137	32
Purchased Power Agreements
Solar:
Solana	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
Badger	Tonopah, AZ	2013	30	15
Gillespie	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				629	0
Distributed Energy
Solar (c)
Third-party Owned	AZ	Various		275	69
Agreement 1	Bagdad, AZ	2011	25	15
Agreement 2	AZ	2011-2012	20-21	18
Total Distributed Energy				308	69
Total Renewable Portfolio				1074	101

(a)Under the AZ Sun Program, an additional 20 MW has been approved to be contracted, but is not included in the table above since it is not yet under contract.  Another 30 MW is possible under AZ Sun, but has not yet been approved.

(b)Includes Flagstaff Community Power Project and APS School and Government Program.

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

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Demand Side Management

In December 2009, Arizona regulators 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.  The ACC initiated its Energy Efficiency rulemaking, with a proposed Energy Efficiency Standard (“EES”) 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 2009 Settlement Agreement).

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 continues its work on 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 during 2015 and is contingent upon APS meeting certain project milestones, including DOE-established budget parameters.

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 popular with customers installing or having installed products such as rooftop 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.  Although some very limited retail competition existed in APS’s service territory in

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1999 and 2000, 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.

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.

On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.  The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state.  One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution.  On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter.  The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.  The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry.  Workshops in this docket are expected to be held in 2014.

Wholesale

FERC regulates rates for wholesale power sales and transmission services.  (See Note 3 for information regarding APS’s transmission rates.)  During 2013, approximately 5.4% 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 it is unclear if and when the 113th 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 GHG emissions; the cost to reduce emissions; in the event a cap-and-trade program is established, whether any permitted emissions allowances will be allocated to source operators free of cost or auctioned (and, if so, the cost of those allowances in the marketplace) and whether offsets and other measures to moderate the costs of compliance will be available; and, in the event of a carbon tax, the amount of the tax per pound of carbon dioxide (“CO2”) equivalent emitted.

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, entities selling electricity into California, including APS, must hold carbon allowances to cover GHG emissions associated with electricity sales into California from outside the state.  APS is authorized to recover the cost of these carbon allowances through the PSA.

We continue to monitor 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 prior participant in Four Corners, indicated that SB 1368 may prohibit it from making emission control expenditures at the plant and, as a result, SCE sold its entire 48% interest in each of Units 4 and 5 of Four Corners to APS on December 30, 2013.  (See “Energy Sources and Resource Planning — Generation Facilities — Coal-Fueled Generating Facilities — Four Corners” above for details of the sale of SCE’s interest in Four Corners to APS.)

Regulatory Initiatives.  In 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.  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 applicable to power plants in January 2011.  Several groups filed lawsuits challenging EPA’s endangerment finding and the tailoring rule, but the D.C. Circuit upheld these rules.  Petitioners asked

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the United States Supreme Court to reverse all or part of the appeals court’s decision upholding EPA’s GHG rules.  On October 15, 2013, the Supreme Court granted these petitions limiting the question it would review to whether EPA permissibly determined that its regulation of GHG emissions from new motor vehicles triggered permitting requirements under the Clean Air Act for stationary sources that emit such gasses, including power plants.  The Court is expected to issue its decision in the case no later than mid-2014.

APS does not expect that any resulting Supreme Court decision or the tailoring rule will 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 NSR analysis for new sources and major modifications to existing plants.

On June 25, 2013, President Obama unveiled his Climate Action Plan addressing his plans to reduce GHG emissions in the United States.  While the plan identifies a wide range of strategies for cutting GHG emissions, most important to APS and the electric utility industry is the implementation of carbon pollution standards for new, modified, and existing fossil-fired electric generating units.  Concurrent with the President’s speech, the White House issued a Presidential Memorandum directing EPA to use its existing authorities under the Clean Air Act to develop GHG emission standards for new, modified, and existing power plants.  The Presidential Memorandum directs EPA to propose GHG emission standards for modified and existing units by June 1, 2014 and to finalize them by June 1, 2015.  The memorandum further directed EPA to reissue proposed standards of performance for new power plants by September 20, 2013 and to finalize them in a timely fashion.

Consistent with President Obama’s June 2013 directive, pursuant to its authority under the Clean Air Act and its endangerment finding, on September 20, 2013, EPA issued a proposed rule, which would establish New Source Performance Standards (“NSPS”) for new fossil-fired power plants.  Once finalized, APS does not expect that the GHG NSPS will have any material impact on its current operations.  EPA indicated in its proposal that the rule will not apply to modified or reconstructed electric generating units, which are to be addressed in a subsequent rulemaking.  We cannot currently predict the shape of any final rules or standards for existing fossil-fired power plants or assess how they might potentially impact the company.  APS will continue to monitor these standards as they are developed.

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 solar, wind, geothermal, biogas, and biomass, and we expect the percentage of renewable energy in our resource portfolio to increase over the coming years.

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.

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EPA Environmental Regulation

Regional Haze Rules.  In 1999, 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, including fossil-fired power plants.  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 in early 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 State Implementation Plan (“SIP”) for Cholla and other sources in Arizona in early 2011.

On December 2, 2011, EPA provided notice of a proposed consent decree to address a lawsuit filed by a number of environmental non-governmental organizations, which alleged that EPA failed to promulgate Federal Implementation Plans (“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 (“SO2”) and emissions of particulate matter (“PM”), but added a SO2 removal efficiency requirement of 95%.  In addition, EPA disapproved ADEQ’s BART determinations for oxides of nitrogen (“NOx”) and promulgated a FIP establishing a new, more stringent “bubbled” NOx emission 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 SCR control technology on all three of the Cholla units.  APS’s total costs for these post-combustion NOx controls would be approximately $200 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 emission limit for NOx.

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.  We expect briefing in the case to be completed in February 2014.

Four Corners.  On August 6, 2012, EPA issued its final BART determination for Four Corners.  The rule included two compliance options.  On December 30, 2013, APS notified EPA that the Four Corners participants selected the BART alternative, which required APS to retire Four Corners Units 1-3 by January 1, 2014 and install and operate SCR control technology on Units 4

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and 5 by July 31, 2018.  Consistent with this alternative, APS retired Four Corners Units 1-3 on December 30, 2013.  APS’s 63% share of the costs for these controls is estimated to be approximately $350 million.  Approximately half of these costs are included in the capital expenditure estimates in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Expenditures” in Item 7 because APS expects to incur that portion of the costs during the 2014 through 2016 timeframe.  For PM emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lb/MMBtu and a 20% opacity limit, both of which are achievable through operation of the existing baghouses.  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.

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.  The court granted APS’s motion for leave to intervene as a defendant in the case.  A decision is expected before the end of 2014.  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.

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 plant-wide NOx 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 NOx controls could be up to approximately $200 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 because APS expects to incur such costs in years following 2016.  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 each of 2021, 2022, and 2023.  In response to EPA’s request for comments on other options that could set longer time frames for installing pollution controls if the Navajo Plant can achieve additional emission reductions, on July 26, 2013, a group of stakeholders, including SRP, the operating agent for the Navajo Plant, submitted to EPA two suggested alternatives to BART, which would achieve greater NOx emission reductions than EPA’s proposed BART rule.  If the rule is finalized as proposed, depending on which alternate operating scenario the Navajo Plant participants ultimately select, the required NOx emission reductions could be achieved by either closing one of the three 750 MW units at the plant or curtailing energy production across all three units, such that the emission reductions are commensurate with the closure of approximately one of the Navajo Plant units.  On September 25, 2013, EPA issued a supplemental BART proposal proposing to determine that these alternatives are “better than BART” because NOx emissions that would be achieved thereunder would result in greater reasonable progress toward the national visibility goal than EPA’s proposed BART determination.

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.  Similarly, SRP

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will have until April 16, 2016 to comply with MATS at the Navajo Plant, as a result of a one-year extension granted by EPA and the Navajo Nation EPA on January 27, 2014.

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 estimates that the cost for the remaining equipment necessary to meet these standards is approximately $120 million for Cholla Units 2 and 3.  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.  No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules.  SRP, the operating agent for the Navajo Plant, is still evaluating compliance options under the rules.

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 their 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.

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 will issue the final standards upon completion of its ongoing ESA consultations with the U.S. Fish and Wildlife Service and National Marine Fisheries Service and is working to finalize the standards by April 2014.

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 under Subtitle D of the Resource Conservation and Recovery Act (“RCRA”) or hazardous waste under Subtitle C of RCRA 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.

In April 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, which were consolidated with the environmental groups’ lawsuits.  On January 29, 2014, the parties in the CCR

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deadline litigation filed a consent decree with the court obligating EPA to make a final decision by December 2014 whether or not to adopt the Subtitle D option for CCR.  The consent decree does not foreclose EPA from adopting the Subtitle C option.  We cannot currently predict the timing or content 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.

Effluent Limitation Guidelines.  On April 19, 2013, EPA proposed revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil-fired electric generating units.  EPA’s proposal offers numerous options (four of which are “preferred alternatives”) that target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities, and non-chemical metal cleaning wastes operations.  The preferred alternatives differ with respect to the scope of requirements that would be applicable to existing discharges of pollutants found in wastestreams generated at existing power plants.  All four alternatives would establish a “zero discharge” effluent limit for all pollutants in fly ash transport water.  However, requirements governing bottom ash transport water differ depending on which alternative EPA ultimately chooses and could range from effluent limits based on Best Available Technology Economically Achievable to “zero discharge” effluent limits.  Depending on which alternative EPA finalizes, Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques.  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.  EPA is currently subject to a consent decree deadline to finalize the revised guidelines by May 2014, although it is in negotiations to obtain an extension of time.

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, the following year, President Obama decided to withdraw EPA’s revised ozone standards until completion of the next review.  EPA had a March 2013 deadline to complete its review of the 2008 ozone NAAQS, but failed to meet it.  Although EPA has not announced a timeline for its review, it may release new proposed standards in the second half of 2014.  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 located in ozone nonattainment areas.  At this time, APS is unable to predict the timing of the final standards or what impact the adoption of these standards may have on its financial position, results of operations, or cash flows.

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 NSR 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 any resulting actions the EPA may take, including any potential litigation.

Clean Air Act Citizen Lawsuit.  On October 4, 2011, Earthjustice, on behalf of several environmental non-governmental organizations, filed a lawsuit in the United States District Court for the District of New

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Mexico against APS and the other Four Corners participants alleging violations of the NSR provisions of the Clean Air Act.  Subsequent to filing its original complaint, on January 6, 2012, Earthjustice filed an amended complaint adding claims for violations of the Clean Air Act’s NSPS program.  Among other things, the environmental 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.  The case is being held in abeyance while the parties seek to negotiate a settlement.  On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay.  At such time as the stay is lifted, APS and the other Four Corners participants may reinstate their motions to dismiss.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

Superfund-Related Matters.  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 52nd 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.

On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

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.

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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.

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’s 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

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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.  In addition, APS is a party to a water contract that allows the company to secure water for Four Corners in the event of a water shortage and is a party to a shortage sharing agreement, which provides for the apportionment of water supplies to Four Corners in the event of a water shortage in the San Juan River Basin.

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.  Several 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 APS’s 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 Arizona Supreme 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.

BUSINESS OF OTHER SUBSIDIARIES

Our other operating subsidiary, El Dorado, is not expected to contribute in any material way to our future financial performance, nor will it require any material amounts of capital over the next three years.  We continue to focus on our core utility business and streamlining the Company.

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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, 2013, El Dorado had total assets of $15 million.

SunCor

In February 2012, our other first-tier subsidiary, SunCor, filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business.  On March 25, 2013, the bankruptcy plan submitted to the court and agreed to by SunCor and its creditors (the “Joint Plan”) became effective.  The Joint Plan provides for the full release of Pinnacle West and its affiliates from any and all claims related to SunCor, SunCor’s subsidiaries, and their respective estates.  SunCor and its subsidiaries are in the process of being formally dissolved.

OTHER INFORMATION

Pinnacle West, APS and El Dorado 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, 2013
Pinnacle West	400 North Fifth Street Phoenix, AZ 85004	1985	81
APS	400 North Fifth Street P.O. Box 53999 Phoenix, AZ 85072-3999	1920	6,352
El Dorado	400 North Fifth Street Phoenix, AZ 85004	1983	—
Total			6,433

The APS number includes employees at jointly-owned generating facilities (approximately 2,865 employees) for which APS serves as the generating facility manager.  Approximately 1,797 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.  The Company is currently engaged in discussions with union representatives to enter into an extension of the current agreement.  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 certified the results.  The Company is currently engaged in negotiations with the USPA over the terms of a new collective bargaining agreement.

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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.

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 Corporate Secretary, Mail 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 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 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 FERC could have a material adverse impact on our financial condition, results of operations or cash flows.

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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 FERC, 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, FERC can impose penalties (up to one million dollars per day per violation) for failure to comply with mandatory electric reliability standards.  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 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 safety-related, security-related and other licensing 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 tsunamis 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 has been 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 complete its formal actions as a result of its review.  As a result of the Fukushima event, however, the NRC has directed nuclear power plants to implement the first tier recommendations of the NRC’s Near Term Task Force.  In response to these recommendations, Palo Verde expects to spend approximately $100 million for capital enhancements to the plant over the next several years (APS’s share is 29.1%).  We cannot predict whether these amounts will increase or whether additional financial and/or operational requirements on Palo Verde and APS may be imposed.

In the event of noncompliance with its requirements, the NRC has the authority to impose a progressively increased inspection regime that could ultimately result in the shut-down of a unit or civil penalties, 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.

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

Regional Haze.  APS has received final rulemakings 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 BART 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.

Mercury and other Hazardous Air Pollutants.  EPA issued MATS to regulate emissions of mercury and other hazardous air pollutants from fossil-fired power plants.  The MATS will require APS to install additional pollution control equipment at Cholla and possibly the Navajo Plant.  The financial impact of installing and operating such equipment could jeopardize the economic viability of Cholla.

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.

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Effluent Limitation Guidelines.  EPA is expected to finalize revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil-fired electric generating units in 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, repair and replacement 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 at Four Corners.  Several environmental non-governmental organizations 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 groups prevail in their Clean Air Act lawsuit, 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.

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 GHG emissions.

Concern over climate change, deemed by many to be induced by rising levels of GHG in the atmosphere, has led to significant legislative and regulatory efforts to limit CO2, which is a major byproduct of the combustion of fossil fuel, and other GHG emissions.

Financial Risks — Potential Greenhouse Gas Regulation.  EPA is taking action to regulate domestic GHG emissions and is expected to issue proposed regulations in mid-2014.  Any limitations on CO2 and other GHG emissions resulting from this regulatory effort could require substantial additional capital expenditures and operating costs and could have a material adverse impact on all fossil-fuel-fired generation facilities (particularly coal-fired facilities, which constitute approximately 30% of APS’s owned and leased generation capacity).

At the state level, the California legislature enacted legislation to address GHG emissions and the California Air Resources Board approved regulations that established a cap-and-trade program for

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GHGs.  This legislation, regulations and other state-specific initiatives may affect APS’s business, including sales into the impacted states.

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.

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.  On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.  The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state.  One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution.  On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter.  The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.  One of these options could be a continuation or expansion of APS’s existing AG (Alternative Generation) — 1 program, which essentially allows up to 200 MW of cumulative load to be served via a buy-through arrangement with competitive suppliers of generation.  We cannot predict future regulatory or legislative action that might result in increased competition.

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

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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 and facilities.  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 most recent retail rate case (the “2012 Settlement Agreement”) includes a mechanism, the LFCR, to address these matters.

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.

Customer and Sales Growth.  For the three years 2011 through 2013, APS’s retail customer growth averaged 1.0% per year.  We currently expect annual customer growth to average about 2.5% for 2014 through 2016 based on our assessment of modestly improving economic conditions, both nationally and in Arizona.  For the three years 2011 through 2013, APS experienced annual increases in retail electricity sales averaging 0.1%, adjusted to exclude the effects of weather variations.  We currently estimate that annual retail electricity sales in kWh will increase on average by about 1% during 2014 through 2016, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but 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.  Additionally, recovery of a substantial portion of our fixed costs of providing service is based upon the volumetric amount of our sales.  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.

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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.  Concerns over physical security of these assets is also increasing, which may require us to incur additional capital and operating costs to address. Damage to certain of our facilities due to vandalism or other deliberate acts could lead to outages or other adverse effects.

The inability to successfully develop or acquire generation resources to meet reliability requirements, new or evolving standards or 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.  The current abundance of low, stably priced natural gas, together with environmental and other concerns surrounding coal-fired generation resources, create strategic questions related to the appropriate generation portfolio and fuel diversification mix.  In addition, APS is required by the ACC to meet certain energy resource portfolio requirements such as the EES and the RES.  The development of any generation facility is subject to many 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 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.

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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 exceed the amount of insurance coverage.  In addition, APS may be required under federal law to pay up to $111 million (but not more than $16.4 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”) 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

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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 or emissions, including clean coal and coal gasification, renewable technologies including photovoltaic (solar) cells, customer-sited generation (solar), energy storage (batteries), 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.

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 on a long-term basis, and their use on large-scale systems is not as advanced and established as APS’s existing technologies and equipment.  Widespread installation and acceptance of these technologies could enable the entry of new market participants, such as technology companies, into the interface between APS and its customers and could have other unpredictable effects on APS’s business.

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, with approximately 38% of employees eligible to retire by 2017.  Although we have undertaken efforts to recruit and train new employees, we face increased competition for talent.  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.  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

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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 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.  We obtained cyber insurance to provide coverage for a portion of the losses and damages that may result from a security breach of our information technology systems, but such insurance may not cover the total loss or damage caused by a breach.

FINANCIAL RISKS

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

Pinnacle West and APS 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 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.

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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 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.

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 into the related trusts.  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 OCI.  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

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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.

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 financing 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.

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;

·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.

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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;

·the ability of the Board of Directors to increase the size of the Board of Directors and fill vacancies on the Board of Directors, 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 of Directors 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.

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 2013 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 4, 5 (c)	2	63	%	Coal	Base Load	970
Cholla	3			Coal	Base Load	647
Navajo (d)	3	14	%	Coal	Base Load	315
Ocotillo	2			Gas	Peaking	220
Total Steam						2,152
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
Hyder II	1			Solar	As Available	14
Foothills	1			Solar	As Available	35
APS Owned Distributed Energy				Solar	As Available	15
Multiple facilities				Solar	As Available	4
Total Solar						137
Total Capacity						6,394

(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

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interests in Palo Verde.  The other participants are Salt River Project (17.49%), SCE (15.8%), El Paso (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%), Tucson Electric Power Company (7%) and El Paso (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, in December 2013 APS acquired SCE’s 48% interest in Units 4 and 5, and closed 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 5,908 pole miles of overhead lines and approximately 49 miles of underground lines, 5,685 miles of which are located in Arizona.  APS’s distribution facilities consist of approximately 11,399 miles of overhead lines and approximately 17,758 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, 2013:

	Percent Owned (Weighted-Average)
Morgan — Pinnacle Peak System	64.5	%
Palo Verde — Estrella 500kV System	50.0	%
Round Valley System	50.0	%
ANPP 500kV System	34.2	%
Navajo Southern System	22.2	%
Four Corners Switchyards	48.1	%
Palo Verde — Yuma 500kV System	18.0	%
Phoenix — Mead System	17.1	%
Palo Verde — Morgan System	90.0	%

Expansion.  Each year APS prepares and files with the ACC a ten-year transmission plan.  In APS’s 2014 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 with the capability to string 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 2014 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.  In recent negotiations, 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 is therefore uncertain.

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 environmental matters, Superfund–related matters, matters related to a September 2011 power outage and a New Mexico tax matter.

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 21, 2014, current positions and principal occupations for the past five years are as follows:

Name	Age	Position	Period
Donald E. Brandt	59	Chairman of the Board and Chief Executive Officer of Pinnacle West; Chairman of the Board of APS	2009-Present
		President of APS	2013-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
Robert S. Bement	58	Senior Vice President, Site Operations, PVNGS, of APS	2010-Present
		Vice President, Nuclear Operations of APS	2007-2010
Denise R. Danner	58	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	50	Vice President, Transmission and Distribution Operations of APS	2014-Present
		Vice President, Resource Management of APS	2012-2014
		Vice President, Power Marketing, Resource Planning and Acquisition of APS	2011-2012
		Vice President, Power Marketing and Resource Planning of APS	2010-2011
		General Manager, Strategic Planning and Resource Acquisition of APS	2009-2010
		Director of Resource Acquisitions and Renewables of APS	2007-2009
Randall K. Edington	60	Executive Vice President and Chief Nuclear Officer, PVNGS, 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	60	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	52	Senior Vice President, Transmission, Distribution & Customers of APS	2014-Present
		Vice President, Energy Delivery of APS	2008-2014
Jeffrey B. Guldner	48	Senior Vice President, Public Policy of APS	2014-Present
		Senior Vice President, Customers and Regulation of APS	2012-2014
		Vice President, Rates and Regulation of APS	2007-2012
James R. Hatfield	56	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
John S. Hatfield	48	Vice President, Communications of APS	2010-Present
		Director, Corporate Communications of SCE	2004-2010
Tammy D. McLeod	52	Vice President, Resource Management of APS	2014-Present
		Vice President and Chief Customer Officer of APS	2007-2014
Lee R. Nickloy	47	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	58	Executive Vice President, Operations of APS	2012-Present
		Senior Vice President, Fossil Operations of APS	2009-2012
		Senior Vice President of Exelon Generation and President of Exelon Power	2004-2009

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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 14, 2014, Pinnacle West’s common stock was held of record by approximately 23,053 shareholders.

QUARTERLY STOCK PRICES AND DIVIDENDS PAID PER SHARE

STOCK SYMBOL: PNW

							Dividends
2013	High		Low		Close		Per Share
1st Quarter	$	57.96	$	51.50	$	57.89	$	0.545
2nd Quarter	61.89		51.56		55.47		0.545
3rd Quarter	60.33		52.03		54.74		0.545
4th Quarter	58.70		52.32		52.92		0.5675

							Dividends
2012	High		Low		Close		Per Share
1st Quarter	$	48.86	$	46.15	$	47.90	$	0.525
2nd Quarter	52.30		45.95		51.74		0.525
3rd Quarter	54.66		51.19		52.80		0.525
4th Quarter	54.20		48.73		50.98		0.545

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 2013 and 2012.

Common Stock Dividends

(Dollars in Thousands)

Quarter	2013		2012
1st Quarter	$	59,800	$	57,400
2nd Quarter	59,900		47,500
3rd Quarter	59,900		57,500
4th Quarter	62,500		59,800

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, 2013, 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 2013.

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, 2013	60,823	$	57.56	—	—
November 1 – November 30, 2013	—	—		—	—
December 1 – December 31, 2013	—	—		—	—
Total	60,823	$	57.56	—	—

(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

	2013		2012			2011		2010		2009
	(dollars in thousands, except per share amounts)
OPERATING RESULTS
Operating revenues	$	3,454,628	$	3,301,804		$	3,241,379	$	3,189,199	$	3,153,656
Income from continuing operations	$	439,966	$	418,993		$	355,634	$	344,851	$	256,048
Income (loss) from discontinued operations – net of income taxes (a)	—		(5,829		)	11,306		25,358		(183,284		)
Net income	439,966		413,164			366,940		370,209		72,764
Less: Net income attributable to noncontrolling interests	33,892		31,622			27,467		20,156		4,434
Net income attributable to common shareholders	$	406,074	$	381,542		$	339,473	$	350,053	$	68,330
COMMON STOCK DATA
Book value per share – year-end	$	38.07	$	36.20		$	34.98	$	33.86	$	32.69
Earnings per weighted-average common share outstanding:
Continuing operations attributable to common shareholders – basic	$	3.69	$	3.54		$	3.01	$	3.05	$	2.34
Net income attributable to common shareholders – basic	$	3.69	$	3.48		$	3.11	$	3.28	$	0.68
Continuing operations attributable to common shareholders – diluted	$	3.66	$	3.50		$	2.99	$	3.03	$	2.34
Net income attributable to common shareholders – diluted	$	3.66	$	3.45		$	3.09	$	3.27	$	0.67
Dividends declared per share	$	2.23	$	2.67		$	2.10	$	2.10	$	2.10
Weighted-average common shares outstanding – basic	109,984,160		109,510,296			109,052,840		106,573,348		101,160,659
Weighted-average common shares outstanding – diluted	110,805,943		110,527,311			109,864,243		107,137,785		101,263,795
BALANCE SHEET DATA
Total assets	$	13,508,686	$	13,379,615		$	13,111,018	$	12,392,998	$	12,035,253
Liabilities and equity:
Current liabilities	$	1,618,644	$	1,083,542		$	1,342,705	$	1,449,704	$	1,279,288
Long-term debt less current maturities	2,796,465		3,199,088			3,019,054		3,045,794		3,496,524
Deferred credits and other	4,753,117		4,994,696			4,818,673		4,122,274		3,831,437
Total liabilities	9,168,226		9,277,326			9,180,432		8,617,772		8,607,249
Total equity	4,340,460		4,102,289			3,930,586		3,775,226		3,428,004
Total liabilities and equity	$	13,508,686	$	13,379,615		$	13,111,018	$	12,392,998	$	12,035,253

(a)Amounts primarily related to SunCor and APSES discontinued operations (see Note 1).

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SELECTED FINANCIAL DATA

ARIZONA PUBLIC SERVICE COMPANY – CONSOLIDATED

	2013		2012		2011		2010		2009
	(dollars in thousands)
OPERATING RESULTS
Electric operating revenues	$	3,451,251	$	3,293,489	$	3,237,241	$	3,180,807	$	3,149,500
Fuel and purchased power costs	1,095,709		994,790		1,009,464		1,046,815		1,178,620
Other operating expenses	1,733,677		1,693,170		1,673,394		1,584,955		1,501,081
Operating income	621,865		605,529		554,383		549,037		469,799
Other income	20,797		16,358		24,974		20,138		13,893
Interest expense — net of allowance for borrowed funds	183,801		194,777		215,584		213,349		213,258
Net income	458,861		427,110		363,773		355,826		270,434
Less: Net income attributable to noncontrolling interests	33,892		31,613		27,524		20,163		19,209
Net income attributable to common shareholder	$	424,969	$	395,497	$	336,249	$	335,663	$	251,225
BALANCE SHEET DATA
Total assets	$	13,381,377	$	13,242,542	$	13,032,237	$	12,271,877	$	11,730,500
Liabilities and equity:
Total equity	$	4,454,874	$	4,222,483	$	4,051,406	$	3,916,037	$	3,527,679
Long-term debt less current maturities	2,671,465		3,074,088		2,894,054		3,045,794		3,306,406
Total capitalization	7,126,339		7,296,571		6,945,460		6,961,831		6,834,085
Current liabilities	1,580,847		1,043,087		1,322,714		1,234,865		1,070,970
Deferred credits and other	4,674,191		4,902,884		4,764,063		4,075,181		3,825,445
Total liabilities and equity	$	13,381,377	$	13,242,542	$	13,032,237	$	12,271,877	$	11,730,500

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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.  The March 2011 earthquake and tsunamis in Japan and the resulting accident at Japan’s Fukushima Daiichi nuclear power station had a significant impact on nuclear power operators worldwide.  In the aftermath of the accident, the NRC conducted an independent assessment to consider actions to ensure that its regulations reflect lessons learned from the Fukushima events.

Although the NRC has repeatedly affirmed its position that continued operation of U.S. commercial nuclear power plants does not impose an immediate risk to public health and safety, the NRC has proposed enhancements to U.S. commercial nuclear power plant equipment and emergency plans.  APS management continues to work closely with the NRC and others in the nuclear industry to ensure that the enhancements are implemented in an organized, sequential and structured way consistent with their safety benefit and significance of the issue being addressed.

Coal and Related Environmental Matters and Transactions.  APS is a joint owner of three coal-fired power plants and acts as operating agent for two of the plants.  APS is focused on the impacts on its coal fleet that may result from increased regulation and potential legislation concerning GHG 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.

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Four Corners

Asset Purchase Agreement and Coal Supply Matters.  SCE, a participant in Four Corners, previously indicated that certain California legislation prohibited 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.  On December 30, 2013, APS and SCE closed this transaction.  The final purchase price for the interest was approximately $182 million, subject to certain minor post-closing adjustments.

In connection with APS’s most recent retail rate case with the ACC, the ACC reserved the right to review the prudence of the Four Corners transaction for cost recovery purposes upon the closing of the transaction.  On December 30, 2013, APS filed an application with the ACC to request rate adjustments prior to its next general rate case related to APS’s acquisition of SCE’s interest in Four Corners.  If approved, these would result in an average bill impact to residential customers of approximately 2%.  APS cannot predict the outcome of this request.

Concurrently with the closing of the SCE transaction, BHP Billiton, the parent company of BNCC, the coal supplier and operator of the mine that serves Four Corners, transferred its ownership of BNCC to NTEC, a company formed by the Navajo Nation to own the mine and develop other energy projects.  BHP Billiton will be retained by NTEC under contract as the mine manager and operator until July 2016.  Also occurring concurrently with the closing, the Four Corners’ co-owners executed the 2016 Coal Supply Agreement.  El Paso, a 7% owner in Units 4 and 5 of Four Corners, did not sign the 2016 Coal Supply Agreement.  Under the 2016 Coal Supply Agreement, APS has agreed to assume the 7% shortfall obligation.  When APS ultimately acquires a right to EPE’s interest in Four Corners, by agreement or operation of law, NTEC will have an option to purchase the interest within a certain timeframe pursuant to an option granted by APS to NTEC.  The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% shortfall obligations in the event NTEC does not exercise its option.

Pollution Control Investments and Shutdown of Units 1, 2 and 3.  EPA, in its final regional haze rule for Four Corners, required the Four Corners’ owners to elect one of two emissions alternatives to apply to the plant.  On December 30, 2013, APS, on behalf of the co-owners, notified EPA that they chose the alternative BART compliance strategy requiring the permanent closure of Units 1, 2 and 3 by January 1, 2014 and installation and operation of SCR controls on Units 4 and 5 by July 31, 2018.  On December 30, 2013, APS retired Units 1, 2 and 3.

Lease Extension.  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 are pursuing.  A federal environmental review is underway as part of the DOI review process.  APS will also require a PSD permit from EPA to install SCR control technology at Four Corners.  APS cannot predict whether these federal approvals will be granted, and if so on a timely basis, or whether any conditions that may be attached to them will be acceptable to the Four Corners owners.

Transmission and Delivery.  APS is working closely with regulators to identify and plan for transmission needs that continue to support system reliability, access to markets and renewable energy development.  The capital expenditures table presented in the “Liquidity and Capital Resources” section

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below includes new transmission projects through 2016, along with other transmission costs for upgrades and replacements.  APS is also working to establish and expand smart grid technologies throughout its service territory to provide long-term benefits both to APS and its customers.  APS is strategically 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 4.5% of retail electric sales in 2014 and increases annually until it reaches 15% in 2025.  In the 2009 Settlement Agreement, APS agreed to exceed the RES standards, committing to use APS’s best efforts to obtain 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 currently 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 targets development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties).

On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million.  In a final order dated January 7, 2014, the ACC approved the requested budget.  Also in 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits.  On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules so that utilities can establish compliance without using renewable energy credits.

On July 12, 2013, APS filed an application with the ACC proposing a solution to fix the cost shift brought by the current net metering rules.  In its application, APS requested that the ACC cause all new residential customers installing new rooftop solar systems to either:  (i) take electric service under APS’s demand-based ECT-2 rate and remain eligible for net metering; or (ii) take service under the customer’s existing rate as if no distributed energy system was installed and receive a bill credit for 100% of the distributed energy system’s output at a market-based price.  APS also proposed that the ACC:  (i) grandfather current rates and use of net metering for existing and immediately pending distributed energy customers; and (ii) continue using direct cash incentives for new distributed energy installations.

On December 3, 2013, the ACC issued its order on APS’s net metering proposal.  The ACC instituted a charge on future customers who install rooftop solar panels and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases.  The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid. The new policy will be in effect until the next APS rate case.

In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid.  ACC staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists.  The fixed charge does not increase APS’s revenue,

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but instead will modestly reduce the impact of the cost shift on non-solar customers. The ACC acknowledged that the new charge addresses only a portion of the cost shift.

Demand Side Management.  In December 2009, Arizona regulators 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.  The ACC initiated an Energy Efficiency rulemaking, with a proposed EES 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.  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.  This amount was recovered by the then-existing DSMAC over a twelve-month period beginning March 1, 2012.  This amount did not include $10 million already being recovered in general retail base rates, but did include amortization of 2009 costs (approximately $5 million of the $72 million).

On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan.  In 2013, the standards 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.

The ACC Staff recommendation and proposed order, issued on October 30, 2013, largely recommended continuing the status quo, although at lower funding levels.  ACC Staff recommended approval of all existing cost-effective energy efficiency and demand response programs and a budget of $68.9 million going forward.  APS expects to receive a decision from the ACC in early 2014.

On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified or abolished. This spring the ACC will hold a series of three workshops to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

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 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 the 2012 Settlement Agreement detailing the terms upon which the parties have agreed to settle the rate case.  See Note 3 for details regarding the 2012 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 acquisition of SCE’s interest in Units 4 and 5 of Four Corners, APS and SCE agreed, via a “Transmission Termination Agreement,” that upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination.  APS and SCE negotiated an

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alternate arrangement under which SCE will assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group for transmission of the additional power received from Four Corners.  This arrangement becomes effective upon FERC approval and will remain in effect until the net payments received by SCE in connection with the assignments reach $40 million, at which time the arrangement and the Transmission Agreement will terminate.  APS believes that FERC will approve the alternate arrangement as filed but, if not approved, SCE and APS will again be subject to the terms of the Transmission Termination Agreement.  APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement.  If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration.  APS is unable to predict the outcome of this matter if it proceeds to arbitration.

On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.  The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state.  One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution.  On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter.  The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.  The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry.  Workshops in this docket are expected to be held in 2014.

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.

El Dorado.  The operations of El Dorado, our only other operating subsidiary, 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.

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 2011 through 2013, 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

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mechanisms.  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 2013 was 1.3% compared with the prior year.  For the three years 2011 through 2013, APS’s customer growth averaged 1.0% per year.  We currently expect annual customer growth to average about 2.5% for 2014 through 2016 based on our assessment of modestly improving economic conditions, both nationally and in Arizona.  Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, decreased 0.5% in 2013 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 and customer growth.  For the three years 2011 through 2013, APS experienced annual increases in retail electricity sales averaging 0.1%, adjusted to exclude the effects of weather variations.  We currently estimate that annual retail electricity sales in kWh will increase on average about 1% during 2014 through 2016, 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 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 and energy conservation, impacts of energy efficiency programs and growth in distributed generation, and responses to retail price changes.  Based on past experience, a reasonable range of variation in our kWh 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.

Weather.  In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data.  Historically, 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 customer and sales growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors.  In the 2009 Settlement Agreement, 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

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distribution facilities), and changes in depreciation and amortization rates.  See “Capital Expenditures” below for information regarding the planned additions to our facilities.  See Note 1 regarding deferral of certain costs pursuant to an ACC order.

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 10.5% of the assessed value for 2013, 9.6% for 2012, and 9.0% for 2011.  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 2012 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 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 only 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.

Operating Results – 2013 compared with 2012.

Our consolidated net income attributable to common shareholders for the year ended December 31, 2013 was $406 million, compared with net income of $382 million for the prior year.  The results reflect an increase of approximately $21 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; and lower net interest charges due to lower debt balances and lower interest rates in the current-year period.  These positive factors were partially offset by higher operations and maintenance expenses; higher fuel and purchased power costs, net of related deferrals; lower retail sales as a result of changes in customer usage related to energy efficiency, customer conservation and distributed generation, partially offset by customer growth; and higher depreciation and amortization expenses.

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

	Year Ended December 31,
	2013			2012			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	2,356		$	2,299		$	57
Operations and maintenance	(925		)	(885		)	(40		)
Depreciation and amortization	(416		)	(404		)	(12		)
Taxes other than income taxes	(164		)	(159		)	(5		)
Other income (expenses), net	11			6			5
Interest charges, net of allowance for borrowed funds used during construction	(187		)	(200		)	13
Income taxes	(232		)	(237		)	5
Less income related to noncontrolling interests (Note 19)	(34		)	(32		)	(2		)
Regulated electricity segment net income	409			388			21
All other	(3		)	—			(3		)
Income from Continuing Operations Attributable to Common Shareholders	406			388			18
Loss from Discontinued Operations Attributable to Common Shareholders (a)	—			(6		)	6
Net Income Attributable to Common Shareholders	$	406		$	382		$	24

(a)Includes activities related to SunCor.

Operating revenues less fuel and purchased power expenses.  Regulated electricity segment operating revenues less fuel and purchased power expenses were $57 million higher for the year ended December 31, 2013 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		$	6		$	58
Higher demand-side management, renewable energy and similar regulatory surcharges	34			7			27
Higher retail transmission revenues	11			—			11
Lower retail sales due to changes in customer usage patterns and related pricing, partially offset by customer growth	(17		)	(4		)	(13		)
Higher fuel and purchased power costs, net of related deferrals and off-system sales	74			95			(21		)
Miscellaneous items, net	(8		)	(3		)	(5		)
Total	$	158		$	101		$	57

Operations and maintenance.  Operations and maintenance expenses increased $40 million for the year ended December 31, 2013 compared with the prior year primarily because of:

·An increase of $14 million related to technical analysis, consulting, advertising and communications costs;

·An increase of $13 million related to costs for demand-side management, renewable energy and similar regulatory programs, which were largely offset in operating revenues;

·An increase of $9 million related to the closure of Four Corners Units 1, 2, and 3, deferred for regulatory recovery in depreciation;

·An increase of $6 million in energy delivery and customer service costs;

·An increase of $6 million in information technology costs;

·A decrease of $6 million in generation costs primarily related to lower fossil generation outage costs and lower nuclear generation costs; and

·A decrease of $2 million related to other miscellaneous factors.

Depreciation and amortization.  Depreciation and amortization expenses were $12 million higher for the year ended December 31, 2013 compared with the prior year, primarily because of

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increased plant in service, partially offset by the regulatory deferral of operating expenses associated with the closure of Four Corners Units 1, 2, and 3.

Interest charges, net of allowance for borrowed funds used during construction.  Interest charges, net of allowance for borrowed funds used during construction, decreased $13 million for the year ended December 31, 2013 compared with the prior year, primarily because of lower debt balances and lower interest rates in the current year.

Income taxes.  Income taxes were $5 million lower for the year ended December 31, 2013 compared with the prior year primarily due to a lower effective tax rate in the current period, partially offset by the effects of higher pretax income in the current year.

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 made to SunCor’s estate as part of a negotiated resolution to the bankruptcy (see Note 1) 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 19)	(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 made to SunCor’s estate as part of a negotiated resolution to the bankruptcy (see Note 1) and absence of a gain related to the sale of our investment in APSES in 2011.

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.  The level of our common stock dividends and future dividend growth will be dependent on declaration by our Board of Directors and 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, 2013, APS’s common equity ratio, as defined, was 58%.  Its total shareholder equity was approximately $4.3 billion, and total capitalization was approximately $7.5 billion.  Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $3.0 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.

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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, 2013, 2012 and 2011 (dollars in millions):

Pinnacle West Consolidated

	2013			2012			2011
Net cash flow provided by operating activities	$	1,153		$	1,171		$	1,125
Net cash flow used for investing activities	(1,009		)	(873		)	(782		)
Net cash flow used for financing activities	(161		)	(305		)	(420		)
Net decrease in cash and cash equivalents	$	(17	)	$	(7	)	$	(77	)

Arizona Public Service Company

	2013			2012			2011
Net cash flow provided by operating activities	$	1,194		$	1,176		$	1,128
Net cash flow used for investing activities	(1,009		)	(873		)	(834		)
Net cash flow used for financing activities	(185		)	(319		)	(374		)
Net decrease in cash and cash equivalents	$	—		$	(16	)	$	(80	)

Operating Cash Flows

2013 Compared with 2012.  Pinnacle West’s consolidated net cash provided by operating activities was $1,153 million in 2013, compared to $1,171 million in 2012, a decrease of $18 million in net cash provided.  The decrease is primarily related to a $127 million change in cash collateral posted and $76 million of higher pension contributions made in 2013 compared to 2012 (approximately $18 million of which is reflected in capital expenditures).  The decrease is partially offset by approximately $167 million of higher cash inflows primarily due to higher authorized revenue requirements resulting from the retail regulatory settlement effective July 1, 2012 and other changes in working capital.

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.

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 Income 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 107% funded as of January 1, 2013 and is estimated to be approximately 103% funded as of January 1, 2014.  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 $141 million in 2013, $65 million in 2012, and zero in 2011.  The minimum contributions for the pension plan total $141 million for the next three years under the recently enacted Moving Ahead

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for Progress in the 21st Century Act (zero in 2014, $19 million in 2015 and $122 million in 2016).  Instead, we expect to make voluntary contributions totaling $300 million for the next three years ($175 million in 2014, of which $70 million was already contributed in early 2014, up to $100 million in 2015, and up to $25 million in 2016).  With regard to contributions to our other postretirement benefit plans, we made a contribution of approximately $14 million in 2013, $23 million in 2012, and $19 million in 2011.  The contributions to our other postretirement benefit plans for 2014, 2015 and 2016 are expected to be approximately $10 million each year.

The $70 million long-term income tax receivable on the Consolidated Balance Sheets as of December 31, 2012 represented the anticipated refund related to an APS tax accounting method change approved by the Internal Revenue Service (“IRS”) in the third quarter of 2009.  On July 9, 2013, IRS guidance was released which provided clarification regarding the timing and amount of this cash receipt.  As a result of this guidance, uncertain tax positions decreased $67 million during the third quarter.  This decrease in uncertain tax positions resulted in a corresponding increase to the total anticipated refund due from the IRS and an offsetting increase in long-term deferred tax liabilities.  Additionally, as a result of this IRS guidance, the resulting $137 million anticipated refund was reclassified to current income tax receivable.

During the year ended December 31, 2013, the IRS finalized the examination of tax returns for the years ended December 31, 2008 and 2009, and the $137 million anticipated refund was reduced by approximately $4 million to reflect the outcome of this examination.  On December 17, 2013, the Joint Committee on Taxation approved the anticipated refund.  Cash related to this refund was received in the first quarter of 2014.

Investing Cash Flows

2013 Compared with 2012.  Pinnacle West’s consolidated net cash used for investing activities was $1,009 million in 2013, compared to $873 million in 2012, an increase of $136 million in net cash used.  The increase in net cash used for investing activities is primarily related to APS’s purchase of SCE’s interest in Units 4 and 5 of Four Corners of approximately $209 million, partially offset by a decrease of approximately $73 million in other capital expenditures.

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.

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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,
	2014		2015		2016
APS
Generation:
Nuclear Fuel	$	80	$	86	$	88
Renewables	118		7		—
Environmental	30		57		213
Other Generation	230		248		355
Distribution	255		374		363
Transmission	198		213		196
Other (a)	54		41		48
Total APS	$	965	$	1,026	$	1,263

(a)Primarily information systems and facilities projects.

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.  The estimated Renewables expenditures include 20 MW of utility-scale solar projects which were approved by the ACC in the 2014 RES Implementation Plan.  We have not included estimated costs for Cholla’s compliance with MATS or EPA’s regional haze rule since we have challenged the regional haze rule judicially and are considering our future options with respect to that plant if the regional haze rule is upheld.  The portion of estimated costs through 2016 for installation of pollution control equipment needed to ensure Four Corners’ compliance with EPA’s regional haze rules have been included in the table above.  We are monitoring the status of other environmental matters, which, depending on their final outcome, could require modification to our planned 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

2013 Compared with 2012.  Pinnacle West’s consolidated net cash used for financing activities was $161 million in 2013, compared to $305 million of net cash used in 2012, a decrease of $144

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million in net cash used.  The decrease in net cash used for financing activities is primarily due to $531 million in lower repayments of long-term debt, largely offset by $340 million in lower issuances of long-term debt and a $31 million net change in APS’s commercial paper borrowings, which is classified as short-term borrowings on the Consolidated Balance Sheets.  On December 30, 2013, commercial paper issuances were used to fund the acquisition of SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners (see below).

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).

Significant Financing Activities.  On December 18, 2013, the Pinnacle West Board of Directors declared a quarterly dividend of $0.5675 per share of common stock, payable on March 3, 2014, to shareholders of record on February 3, 2014.  During 2013, Pinnacle West increased its indicated annual dividend from $2.18 per share to $2.27 per share.  For the year ended December 31, 2013, Pinnacle West’s total dividends paid per share of common stock were $2.20 per share, which resulted in dividend payments of $235 million.

On March 22, 2013, APS issued an additional $100 million par amount of its outstanding 4.50% unsecured senior notes that mature on April 1, 2042.  The net proceeds from the sale were used to repay short-term commercial paper borrowings and replenish cash used to redeem certain tax-exempt indebtedness in November 2012.

On May 1, 2013, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series C, due 2029.  On May 28, 2013, we remarketed the bonds.  The interest rate for these bonds was set to a new term rate.  The new term rate for these bonds ends, subject to a mandatory tender, on May 30, 2018.  During this time, the bonds will bear interest at a rate of 1.75% per annum.  These bonds are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2013 and were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.

On July 12, 2013, APS purchased all $33 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 1994 Series A, due 2029.  On January 15, 2014, these bonds were canceled.  These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.

On October 11, 2013, APS purchased all $32 million of the City of Farmington, New Mexico Pollution Control Revenue Bonds, 1994 Series C, due 2024.  On January 15, 2014, these bonds were canceled.  These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.

On January 10, 2014, APS issued $250 million of 4.70% unsecured senior notes that mature on January 15, 2044.  The proceeds from the sale were used to repay commercial paper which was used to fund the purchase price and costs associated with the acquisition of SCE’s 48% ownership interest in

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each of Units 4 and 5 of Four Corners and to replenish cash used to re-acquire two series of tax-exempt indebtedness.

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, 2013, 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, 2013, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding, and no commercial paper borrowings.

On April 9, 2013, APS refinanced its $500 million revolving credit facility that would have matured in February 2015, with a new $500 million facility.  The new revolving credit facility matures in April 2018.

At December 31, 2013, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that was refinanced in April 2013 (see above) and a $500 million credit 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 can 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, 2013, APS had no outstanding borrowings or letters of credit under its revolving credit facilities.  APS had commercial paper borrowings of $153 million at December 31, 2013.

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.

See Note 17 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, 2013, the ratio was approximately 47% 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

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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 14, 2014 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 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	Baa1	A-	BBB+
Commercial paper	P-2	A-2	F2
Outlook	Stable	Stable	Stable
APS
Corporate credit rating	A3	A-	BBB+
Senior unsecured	A3	A-	A-
Secured lease obligation bonds	A3	A-	A-
Commercial paper	P-2	A-2	F2
Outlook	Stable	Stable	Stable

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Off-Balance Sheet Arrangements

See Note 19 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, 2013 (dollars in millions):

	2014		2015- 2016		2017- 2018		Thereafter		Total
Long-term debt payments, including interest: (a)
APS	$	710	$	986	$	270	$	3,374	$	5,340
Pinnacle West	2		127		—		—		129
Total long-term debt payments, including interest	712		1,113		270		3,374		5,469
Short-term debt payments, including interest (b)	153		—		—		—		153
Fuel and purchased power commitments (c)	644		1,229		1,154		8,471		11,498
Renewable energy credits (d)	48		84		84		453		669
Purchase obligations (e)	85		37		39		246		407
Coal reclamation	1		9		28		170		208
Nuclear decommissioning funding requirements	17		19		4		66		106
Noncontrolling interests (f)	20		35		—		—		55
Operating lease payments	20		23		9		59		111
Total contractual commitments	$	1,700	$	2,549	$	1,588	$	12,839	$	18,676

(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, 2013 (see Note 6).

(b)The short-term debt represents commercial paper borrowings at APS (see Note 5).

(c)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).  These amounts include commitments incurred from acquiring SCE’s interest in Four Corners.

(d)Contracts to purchase renewable energy credits in compliance with the RES (see Note 3).

(e)These contractual obligations include commitments for capital expenditures and other obligations.

(f)Payments to the noncontrolling interests relate to the Palo Verde Sale Leaseback (see Note 19).  We have committed to retain the assets relating to the noncontrolling interests 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.  Such value is unknown at this time and is subject to an appraisal process. 

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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 $42 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain.  This table also excludes approximately zero, $19 million and $122 million in estimated minimum pension contributions for 2014, 2015 and 2016, respectively (see Note 8).

CRITICAL ACCOUNTING POLICIES

In preparing the financial statements in accordance with accounting principles generally accepted in the United States of America (“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 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 Arizona 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 $809 million of regulatory assets and $901 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2013.

Included in the balance of regulatory assets at December 31, 2013 is a regulatory asset of $314 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

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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, 2013 reported pension liability on the Consolidated Balance Sheets and our 2013 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):

	Increase (Decrease)
Actuarial Assumption (a)	Impact on Pension Liability			Impact on Pension Expense
Discount rate:
Increase 1%	$	(280	)	$	(14	)
Decrease 1%	337			16
Expected long-term rate of return on plan assets:
Increase 1%	—			(10		)
Decrease 1%	—			10

(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, 2013 reported other postretirement benefit obligation on the Consolidated Balance Sheets and our 2013 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%	$	(120	)	$	(7	)
Decrease 1%	151			9
Healthcare cost trend rate (b):
Increase 1%	149			13
Decrease 1%	(120		)	(10		)
Expected long-term rate of return on plan assets – pretax:
Increase 1%	—			(3		)
Decrease 1%	—			3

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(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 healthcare cost trend rate.

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

Fair Value Measurements

We account for derivative instruments, investments held in our nuclear decommissioning trust fund, 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 a discussion on accounting policies and Note 14 for further fair value measurement discussion.

OTHER ACCOUNTING MATTERS

During 2013, we adopted new accounting guidance relating to balance sheet offsetting disclosures, and disclosures of amounts reclassified from accumulated OCI.  During the first quarter of 2014 we are required to adopt new accounting guidance related to balance sheet presentation of certain unrecognized tax benefits.  See Note 2.

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 20) and benefit plan assets.  The nuclear decommissioning trust fund and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments.  Nuclear decommissioning and benefit plan costs are recovered in regulated electricity prices.

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, 2013 and

71

2012.  The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2013 and 2012 (dollars in thousands):

Pinnacle West – Consolidated

	Short-Term Debt				Variable-Rate Long-Term Debt				Fixed-Rate Long-Term Debt
	Interest				Interest				Interest
2013	Rates		Amount		Rates		Amount		Rates		Amount
2014	0.23	%	$	153,125	—		$	—	5.58	%	$	540,424
2015	—		—		1.02	%	157,000		4.79	%	313,420
2016	—		—		0.06	%	43,580		6.15	%	314,000
2017	—		—		—		—		—		—
2018	—		—		—		—		1.75	%	32,000
Years thereafter	—		—		—		—		6.12	%	1,940,150
Total			$	153,125	—		$	200,580			$	3,139,994
Fair value			$	153,125			$	200,580			$	3,378,102

	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

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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, 2013 and 2012.  The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2013 and 2012 (dollars in thousands):

APS — Consolidated

	Short-Term Debt				Variable-Rate Long-Term Debt				Fixed-Rate Long-Term Debt
	Interest				Interest				Interest
2013	Rates		Amount		Rates		Amount		Rates		Amount
2014	0.23	%	$	153,125	—		$	—	5.58	%	$	540,424
2015	—		—		0.03	%	32,000		4.79	%	313,420
2016	—		—		0.06	%	43,580		6.15	%	314,000
2017	—		—		—		—		—		—
2018	—		—		—		—		1.75	%	32,000
Years thereafter	—		—		—		—		6.12	%	1,940,150
Total			$	153,125	—		$	75,580			$	3,139,994
Fair value			$	153,125			$	75,580			$	3,378,102

	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

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.

73

The following table shows the net pretax changes in mark-to-market of our derivative positions in 2013 and 2012 (dollars in millions):

	2013			2012
Mark-to-market of net positions at beginning of year	$	(122	)	$	(222	)
Recognized in earnings (a):
Change in mark-to-market gains (losses) for future period deliveries	(1		)	1
Decrease in regulatory asset	6			37
Recognized in OCI:
Change in mark-to-market losses for future period deliveries (b)	—			(37		)
Mark-to-market losses realized during the period	44			99
Change in valuation techniques	—			—
Mark-to-market of net positions at end of year	$	(73	)	$	(122	)

(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, 2013 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	2014			2015			2016			2017			2018			Years thereafter			Total  fair  value
Observable prices provided by other external sources	$	(15	)	$	(6	)	$	(3	)	$	—		$	—		$	—		$	(24	)
Prices based on unobservable inputs	(11		)	(12		)	(12		)	(5		)	(4		)	(5		)	(49		)
Total by maturity	$	(26	)	$	(18	)	$	(15	)	$	(5	)	$	(4	)	$	(5	)	$	(73	)

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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, 2013 and 2012 (dollars in millions):

	December 31, 2013 Gain (Loss)					December 31, 2012 Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Earnings (a)
Natural gas	$	—	$	—		$	—	$	—
Regulatory asset (liability) or OCI (b)
Electricity	6		(6		)	7		(7		)
Natural gas	26		(26		)	25		(25		)
Total	$	32	$	(32	)	$	32	$	(32	)

(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 17 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.

75

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)	77
Report of Independent Registered Public Accounting Firm	78
Pinnacle West Consolidated Statements of Income for 2013, 2012 and 2011	80
Pinnacle West Consolidated Statements of Comprehensive Income for 2013, 2012, and 2011	81
Pinnacle West Consolidated Balance Sheets as of December 31, 2013 and 2012	82
Pinnacle West Consolidated Statements of Cash Flows for 2013, 2012 and 2011	84
Pinnacle West Consolidated Statements of Changes in Equity for 2013, 2012 and 2011	85
Notes to Pinnacle West’s Consolidated Financial Statements	86
Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)	153
Report of Independent Registered Public Accounting Firm	154
APS Consolidated Statements of Income for 2013, 2012 and 2011	156
APS Consolidated Statements of Comprehensive Income for 2013, 2012, and 2011	157
APS Consolidated Balance Sheets as of December 31, 2013 and 2012	158
APS Consolidated Statements of Cash Flows for 2013, 2012 and 2011	160
APS Consolidated Statements of Changes in Equity for 2013, 2012 and 2011	161
Supplemental Notes to APS’s Consolidated Financial Statements	163
Financial Statement Schedules for 2013, 2012 and 2011
Pinnacle West Schedule I – Condensed Statements of Comprehensive Income for 2013, 2012 and 2011	170
Pinnacle West Schedule I – Condensed Balance Sheets as of December 31, 2013 and 2012	171
Pinnacle West Schedule I – Condensed Statements of Cash Flows for 2013, 2012 and 2011	172
Pinnacle West Schedule II – Reserve for Uncollectibles for 2013, 2012 and 2011	173
APS Schedule II – Reserve for Uncollectibles for 2013, 2012 and 2011	174

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

76

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.  Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on our evaluation under the framework in Internal Control — Integrated Framework (1992), our management concluded that our internal control over financial reporting was effective as of December 31, 2013.  The effectiveness of our internal control over financial reporting as of December 31, 2013 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 21, 2014

77

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, 2013 and 2012 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, 2013.  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, 2013, based on criteria established in Internal Control — Integrated Framework (1992) 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.

78

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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, 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, 2013, based on the criteria established in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ Deloitte & Touche LLP

Phoenix, Arizona

February 21, 2014

79

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

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

	Year Ended December 31,
	2013			2012			2011
OPERATING REVENUES	$	3,454,628		$	3,301,804		$	3,241,379
OPERATING EXPENSES
Fuel and purchased power	1,095,709			994,790			1,009,464
Operations and maintenance	924,727			884,769			904,286
Depreciation and amortization	415,708			404,336			427,054
Taxes other than income taxes	164,167			159,323			147,408
Other expenses	7,994			6,831			6,659
Total	2,608,305			2,450,049			2,494,871
OPERATING INCOME	846,323			851,755			746,508
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction (Note 1)	25,581			22,436			23,707
Other income (Note 18)	1,704			1,606			3,111
Other expense (Note 18)	(16,024		)	(19,842		)	(10,451		)
Total	11,261			4,200			16,367
INTEREST EXPENSE
Interest charges	201,888			214,616			241,995
Allowance for borrowed funds used during construction (Note 1)	(14,861		)	(14,971		)	(18,358		)
Total	187,027			199,645			223,637
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	670,557			656,310			539,238
INCOME TAXES (Note 4)	230,591			237,317			183,604
INCOME FROM CONTINUING OPERATIONS	439,966			418,993			355,634
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $—, $(3,813) and $7,418 (Note 1)	—			(5,829		)	11,306
NET INCOME	439,966			413,164			366,940
Less: Net income attributable to noncontrolling interests (Note 19)	33,892			31,622			27,467
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	406,074		$	381,542		$	339,473
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	109,984			109,510			109,053
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	110,806			110,527			109,864
EARNINGS PER WEIGHTED — AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	3.69		$	3.54		$	3.01
Net income attributable to common shareholders — basic	3.69			3.48			3.11
Income from continuing operations attributable to common shareholders — diluted	3.66			3.50			2.99
Net income attributable to common shareholders — diluted	3.66			3.45			3.09
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	406,074		$	387,380		$	328,110
Discontinued operations, net of tax	—			(5,838		)	11,363
Net income attributable to common shareholders	$	406,074		$	381,542		$	339,473

See Notes to Pinnacle West’s Consolidated Financial Statements.

80

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)

	Year Ended December 31,
	2013			2012			2011
NET INCOME	$	439,966		$	413,164		$	366,940
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $140, $14,900, and $37,389 (Note 17)	(213		)	(22,763		)	(57,271		)
Reclassification of net realized loss, net of tax benefit of $17,472, $39,120, and $46,288 (Note 17)	26,747			59,887			70,902
Pension and other postretirement benefits activity, net of tax (expense) benefit of $(6,156), $(651), and $3,935 (Note 8)	9,421			1,031			(6,026		)
Total other comprehensive income	35,955			38,155			7,605
COMPREHENSIVE INCOME	475,921			451,319			374,545
Less: Comprehensive income attributable to noncontrolling interests	33,892			31,622			27,467
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	442,029		$	419,697		$	347,078

See Notes to Pinnacle West’s Consolidated Financial Statements.

81

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	December 31,
	2013			2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	9,526		$	26,202
Customer and other receivables	299,904			277,225
Accrued unbilled revenues	96,796			94,845
Allowance for doubtful accounts	(3,203		)	(3,340		)
Materials and supplies (at average cost)	221,682			218,096
Fossil fuel (at average cost)	38,028			31,334
Deferred income taxes (Note 4)	91,152			152,191
Income tax receivable (Note 4)	135,517			2,423
Assets from risk management activities (Note 17)	17,169			25,699
Deferred fuel and purchased power regulatory asset (Note 3)	20,755			72,692
Other regulatory assets (Note 3)	76,388			71,257
Other current assets	39,895			37,102
Total current assets	1,043,609			1,005,726
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 17)	23,815			35,891
Nuclear decommissioning trust (Notes 14 and 20)	642,007			570,625
Other assets	60,875			62,694
Total investments and other assets	726,697			669,210
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 10)
Plant in service and held for future use	15,200,464			14,346,367
Accumulated depreciation and amortization	(5,300,219		)	(4,929,613		)
Net	9,900,245			9,416,754
Construction work in progress	581,369			565,716
Palo Verde sale leaseback, net of accumulated depreciation of $225,925 and $222,055 (Note 19)	125,125			128,995
Intangible assets, net of accumulated amortization of $439,703 and $411,543	157,689			162,150
Nuclear fuel, net of accumulated amortization of $146,057 and $133,950	124,557			122,778
Total property, plant and equipment	10,888,985			10,396,393
DEFERRED DEBITS
Regulatory assets (Notes 1, 3 and 4)	711,712			1,099,900
Income tax receivable (Note 4)	—			70,389
Other	137,683			137,997
Total deferred debits	849,395			1,308,286
TOTAL ASSETS	$	13,508,686		$	13,379,615

See Notes to Pinnacle West’s Consolidated Financial Statements.

82

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	December 31,
	2013			2012
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	284,516		$	221,312
Accrued taxes (Note 4)	130,998			124,939
Accrued interest	48,351			49,380
Common dividends payable	62,528			59,789
Short-term borrowings (Note 5)	153,125			92,175
Current maturities of long-term debt (Note 6)	540,424			122,828
Customer deposits	76,101			79,689
Liabilities from risk management activities (Note 17)	31,892			73,741
Liability for asset retirements (Note 12)	32,896			—
Regulatory liabilities (Note 3)	99,273			88,116
Other current liabilities	158,540			171,573
Total current liabilities	1,618,644			1,083,542
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)	2,796,465			3,199,088
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)	2,351,882			2,151,371
Regulatory liabilities (Notes 1, 3 and 4)	801,297			759,201
Liability for asset retirements (Note 12)	313,833			357,097
Liabilities for pension and other postretirement benefits (Note 8)	513,628			1,058,755
Liabilities from risk management activities (Note 17)	70,315			85,264
Customer advances	114,480			109,359
Coal mine reclamation	207,453			118,860
Deferred investment tax credit	152,361			99,819
Unrecognized tax benefits (Note 4)	42,209			71,135
Other	185,659			183,835
Total deferred credits and other	4,753,117			4,994,696
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY (Note 7)
Common stock, no par value; authorized 150,000,000 shares, issued 110,280,703 at end of 2013 and 109,837,957 at end of 2012	2,491,558			2,466,923
Treasury stock at cost; 98,944 shares at end of 2013 and 95,192 shares at end of 2012	(4,308		)	(4,211		)
Total common stock	2,487,250			2,462,712
Retained earnings	1,785,273			1,624,102
Accumulated other comprehensive loss:
Pension and other postretirement benefits (Note 8)	(54,995		)	(64,416		)
Derivative instruments (Note 17)	(23,058		)	(49,592		)
Total accumulated other comprehensive loss	(78,053		)	(114,008		)
Total shareholders’ equity	4,194,470			3,972,806
Noncontrolling interests (Note 19)	145,990			129,483
Total equity	4,340,460			4,102,289
TOTAL LIABILITIES AND EQUITY	$	13,508,686		$	13,379,615

See Notes to Pinnacle West’s Consolidated Financial Statements.

83

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

	Year Ended December 31,
	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	439,966		$	413,164		$	366,940
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sale of energy-related products and services business	—			—			(10,404		)
Depreciation and amortization including nuclear fuel	492,322			481,262			493,784
Deferred fuel and purchased power	21,678			71,573			69,166
Deferred fuel and purchased power amortization	31,190			(116,716		)	(155,157		)
Allowance for equity funds used during construction	(25,581		)	(22,436		)	(23,707		)
Deferred income taxes	249,296			187,023			117,952
Deferred investment tax credit	52,542			41,579			58,240
Change in derivative instruments fair value	534			(749		)	4,064
Changes in current assets and liabilities:
Customer and other receivables	(44,991		)	14,587			40,626
Accrued unbilled revenues	(1,951		)	30,394			(21,947		)
Materials, supplies and fossil fuel	(11,878		)	(23,043		)	(23,398		)
Income tax receivable	(133,094		)	(4,043		)	3,983
Other current assets	(17,913		)	(27,352		)	(3,079		)
Accounts payable	45,414			(96,600		)	58,346
Accrued taxes	6,059			12,736			8,085
Other current liabilities	(7,513		)	23,869			20,358
Change in margin and collateral accounts — assets	993			2,216			33,349
Change in margin and collateral accounts — liabilities	12,355			137,785			29,731
Change in long-term income tax receivable	137,270			(1,756		)	(3,530		)
Change in unrecognized tax benefits	(91,425		)	(2,583		)	8,410
Change in other regulatory liabilities	64,473			13,539			37,009
Change in other long-term assets	(41,757		)	6,872			(41,722		)
Change in other long-term liabilities	(24,682		)	29,801			58,484
Net cash flow provided by operating activities	1,153,307			1,171,122			1,125,583
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,016,322		)	(889,551		)	(884,350		)
Contributions in aid of construction	41,090			49,876			38,096
Allowance for borrowed funds used during construction	(14,861		)	(14,971		)	(18,358		)
Proceeds from sale of energy-related products and services business	—			—			45,111
Proceeds from nuclear decommissioning trust sales	446,025			417,603			497,780
Investment in nuclear decommissioning trust	(463,274		)	(434,852		)	(513,799		)
Proceeds from sale of life insurance policies	—			—			55,444
Other	(2,059		)	(1,099		)	(1,931		)
Net cash flow used for investing activities	(1,009,401		)	(872,994		)	(782,007		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	136,307			476,081			470,353
Repayment of long-term debt	(122,828		)	(654,286		)	(655,169		)
Short-term borrowings and payments — net	60,950			92,175			(16,600		)
Dividends paid on common stock	(235,244		)	(225,075		)	(221,728		)
Common stock equity issuance	17,319			15,955			15,841
Distributions to noncontrolling interests	(17,385		)	(10,529		)	(10,210		)
Other	299			170			(2,668		)
Net cash flow used for financing activities	(160,582		)	(305,509		)	(420,181		)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(16,676		)	(7,381		)	(76,605		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	26,202			33,583			110,188
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	9,526		$	26,202		$	33,583

See Notes to Pinnacle West’s Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(dollars in thousands, except per share amounts)

	Year Ended December 31,
	2013			2012			2011
COMMON STOCK (Note 7)
Balance at beginning of year	$	2,466,923		$	2,444,247		$	2,421,372
Issuance of common stock	24,635			22,676			22,875
Balance at end of year	2,491,558			2,466,923			2,444,247
TREASURY STOCK (Note 7)
Balance at beginning of year	(4,211		)	(4,717		)	(2,239		)
Purchase of treasury stock	(9,727		)	(4,607		)	(3,720		)
Reissuance of treasury stock used for stock compensation	9,630			5,113			1,242
Balance at end of year	(4,308		)	(4,211		)	(4,717		)
RETAINED EARNINGS
Balance at beginning of year	1,624,102			1,534,483			1,423,961
Net income attributable to common shareholders	406,074			381,542			339,473
Common stock dividends declared ($2.23, $2.67, and $2.10 per share)	(244,903		)	(291,923		)	(228,951		)
Balance at end of year	1,785,273			1,624,102			1,534,483
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Balance at beginning of year	(114,008		)	(152,163		)	(159,767		)
Other comprehensive income attributable to common shareholders	35,955			38,155			7,604
Balance at end of year	(78,053		)	(114,008		)	(152,163		)
NONCONTROLLING INTERESTS
Balance at beginning of year	129,483			108,736			91,899
Net income attributable to noncontrolling interests	33,892			31,622			27,467
Net capital activities by noncontrolling interests	(17,385		)	(10,875		)	(10,630		)
Balance at end of year	145,990			129,483			108,736
TOTAL EQUITY	$	4,340,460		$	4,102,289		$	3,930,586
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
Net income attributable to common shareholders	$	406,074		$	381,542		$	339,473
Other comprehensive income	35,955			38,155			7,605
Comprehensive income attributable to common shareholders	$	442,029		$	419,697		$	347,078

See Notes to Pinnacle West’s Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 and essentially all of these assets were sold in 2009 and 2010.  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 reported as discontinued operations.  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 reported as discontinued operations.  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 19).

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.

Certain line items are presented in more detail on the Consolidated Balance Sheets and Consolidated Statements of Cash Flows than was presented in the prior years.  Other line items are more condensed than the previous presentation.  The prior year amounts were reclassified to conform to the current year presentation.  These reclassifications had no impact on total assets or net cash flow provided by operating activities.  The following tables show the impacts of the reclassifications of prior years (previously reported) amounts (dollars in thousands):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Balance Sheets - December 31, 2012	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Long-Term Debt less Current Maturities —
Long-term debt less current maturities	$	3,160,219	$	38,869		$	3,199,088
Long-Term Debt less Current Maturities —
Palo Verde sale leaseback lessor notes less
current maturities	38,869		(38,869		)	—

Statement of Cash Flows for the Year Ended December 31, 2012	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
Deferred income taxes	$	228,602	$	(41,579	)	$	187,023
Deferred investment tax credit	—		41,579			41,579
Accrued taxes and income tax receivable	8,693		(8,693		)	—
Income tax receivable	—		(4,043		)	(4,043		)
Accrued taxes	—		12,736			12,736

Statement of Cash Flows for the Year Ended December 31, 2011	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
Deferred income taxes	$	176,192	$	(58,240	)	$	117,952
Deferred investment tax credit	—		58,240			58,240
Accrued taxes and income tax receivable	12,068		(12,068		)	—
Income tax receivable	—		3,983			3,983
Accrued taxes	—		8,085			8,085

Accounting Records and Use of Estimates

Our accounting records are maintained in accordance with 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Regulatory Accounting

APS is regulated by the ACC and 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 Arizona 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 by customer class 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 Settlement Agreement (see Note 3).  Effective July 1, 2012, as a result of the 2012 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Property, Plant and Equipment

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 calculated 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, 2013 were as follows:

·Fossil plant — 18 years;

·Nuclear plant — 26 years;

·Other generation — 26 years;

·Transmission — 37 years;

·Distribution — 34 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 use of the new Palo Verde nuclear plant lives, effective January 1, 2012.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pursuant to an ACC order, we defer operating costs related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  See Note 3 for further discussion.  These costs are deferred on the depreciation line of the Consolidated Statements of Income.

For the years 2011 through 2013, the depreciation rates ranged from a low of 0.45% to a high of 12.08%.  The weighted-average rate was 3.00% for 2013, 2.71% for 2012, and 2.98% for 2011.

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 8.56% for 2013, 8.60% for 2012, and 10.25% for 2011.  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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 17 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 an other postretirement benefit plan for the employees of Pinnacle West and our subsidiaries that provides 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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,
	2013		2012		2011
Cash paid during the period for:
Income taxes, net of refunds	$	18,537	$	2,543	$	10,324
Interest, net of amounts capitalized	184,010		200,923		217,789
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	33,184	$	26,208	$	27,245
Dividends declared but not paid	62,528		59,789		—
Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 3)	145,609		—		—

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 $53 million in 2013, $50 million in 2012, and $47 million in 2011.  Estimated amortization expense on existing intangible assets over the next five years is $47 million in 2014, $38 million in 2015, $29 million in 2016, $19 million in 2017, and $7 million in 2018.  At December 31, 2013, 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 20 for more information on these investments.

Business Segments

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. All other segment activities are insignificant.

2.New Accounting Standards

During 2013, we adopted, on a retrospective basis, new guidance relating to balance sheet offsetting disclosures.  The new guidance requires enhanced disclosures regarding an entity’s ability to offset certain instruments on the balance sheet and how offsetting impacts the balance sheet.  The adoption of this guidance resulted in expanded disclosures relating to our derivative instruments (see Note 17), but did not impact our financial statement results.

During 2013, we also adopted, on a prospective basis, new guidance relating to reporting amounts reclassified from accumulated other comprehensive income.  This guidance requires new disclosures relating to accumulated other comprehensive income and how reclassifications from accumulated other comprehensive income impact net income.  As a result of adopting this new guidance, we have included a new footnote disclosure to provide the information required by the new standard (see Notes 21 and S-4).  The adoption of this guidance did not impact our financial statement results.

In July 2013, new guidance was issued which will generally require entities to present unrecognized tax benefits as a reduction to any available deferred tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward.  The intent of this guidance is to eliminate diversity in practice in the presentation of certain unrecognized tax benefits.  The new guidance is effective for us during the first quarter of 2014, and is permitted to be adopted using either a prospective or retrospective application.  Currently, we do not present unrecognized tax benefits as a reduction to deferred tax asset carryforwards on the balance sheet.  As a result, the adoption of this new guidance

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

will impact our balance sheet presentation; however, we do not expect these presentation changes to be material to our balance sheet.  The adoption of this new guidance will not impact our results of operations or cash flows.

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 by approximately 6.6%.  On January 6, 2012, APS and other parties to the general retail rate case entered into the 2012 Settlement Agreement detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications.

Settlement Agreement

The 2012 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 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 2012 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 2012 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 2012 Settlement Agreement.

Other key provisions of the 2012 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;

·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;

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

·A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners (APS made its filing under this provision on December 30, 2013, which would result in an average bill impact to residential customers of approximately 2% if approved as requested);

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

·Modifications to the Environmental Improvement Surcharge 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 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 2009 Settlement Agreement discussed below;

·Allowing a negative credit that existed 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 2012 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 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs 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 the 2009 Settlement Agreement entered into by APS and twenty-one other parties.  The 2009 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 $700 million during the period beginning June 1, 2009 through December 31, 2014 and compliance with various

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

financial conditions, including the maintenance of a prescribed capital structure (APS was able to meet these conditions without the need for additional equity infusions beyond the $253 million infused into APS in the second quarter of 2010); and

·Renewable energy programs that require APS to expand its use of renewable energy through 2015, as well as allow for concurrent recovery of renewable energy expenses.

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 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million.  In a final order dated January 7, 2014, the ACC approved the requested budget.  Also in 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits.  On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules so that utilities can establish compliance without using renewable energy credits.

On July 12, 2013, APS filed an application with the ACC proposing a solution to fix the cost shift brought by the current net metering rules.  In its application, APS requested that the ACC cause all new residential customers installing new rooftop solar systems to either:  (i) take electric service under APS’s demand-based ECT-2 rate and remain eligible for net metering; or (ii) take service under the customer’s existing rate as if no distributed energy system was installed and receive a bill credit for 100% of the distributed energy system’s output at a market-based price.  APS also proposed that the ACC:  (i) grandfather current rates and use of net metering for existing and immediately pending distributed energy customers; and (ii) continue using direct cash incentives for new distributed energy installations.

On December 3, 2013, the ACC issued its order on APS’s net metering proposal.  The ACC instituted a charge on future customers who install rooftop solar panels and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid. The new policy will be in effect until the next APS rate case.

In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the

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electrical grid.  ACC professional staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists. The fixed charge does not increase APS’s revenue, but instead will modestly reduce the impact of the cost shift on non-solar customers. The ACC acknowledged that the new charge addresses only a portion of the cost shift.

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.

On June 1, 2011, APS filed its 2012 Demand Side Management Implementation Plan consistent with the ACC’s Electric Energy Efficiency Rules, 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 2009 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.  This amount was recovered by the then existing DSMAC over a twelve-month period beginning March 1, 2012.  This amount does not include $10 million already being recovered in general retail base rates, but does include amortization of 2009 costs (approximately $5 million of the $72 million).

On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan.  In 2013, the standards 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.

The ACC Staff recommendation and proposed order, issued on October 30, 2013, largely recommended continuing the status quo, although at lower funding levels.  ACC Staff recommended approval of all existing cost-effective energy efficiency and demand response programs and a budget of $68.9 million going forward.  APS expects to receive a decision from the ACC in early 2014.

On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified or abolished.  This spring the ACC will hold a series of three workshops to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

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 1st (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;

·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);

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·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 for 2013 and 2012 (dollars in millions):

	Twelve Months Ended December 31,
	2013			2012
Beginning balance	$	73		$	28
Deferred fuel and purchased power costs - current period	(21		)	(72		)
Amounts (charged) credited to customers	(31		)	117
Ending balance	$	21		$	73

The PSA rate for the PSA year beginning February 1, 2014 is $0.001557 per kWh, as compared to $0.001329 per kWh for the prior year.  This represents a $0.000228 per kWh increase over the 2013 PSA charge.  This new rate is comprised of a forward component of $0.001277 per kWh and a historical component of $0.000280 per kWh.  Any uncollected (overcollected) deferrals during the 2014 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2015.

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.  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 2012 Settlement Agreement (discussed above), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

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

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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- or under-collected amounts.

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.

Effective June 1, 2013, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $26 million for the twelve-month period beginning June 1, 2013 in accordance with the FERC-approved formula.  Pursuant to the 2012 Settlement Agreement (discussed above), an adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2013.

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 APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement 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 APS’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 a LFCR adjustment every January thereafter.  On February 12, 2013, the ACC approved a LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the 2012 Settlement Agreement went into effect on July 1, 2012.  APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014.  APS anticipates that the ACC will consider whether to approve APS’s LFCR adjustment prior to the end of March 2014.

Deregulation

On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.  The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state.  One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution.  On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Constitutional authority before any further examination of this matter.  The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.  The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry.  Workshops in this docket are expected to be held in 2014.

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Four Corners

On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners.  As a result of this purchase, APS now owns 63% of Units 4 and 5.  APS has a total entitlement from Four Corners of 970 MW.  The final purchase price for the interest was approximately $182 million.  APS acquired assets and assumed certain of SCE’s decommissioning and mine reclamation obligations.  We have recognized plant-in-service, net of accumulated depreciation, of $316 million, which includes an acquisition adjustment of $255 million.  In addition, we have recognized a liability of $34 million for the decommissioning obligations, $93 million for the mine reclamation obligations, $18 million of other various liabilities, and $11 million of construction work in progress relating to this purchase.  These amounts are subject to revision during the measurement period, not to exceed one year, to the extent additional information is obtained about the facts and circumstances that existed as of the acquisition date.  While we expect the ACC to approve the recovery of the acquisition adjustment, should recovery be disallowed, it will be reclassified from plant-in-service to goodwill, subject to impairment testing.  The decommissioning and mine reclamation obligations were recognized at their fair value.  Because APS’s rates are regulated, APS expects to recover the costs of the acquired plant assets, including a return on its investment based on its cost of capital.  APS believes this return is consistent with what a market participant would consider to be fair value in APS’s regulatory environment.  Accordingly, APS believes the cost of the plant assets approximate their fair value.

The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  APS made its filing under this provision on December 30, 2013.  This includes deferral for future recovery of all non-fuel operating cost for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Four Corners Units 1-3.  The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Four Corners Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Four Corners Units 1-3 was $37 million as of December 31, 2013.

As part of APS’s acquisition of SCE’s interest in Units 4 and 5 of Four Corners, APS and SCE agreed, via a “Transmission Termination Agreement,” that upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination.  APS and SCE negotiated an alternate arrangement under which SCE will assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group for transmission of the additional power received from Four Corners.  This arrangement becomes effective upon FERC approval and will remain in effect until the net payments received by SCE in connection with the assignments reach $40 million, at which time the arrangement and the Transmission Agreement will terminate.  APS believes that FERC will approve the alternate arrangement as filed but, if not approved, SCE and APS will again be subject to the terms of the Transmission Termination Agreement.  As we previously disclosed, APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement.  If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration.  APS is unable to predict the outcome of this matter if it proceeds to arbitration.

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Regulatory Assets and Liabilities

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

	Remaining Amortization		December 31, 2013				December 31, 2012
	Period		Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	(a	)	$	—	$	314	$	—	$	780
Income taxes — AFUDC equity	2043		4		105		4		92
Deferred fuel and purchased power — mark-to-market (Note 17)	2016		5		29		19		21
Transmission vegetation management	2016		9		14		9		23
Coal reclamation	2038		8		18		8		24
Palo Verde VIEs (Note 19)	2046		—		41		—		38
Deferred compensation	2036		—		34		—		34
Deferred fuel and purchased power (b) (c)	2014		21		—		73		—
Tax expense of Medicare subsidy	2023		2		15		2		17
Loss on reacquired debt	2034		1		17		2		18
Income taxes — investment tax credit basis adjustment	2043		1		39		1		26
Pension and other postretirement benefits deferral	2015		8		4		8		13
Four Corners cost deferral	2024		—		37		—		—
Lost fixed cost recovery	2014		25		—		7		—
Transmission cost adjustor	2015		8		2		10		—
Retired power plant costs	2020		3		18		—		—
Other	Various		2		25		1		14
Total regulatory assets (d)			$	97	$	712	$	144	$	1,100

(a)This asset represents the future recovery of under-funded pension and other postretirement benefit obligations 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.  See Note 8 for further discussion.

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

(c)Subject to a carrying charge.

(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.”

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

	Remaining Amortization		December 31, 2013				December 31, 2012
	Period		Current		Non-Current		Current		Non-Current
Removal costs	(a	)	$	28	$	303	$	27	$	321
Asset retirement obligations	(a	)	—		266		—		256
Renewable energy standard (b)	2015		33		15		43		—
Income taxes — change in rates	2043		—		74		—		66
Spent nuclear fuel	2047		6		36		10		36
Deferred gains on utility property	2019		2		10		2		12
Income taxes — deferred investment tax credit	2043		3		79		2		52
Demand side management (b)	2014		27		—		4		—
Other	Various		—		18		—		16
Total regulatory liabilities			$	99	$	801	$	88	$	759

(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 statement purposes.  The tax effect of these differences is recorded as deferred taxes.  We calculate deferred taxes using 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 ITCs 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 $70 million long-term income tax receivable on the Consolidated Balance Sheets as of December 31, 2012 represented the anticipated refund related to an APS tax accounting method change approved by the IRS in the third quarter of 2009.  On July 9, 2013, IRS guidance was released which provided clarification regarding the timing and amount of this cash receipt.  As a result of this guidance, uncertain tax positions decreased $67 million during the third quarter.  This decrease in uncertain tax positions resulted in a corresponding increase to the total anticipated refund due from the IRS and an offsetting increase in long-term deferred tax liabilities.  Additionally, as a result of this IRS guidance, the resulting $137 million anticipated refund was reclassified to current income tax receivable.

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During the year ended December 31, 2013, the IRS finalized the examination of tax returns for the years ended December 31, 2008 and 2009, and the $137 million anticipated refund was reduced by approximately $4 million to reflect the outcome of this examination.  On December 17, 2013, the Joint Committee on Taxation approved the anticipated refund.  Cash related to this refund was received in the first quarter of 2014.

On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property.  These final regulations apply to tax years beginning on or after January 1, 2014.  Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS, resulting in a cumulative effect adjustment.  To account for the adoption of these regulations, plant-related long-term deferred tax liabilities decreased by $84 million, with the offsetting decrease to current deferred income tax assets.  Prior to the issuance of these regulations, this $84 million would have been repaid over 20 years through lower tax depreciation deductions.

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 19).  As a result, there is no income tax expense associated with the VIEs recorded on the Consolidated Statements of Income.

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):

	2013			2012			2011
Total unrecognized tax benefits, January 1	$	133,422		$	136,005		$	127,595
Additions for tax positions of the current year	3,516			5,167			10,915
Additions for tax positions of prior years	13,158			—			—
Reductions for tax positions of prior years for:
Changes in judgment	(108,099		)	(7,729		)	(1,555		)
Settlements with taxing authorities	—			—			(124		)
Lapses of applicable statute of limitations	—			(21		)	(826		)
Total unrecognized tax benefits, December 31	$	41,997		$	133,422		$	136,005

Included in the balances of unrecognized tax benefits at December 31, 2013, 2012 and 2011 were approximately $10 million, $10 million and $8 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, 2010 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 2010.

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

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Statements of Income related to unrecognized tax benefits was a pre-tax benefit of $4 million for 2013, a pre-tax expense of $4 million for 2012, and a pre-tax expense of $3 million for 2011.

The total amount of accrued liabilities for interest recognized in the Consolidated Balance Sheets related to unrecognized tax benefits was less than $1 million as of December 31, 2013, $13 million as of December 31, 2012 and $9 million as of December 31, 2011.  To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate.  Additionally, as of December 31, 2013, 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,
	2013			2012			2011
Current:
Federal	$	(81,784	)	$	(3,493	)	$	(310	)
State	10,537			8,395			15,140
Total current	(71,247		)	4,902			14,830
Deferred:
Federal	279,973			200,322			159,566
State	21,865			28,280			16,626
Total deferred	301,838			228,602			176,192
Total income tax expense	230,591			233,504			191,022
Less: income tax expense (benefit) on discontinued operations	—			(3,813		)	7,418
Income tax expense — continuing operations	$	230,591		$	237,317		$	183,604

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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,
	2013			2012			2011
Federal income tax expense at 35% statutory rate	$	234,695		$	229,709		$	188,733
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	21,387			23,819			19,594
Credits and favorable adjustments related to prior years resolved in current year	(3,356		)	—			—
Medicare Subsidy Part-D	823			483			823
Allowance for equity funds used during construction (see Note 1)	(6,997		)	(6,158		)	(6,881		)
Palo Verde VIE noncontrolling interest (see Note 19)	(11,862		)	(11,065		)	(9,636		)
Other	(4,099		)	529			(9,029		)
Income tax expense — continuing operations	$	230,591		$	237,317		$	183,604

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

	December 31,
	2013			2012
Current asset	$	91,152		$	152,191
Long-term liability	(2,351,882		)	(2,151,371		)
Deferred income taxes — net	$	(2,260,730	)	$	(1,999,180	)

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, 2013 APS has recorded a regulatory liability of $75 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five-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 New Mexico. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability.  As of December 31, 2013, APS has recorded a regulatory liability of $2

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million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

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

	December 31,
	2013			2012
DEFERRED TAX ASSETS
Risk management activities	$	44,920		$	72,243
Regulatory liabilities:
Asset retirement obligation and removal costs	235,959			238,669
Unamortized investment tax credits	82,116			53,837
Other	42,609			33,764
Pension and other postretirement liabilities	198,642			408,764
Renewable energy incentives	65,434			66,941
Credit and loss carryforwards	133,070			139,022
Other	148,492			68,844
Total deferred tax assets	951,242			1,082,084
DEFERRED TAX LIABILITIES
Plant-related	(2,903,730		)	(2,584,166		)
Risk management activities	(16,191		)	(23,940		)
Regulatory assets:
Allowance for equity funds used during construction	(43,058		)	(37,899		)
Deferred fuel and purchased power	(8,282		)	(28,858		)
Deferred fuel and purchased power — mark-to-market	(13,343		)	(15,796		)
Pension and other postretirement benefits	(129,250		)	(316,757		)
Other	(93,202		)	(68,170		)
Other	(4,916		)	(5,678		)
Total deferred tax liabilities	(3,211,972		)	(3,081,264		)
Deferred income taxes — net	$	(2,260,730	)	$	(1,999,180	)

As of December 31, 2013, the deferred tax assets for credit and loss carryforwards relate to federal general business credits of $131 million which first begin to expire in 2031, and other federal and state loss carryforwards of $2 million which first begin to expire in 2018.

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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, 2013 (dollars in millions):

Credit Facility	Expiration	Amount Committed		Unused Amount (a)		Commitment Fees
Pinnacle West Revolving Credit Facility	November 2016	$	200	$	200	0.175	%
APS Revolving Credit Facility	November 2016	500		347		0.125	%
APS Revolving Credit Facility	April 2018	500		500		0.125	%
Total		$	1,200	$	1,047

(a)At December 31, 2013, APS had $153 million of outstanding commercial paper.  Accordingly, at such date, the total combined amount available under its two $500 million credit facilities was $847 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, 2013, 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, 2013, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit and no commercial paper borrowings.

APS

On April 9, 2013, APS refinanced its $500 million revolving credit facility that would have matured in February 2015, with a new $500 million facility.  The new revolving credit facility matures in April 2018.

At December 31, 2013, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that was refinanced in April 2013 (see above) and a $500 million credit 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 can use these facilities to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

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, 2013, APS had no outstanding borrowings or letters of credit under its revolving credit facilities.  In addition, APS had commercial paper borrowings of $153 million at December 31, 2013.

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See “Financial Assurances” in Note 11 for a 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, 2012 (dollars in millions):

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 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 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 a discussion of APS’s separate outstanding letters of credit.

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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, subject to specified parameters and procedures, it (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, 2013 and 2012 (dollars in thousands):

	Maturity	Interest	December 31,
	Dates (a)	Rates	2013			2012
APS
Pollution Control Bonds:
Variable	2029-2038	(b)	$	75,580		$	75,580
Fixed	2024-2034	1.25%-6.00%	426,125			490,275
Total Pollution Control Bonds			501,705			565,855
Senior unsecured notes	2014-2042	4.50%-8.75%	2,675,000			2,575,000
Palo Verde sale leaseback lessor notes	2015	8.00%	38,869			65,547
Unamortized discount			(8,732		)	(9,486		)
Unamortized premium			5,047			—
Total APS long-term debt			3,211,889			3,196,916
Less current maturities	(d)		540,424			122,828
Total APS long-term debt less current maturities			2,671,465			3,074,088
Pinnacle West
Term loan	2015	(c)	125,000			125,000
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES			$	2,796,465		$	3,199,088

(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 0.03%-0.06% at December 31, 2013 and 0.13%-0.15% at December 31, 2012.

(c)The weighted-average interest rate was 1.269% at December 31, 2013 and 1.312% at December 31, 2012.

(d)Current maturities include $215 million of pollution control bonds expected to be remarketed in 2014 and $300 million in senior unsecured notes that mature in 2014.

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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
2014	$	540	$	540
2015	470		345
2016	358		358
2017	—		—
2018	32		32
Thereafter	1,940		1,940
Total	$	3,340	$	3,215

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, 2013				As of December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	125	$	125	$	125
APS	3,212		3,454		3,197		3,750
Total	$	3,337	$	3,579	$	3,322	$	3,875

Credit Facilities and Debt Issuances

APS

On March 22, 2013, APS issued an additional $100 million par amount of its outstanding 4.50% unsecured senior notes that mature on April 1, 2042.  The net proceeds from the sale were used to repay short-term commercial paper borrowings and replenish cash used to redeem certain tax-exempt indebtedness in November 2012.

On May 1, 2013, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series C, due 2029.  On May 28, 2013, we remarketed the bonds.  The interest rate for these bonds was set to a new term rate.  The new term rate for these bonds ends, subject to a mandatory tender, on May 30, 2018.  During this time, the bonds will bear interest at a rate of 1.75% per annum.  These bonds are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2013 and were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.

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On July 12, 2013, APS purchased all $33 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 1994 Series A, due 2029.  On January 15, 2014, these bonds were canceled.  These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.

On October 11, 2013, APS purchased all $32 million of the City of Farmington, New Mexico Pollution Control Revenue Bonds, 1994 Series C, due 2024.  On January 15, 2014, these bonds were canceled.  These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.

On January 10, 2014, APS issued $250 million of 4.70% unsecured senior notes that mature on January 15, 2044.  The proceeds from the sale were used to repay commercial paper which was used to fund the purchase price and costs associated with the acquisition of SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners and to replenish cash used to re-acquire two series of tax-exempt indebtedness.

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

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, 2013, the ratio was approximately 47% 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.

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, 2013, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.3 billion, and total capitalization was approximately $7.5 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.0 billion, assuming APS’s total capitalization remains the

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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 2013, 2012 and 2011 is as follows (dollars in thousands):

	Common Stock			Treasury Stock
	Shares	Amount		Shares		Amount
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 (a)	—	—		(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 (a)	—	—		(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		)
Common stock issuance	442,746	24,635		—		—
Purchase of treasury stock (a)	—	—		(174,290	)	(9,727		)
Reissuance of treasury stock for stock compensation	—	—		170,538		9,630
Balance at December 31, 2013	110,280,703	$	2,491,558	(98,944	)	$	(4,308	)

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

At December 31, 2013, 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 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.

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Pinnacle West also sponsors an other 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 further 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 $8 million during 2013 and $4 million during 2012.

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
	2013			2012			2011			2013			2012			2011
Service cost-benefits earned during the period	$	64,195		$	63,502		$	57,605		$	23,597		$	27,163		$	21,856
Interest cost on benefit obligation	112,392			119,586			124,727			41,536			46,467			46,807
Expected return on plan assets	(146,333		)	(140,979		)	(133,678		)	(45,717		)	(45,793		)	(41,536		)
Amortization of:
Transition obligation	—			—			—			—			452			452
Prior service cost (credit)	1,097			1,143			1,400			(179		)	(179		)	(179		)
Net actuarial loss	39,852			44,250			25,956			11,310			20,233			15,015
Net periodic benefit cost	$	71,203		$	87,502		$	76,010		$	30,547		$	48,343		$	42,415
Portion of cost charged to expense	$	38,968		$	36,333		$	29,312		$	18,469		$	19,321		$	15,208

The following table shows the plans’ changes in the benefit obligations and funded status for the years 2013 and 2012 (dollars in thousands):

	Pension						Other Benefits
	2013			2012			2013			2012
Change in Benefit Obligation
Benefit obligation at January 1	$	2,850,846		$	2,699,126		$	990,418		$	1,047,094
Service cost	64,195			63,502			23,597			27,163
Interest cost	112,392			119,586			41,536			46,467
Benefit payments	(125,269		)	(113,632		)	(26,675		)	(26,279		)
Actuarial (gain) loss	(255,634		)	82,264			(138,458		)	(104,027		)
Benefit obligation at December 31	2,646,530			2,850,846			890,418			990,418
Change in Plan Assets
Fair value of plan assets at January 1	2,079,181			1,850,550			684,221			608,663
Actual return on plan assets	150,546			259,363			76,995			83,567
Employer contributions	140,500			65,000			14,438			22,707
Benefit payments	(106,106		)	(95,732		)	(27,315		)	(30,716		)
Fair value of plan assets at December 31	2,264,121			2,079,181			748,339			684,221
Funded Status at December 31	$	(382,409	)	$	(771,665	)	$	(142,079	)	$	(306,197	)

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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, 2013 and 2012 (dollars in thousands):

	2013		2012
Projected benefit obligation	$	2,646,530	$	2,850,846
Accumulated benefit obligation	2,469,889		2,646,306
Fair value of plan assets	2,264,121		2,079,181

The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2013 and 2012 (dollars in thousands):

	Pension						Other Benefits
	2013			2012			2013			2012
Current liability	$	(10,860	)	$	(19,107	)	$	—		$	—
Noncurrent liability	(371,549		)	(752,558		)	(142,079		)	(306,197		)
Net amount recognized	$	(382,409	)	$	(771,665	)	$	(142,079	)	$	(306,197	)

The following table shows the details related to accumulated other comprehensive loss as of December 31, 2013 and 2012 (dollars in thousands):

	Pension						Other Benefits
	2013			2012			2013			2012
Net actuarial loss	$	344,540		$	644,239		$	57,816		$	238,862
Prior service cost (credit)	2,072			3,169			(296		)	(475		)
APS’s portion recorded as a regulatory asset	(265,107		)	(550,471		)	(49,298		)	(230,020		)
Income tax benefit	(32,204		)	(38,303		)	(2,528		)	(2,585		)
Accumulated other comprehensive loss	$	49,301		$	58,634		$	5,694		$	5,782

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 2014 (dollars in thousands):

	Pension		Other Benefits
Net actuarial loss	$	8,363	$	—
Prior service cost (credit)	874		(179		)
Total amounts estimated to be amortized from accumulated other comprehensive loss and regulatory assets in 2014	$	9,237	$	(179	)

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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:

	Benefit Obligations As of December 31,				Benefit Costs For the Years Ended December 31,
	2013		2012		2013		2012		2011
Discount rate – pension	4.88	%	4.01	%	4.01	%	4.42	%	5.31	%
Discount rate – other benefits	5.10	%	4.20	%	4.20	%	4.59	%	5.49	%
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		7.00	%	7.75	%	7.75	%
Initial healthcare cost trend rate	7.50	%	7.50	%	7.50	%	7.50	%	8.00	%
Ultimate healthcare 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 2014, we are assuming a 6.9% long-term rate of return for pension assets and 7.1% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

The assumed healthcare cost trend rates shown above have a significant effect on the amounts reported for the healthcare plans.  In selecting our healthcare trend rates, we consider past performance and forecasts of healthcare costs.  A one percentage point change in the assumed initial and ultimate healthcare 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	$	13	$	(10	)
Effect on service and interest cost components of net periodic other postretirement benefit costs	14		(11		)
Effect on the accumulated other postretirement benefit obligation	149		(120		)

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.

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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 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 include investments in real estate, 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 2013, the long-term fixed income assets had a target allocation of 58% with a permissible range of 55% to 61% and the return-generating assets had a target allocation of 42% with a permissible range of 45% to 39%.  The return-generating assets have additional target allocations, as a percent of total plan assets, of 22% 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, 2013, long-term fixed income assets represented 55% of total pension plan assets, and return-generating assets represented 45% 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 generally 25% of fixed income assets and 75% of non-fixed income assets.  This asset allocation target mix does not vary with the plan’s funded status.  As of December 31, 2013, investment in fixed income assets represented 38% of the other postretirement benefit plan total assets, and non-fixed income assets represented 62% 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 fixed income securities, 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

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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.

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).  Common and collective 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, 2013, 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.

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The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2013, 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)		Significant Unobservable Inputs (Level 3)			Other (c)		Balance at December 31, 2013
Pension Plan:
Assets:
Cash and cash equivalents	$	504	$	—	$	—		$	—	$	504
Fixed Income Securities:
Corporate	—		898,621		—			—		898,621
U.S. Treasury	231,590		—		—			—		231,590
Other (b)	—		84,011		—			—		84,011
Equities:
U.S. Companies	239,036		—		—			—		239,036
International Companies	19,429		—		—			—		19,429
Common and collective trusts:
U.S. Equities	—		116,150		—			—		116,150
International Equities	—		367,551		—			—		367,551
Fixed Income			137,520							137,520
Real estate	—		119,739		—			—		119,739
Short-term investments and other	—		41,060		8,660		(a)	250		49,970
Total Pension Plan	$	490,559	$	1,764,652	$	8,660		$	250	$	2,264,121
Other Benefits:
Assets:
Fixed Income Securities:
Corporate	$	—	$	153,888	$	—		$	—	$	153,888
U.S. Treasury	98,704		—		—			—		98,704
Other (b)	—		27,936		—			—		27,936
Equities:
U.S. Companies	252,181		—		—			—		252,181
International Companies	20,892		—		—			—		20,892
Common and collective trusts:
U.S. Equities	—		80,751		—			—		80,751
International Equities	—		92,382		—			—		92,382
Real Estate	—		10,761		—			—		10,761
Short-term investments and other	—		8,414		—			2,430		10,844
Total Other Benefits	$	371,777	$	374,132	$	—		$	2,430	$	748,339

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

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

(c)           Represents plan receivables and payables.

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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):

	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.

(c)           Represents plan receivables and payables.

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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, 2013 and 2012 (dollars in thousands):

	Pension
Short-Term Investments and Other	2013			2012
Beginning balance at January 1	$	2,419		$	—
Actual return on assets still held at December 31	(498		)	(668		)
Purchases, sales, and settlements	6,739			3,087
Transfers in and/or out of Level 3	—			—
Ending balance at December 31	$	8,660		$	2,419

Contributions

Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  We made contributions to our pension plan totaling $141 million in 2013, $65 million in 2012, and zero in 2011.  The minimum contributions for the pension plan total $141 million for the next three years under the recently enacted Moving Ahead for Progress in the 21st Century Act (zero in 2014, $19 million in 2015, and $122 million in 2016).  Instead, we expect to make voluntary contributions totaling $300 million for the next three years ($175 million in 2014, of which $70 million was already contributed in early 2014, up to $100 million in 2015, and up to $25 million in 2016).  With regard to contributions to our other postretirement benefit plans, we made a contribution of approximately $14 million in 2013, $23 million in 2012, and $19 million in 2011.  The contributions to our other postretirement benefit plans for 2014, 2015 and 2016 are expected to be approximately $10 million each year.  APS funds its share of the contributions.  APS’s share of the pension plan contribution was $140 million in 2013, $64 million in 2012, and zero in 2011.  APS’s share of the contributions to the other postretirement benefit plan was $14 million in 2013, $22 million in 2012, and $19 million in 2011.

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
2014	$	129,159	$	28,664
2015	143,452		31,804
2016	149,105		34,933
2017	162,678		37,966
2018	169,064		40,972
Years 2019-2023	972,826		245,366

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 2013, 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 $9 million for 2013, $8 million for 2012, and $8 million for 2011.

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 $18 million in 2013, $19 million in 2012, and $21 million in 2011.  APS’s lease expense was $15 million in 2013, $16 million in 2012, and $18 million in 2011.

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
2014	$	20	$	17
2015	17		14
2016	6		5
2017	5		5
2018	4		4
Thereafter	59		59
Total future lease commitments	$	111	$	104

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 VIEs 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 19 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 for providing our own financing.  Our share of operating expenses and utility plant costs related to these facilities is accounted for using proportional consolidation.  The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2013 (dollars in thousands):

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	Percent Owned		Plant in Service		Accumulated Depreciation		Construction Work in Progress
Generating facilities:
Palo Verde Units 1 and 3	29.1	%	$	1,701,844	$	1,027,523	$	22,400
Palo Verde Unit 2 (a)	16.8	%	543,972		338,918		10,095
Palo Verde Common	28.0	% (b)	538,818		219,801		81,599
Palo Verde Sale Leaseback		(a)	351,050		225,925		—
Four Corners Units 4, 5 and Common (d)	63.0	%	809,946		608,194		14,434
Navajo Generating Station Units 1, 2 and 3	14.0	%	270,448		150,501		2,864
Cholla common facilities (c)	63.3	% (b)	148,299		47,851		7,159
Transmission facilities:
ANPP 500kV System	34.2	% (b)	98,145		32,350		1,095
Navajo Southern System	22.2	% (b)	58,702		16,937		518
Palo Verde — Yuma 500kVSystem	18.0	% (b)	12,115		4,656		11,786
Four Corners Switchyards	48.1	% (b)	33,460		9,052		185
Phoenix — Mead System	17.1	% (b)	39,758		12,140		—
Palo Verde — Estrella 500kVSystem	50.0	% (b)	89,571		14,883		21
Morgan — Pinnacle Peak System	64.5	% (b)	130,132		6,651		1,042
Round Valley System	50.0	% (b)	488		268		—
Palo Verde — Morgan System	90.0	% (b)	—		—		36,601

(a)See Note 19.

(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.

(d)See Note 3.

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 United States Court of Federal Claims.  The lawsuit seeks to recover 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 NWPA.  This lawsuit is currently pending in the Court of Federal Claims.

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, 2013,

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APS had a regulatory liability of $42 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

Nuclear Insurance

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act (“Price-Anderson Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial 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 $13.6 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 $13.2 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 $127.3 million, subject to an annual limit of $19 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 $111 million, with an annual payment limitation of approximately $16.4 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”).  Effective April 1, 2013, a sublimit of $1.5 billion for non-nuclear property damage losses site-wide has been imposed on the NEIL property policies.  Effective April 1, 2013, a sublimit of $327.6 million per unit has been imposed on the non-nuclear losses covered by the NEIL accidental outage policy, potentially subject to further limitations.  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 2014 and 2043 that include required purchase provisions.  APS estimates the contract requirements to be approximately $729 million in 2014; $628 million in 2015; $638 million in 2016; $613 million in 2017; $580 million in 2018; and $8.7 billion thereafter.  These fuel and purchased power commitments include the amounts incurred from acquiring SCE’s interest in Four Corners.  However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.

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Of the various fuel and purchased power contracts mentioned above, some of those contracts for coal supply include take-or-pay provisions.  The current coal contracts with take-or-pay provisions have terms that expire in 2031.

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

			Years Ended December 31,
	2014		2015		2016		2017		2018		Thereafter
Coal take-or-pay commitments (a)	$	152	$	157	$	166	$	180	$	175	$	2,539

(a)Total take-or-pay commitments are approximately $3.4 billion.  The total net present value of these commitments is approximately $2.2 billion.

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,
	2013		2012		2011
Total purchases	$	188	$	196	$	191

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 $48 million in 2014; $42 million in 2015; $42 million in 2016; $42 million in 2017; $42 million in 2018; and $453 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 recorded a final coal mine reclamation obligation of approximately $207 million at December 31, 2013 and $119 million at December 31, 2012.  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 2014; $1 million in 2015; $8 million in 2016; $14 million in 2017; $14 million in 2018; and $170 million thereafter.  Any amendments to current coal supply agreements may change the timing of the reimbursement.

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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 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.

On August 6, 2013, RID filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

Southwest Power Outage

Regulatory.  On September 8, 2011 at approximately 3:30 PM, a 500kV 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.  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 9:15 PM on September 8.  Service to customers affected by the wider regional outages was restored by approximately 3:25 AM on September 9.

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.

On January 22, 2014, following non-public preliminary investigations, FERC Staff issued a Notice of Alleged Violations naming six entities involved in the event, including APS.  FERC Staff

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alleges that each of the named entities violated varying numbers of NERC Reliability Standards.  APS is alleged to have violated seven Reliability Standard Requirements.  The allegations of violations are preliminary determinations by FERC Staff and do not constitute findings by FERC itself that any violations have occurred.

APS intends to work with FERC Staff to resolve the matter.  If violations of the 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.  APS cannot predict the timing or financial or operational impacts that may result from the Staff’s Notice of Alleged Violations, including any payments that may result from a settlement if one is reached, or any claims that may be made as a result of the outages.

Litigation.  On September 6, 2013, a purported consumer class action complaint was filed in Federal District Court in San Diego, California, naming APS and Pinnacle West as defendants and seeking damages for loss of perishable inventory and sales as a result of interruption of electrical service.  APS and Pinnacle West filed a motion to dismiss, which the court granted on December 9, 2013.  On January 13, 2014, the plaintiffs appealed the lower court’s decision.

Clean Air Act Citizen 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 NSR 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 environmental 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.  The case is being held in abeyance while the parties seek to negotiate a settlement.  On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay.  At such time as the stay is lifted, APS and the other Four Corners participants may reinstate their motions to dismiss without risk of default.  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 CCRs.  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 the 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 BART to lessen the impacts of emissions on visibility surrounding the

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plants.  Based on EPA’s final standards, APS’s 63% share of the cost of these controls for Four Corners Units 4 and 5 would be approximately $350 million.  APS’s share of costs for upgrades at Navajo, based on EPA’s FIP proposal, could be up to approximately $200 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 $200 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 $120 million for Cholla Units 2 and 3.  No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules.  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, GHG emissions, and other rules or matters involving the Clean Air Act, Clean Water Act, ESA, 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.

Regional Haze Rules — Cholla

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.  We expect briefing in the case to be completed on February 21, 2014.

New Mexico Tax Matter

On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the “Assessment”).  APS’s share of the Assessment is approximately $12 million.  For procedural reasons, on behalf of the Four Corners co-owners, including APS, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013.  The New Mexico Taxation and Revenue Department denied the refund claim.  On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial.  APS believes the Assessment and the refund claim denial are without merit, but cannot predict the timing or outcome of this litigation.

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Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes.  At December 31, 2013, 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 19 for further details on the Palo Verde sale leaseback transactions).  These letters of credit will expire on December 31, 2015, and totaled approximately $32 million at December 31, 2013.  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, 2013, $55 million of such letters of credit were outstanding that will expire in 2014 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.

Pinnacle West has issued parental guarantees and surety bonds for APS which were not material at December 31, 2013.

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.  During the fourth quarter of 2013, a new decommissioning study with updated cash flow estimates was completed for Palo Verde.

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 costs estimates and related cash flows.  In the fourth quarter of 2013, APS finalized the transaction to acquire SCE’s interest in Four Corners.  As part of that transaction, APS assumed SCE’s asset retirement obligation.  Also, APS retired Four Corners Units 1-3 on December 30, 2013.  Decommissioning activities began for Units 1-3 in January 2014.  An update was made to the timing of the Units 1-3 decommissioning cash out flows to coincide with the expected decommissioning activities.

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

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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 2013 and 2012 (dollars in millions):

	2013			2012
Asset retirement obligations at the beginning of year	$	357		$	280
Changes attributable to:
Accretion expense	24			19
Settlements	(12		)	—
Assumed SCE’s obligation	34			—
Estimated cash flow revisions	(56		)	58
Asset retirement obligations at the end of year	$	347		$	357

Decommissioning activities for Four Corners Units 1-3 will begin in January 2014; thus, $33 million of the total asset retirement obligation of $347 million at December 31, 2013, is classified as a current liability on the balance sheet.

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.

13.Selected Quarterly Financial Data (Unaudited)

Consolidated quarterly financial information for 2013 and 2012 is provided in the tables below (dollars in thousands, except per share amounts).  Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.

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	2013 Quarter Ended								2013
	March 31,		June 30,		Sept. 30,		Dec. 31,		Total
Operating revenues	$	686,652	$	915,822	$	1,152,392	$	699,762	$	3,454,628
Operations and maintenance	223,250		229,300		233,323		238,854		924,727
Operating income	86,923		259,812		415,688		83,900		846,323
Income taxes	12,469		77,043		131,912		9,167		230,591
Income from continuing operations	32,836		139,598		234,718		32,814		439,966
Net income attributable to common shareholders	24,444		131,207		226,163		24,260		406,074
Earnings Per Share:
Income from continuing operations attributable to common shareholders — Basic	$	0.22	$	1.19	$	2.06	$	0.22	$	3.69
Net income attributable to common shareholders — Basic	0.22		1.19		2.06		0.22		3.69
Income from continuing operations attributable to common shareholders — Diluted	0.22		1.18		2.04		0.22		3.66
Net income attributable to common shareholders — Diluted	0.22		1.18		2.04		0.22		3.66

	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

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.

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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.

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.

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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.

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

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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 20 for additional discussion about our nuclear decommissioning trust.

Fair Value Tables

The following table presents the fair value at December 31, 2013 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, 2013
Assets
Risk management activities — derivative instruments:
Commodity Contracts	$	—	$	9		$	41		$	(9	) (b)	$	41
Nuclear decommissioning trust:
U.S. commingled equity funds	—		272			—			—			272
Fixed income securities:
U.S. Treasury	107		—			—			—			107
Cash and cash equivalent funds	—		11			—			(3		) (c)	8
Corporate debt	—		88			—			—			88
Mortgage-backed securities	—		85			—			—			85
Municipality bonds	—		71			—			—			71
Other	—		11			—			—			11
Subtotal nuclear decommissioning trust	107		538			—			(3		)	642
Total	$	107	$	547		$	41		$	(12	)	$	683
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(33	)	$	(90	)	$	21	(b)	$	(102	)

(a)Primarily consists of heat rate options and other long-dated electricity contracts.

(b)Represents counterparty netting, margin and collateral.  See Note 17.

(c)Represents nuclear decommissioning trust net pending securities sales and purchases.

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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):

	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 17.

(c)Represents nuclear decommissioning trust net pending securities sales and purchases.

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).

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

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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 volatilities.  If electricity prices and electricity price 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 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 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 tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2013 and December 31, 2012:

	December 31, 2013 Fair Value (millions)				Valuation	Significant		Weighted-
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range	Average
Electricity:
Forward Contracts (a)	$	40	$	66	Discounted cash flows	Electricity forward price (per MWh)	$24.89 - $65.04	$	41.09
Option Contracts (b)	—		19		Option model	Electricity forward price (per MWh)	$39.91 - $85.41	$	58.70
						Natural gas forward price (per MMbtu)	$3.57 - $3.80	$	3.71
						Electricity price volatilities	35% - 94%	59		%
						Natural gas price volatilities	22% - 36%	27		%
Natural Gas:
Forward Contracts (a)	1		5		Discounted cash flows	Natural gas forward price (per MMbtu)	$3.47 - $4.31	$	3.87
Total	$	41	$	90

(a)Includes swaps and physical and financial contracts.

(b)Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities.

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	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.

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, 2013 and 2012 (dollars in millions):

	Year Ended December 31,
Commodity Contracts	2013			2012
Net derivative balance at beginning of period	$	(48	)	$	(51	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			2
Included in OCI	—			(3		)
Deferred as a regulatory asset or liability	(10		)	7
Settlements	10			(5		)
Transfers into Level 3 from Level 2	—			(2		)
Transfers from Level 3 into Level 2	(1		)	4
Net derivative balance at end of period	$	(49	)	$	(48	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—

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

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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.  See Note 6 for our long-term debt fair values.

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, 2013, 2012 and 2011:

	2013		2012			2011
Basic earnings per share:
Income from continuing operations attributable to common shareholders	$	3.69	$	3.54		$	3.01
Income (loss) from discontinued operations	—		(0.06		)	0.10
Earnings per share – basic	$	3.69	$	3.48		$	3.11
Diluted earnings per share:
Income from continuing operations attributable to common shareholders	$	3.66	$	3.50		$	2.99
Income (loss) from discontinued operations	—		(0.05		)	0.10
Earnings per share – diluted	$	3.66	$	3.45		$	3.09

Dilutive stock options and performance shares (which are contingently issuable) increased average common shares outstanding by approximately 822,000 shares in 2013, 1,017,000 shares in 2012 and 811,000 shares in 2011.  Total average common shares outstanding for the purposes of calculating diluted earnings per share were 110,805,943 shares in 2013, 110,527,311 shares in 2012 and 109,864,243 shares in 2011.

For the years ended 2013, 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.

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 since 2012 were issued under the 2012 Plan, and prior awards from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”).

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Restricted Stock Unit Awards and Stock Grants

Stock grants issued to non-officer members of the Board of Directors in 2013, 2012 and 2011, provided the members of the Board of 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.  The members of the Board of Directors who elect to defer may elect to receive payment in either stock, or 50% in cash and 50% in stock.  The members of the Board of Directors may elect to receive payments either as of the last business day of the month following the month in which they separate from service on the Board of Directors, 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 Directors 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 have been 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.  From 2010 through 2013, officers and key employees elected to receive payment in either stock, or 50% in cash and 50% in stock.

Restricted stock unit awards vest and settle over a four-year period.  In addition, officers and key employees accrue dividend rights on 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 through 2013 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.

In December 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 will accrue notional dividends equal to the amount of dividends that would have been received if the Chairman of the Board, President and Chief Executive Officer had directly owned one share of Pinnacle West common stock for each restricted stock unit held from the grant date to each dividend payment 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 vested 50% on February 15, 2013.  The remaining grant will vest 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 they would have received if they had directly owned one share of Pinnacle West common stock for each restricted stock unit held from the grant date to each dividend payment date.  Each additional restricted stock unit

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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 2013, 2012 and 2011:

	2013		2012		2011
Units granted	129,620		202,278		292,242
Grant date fair value (a)	$	55.21	$	49.31	$	41.98

(a)Weighted-average grant date fair value.

The following table is a summary of the status of restricted stock units and stock grants, as of December 31, 2013 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, 2013	480,753	$	43.58
Granted	129,620	55.21
Vested	191,988	40.33
Forfeited	20,409	45.70
Nonvested at December 31, 2013	397,976	47.74

The amount of cash required to settle the payments on restricted stock units is (dollars in millions):

Year	2013		2012		2011
2007 Grant	$	—	$	—	$	1.0
2008 Grant	—		1.9		1.6
2009 Grant	3.0		1.7		1.5
2010 Grant	2.3		0.6		0.6
2011 Grant	2.5		0.7		—
2012 Grant	2.2		—		—

Performance Share Awards

Performance share awards have been granted to officers and key employees under the 2012 Plan since 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 2013, 2012 and 2011 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% is 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,

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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 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 2013, 2012 and 2011:

	2013		2012		2011
Units granted (a)	176,332		185,878		175,072
Grant date fair value (b)	$	55.45	$	47.40	$	41.71

(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, 2013 and changes during the year:

Nonvested shares (a)	Shares	Weighted-Average Grant Date Fair Value
Nonvested at January 1, 2013	347,690	$	44.67
Granted	176,332	55.45
Increase in performance factor	40,183	41.71
Vested	200,915	41.71
Forfeited	18,894	48.11
Nonvested at December 31, 2013	344,396	51.13

(a)Nonvested shares are reflected at 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.

Stock Options

The Company has not granted stock options since 2004 and has no stock options outstanding.

The following table summarizes the option activity under prior equity incentive plans for the year ended December 31, 2013:

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Options	Shares	Weighted- Average  Exercise  Price
Outstanding at January 1, 2013	7,925	$	32.29
Exercised	3,625	32.29
Forfeited or expired	4,300	32.29
Outstanding at December 31, 2013	—	—

Cash received from options exercised under our share-based payment arrangements was $0.1 million for 2013, $0.5 million for 2012, and $1.8 million for 2011.  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, 2013, 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 2013, 2012 and 2011 was $20 million, $19 million and $14 million, respectively.

The compensation cost that has been charged against Pinnacle West’s income for share-based compensation plans was $25 million in 2013, $32 million in 2012, and $23 million in 2011.  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 $10 million in 2013, $13 million in 2012, and $9 million in 2011.  APS’s share of compensation cost that has been charged against income was $25 million in 2013, $32 million in 2012, and $22 million in 2011.

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.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 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

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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.  When amounts have been reclassified from accumulated OCI to earnings, they will be subject to deferral in accordance with the PSA.  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, after May 31, 2012, effectiveness testing is no longer being performed for these contracts.

Prior to the 2012 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 2012 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, 2013, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

Commodity	Quantity
Power	5,765	GWh
Gas	108	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, 2013, 2012 and 2011 (dollars in thousands):

		Year Ended
	Financial Statement	December 31,
Commodity Contracts	Location	2013			2012			2011
Loss Recognized in OCI on Derivative Instruments (Effective Portion)	OCI — derivative instruments	$	(353	)	$	(37,663	)	$	(94,660	)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	(44,219		)	(99,007		)	(117,189		)
Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Fuel and purchased power (b)	—			117			(211		)

(a)During the years ended December 31, 2013, 2012, and 2011, we had zero, $1.8 million, and zero losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

(b)Amounts are before the effect of PSA deferrals.

During the next twelve months, we estimate that a net loss of $21 million before income taxes will be reclassified from accumulated OCI 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.

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The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2013, 2012 and 2011 (dollars in thousands):

		Year Ended
	Financial Statement	December 31,
Commodity Contracts	Location	2013			2012			2011
Net Gain (Loss) Recognized in Income	Operating revenues (a)	$	289		$	103		$	(27	)
Net Loss Recognized in Income	Fuel and purchased power (a)	(10,449		)	(2,747		)	(52,113		)
Total		$	(10,160	)	$	(2,644	)	$	(52,140	)

(a)Amounts are before the effect of PSA deferrals.

Derivative Instruments in the Consolidated Balance Sheets

Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty.  Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements.  Transactions with counterparties that have master netting arrangements are offset and reported net on the Consolidated Balance Sheets.  Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Consolidated Balance Sheets.

We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default.  Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement.  These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit).  These types of transactions are excluded from the offsetting tables presented below.

The significant majority of our derivative instruments are not currently designated as hedging instruments.  The Consolidated Balance Sheets as of December 31, 2013 and December 31, 2012, include gross liabilities of $5 million of derivative instruments designated as hedging instruments.

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The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of December 31, 2013 and 2012.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets.

As of December 31, 2013:(dollars in thousands)	Gross  Recognized  Derivatives(a)			Amounts  Offset (b)			NetRecognizedDerivatives			Other(c)			Amount  Reported on  Balance Sheet
Current Assets	$	24,587		$	(7,425	)	$	17,162		$	7		$	17,169
Investments and Other Assets	25,364			(1,549		)	23,815			—			23,815
Total Assets	49,951			(8,974		)	40,977			7			40,984
Current Liabilities	(50,540		)	26,166			(24,374		)	(7,518		)	(31,892		)
Deferred Credits and Other	(72,123		)	1,808			(70,315		)	—			(70,315		)
Total Liabilities	(122,663		)	27,974			(94,689		)	(7,518		)	(102,207		)
Total	$	(72,712	)	$	19,000		$	(53,712	)	$	(7,511	)	$	(61,223	)

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.

(b)Includes cash collateral provided to counterparties of $19,000.

(c)Represents cash collateral and margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $7,518, and cash margin provided to counterparties of $7.

As of December 31, 2012:(dollars in thousands)	GrossRecognizedDerivatives(a)			Amounts Offset  (b)			NetRecognizedDerivatives			Other(c)			AmountReported onBalance Sheet
Current Assets	$	42,495		$	(17,797	)	$	24,698		$	1,001		$	25,699
Investments and Other Assets	41,563			(5,672		)	35,891			—			35,891
Total Assets	84,058			(23,469		)	60,589			1,001			61,590
Current Liabilities	(105,324		)	57,046			(48,278		)	(25,463		)	(73,741		)
Deferred Credits and Other	(100,986		)	15,722			(85,264		)	—			(85,264		)
Total Liabilities	(206,310		)	72,768			(133,542		)	(25,463		)	(159,005		)
Total	$	(122,252	)	$	49,299		$	(72,953	)	$	(24,462	)	$	(97,415	)

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.

(b)Includes cash collateral provided to counterparties of $49,299.

(c)Represents cash collateral relating to non-derivative instruments or derivatives qualifying for scope exceptions.  Includes cash collateral provided to counterparties of $1,001, and cash collateral received from counterparties of $25,463.  This amount is not subject to offsetting.

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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 92% of Pinnacle West’s $41 million of risk management assets as of December 31, 2013.  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, 2013 (dollars in millions):

	December 31, 2013
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	123
Cash Collateral Posted	19
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)	66

(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 $180 million if our debt credit ratings were to fall below investment grade.

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18.Other Income and Other Expense

The following table provides detail of other income and other expense for 2013, 2012 and 2011 (dollars in thousands):

	2013			2012			2011
Other income:
Interest income	$	1,629		$	1,239		$	1,850
Investment gains — net	—			—			1,165
Miscellaneous	75			367			96
Total other income	$	1,704		$	1,606		$	3,111
Other expense:
Non-operating costs	$	(8,207	)	$	(7,777	)	$	(7,037	)
Investment loss — net	(3,711		)	(2,453		)	—
Miscellaneous	(4,106		)	(9,612		)	(3,414		)
Total other expense	$	(16,024	)	$	(19,842	)	$	(10,451	)

19.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 during 2014 and 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 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 2013, 2012 and 2011 of $34 million, $32 million and $28 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.

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Our Consolidated Balance Sheets at December 31, 2013 and December 31, 2012 include the following amounts relating to the VIEs (in millions):

	December 31, 2013		December 31, 2012
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	125	$	129
Current maturities of long-term debt	26		27
Long-term debt excluding current maturities	13		39
Equity-Noncontrolling interests	146		129

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 Palo Verde 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, 2013, APS would have been required to pay the noncontrolling equity participants approximately $133 million and assume $39 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.

20.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 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, 2013 and December 31, 2012 (dollars in millions):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Fair Value			Total  Unrealized  Gains		Total  Unrealized  Losses
December 31, 2013
Equity securities	$	272		$	129	$	—
Fixed income securities	373			11		(6		)
Net payables (a)	(3		)	—		—
Total	$	642		$	140	$	(6	)

	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	$	—

(a)Net payables relate to pending purchases and sales of securities.

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,
	2013			2012			2011
Realized gains	$	6		$	7		$	8
Realized losses	(7		)	(4		)	(5		)
Proceeds from the sale of securities (a)	446			418			498

(a)Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2013 is as follows (dollars in millions):

	Fair Value
Less than one year	$	9
1 year – 5 years	109
5 years – 10 years	108
Greater than 10 years	147
Total	$	373

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21.Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands):

	Year Ended December 31, 2013
	Derivative  Instruments			Pension and  Other  Postretirement  Benefits			Total
Beginning balance	$	(49,592	)	$	(64,416	)	$	(114,008	)
OCI (loss) before reclassifications	(213		)	5,594			5,381
Amounts reclassified from accumulated other comprehensive loss	26,747		(a)	3,827		(b)	30,574
Net current period OCI	26,534			9,421			35,955
Ending balance	$	(23,058	)	$	(54,995	)	$	(78,053	)

(a)These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 17.

(b)These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 8.

152

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 APS.  Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on our evaluation under the framework in Internal Control — Integrated Framework (1992), our management concluded that our internal control over financial reporting was effective as of December 31, 2013.  The effectiveness of our internal control over financial reporting as of December 31, 2013 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 21, 2014

153

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, 2013 and 2012, 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, 2013.  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, 2013, based on criteria established in Internal Control — Integrated Framework (1992) 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.

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

154

unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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 Arizona Public Service Company and subsidiary as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, 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, 2013, based on the criteria established in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ Deloitte & Touche LLP

Phoenix, Arizona

February 21, 2014

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ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(dollars in thousands)

	Year Ended December 31,
	2013			2012			2011
ELECTRIC OPERATING REVENUES	$	3,451,251		$	3,293,489		$	3,237,241
OPERATING EXPENSES
Fuel and purchased power	1,095,709			994,790			1,009,464
Operations and maintenance	897,824			873,916			895,917
Depreciation and amortization	415,612			404,242			426,958
Income taxes (Notes 4 and S-1)	256,864			256,600			204,066
Taxes other than income taxes	163,377			158,412			146,453
Total	2,829,386			2,687,960			2,682,858
OPERATING INCOME	621,865			605,529			554,383
OTHER INCOME (DEDUCTIONS)
Income taxes (Notes 4 and S-1)	11,769			12,204			11,524
Allowance for equity funds used during construction (Note 1)	25,581			22,436			23,707
Other income (Note S-3)	3,896			2,868			5,071
Other expense (Note S-3)	(20,449		)	(21,150		)	(15,328		)
Total	20,797			16,358			24,974
INTEREST EXPENSE
Interest on long-term debt	188,011			198,398			218,981
Interest on short-term borrowings	6,605			7,135			10,345
Debt discount, premium and expense	4,046			4,215			4,616
Allowance for borrowed funds used during construction (Note 1)	(14,861		)	(14,971		)	(18,358		)
Total	183,801			194,777			215,584
NET INCOME	458,861			427,110			363,773
Less: Net income attributable to noncontrolling interests (Note 19)	33,892			31,613			27,524
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	424,969		$	395,497		$	336,249

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Consolidated Financial Statements.

156

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)

	Year Ended December 31,
	2013			2012			2011
NET INCOME	$	458,861		$	427,110		$	363,773
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $140, $14,888, and $37,397 (Note 17)	(214		)	(22,775		)	(57,262		)
Reclassification of net realized loss, net of tax benefit of $17,472, $39,119 and $46,298 (Note 17)	26,747			59,888			70,891
Pension and other postretirement benefits activity, net of tax (expense) benefit of $(6,003), $408 and $1,910 (Note 8)	9,190			(617		)	(2,925		)
Total other comprehensive income	35,723			36,496			10,704
COMPREHENSIVE INCOME	494,584			463,606			374,477
Less: Comprehensive income attributable to noncontrolling interests	33,892			31,613			27,524
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	460,692		$	431,993		$	346,953

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to APS’s Consolidated Financial Statements.

157

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	December 31,
	2013			2012
ASSETS
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 10)
Plant in service and held for future use	$	15,196,598		$	14,342,501
Accumulated depreciation and amortization	(5,296,501		)	(4,925,990		)
Net	9,900,097			9,416,511
Construction work in progress	581,369			565,716
Palo Verde sale leaseback, net of accumulated depreciation of $225,925 and $222,055 (Note 19)	125,125			128,995
Intangible assets, net of accumulated amortization of $439,703 and $411,543	157,534			161,995
Nuclear fuel, net of accumulated amortization of $146,057 and $133,950	124,557			122,778
Total property, plant and equipment	10,888,682			10,395,995
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 14 and 20)	642,007			570,625
Assets from risk management activities (Note 17)	23,815			35,891
Other assets	33,709			31,650
Total investments and other assets	699,531			638,166
CURRENT ASSETS
Cash and cash equivalents	3,725			3,499
Customer and other receivables	299,055			274,815
Accrued unbilled revenues	96,796			94,845
Allowance for doubtful accounts	(3,203		)	(3,340		)
Materials and supplies (at average cost)	221,682			218,096
Fossil fuel (at average cost)	38,028			31,334
Income tax receivable	135,179			589
Assets from risk management activities (Note 17)	17,169			25,699
Deferred fuel and purchased power regulatory asset (Note 3)	20,755			72,692
Other regulatory assets (Note 3)	76,388			71,257
Deferred income taxes (Notes 4 and S-1)	—			74,420
Other current assets	39,153			37,077
Total current assets	944,727			900,983
DEFERRED DEBITS
Regulatory assets (Notes 1, 3, 4 and S-1)	711,712			1,099,900
Income tax receivable (Notes 4 and S-1)	—			70,784
Unamortized debt issue costs	21,860			22,492
Other	114,865			114,222
Total deferred debits	848,437			1,307,398
TOTAL ASSETS	$	13,381,377		$	13,242,542

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to APS’s Consolidated Financial Statements.

158

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	December 31,
	2013			2012
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital	2,379,696			2,379,696
Retained earnings	1,804,398			1,624,237
Accumulated other comprehensive (loss):
Pension and other postretirement benefits (Note 8)	(30,313		)	(39,503		)
Derivative instruments (Note 17)	(23,059		)	(49,592		)
Total shareholder equity	4,308,884			4,093,000
Noncontrolling interests (Note 19)	145,990			129,483
Total equity	4,454,874			4,222,483
Long-term debt less current maturities (Note 6)	2,671,465			3,074,088
Total capitalization	7,126,339			7,296,571
CURRENT LIABILITIES
Short-term borrowings (Note 5)	153,125			92,175
Current maturities of long-term debt (Note 6)	540,424			122,828
Accounts payable	281,237			215,577
Accrued taxes (Notes 4 and S-1)	122,460			116,700
Accrued interest	48,132			49,135
Common dividends payable	62,500			59,800
Customer deposits	76,101			79,689
Deferred income taxes	2,033			—
Liabilities from risk management activities (Note 17)	31,892			73,741
Liabilities for asset retirements (Note 12)	32,896			—
Regulatory liabilities (Note 3)	99,273			88,116
Other current liabilities	130,774			145,326
Total current liabilities	1,580,847			1,043,087
DEFERRED CREDITS AND OTHER
Deferred income taxes (Notes 4 and S-1)	2,347,724			2,133,976
Regulatory liabilities (Notes 1, 3, 4, and S-1)	801,297			759,201
Liability for asset retirements (Note 12)	313,833			357,097
Liabilities for pension and other postretirement benefits (Note 8)	476,017			1,017,556
Liabilities from risk management activities (Note 17)	70,315			85,264
Customer advances	114,480			109,359
Coal mine reclamation	207,453			118,860
Deferred investment tax credit	152,361			99,819
Unrecognized tax benefits (Notes 4 and S-1)	42,209			70,932
Other	148,502			150,820
Total deferred credits and other	4,674,191			4,902,884
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	13,381,377		$	13,242,542

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to APS’s Consolidated Financial Statements.

159

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

	Year Ended December 31,
	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	458,861		$	427,110		$	363,773
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	492,226			481,168			493,653
Deferred fuel and purchased power	21,678			71,573			69,166
Deferred fuel and purchased power amortization	31,190			(116,716		)	(155,157		)
Allowance for equity funds used during construction	(25,581		)	(22,436		)	(23,707		)
Deferred income taxes	278,101			202,159			110,565
Deferred investment tax credit	52,542			41,579			58,240
Change in derivative instruments fair value	534			(749		)	4,064
Changes in current assets and liabilities:
Customer and other receivables	(46,552		)	12,914			34,913
Accrued unbilled revenues	(1,951		)	30,394			(21,947		)
Materials, supplies and fossil fuel	(11,878		)	(23,043		)	(23,398		)
Income tax receivable	(134,590		)	(2,280		)	2,869
Other current assets	(17,112		)	(27,745		)	(5,473		)
Accounts payable	47,870			(97,395		)	73,369
Accrued taxes	5,760			7,330			2,234
Other current liabilities	(9,005		)	6,070			18,762
Change in margin and collateral accounts — assets	993			2,216			33,349
Change in margin and collateral accounts — liabilities	12,355			137,785			29,731
Change in long-term regulatory liabilities	64,473			13,539			37,009
Change in long-term income tax receivable	137,665			(1,756		)	(3,530		)
Change in unrecognized tax benefits	(91,244		)	(2,583		)	9,125
Change in other long-term assets	(46,043		)	1,391			(41,788		)
Change in other long-term liabilities	(25,601		)	34,854			61,990
Net cash flow provided by operating activities	1,194,691			1,175,379			1,127,812
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,016,322		)	(889,551		)	(878,546		)
Contributions in aid of construction	41,090			49,876			38,096
Allowance for borrowed funds used during construction	(14,861		)	(14,971		)	(18,358		)
Proceeds from nuclear decommissioning trust sales	446,025			417,603			497,780
Investment in nuclear decommissioning trust	(463,274		)	(434,852		)	(513,799		)
Proceeds from sale of life insurance policies	—			—			44,183
Other	(2,067		)	(1,099		)	(3,306		)
Net cash flow used for investing activities	(1,009,409		)	(872,994		)	(833,950		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	136,307			351,081			295,353
Repayment of long-term debt	(122,828		)	(529,286		)	(430,169		)
Short-term borrowings and payments — net	60,950			92,175			—
Dividends paid on common stock	(242,100		)	(222,200		)	(228,900		)
Noncontrolling interests	(17,385		)	(10,529		)	(10,210		)
Net cash flow used for financing activities	(185,056		)	(318,759		)	(373,926		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	226			(16,374		)	(80,064		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	3,499			19,873			99,937
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	3,725		$	3,499		$	19,873
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Income taxes, net of refunds	$	7,524		$	1,196		$	25,975
Interest, net of amounts capitalized	$	180,757		$	196,038		$	210,995
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	33,184		$	26,208		$	27,245
Dividends declared but not paid	$	62,500		$	59,800		$	—
Liabilities assumed related to acquisition of SCE’s Four Corners’ interest	$	145,609		$	—		$	—

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to APS’s Consolidated Financial Statements.

160

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(dollars in thousands)

	Year Ended December 31,
	2013			2012			2011
COMMON STOCK	$	178,162		$	178,162		$	178,162
ADDITIONAL PAID-IN CAPITAL	2,379,696			2,379,696			2,379,696
RETAINED EARNINGS
Balance at beginning of year	1,624,237			1,510,740			1,403,390
Net income attributable to common shareholder	424,969			395,497			336,249
Dividends on common stock	(244,800		)	(282,000		)	(228,900		)
Other	(8		)	—			1
Balance at end of year	1,804,398			1,624,237			1,510,740
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Balance at beginning of year	(89,095		)	(125,591		)	(136,295		)
Other comprehensive income attributable to common shareholder	35,723			36,496			10,704
Balance at end of year	(53,372		)	(89,095		)	(125,591		)
NONCONTROLLING INTERESTS
Balance at beginning of year	129,483			108,399			91,084
Net income attributable to noncontrolling interests	33,892			31,613			27,524
Net capital activities by noncontrolling interests	(17,385		)	(10,529		)	(10,209		)
Balance at end of year	145,990			129,483			108,399
TOTAL EQUITY	$	4,454,874		$	4,222,483		$	4,051,406
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER
Net income attributable to common shareholder	$	424,969		$	395,497		$	336,249
Other comprehensive income	35,723			36,496			10,704
Total comprehensive income attributable to common shareholder	$	460,692		$	431,993		$	346,953

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to APS’s Consolidated Financial Statements.

161

Certain notes to APS’s consolidated financial statements are combined with the notes to Pinnacle West’s consolidated financial statements.  Listed below are the consolidated notes to Pinnacle West’s consolidated financial statements, the majority of which also relate to APS’s consolidated financial statements.  In addition, listed below are the supplemental notes which are required disclosures for APS and should be read in conjunction with Pinnacle West’s Consolidated Notes.

	Consolidated Note Reference	APS’s Supplemental Note 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	—
Derivative Accounting	Note 17	—
Other Income and Other Expense	Note 18	Note S-3
Palo Verde Sale Leaseback Variable Interest Entities	Note 19	—
Nuclear Decommissioning Trusts	Note 20	—
Changes in Accumulated Other Comprehensive Loss	Note 21	Note S-4

162

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.

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 currently enacted 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 ITCs and the change in income tax rates.

In accordance with regulatory requirements, APS ITCs 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 as of December 31, 2012 represented the anticipated refund related to an APS tax accounting method change approved by the IRS in the third quarter of 2009.  On July 9, 2013, IRS guidance was released which provided clarification regarding the timing and amount of this cash receipt.  As a result of this guidance, uncertain tax positions decreased $67 million during the third quarter.  This decrease in uncertain tax positions resulted in a corresponding increase to the total anticipated refund due from the IRS and an offsetting increase in long-term deferred tax liabilities.  Additionally, as a result of this IRS guidance, the $138 million anticipated refund was reclassified to current income tax receivable.

During the year ended December 31, 2013, the IRS finalized the examination of tax returns for the years ended December 31, 2008 and 2009, and the $138 million anticipated refund was reduced by approximately $2 million to reflect the outcome of this examination.  On December 17, 2013, the Joint Committee on Taxation approved the anticipated refund.  Cash related to this refund was received in the first quarter of 2014.

On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property.  These final regulations apply to tax years beginning on or after January 1, 2014.  Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS resulting in a cumulative effect adjustment.  To account for the adoption of these regulations plant-related long-term deferred tax liabilities decreased by $84 million, with the offsetting decrease to current deferred income tax assets.  Prior to the issuance of these regulations, this $84 million would have been repaid over 20 years through lower tax depreciation deductions.

163

ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 19).  As a result, there is no income tax expense associated with the VIEs recorded on APS’s Consolidated Statements of Income.

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):

	2013			2012			2011
Total unrecognized tax benefits, January 1	$	133,241		$	135,824		$	126,698
Additions for tax positions of the current year	3,516			5,167			10,915
Additions for tax positions of prior years	13,158			—			—
Reductions for tax positions of prior years for:
Changes in judgment	(107,918		)	(7,729		)	(1,555		)
Settlements with taxing authorities	—			—			(124		)
Lapses of applicable statute of limitations	—			(21		)	(110		)
Total unrecognized tax benefits, December 31	$	41,997		$	133,241		$	135,824

Included in the balance of unrecognized tax benefits at December 31, 2013, 2012 and 2011 were approximately $10 million, $10 million and $8 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, 2010 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 2010.

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 benefit of $4 million for 2013, a pre-tax expense of $4 million for 2012 and a pre-tax expense of $3 million for 2011.

The total amount of accrued liabilities for interest recognized in the Balance Sheets related to unrecognized tax benefits was less than $1 million as of December 31, 2013, $13 million as of December 31, 2012 and $9 million as of December 31, 2011.  To the extent that matters are settled favorably, this amount could be reversed and decrease our effective tax rate.  Additionally, as of December 31, 2013, 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.

164

ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	Year Ended December 31,
	2013			2012			2011
Current:
Federal	$	(97,531	)	$	(11,650	)	$	4,633
State	11,983			12,308			19,104
Total current	(85,548		)	658			23,737
Deferred:
Federal	305,389			216,367			154,632
State	25,254			27,371			14,173
Total deferred	330,643			243,738			168,805
Total income tax expense	$	245,095		$	244,396		$	192,542

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):

	Year Ended December 31,
	2013			2012			2011
Federal income tax expense at 35% statutory rate	$	246,384		$	235,027		$	194,710
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	23,970			25,379			21,139
Credits and favorable adjustments related to prior years resolved in current year	(3,231		)	—			—
Medicare Subsidy Part-D	823			483			823
Allowance for equity funds used during construction (see Note 1)	(6,997		)	(6,158		)	(6,880		)
Palo Verde VIE noncontrolling interest (see Note 19)	(11,862		)	(11,065		)	(9,633		)
Other	(3,992		)	730			(7,617		)
Income tax expense	$	245,095		$	244,396		$	192,542

165

ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	December 31,
	2013			2012
Current asset (liability)	$	(2,033	)	$	74,420
Long-term liability	(2,347,724		)	(2,133,976		)
Deferred income taxes — net	$	(2,349,757	)	$	(2,059,556	)

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, 2013, APS has recorded a regulatory liability of $75 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five-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 New Mexico.  In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability.  As of December 31, 2013, APS has recorded a regulatory liability of $2 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

166

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,
	2013			2012
DEFERRED TAX ASSETS
Regulatory liabilities:
Asset retirement obligation and removal costs	$	235,959		$	238,669
Unamortized investment tax credits	82,116			53,837
Other	42,609			33,764
Risk management activities	44,920			72,243
Pension and other postretirement liabilities	186,213			392,486
Renewable energy incentives	65,434			66,941
Credit and loss carryforwards	38,183			52,441
Other	166,781			111,327
Total deferred tax assets	862,215			1,021,708
DEFERRED TAX LIABILITIES
Plant-related	(2,903,730		)	(2,584,166		)
Risk management activities	(16,191		)	(23,940		)
Regulatory assets:
Allowance for equity funds used during construction	(43,058		)	(37,899		)
Deferred fuel and purchased power	(8,282		)	(28,858		)
Deferred fuel and purchased power — mark-to-market	(13,343		)	(15,796		)
Pension and other postretirement benefits	(129,250		)	(316,757		)
Other	(93,202		)	(68,170		)
Other	(4,916		)	(5,678		)
Total deferred tax liabilities	(3,211,972		)	(3,081,264		)
Deferred income taxes — net	$	(2,349,757	)	$	(2,059,556	)

As of December 31, 2013, the deferred tax assets for credit and loss carryforwards relate primarily to federal general business credits which first begin to expire in 2031.

167

ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

S-2.Selected Quarterly Financial Data (Unaudited)

Quarterly financial information for 2013 and 2012 is as follows (dollars in thousands):

	2013 Quarter Ended,								2013
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	685,827	$	915,065	$	1,151,535	$	698,824	$	3,451,251
Operations and maintenance	220,752		224,950		222,617		229,505		897,824
Operating income	74,862		183,728		284,251		79,024		621,865
Net income attributable to common shareholder	26,042		133,949		234,954		30,024		424,969

	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

S-3.Other Income and Other Expense

The following table provides detail of APS’s other income and other expense for 2013, 2012 and 2011 (dollars in thousands):

	2013			2012			2011
Other income:
Interest income	$	1,234		$	310		$	406
Investment gains — net	—			—			1,418
Miscellaneous	2,662			2,558			3,247
Total other income	$	3,896		$	2,868		$	5,071
Other expense:
Non-operating costs (a)	$	(9,626	)	$	(8,706	)	$	(8,810	)
Asset dispositions	(4,992		)	(1,511		)	(1,352		)
Miscellaneous	(5,831		)	(10,933		)	(5,166		)
Total other expense	$	(20,449	)	$	(21,150	)	$	(15,328	)

(a)As defined by FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).

168

ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

S-4.Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands):

	Year Ended December 31, 2013
	Derivative  Instruments			Pension and  Other  Postretirement  Benefits			Total
Beginning balance	$	(49,592	)	$	(39,503	)	$	(89,095	)
OCI (loss) before reclassifications	(214		)	5,387			5,173
Amounts reclassified from accumulated other comprehensive loss	26,747		(a)	3,803		(b)	30,550
Net current period OCI	26,533			9,190			35,723
Ending balance	$	(23,059	)	$	(30,313	)	$	(53,372	)

(a)These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 17.

(b)These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 8.

169

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

	Year Ended December 31,
	2013			2012			2011
Operating revenues	$	799		$	6,133		$	1,034
Operating expenses	24,930			12,125			8,811
Operating loss	(24,131		)	(5,992		)	(7,777		)
Other
Equity in earnings of subsidiaries	420,926			391,528			335,859
Other expense	(1,999		)	(2,001		)	(1,481		)
Total	418,927			389,527			334,378
Interest expense	3,226			4,868			8,053
Income from continuing operations	391,570			378,667			318,548
Income tax benefit	(14,504		)	(7,079		)	(8,938		)
Income from continuing operations — net of income taxes	406,074			385,746			327,486
Income (loss) from discontinued operations — net of income taxes	—			(4,204		)	11,987
Net income attributable to common shareholders	406,074			381,542			339,473
Other comprehensive income — attributable to common shareholders	35,955			38,155			7,605
Total comprehensive income — attributable to common shareholders	$	442,029		$	419,697		$	347,078

See Notes to Pinnacle West’s Consolidated Financial Statements.

170

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED BALANCE SHEETS

(in thousands)

	December 31,
	2013			2012
ASSETS
Current assets
Cash and cash equivalents	$	5,798		$	22,679
Accounts receivable	80,108			92,906
Current deferred income taxes	93,185			77,771
Income tax receivable	1,853			3,350
Other current assets	242			25
Total current assets	181,186			196,731
Investments and other assets
Investments in subsidiaries	4,455,049			4,223,301
Other assets	13,789			13,833
Total investments and other assets	4,468,838			4,237,134
Total Assets	$	4,650,024		$	4,433,865
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	3,279		$	5,735
Accrued taxes	8,538			8,239
Common dividends payable	62,528			59,789
Other current liabilities	31,295			41,000
Total current liabilities	105,640			114,763
Long-term debt less current maturities	125,000			125,000
Deferred credits and other
Deferred income taxes	4,158			17,395
Pension and other postretirement liabilities	37,611			41,199
Other	37,155			33,219
Total deferred credits and other	78,924			91,813
Common stock equity
Common stock	2,487,250			2,462,712
Accumulated other comprehensive loss	(78,053		)	(114,008		)
Retained earnings	1,785,273			1,624,102
Total Pinnacle West Shareholders’ equity	4,194,470			3,972,806
Noncontrolling interests	145,990			129,483
Total Equity	4,340,460			4,102,289
Total Liabilities and Equity	$	4,650,024		$	4,433,865

See Notes to Pinnacle West’s Consolidated Financial Statements.

171

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2013			2012			2011
Cash flows from operating activities
Net income	$	406,074		$	381,542		$	339,473
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries — net	(420,926		)	(391,528		)	(335,859		)
Depreciation and amortization	95			94			97
Gain on sale of energy-related business	—			—			(10,404		)
Deferred income taxes	(28,806		)	(15,135		)	7,387
Accounts receivable	21,671			28,763			(24,201		)
Accounts payable	(2,449		)	879			(2,677		)
Accrued taxes and income tax receivables — net	1,402			(3,103		)	7,512
Dividends received from subsidiaries	242,100			222,200			228,900
Other	(15,065		)	(4,589		)	19,270
Net cash flow provided by operating activities	204,096			219,123			229,498
Cash flows from investing activities
Investments in subsidiaries	(3,400		)	—			—
Repayments of loans from subsidiaries	2,149			996			61,143
Proceeds from sale of energy-related products and services business	—			—			45,111
Advances of loans to subsidiaries	(2,099		)	(1,200		)	(64,970		)
Proceeds from sale of life insurance policies	—			—			9,357
Net cash flow provided by (used for) investing activities	(3,350		)	(204		)	50,641
Cash flows from financing activities
Issuance of long-term debt	—			125,000			175,000
Short-term borrowings and payments — net	—			—			(16,600		)
Dividends paid on common stock	(235,244		)	(225,075		)	(221,728		)
Repayment of long-term debt	—			(125,000		)	(225,000		)
Common stock equity issuance	17,319			15,955			15,841
Other	298			170			(2,667		)
Net cash flow used for financing activities	(217,627		)	(208,950		)	(275,154		)
Net increase (decrease) in cash and cash equivalents	(16,881		)	9,969			4,985
Cash and cash equivalents at beginning of year	22,679			12,710			7,725
Cash and cash equivalents at end of year	$	5,798		$	22,679		$	12,710

See Notes to Pinnacle West’s Consolidated Financial Statements.

172

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:
2013	$	3,340	$	4,923	$	—	$	5,060	$	3,203
2012	3,748		5,290		—		5,698		3,340
2011	4,709		5,672		—		6,633		3,748

173

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:
2013	$	3,340	$	4,923	$	—	$	5,060	$	3,203
2012	3,748		5,290		—		5,698		3,340
2011	4,376		5,751		—		6,379		3,748

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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, 2013.  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, 2013.  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 77 of this report and “Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)” on page 153 of this report.

(c)Attestation Reports of the Registered Public Accounting Firm

Reference is made to “Report of Independent Registered Public Accounting Firm” on page 78 of this report and “Report of Independent Registered Public Accounting Firm” on page 154 of this report on the internal control over financial reporting of Pinnacle West and APS, respectively.

(d)Changes In Internal Control Over Financial Reporting

No change in Pinnacle West’s or APS’s internal control over financial reporting occurred during the fiscal quarter ended December 31, 2013 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’s internal control over financial reporting.

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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 21, 2014 (the “2014 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 General Counsel, the President and Chief Operating Officer of APS and other persons designated as financial executives by the Chair of the Audit Committee.  The Code of Ethics for Financial Executives is posted on Pinnacle West’s website (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 2014 Proxy Statement.

ITEM 12.  SECURITY OWNERSHIP OF

CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

AND RELATED STOCKHOLDER MATTERS

Reference is hereby made to “Ownership of Pinnacle West Stock” in the 2014 Proxy Statement.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table sets forth information as of December 31, 2013 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	1,736,753	—	3,538,513
Equity compensation plans not approved by security holders	—	—	—
Total	1,736,753	—	3,538,513

(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 be granted; and (c) the 2012 Plan, which was approved by our shareholders at our 2012 annual meeting of shareholders.  See

177

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 2014 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 2014 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	2012		2013
Audit Fees (1)	$	1,659,087	$	1,859,270
Audit-Related Fees (2)	174,310		189,990
Tax Fees (3)	—		28,000

(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 2013 and 2012.

(3)The aggregate fees billed primarily related to tax compliance and tax planning.

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 Chair 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 Chair 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 in 2013 were pre-approved by the Audit Committee or the Chair of the Audit Committee consistent with the pre-approval policy.

178

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

179

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

180

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

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

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

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

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

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

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
10.2.1b	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
10.2.1ab	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
10.2.1bb	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
10.2.1cb	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

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
10.2.1db	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
10.2.2b	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
10.2.2ab	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
10.2.2bb	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
10.2.2cb	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

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
10.2.3b	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
10.2.3ab	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
10.2.4b	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

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
10.2.4ab	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
10.2.4bb	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
10.2.4cb	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

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
10.2.4db	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
10.2.5b	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
10.2.5ab	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
10.2.5bb	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
10.2.5cb	Pinnacle West APS	Third Amendment to the Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates

191

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
10.3.1b	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
10.3.1ab	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
10.3.2b	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
10.4.1b	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
10.4.2b	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
10.4.3b	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
10.4.4b	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

192

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
10.4.5b	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
10.4.6 b	Pinnacle West	Letter Agreement dated May 21, 2009, between Pinnacle West 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
10.5.1bd	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
10.5.1abd	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

193

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
10.5.2bd	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
10.5.3bd	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	10.5.4 to Pinnacle West/APS 2012 Form 10-K, File Nos. 1-8962 and 1-4473	2-22-13
10.6.1b	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
10.6.1abd	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
10.6.1bbd	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

194

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
10.6.1cbd	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
10.6.1dbd	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
10.6.2b	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
10.6.2ab	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
10.6.2bbd	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
10.6.2cbd	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
10.6.2dbd	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

195

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
10.6.2ebd	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
10.6.2fbd	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
10.6.2gbd	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
10.6.3b	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
10.6.4b	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
10.6.5b	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
10.6.6bd	Pinnacle West APS	Summary of 2014 CEO Variable Incentive Plan and Officer Variable Incentive Plan

196

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
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
10.6.8b	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
10.6.8abd	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
10.6.8bbd	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
10.6.8cbd	Pinnacle West	Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan
10.6.8dbd	Pinnacle West	Form of Restricted Stock Unit Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan
10.6.8ebd	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
10.6.8fbd	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

197

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
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
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

198

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
10.7.2a	Pinnacle West APS	Application and Amendment No. 1 to Grant of multi-party rights-of-way and easements, Four Corners 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 APS rights- of-way and easements, Four Corners Site	5.05 to APS’s Form S-7 Registration Statement, File No. 2-59644	9-1-77
10.7.3a	Pinnacle West APS	Application and Amendment No. 1 to Grant of APS rights-of-way and easements, Four Corners 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

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

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
10.9.1	Pinnacle West APS	ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso, 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 ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso, 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
10.9.1b	Pinnacle West APS	Amendment No. 14 to ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso, 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

201

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
10.9.1c	Pinnacle West APS	Amendment No. 15, dated November 29, 2010, to ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso, 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
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

202

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
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 DOE 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
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, as Borrower, JPMorgan Chase Bank, N.A., as Agent, and the lenders and other parties thereto	10.11.2 to Pinnacle West/APS 2012 Form 10-K Report, File Nos. 1-8962 and 1-4473	2-22-13

203

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
10.11.3	Pinnacle West	Five-Year Credit Agreement dated as of November 4, 2011 among Pinnacle West, 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
10.11.4	APS	$500,000,000 Four-Year Credit Agreement dated as of February 14, 2011 among APS 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

204

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
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
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
10.11.7	APS	Five-Year Credit Agreement dated as of April 9, 2013 among APS, as Borrower, Barclays Bank PLC, as Agent and the lenders and other parties thereto	10.1 to Pinnacle West/APS March 31, 2013 Form 10-Q Report, File Nos. 1-8692 and 1-4473	5-3-13

205

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
10.12.1c	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
10.12.1ac	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
10.12.1bc	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

206

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
10.12.1cc	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
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

207

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
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
10.13.1	Pinnacle West APS	Agreement between Pinnacle West Energy Corporation and APS for Transportation and Treatment of Effluent by and between Pinnacle West Energy Corporation and APS dated as of the 10th 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

208

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
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
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 SRP	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 SRP	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 SRP	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 SRP	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 SRP 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

209

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 SCE 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
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

210

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
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
32.1e	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
32.2e	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

211

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
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
99.2c	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

212

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
99.2ac	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
99.2bc	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

213

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
99.3c	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
99.3ac	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

214

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
99.3bc	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
99.4c	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
99.4ac	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

215

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
99.4bc	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

216

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
99.5a	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
99.5b	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

217

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
99.6a	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

218

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
99.6b	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
99.7a	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

219

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
99.8c	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	ACC 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	Pinnacle West APS	XBRL Instance Document
101.SCH	Pinnacle West APS	XBRL Taxonomy Extension Schema Document
101.CAL	Pinnacle West APS	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	Pinnacle West APS	XBRL Taxonomy Extension Label Linkbase Document

220

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Date Filed
101.PRE	Pinnacle West APS	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	Pinnacle West APS	XBRL Taxonomy Definition Linkbase Document

aReports 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.

bManagement contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 15(b) of Form 10-K.

cAn 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.

dAdditional 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.

eFurnished herewith as an Exhibit.

221

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 21, 2014	/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	February 21, 2014
(Donald E. Brandt, Chairman	and Director
of the Board of Directors, President
and Chief Executive Officer)
/s/ James R. Hatfield	Principal Financial Officer	February 21, 2014
(James R. Hatfield,
Executive Vice President and
Chief Financial Officer)
/s/ Denise R. Danner	Principal Accounting Officer	February 21, 2014
(Denise R. Danner,
Vice President, Controller and
Chief Accounting Officer)

222

/s/ Susan Clark-Johnson	Director	February 21, 2014
(Susan Clark-Johnson)
/s/ Denis A. Cortese, M.D.	Director	February 21, 2014
(Denis A. Cortese, M.D.)
/s/ Michael L. Gallagher	Director	February 21, 2014
(Michael L. Gallagher)
/s/ Roy A. Herberger, Jr., Ph.D.	Director	February 21, 2014
(Roy A. Herberger, Jr., Ph.D.)
/s/ Dale E. Klein, Ph.D.	Director	February 21, 2014
(Dale E. Klein, Ph.D.)
/s/ Humberto S. Lopez	Director	February 21, 2014
(Humberto S. Lopez)
/s/ Kathryn L. Munro	Director	February 21, 2014
(Kathryn L. Munro)
/s/ Bruce J. Nordstrom	Director	February 21, 2014
(Bruce J. Nordstrom)
	Director	February 21, 2014
(Richard P. Fox)
	Director	February 21, 2014
(David P. Wagener)

223

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.

	ARIZONA PUBLIC SERVICE COMPANY
	(Registrant)
Date: February 21, 2014	/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 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.

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	February 21, 2014
(Donald E. Brandt, Chairman	and Director
of the Board of Directors, President and
Chief Executive Officer)
/s/ James R. Hatfield	Principal Financial Officer	February 21, 2014
(James R. Hatfield,
Executive Vice President and
Chief Financial Officer)
/s/ Denise R. Danner	Principal Accounting Officer	February 21, 2014
(Denise R. Danner,
Vice President, Controller and
Chief Accounting Officer)

224

/s/ Susan Clark-Johnson	Director	February 21, 2014
(Susan Clark-Johnson)
/s/ Denis A. Cortese, M.D.	Director	February 21, 2014
(Denis A. Cortese, M.D.)
/s/ Michael L. Gallagher	Director	February 21, 2014
(Michael L. Gallagher)
/s/ Roy A. Herberger, Jr., Ph.D.	Director	February 21, 2014
(Roy A. Herberger, Jr., Ph.D.)
/s/ Dale E. Klein, Ph.D.	Director	February 21, 2014
(Dale E. Klein, Ph.D.)
/s/ Humberto S. Lopez	Director	February 21, 2014
(Humberto S. Lopez)
/s/ Kathryn L. Munro	Director	February 21, 2014
(Kathryn L. Munro)
/s/ Bruce J. Nordstrom	Director	February 21, 2014
(Bruce J. Nordstrom)
	Director	February 21, 2014
(Richard P. Fox)
	Director	February 21, 2014
(David P. Wagener)

225

EX-10.2.5C

Exhibit 10.2.5c

THIRD AMENDMENT
TO THE
DEFERRED COMPENSATION PLAN OF 2005 FOR EMPLOYEES OF
PINNACLE WEST CAPITAL CORPORATION AND AFFILIATES

Effective as of January 1, 2005, Pinnacle West Capital Corporation (the “Company”) adopted the Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates (the “Plan”).  The Plan has been amended on two prior occasions.  By this instrument, the Company now desires to amend the Plan to clarify the provisions of Section 5.1(a).

1.             This Third Amendment amends only the provision of the Plan noted below.  Those provisions not expressly amended shall be considered in full force and effect.  This Third Amendment also supersedes the other provisions of the Plan to the extent those provisions are inconsistent with the provisions and intent of this Third Amendment.

2.             Section 5.1(a) (Payment of Termination Benefit — Lump Sum or Installments) of the Plan shall be amended and restated in its entirety to read as follows:

5.1Payment of Termination Benefit.

(a)           Lump Sum or Installments.  A Participant may elect to receive his or her Termination Benefit in a lump sum or in equal annual payments over a period of five (5), ten (10) or fifteen (15) years (the latter determined in accordance with Section 3.7 above) by so electing in an Election Form.  In the Election Form, the Participant also shall specify whether the lump sum payment will be paid or the installment payments will begin within 30 days following either (i) his or her Separation from Service or (ii) the later of his or her attainment of age fifty-five (55) or his or her Separation from Service.  The Participant may change his or her election to an allowable alternative payout date or period by submitting a new Election Form to the Company in accordance with Section 3.6.  Failure to make an election will result in the benefits being paid in a lump sum within 30 days after the Participant’s Separation from Service.  Any election under this Section 5.1 shall be irrevocable,

except to the extent provided in Section 3.6.  Notwithstanding the foregoing, payment of the Termination Benefit shall not be made or commence prior to the date which is six (6) months after the date of a Participant’s Separation from Service in the case of a Participant who is determined to be a Specified Employee.

IN WITNESS WHEREOF, Pinnacle West Capital Corporation has caused this Third Amendment to be executed as of this 18th day of December, 2013.

PINNACLE WEST CAPITAL CORPORATION
By:	/s/ Donald R. Brandt
	Its:	Chairman of the Board, President and CEO

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EX-10.6.6

Exhibit 10.6.6

Summary of 2014 Incentive Plans

On December 17, 2013, the Human Resources Committee (the “Committee”) of the Pinnacle West Capital Corporation (“Pinnacle West”) Board of Directors (the “Board”) approved the Pinnacle West 2014 Annual Incentive Award Plan (the “PNW Plan”), which provides an incentive award opportunity for Donald E. Brandt, the Chairman of the Board, President, and Chief Executive Officer of Pinnacle West and the Chairman of the Board, President and Chief Executive Officer of Arizona Public Service Company (“APS”).  On December 18, 2013, the Board, acting on the recommendation of the Committee, approved the APS 2014 Annual Incentive Award Plan (the “APS Plan”), which includes an incentive award opportunity for James R. Hatfield, Executive Vice President and Chief Financial Officer, and David P. Falck, Executive Vice President and General Counsel, and the APS 2014 Annual Incentive Award Plan for Palo Verde Employees (the “Palo Verde Plan”), which includes an incentive award opportunity for Randall K. Edington, Executive Vice President and Chief Nuclear Officer.  The PNW Plan, the APS Plan and the Palo Verde Plan are referred to collectively herein as the “2014 Plans.”

No incentive payments will be awarded under the PNW Plan or the APS Plan unless Pinnacle West, with respect to Mr. Brandt, and APS, with respect to Messrs. Hatfield and Falck, each achieves a specified threshold earnings level.  No incentive payment will be awarded under the earnings portion of the Palo Verde Plan with respect to Mr. Edington unless the Palo Verde Nuclear Generating Station (“Palo Verde”) achieves specified business unit performance goals.  The Committee will evaluate the impacts of unusual or nonrecurring adjustments to earnings in determining whether any earnings level has been met for purposes of the 2014 Plans.  Arizona Corporation Commission rate-related impacts are excluded.

The award opportunity for Mr. Brandt is based on the achievement of specified 2014 Pinnacle West earnings levels.  Mr. Brandt has an award opportunity of up to 50% of his base salary if the threshold earnings level is met, up to 100% of his base salary if a target earnings level is met, and up to 200% of his base salary if a maximum earnings level is met, before potential adjustments for business results and individual performance; however, in no event may Mr. Brandt’s award exceed 200% of his base salary.  In considering Mr. Brandt’s individual performance, the Committee may also consider shareholder value creation, customer service, financial strength, operating performance, safety performance, leadership effectiveness and other general performance objectives.

The award opportunities for Messrs. Hatfield and Falck under the APS Plan and for Mr. Edington under the Palo Verde Plan are based on the achievement of specified 2014 APS earnings levels and specified business unit performance goals.  Messrs. Hatfield and Falck have a target award opportunity of up to 60% of their base salary.  Messrs. Hatfield and Falck may earn less than the target amount or more, up to a maximum award opportunity of up to 120% of their base salary, depending on the

achievement of the earnings and business unit performance goals separately or in combination, and before adjustment for individual performance.  Mr. Edington has an award opportunity of 12.5% of his base salary, a target of 50% of his base salary, and up to a maximum of 100% of his base salary, depending on the achievement of the earnings and business unit performance goals, separately or in combination, and before adjustment for individual performance.  In no event may the award to each of Messrs. Hatfield, Falck and Edington exceed two times his target amount.  The business unit performance indicators that will be considered for Messrs. Hatfield and Falck are derived from the following APS critical areas of focus as provided in its Strategic Framework:  employees, operational excellence and shareholder value.  The business unit performance indicators for Mr. Edington are based on employees, operational excellence, performance improvement and shareholder value.  In considering each Officer’s individual performance, the Committee may also consider additional factors such as shareholder value creation, customer service, financial strength, operating performance, safety, and the Chief Executive Officer’s assessment of the Officer’s performance during the year.

In addition, consistent with Mr. Edington’s letter agreement regarding his employment, the Board approved a separate compensation opportunity for Mr. Edington of up to $125,000 upon the achievement of specific performance measures tied to Palo Verde operations performance and regulatory evaluations.

EX-10.6.8C

Exhibit 10.6.8c

PERFORMANCE SHARE AWARD AGREEMENT

THIS AWARD AGREEMENT is made and entered into as of                           ,                (the “Date of Grant”), by and between Pinnacle West Capital Corporation (the “Company”), and                                    (“Employee”).

BACKGROUND

A.The Board of Directors of the Company (the “Board of Directors”) has adopted, and the Company’s shareholders have approved, the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan (the “Plan”), pursuant to which Performance Share Awards and Dividend Equivalent Awards may be granted to employees of the Company and its Subsidiaries.

B.The Company desires to grant to Employee Performance Shares and Dividend Equivalents under the terms of the Plan.

C.Pursuant to the Plan, the Company and Employee agree as follows:

AGREEMENT

1.Grant of Award. Pursuant to action of the Committee, which was taken on the Date of Grant, the Company grants to Employee                          (        ) Performance Shares and related Dividend Equivalents. The Performance Shares granted under this Section 1 are referred to in this Award Agreement as the “Base Grant.”

2.Award Subject to Plan. This Performance Share Award and the related Dividend Equivalent Award are granted under and are expressly subject to all of the terms and provisions of the Plan, which terms are incorporated herein by reference, and this Award Agreement. In the event of any conflict between the terms and conditions of this Award Agreement and the Plan, the provisions of the Plan shall control.

3.Performance Period. The Performance Period for this Award begins January 1,             , and ends December 31,           .

4.Payment and Vesting.

(a)Performance Shares Payable In Stock. As soon as practicable in the fiscal year immediately following the end of the Performance Period, the Company will determine (i) the Company’s Total Shareholder Return (as defined herein) as compared to the Total Shareholder Return of the companies in the S&P 1500 Super Composite Electric Utility Index (the “Growth Index”) over the Performance Period and (ii) the Company’s Average Performance with respect to the Performance Metrics (as defined herein). The Company then will deliver to Employee one (1) share of the Company’s Stock for each then-outstanding Performance Share under this Award Agreement, subject to adjustment pursuant to Section 5 below. The Stock payout, if any, related to the Company’s Total Shareholder Return will be made on or before                       ,             . The Company anticipates that the Stock payout, if any, related to the Performance Metrics will be made by                         ,            and in no event will such Stock payout be made later than December 31,             .

(b)Normal or Early Retirement, Death or Disability; Late Career Recipient.

(i) Provided that Employee either qualifies for “Early Retirement” or “Normal Retirement” under the Pinnacle West Capital Corporation Retirement Plan (the “Retirement Plan”), or is a Late Career Recipient (as defined below), in the case of Employee’s death or Disability, Employee shall be deemed to have been employed by the Company through the end of the

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Performance Period and Employee (or his or her estate) will receive the Stock, if any, to which Employee is entitled at the time specified in Section 4(a).

(ii) In the case of Employee’s termination of employment during the Performance Period which constitutes an Early Retirement or a Normal Retirement under the Retirement Plan, Employee shall be deemed to have been employed by the Company through the end of the Performance Period and Employee (or his or her estate) will receive the Stock, if any, to which Employee is entitled at the time specified in Section 4(a).

(iii) If, at the time of Employee’s death, Disability or retirement Employee has reached sixty (60) years of age and has been credited with at least five (5) Years of Service, as defined under the Retirement Plan, and does not otherwise meet the criteria for Early Retirement or Normal Retirement under the Retirement Plan, Employee shall be treated for purposes of this Agreement as a “Late Career Recipient”. Upon a Late Career Recipient’s retirement during the Performance Period, Employee will receive a straight prorated payout of the number of Performance Shares calculated in accordance with Section 5 based on the number of days Employee was employed during the Performance Period. Upon a Late Career Recipient’s retirement following the end of the Performance Period, Employee will receive a payout of the number of Performance Shares calculated in accordance with Section 5. No fractional Stock shall be issued. If the Stock payout results in a fractional share of one-half or greater, such fraction will be increased to provide for the issuance of a full share of Stock. Employee will receive the Stock, if any, to which Employee is entitled at the time specified in Section 4(a).

(c)Termination Without Cause. In the event Employee’s employment is terminated by the Company without cause, the Chief Executive Officer (“CEO”) of the Company may determine in his discretion if, to what extent, and when any unvested portion of the Performance Shares granted under this Agreement should vest; provided, however, that (i) any vesting of unvested Performance Shares granted under this Agreement pursuant to this Section 4(c) shall be approved by the Committee, and (ii) nothing herein shall obligate the CEO to exercise his discretion to cause any unvested Performance Shares to vest.

(d)Termination For Cause. Notwithstanding any other provision in this Section 4, in the event Employee is terminated for Cause, then regardless of Employee’s retirement, Early Retirement, Normal Retirement, death or Disability, Employee shall forfeit the right to receive any Stock hereunder that Employee would otherwise be entitled to receive following his or her date of termination. For purposes only of this Section 4(d), “Cause” means (A) embezzlement, theft, fraud, deceit and/or dishonesty by the Employee involving the property, business or affairs of the Company or any of its Subsidiaries, or (B) an act of moral turpitude which in the sole judgment of the CEO reflects adversely on the business or reputation of the Company or any of its Subsidiaries or negatively affects any of the Company’s or any of its Subsidiaries’ employees or customers.

(e)Disability. “Disability” has the meaning set forth for such term in the Retirement Plan.

(f)Dividend Equivalents. In satisfaction of the Dividend Equivalents Award made pursuant to Section 1, at the time of the Company’s delivery of Stock to Employee pursuant to this Section 4, the Company also will deliver to Employee fully transferrable shares of Stock equal in value to the amount of dividends, if any, that Employee would have received if Employee had directly owned the Stock to which the Performance Shares relate from the Date of Grant to the date of the Stock payout, plus interest on such amount at the rate of 5 percent compounded quarterly, as determined pursuant to the Plan. The number of shares of Stock distributed to Employee will be determined by dividing the amount of the Dividend Equivalents and interest by the Fair Market Value of one share of Stock as of the applicable date of the Stock payout. No fractional Stock shall be issued. If the Stock payout results in a fractional share of one-half or greater, such fraction will be increased to provide for the issuance of a full share of Stock.

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(g)Impact on Pension. The value of the shares of Stock distributed upon payment for the Performance Shares and Dividend Equivalents will be disregarded for purposes of calculating the amount of Employee’s benefit under any Company retirement plans.

5.Performance Criteria and Adjustments. Fifty percent (50%) of the Performance Shares awarded under this Award Agreement will be determined pursuant to Section 5(a) and fifty percent (50%) of the Performance Shares awarded under this Award Agreement will be determined pursuant to Section 5(b). In no event will Employee be entitled to receive a number of Performance Shares pursuant to this Award Agreement greater than 2.0 times the Base Grant.

(a)Adjustment of Base Grant for Total Shareholder Return. Fifty percent (50%) of the Base Grant will increase or decrease based upon the Company’s “Total Shareholder Return” as compared to the Total Shareholder Return of the companies in the Growth Index during the Performance Period, as follows:

If the Company’s Total Shareholder Return Over The Performance Period As Compared to the Total Shareholder Return of the Companies in the Growth Index is:	The Number of Performance Shares will be:
90th Percentile or greater	1.0 X Base Grant
75th Percentile	.75 X Base Grant
50th Percentile	0.5 X Base Grant
25th Percentile	0.25 X Base Grant
Less than 25th Percentile	None

If intermediate percentiles are achieved, the number of Performance Shares awarded will be prorated (partial shares will be rounded down to the nearest whole share when applicable). For example, if the Company’s Total Shareholder Return during the Performance Period places the Company’s performance in the 60th percentile, then the number of Performance Shares would be increased to 0.60 (0.5 X 60/50) multiplied by the Base Grant. In no event will Employee be entitled to receive a number of Performance Shares pursuant to this Subsection 5(a) greater than 1.0 times the Base Grant.

(b)Adjustment of Base Grant for Performance Metrics. Fifty percent (50%) of the Base Grant will increase or decrease based upon the Company’s “Average Performance” with respect to the “Performance Metrics,” as follows:

If the Company’s Average Performance is:	The Number of Performance Shares will be:
90th Percentile or greater	1.0 X Base Grant
75th Percentile	.75 X Base Grant
50th Percentile	0.5 X Base Grant
25th Percentile	0.25 X Base Grant
Less than 25th Percentile	None

If intermediate percentiles are achieved, the number of Performance Shares awarded pursuant to this Subsection 5(b) will be prorated (partial shares will be rounded down to the nearest whole share when applicable). For example, if the Company’s Average Performance during the Performance Period places the Company’s performance in the 60th percentile, then the number of Performance Shares would be increased to .60 (0.5 X 60/50) multiplied by the Base Grant. In no event will Employee be entitled to receive a number of Performance Shares pursuant to this Subsection (b) greater than 1.0 times the Base Grant.

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6.Definitions.

(a)Performance Metrics. The “Performance Metrics” for the Performance Period are: (i) the JD Power Residential National Large Segment Survey for investor-owned utilities; (ii) the System Average Interruption Frequency Index (Major Events Excluded) (“SAIFI”); (iii) Arizona Public Service Company’s customer to employee improvement ratio; (iv) the OSHA rate (All Incident Injury Rate); (v) nuclear capacity factor; and (vi) coal capacity factor.

(1)With respect to the Performance Metric described in clause (i) of this Subsection 6(a), the JD Power Residential National Large Segment Survey will provide data on an annual basis reflecting the Company’s percentile ranking, relative to other participating companies.

(2)With respect to the Performance Metric described in clause (ii) of this Subsection 6(a), the Edison Electric Institute (“EEI”) will provide data on an annual basis regarding the SAIFI result of the participating companies; the Company will calculate its SAIFI result for the year in question and determine its percentile ranking based on the information provided by EEI.

(3)With respect to the Performance Metric described in clause (iii) of this Subsection 6(a), SNL, an independent third party data system, will provide data on an annual basis regarding the customer and employee counts; the Company will use its customer and employee counts for the year in question and determine its percentile ranking based on the information provided by SNL. Only those companies whose customers and employees were included in the data provided by SNL in each of the years of the Performance Period will be considered.

(4)With respect to the Performance Metric described in clause (iv) of this Subsection 6(a), EEI will provide data on an annual basis regarding the OSHA rate of the participating companies; the Company will calculate its OSHA rate for the year in question and determine its percentile ranking based on the information provided by EEI.

(5)With respect to the Performance Metric described in clause (v) of this Subsection 6(a), SNL will provide data on an annual basis regarding the nuclear capacity factors of the participating nuclear plants; the Company will calculate its nuclear capacity factor for the year in question and determine its percentile ranking based on the information provided by SNL. Only those plants that were included in the data provided by SNL in each of the years of the Performance Period will be considered.

(6)With respect to the Performance Metric described in clause (vi) of this Subsection 6(a), SNL will provide data on an annual basis regarding the coal capacity factors of the participating coal plants; the Company will calculate its coal capacity factor for the year in question and determine its percentile ranking based on the information provided by SNL. Only those plants that were included in the data provided by SNL in each of the years of the Performance Period will be considered.

(7)The Company’s percentile ranking during the Performance Period for each Performance Metric will be the average of the Company’s percentile ranking for each Performance Metric during each of the three years of the Performance Period (each, an “Average Performance Metric”); provided, however, that if the third year of a Performance Metric is not calculable by December 15 of the following year, the Performance Metric shall consist of the three most recent years for which such Performance Metric is calculable. The Company’s “Average Performance,” for purposes of determining any Base Grant adjustments pursuant to Subsection 5(b) above will be the average of the Average Performance Metrics. If only quartile, rather than percentile, rankings are available for a particular Performance Metric, the Average Performance Metric for any such Performance Metric shall be expressed as a percentile. For example, if the Performance Metric was in the top quartile for two

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Performance Periods and in the lowest quartile in the other Performance Period, the average of these quartiles would be 3 (the average of 4, 4, and 1) and the Average Performance Metric would be the 75th percentile (3 /4). The calculations in this Subsection 6(a)(7) will be verified by the Company’s internal auditors.

(8)If either EEI or SNL discontinues providing the data specified above, the Committee shall select a data source that, in the Committee’s judgment, will provide data most comparable to the data provided by EEI or SNL, as the case may be. If the JD Power Residential National Large Segment Survey for investor-owned utilities (or a successor JD Power survey) is not available during each of the years of the Performance Period, the Performance Metric associated with the JD Power Residential Survey (Subsection 6(a)(1)) will be disregarded and not included in the Company’s Average Performance for purposes of determining any Base Grant adjustments pursuant to Subsection 5(b).

(b)Total Shareholder Return. “Total Shareholder Return” for the Performance Period is the measure of a company’s stock price appreciation plus any dividends paid during the Performance Period. Only those companies that were included in the Growth Index in each of the years of the Performance Period will be considered. Total Shareholder Return for the Company and the companies in the Growth Index will be determined using the Daily Comparative Return as calculated by Bloomberg (or other independent third party data system). If the Growth Index is discontinued, the Committee shall select the most comparable index then in use for the sector comparison. In addition, if the sector comparison is no longer representative of the Company’s industry or business, the Committee shall replace the Growth Index with the most representative index then in use. Once the Total Shareholder Returns of the Company and all relevant companies in the Growth Index have been determined, the member companies will be ranked from greatest to least. Percentiles will be calculated (interpolated from 0% to 100%) based on a company’s relative ranking. Percentiles will be carried out to one (1) decimal place. If the Company is not in the Growth Index, then its percentile will be interpolated between the companies listed in the relative ranking. These calculations will be verified by the Company’s internal auditors.

7.Termination of Award. This Award Agreement will terminate and be of no further force or effect on the date that Employee is no longer employed by the Company or any of its Subsidiaries, whether due to voluntary or involuntary termination, death, retirement, disability, or otherwise, except as specifically set forth in Section 4 above or in Article 15 of the Plan. Employee will, however, be entitled to receive any Stock and Dividend Equivalents payable under Section 4 of this Award Agreement if Employee’s employment terminates after the end of the Performance Period but before Employee’s receipt of such Stock and Dividend Equivalents.

8.Section 409A Compliance. If the Company concludes, in the exercise of its discretion, that this Award is subject to Section 409A of the Code, the Plan and this Award Agreement shall be administered in compliance with Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with Section 409A. If the Company concludes, in the exercise of its discretion, that this Award is not subject to Section 409A, but, instead, is eligible for the short-term deferral exception to the requirements of Section 409A, the Plan and this Award Agreement shall be administered to comply with the requirements of the short-term deferral exception to the requirements of Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with the requirements of such exception. In either event, Employee does not have any right to make any election regarding the time or form of any payment due under this Award Agreement other than the tax withholding election described in Section 9.

9.Tax Withholding. Employee is responsible for any and all federal, state, and local income, payroll or other tax obligations or withholdings (collectively, the “Taxes”) arising out of this Award. Employee shall pay any and all Taxes due in connection with a payout of Stock hereunder by check or by having the Company withhold shares of Stock from such payout. No later than April 30,         , Employee must elect, on the election form attached hereto, how Employee will satisfy the tax

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obligations upon a payout. In the absence of a timely election by Employee, Employee’s tax withholding obligation will be satisfied through the Company’s withholding of shares of Stock as set forth above.

10.Continued Employment. Nothing in the Plan or this Award Agreement shall be interpreted to interfere with or limit in any way the right of the Company or its Subsidiaries to terminate Employee’s employment or services at any time. In addition, nothing in the Plan or this Award Agreement shall be interpreted to confer upon Employee the right to continue in the employ or service of the Company or its Subsidiaries.

11.Confidentiality. During Employee’s employment and after termination thereof for any reason, Employee agrees that Employee will not, directly or indirectly, in one or a series of transactions, disclose to any person, or use or otherwise exploit for Employee’s own benefit or for the benefit of anyone other than the Company or any of its Affiliates any Confidential Information (as hereinafter defined), whether prepared by Employee or not; provided, however, that during the term of Employee’s employment, any Confidential Information may be disclosed (i) to officers, representatives, employees and agents of the Company and its Affiliates who need to know such Confidential Information in order to perform the services or conduct the operations required or expected of them in the business, and (ii) in good faith by Employee in connection with the performance of Employee’s job duties to persons who are authorized to receive such information by the Company or its Affiliates. Employee shall have no obligation to keep confidential any Confidential Information, if and to the extent disclosure of any such information is specifically required by law; provided, however, that in the event disclosure is required by applicable law, Employee shall provide the Company with prompt notice of such requirement, prior to making any disclosure, so that it may seek an appropriate protective order.

Employee agrees that all Confidential Information of the Company and its Affiliates (whether now or hereafter existing) conceived, discovered or made by him during employment exclusively belongs to the Company or its Affiliates (and not to Employee). Employee will promptly disclose such Confidential Information to the Company and perform all actions reasonably requested by the Company to establish and confirm such exclusive ownership. For purposes of this Section 11, the term “Confidential Information” shall mean and include any information disclosed to Employee any time during Employee’s employment with the Company or its Affiliates or thereafter which is not generally known to the public, including, but not limited to, information concerning the Company’s or its Affiliates’ assets and valuations, business plans, methods of operation, management, information systems, procedures, processes, practices, policies, plans, programs, personnel and/or reports or other information prepared by appraisers, consultants, advisors, bankers or attorneys.

12.Restrictive Covenants.

(a)Non-Competition.  Employee agrees that for a period of 12 months following any Termination of Employment voluntarily by Employee (other than due to Disability),  Employee shall not, without the prior written consent of the Company’s General Counsel, participate, whether as a consultant, employee, contractor, partner, owner (ownership of less than 5% of the outstanding stock of a publicly traded company will not be considered ownership under this provision), co-owner, or otherwise, with any business, corporation, group, entity or individual that is or intends to be engaged in the business activity of supplying electricity in any area of Arizona for which the Company or its Affiliates is authorized to supply electricity.

(b)Employee Non-Solicitation. Employee agrees that for a period of 12 months following Employee’s termination of employment for any reason, Employee will not encourage, induce, or otherwise solicit, or actively assist any other person or organization to encourage, induce or otherwise solicit, directly or indirectly, any employee of the Company or any of its Affiliates to terminate his or her employment with the Company or its Affiliates, or otherwise interfere with the advantageous business relationship of Pinnacle West and its Affiliates with their employees.

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(c)[No Pledging or Hedging. Employee agrees that during his or her term of employment and for a period of 90 days thereafter, Employee will not pledge, margin, hypothecate, hedge, or otherwise grant an economic interest in any shares of Company stock received by Employee pursuant to this Award (net of shares sold or surrendered to meet tax withholding or exercise requirements). This restriction shall extend to the purchase or creation of any short sales, zero-cost collars, forward sales contracts, puts, calls, options or other derivative securities in respect of any shares of Company stock.]

(d)Remedies. If Employee fails to comply with Sections 11, 12(a), [or] 12(b) [or 12(c)] in a material respect, the Company may (i) cause any of Employee’s unvested Performance Shares and related Dividend Equivalents to be cancelled and forfeited, (ii) refuse to deliver shares of Stock or cash in exchange for vested Performance Shares or Dividend Equivalents, and/or (iii) pursue any other rights and remedies the Company may have pursuant to this Award Agreement or the Plan at law or in equity including, specifically, injunctive relief.

13.Non-Transferability. Neither this Award nor any rights under this Award Agreement may be assigned, transferred, or in any manner encumbered except as provided in the Plan.

14.Definitions: Copy of Plan and Plan Prospectus. To the extent not specifically defined in this Award Agreement, all capitalized terms used in this Award Agreement will have the same meanings ascribed to them in the Plan. By signing this Award Agreement, Employee acknowledges receipt of a copy of the Plan and the related Plan Prospectus.

15.Amendment. Except as provided below, any amendments to this Award Agreement must be made by a written agreement executed by the Company and Employee. The Company may amend this Award Agreement unilaterally, without the consent of Employee, if the change (i) is required by law or regulation, (ii) does not adversely affect in any material way the rights of Employee, or (iii) is required to cause the benefits under the Plan to qualify as performance-based compensation within the meaning of Section 162(m) of the Code or to comply with the provisions of Section 409A of the Code and applicable regulations or other interpretive authority. Additional rules relating to amendments to the Plan or any Award Agreement to assure compliance with Section 409A of the Code are set forth in Section 17.15 of the Plan.

16.Performance-Based Award. This Award is intended to be a Performance-Based Award if Employee is considered to be a Covered Employee for the tax year of the Company for which the Company claims a related tax deduction.

IN WITNESS WHEREOF, the Company has caused this Award Agreement to be executed, as of the Date of Grant, by an authorized representative of the Company and this Award Agreement has been executed by Employee.

PINNACLE WEST CAPITAL CORPORATION

By:

Its:

Date:

EMPLOYEE

By:

Date:

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Pinnacle West Capital Corporation

PERFORMANCE SHARE AWARD
ELECTION FORM

(applies to Award Agreement dated     /    /        )

INFORMATION ABOUT YOU

Last First Middle Initial Employee ID#

TAX WITHHOLDING ELECTION
I hereby elect to satisfy any tax withholding obligation associated with my receipt of Stock pursuant to my Performance Share Award in the following form (place an “X” in the “Check” column or in the “Stock” column):
Check	Stock
(I will write a check for my taxes that are due and deliver it to the Company within one (1) day of the release of the Stock)	(The Company should withhold shares of my Stock to cover my taxes)
o	o
To the extent permitted by law, I hereby elect Federal tax withholding of: ¨ minimum withholding rate in effect at the time of release (currently 25%); ¨              percent (within the range of 25% and 39.6%): or ¨ maximum withholding rate in effect at the time of a release (currently 39.6%).
PARTICIPANT NAME (PLEASE PRINT)
	DATE
PARTICIPANT SIGNATURE

IMPORTANT NOTE: Please complete and return this Election Form to Jennifer Mellegers at Mail Station 9996 by                  ,         .

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EX-10.6.8D

Exhibit 10.6.8d

RESTRICTED STOCK UNIT AWARD AGREEMENT

THIS AWARD AGREEMENT is made and entered into as of                         ,              (the “Date of Grant”), by and between Pinnacle West Capital Corporation (the “Company”), and                                          (“Employee”).

BACKGROUND

A.The Board of Directors of the Company (the “Board of Directors”) has adopted, and the shareholders of the Company have approved, the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan (the “Plan”), pursuant to which Restricted Stock Units and Dividend Equivalents may be granted to employees of the Company and its Subsidiaries.

B.The Company desires to grant to Employee Restricted Stock Units and Dividend Equivalents under the terms of the Plan.

C.Pursuant to the Plan, the Company and Employee agree as follows:

AGREEMENT

1.Grant of Award.  Pursuant to action of the Committee which was taken on the Date of Grant, the Company grants to Employee                        (          ) Restricted Stock Units and related Dividend Equivalents.

2.Award Subject to Plan.  This Restricted Stock Unit Award and the related Dividend Equivalent Award are granted under and are expressly subject to all of the terms and provisions of the Plan, which terms are incorporated herein by reference, and this Award Agreement.  In the event of any conflict between the terms and conditions of this Award Agreement and the Plan, the provisions of the Plan shall control.

3.Vesting of Restricted Stock Units.

(a)Regular Vesting.  The Restricted Stock Units granted pursuant to Section 1 will vest and no longer be subject to the restrictions of and forfeiture under this Award Agreement on the following dates (each a “Vesting Date”) and as otherwise set forth in this Section 3:

(i)x,xxx Restricted Stock Units will vest on                       ,           ;

(ii)x,xxx Restricted Stock Units will vest on                       ,           ;;

(iii)x,xxx Restricted Stock Units will vest on                       ,           ;; and

(iv)The remaining x,xxx Restricted Stock Units will vest on                       ,           ;.

(b)Normal or Early Retirement, Death or Disability.

(i)Provided that Employee either qualifies for “Early Retirement” or “Normal Retirement”, as defined in the Pinnacle West Capital Corporation Retirement Plan (the “Retirement Plan”), or is a Late Career Recipient

(as defined below), the Restricted Stock Units will fully vest and no longer be subject to the restrictions of and forfeiture under this Award Agreement upon Employee’s death or Disability.

(ii)The Restricted Stock Units will fully vest and no longer be subject to the restrictions of and forfeiture under this Award Agreement upon Employee’s termination of employment which constitutes an Early Retirement or a Normal Retirement.

(c)Late Career Recipient.  If, at the time of Employee’s death, Disability or retirement, Employee has reached sixty (60) years of age and has been credited with at least five (5) Years of Service, as defined under the Retirement Plan, and does not otherwise meet the criteria for Early Retirement or Normal Retirement under the Retirement Plan, Employee shall be treated for purposes of this Agreement as a “Late Career Recipient.”  Upon the date of a Late Career Recipient’s retirement (the “Effective Date”), a portion of Employee’s unvested Restricted Stock Units that would have vested on the next Vesting Date will vest on a straight pro-rata basis based on the number of days elapsed between the last Vesting Date (or, if a Vesting Date has not yet occurred, the Date of Grant) and the Effective Date.  Payment will be made on the next Vesting Date following the Effective Date in accordance with Section 4(a).  No fractional Stock shall be issued.  If the Stock payout results in a fractional share of one-half or greater, such fraction will be increased to provide for the issuance of a full share of Stock.

(d)Termination Without Cause.  In the event Employee’s employment is terminated by the Company without cause, the Chief Executive Officer of the Company (the “CEO”) may determine in his discretion if, to what extent, and when, any unvested portion of the Restricted Stock Units granted pursuant to this Award should vest; provided, however, that (i) any vesting of unvested Restricted Stock Units pursuant to this Section 3(d) shall be approved by the Chair of the Committee, and (ii) nothing herein shall obligate the CEO to exercise his discretion to cause any unvested Restricted Stock Units to vest.

(e)Termination For Cause.  Notwithstanding any other provision in this Section 3, in the event Employee’s employment is terminated for Cause, then regardless of Employee’s retirement, Early Retirement, Normal Retirement, death or Disability, Employee shall forfeit the right to receive any cash payment or Stock hereunder that Employee would otherwise be entitled to receive following his or her date of termination.  For purposes only of this Section 3(e), “Cause” means (A) embezzlement, theft, fraud, deceit and/or dishonesty by the Employee involving the property, business or affairs of the Company or any of its Subsidiaries, or (B) an act of moral turpitude which in the sole judgment of the CEO reflects adversely on the business or reputation of the Company or any of its Subsidiaries or negatively affects any of the Company’s or any of its Subsidiaries’ employees or customers.

(f)Disability.  “Disability” has the meaning set forth for such term in the Retirement Plan.

4.Payment.

(a)Time and Form of Payment.  When a Restricted Stock Unit vests in accordance with Section 3 above, Employee (or his or her estate) shall receive in exchange for each Restricted Stock Unit one unrestricted fully transferrable share of Stock.  Employee may elect, pursuant to Section 4(b), to receive payment for the Restricted Stock Units payable on any Vesting Date in the form of fully

2

transferrable shares of Stock or 50% cash and 50% in fully transferrable shares of Stock.  Except as provided in Section 3(d) above following a termination of employment without cause, if a Restricted Stock Unit vests prior to the applicable Vesting Date due to Employee’s status as a Late Career Recipient or Employee’s death, Disability, Early Retirement, or Normal Retirement, the payment will be made on the Vesting Date applicable to such Restricted Stock Unit.  Except as provided in Section 3(d) above following a termination of employment without cause, any cash payment will be based on the Fair Market Value of one share of Stock determined as of the applicable Vesting Date.  The payment shall be made within 30 days of the applicable Vesting Date, provided that any payment for a Restricted Stock Unit that vests prior to the applicable Vesting Date due to the death or Disability of Employee, or due to the retirement of a Late Career Recipient, shall be made no later than March 15 of the year following the year in which Employee dies, becomes Disabled, or, in the case of a Late Career Recipient, retires.  If Employee dies after acquiring a vested interest in the Restricted Stock Units but before receiving payment for the Restricted Stock Units, the payment will be made to Employee’s designated beneficiary in accordance with the elections previously made by Employee.

(b)Election of Form of Payment.  No later than April 30,         , Employee must elect to receive payment for Employee’s vested Restricted Stock Units and Dividend Equivalents in fully transferable shares of Stock or 50% in cash and 50% in fully transferrable shares of Stock by completing and returning to the Company the election form attached to this Agreement.  In the absence of a timely election by Employee, Employee will receive payment for the vested Restricted Stock Units and Dividend Equivalents in fully transferable shares of Stock.

(c)Dividend Equivalents.  In satisfaction of the Dividend Equivalents Award made pursuant to Section 1, at the time of the Company’s delivery of payment pursuant to Section 3 or Section 4(a), the Company also will deliver to Employee a payment equal to the amount of dividends, if any, that Employee would have received if Employee had directly owned the Stock to which the Restricted Stock Units relate from the Date of Grant to the applicable Vesting Date, plus interest on such amount at the rate of 5 percent compounded quarterly.  Pursuant to the election filed by the Employee pursuant to Section 4(b), payment for the Dividend Equivalents and interest will be made in fully transferrable shares of Stock, or 50% in cash and 50% in fully transferrable shares of Stock.  The number of shares of Stock distributed to Employee will be determined by dividing the amount of the Dividend Equivalents and interest by the Fair Market Value of one share of Stock as of the applicable date of vesting. No fractional Stock shall be issued.  If the Stock payout results in a fractional share of one-half or greater, such fraction will be increased to provide for the issuance of a full share of Stock.

(d)Impact on Pension Plans. The value of the shares of Stock distributed upon payment for the Restricted Stock Units and Dividend Equivalents will be disregarded for purposes of calculating the amount of Employee’s benefit under any Company retirement plans.

5.Termination of Award.  Except as otherwise provided in Section 3 above or in Article 15 of the Plan, in the event of the termination of Employee’s employment with the Company or any of its Subsidiaries, whether due to voluntary or involuntary termination, retirement, death, disability or otherwise, Employee’s right to vest in any additional Restricted Stock Units or Dividend Equivalents under the Plan or this Award Agreement, if any, will terminate. Any unvested Restricted Stock Units and the related Dividend Equivalents will

3

be forfeited effective as of the date that Employee terminates active employment with the Company or any of its Subsidiaries.

6.Section 409A Compliance.  If the Company concludes, in the exercise of its discretion, that this Award is subject to Section 409A of the Code, the Plan and this Award Agreement shall be administered in compliance with Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with Section 409A.  If the Company concludes, in the exercise of its discretion, that this Award is not subject to Section 409A, but, instead, is eligible for the short-term deferral exception to the requirements of Section 409A, the Plan and this Award Agreement shall be administered to comply with the requirements of the short-term deferral exception to the requirements of Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with the requirements of such exception.  In either event, Employee does not have any right to make any election regarding the time or form of any payment due under this Award Agreement other than the election described in Section 4(b).

7.Tax Withholding.  Employee is responsible for any and all federal, state, and local income, payroll or other tax obligations or withholdings (collectively, the “Taxes”) arising out of this Award.  Employee shall pay any and all Taxes due prior to the payout of Stock or cash hereunder by check or other arrangement acceptable to the Company.  Employee shall pay any and all Taxes due in connection with a payout of Stock or cash hereunder by check or by having the Company withhold cash or shares of Stock from such payout.  No later than April 30,         , Employee must elect, on the election form described in Section 4(b), how Employee will satisfy the tax obligations upon a payout.  In the absence of a timely election by Employee, Employee’s tax withholding obligation upon a payout will be satisfied through the Company’s withholding of cash or shares of Stock as set forth above.

8.Continued Employment.  Nothing in the Plan or this Award Agreement shall be interpreted to interfere with or limit in any way the right of the Company or its Subsidiaries to terminate Employee’s employment or services at any time.  In addition, nothing in the Plan or this Award Agreement shall be interpreted to confer upon Employee the right to continue in the employ or service of the Company or its Subsidiaries.

9.Confidentiality.  During Employee’s employment and after termination thereof for any reason, Employee agrees that Employee will not, directly or indirectly, in one or a series of transactions, disclose to any person, or use or otherwise exploit for Employee’s own benefit or for the benefit of anyone other than the Company or any of its Affiliates any Confidential Information (as hereinafter defined), whether prepared by Employee or not; provided, however, that during the term of Employee’s employment, any Confidential Information may be disclosed (i) to officers, representatives, employees and agents of the Company and its Affiliates who need to know such Confidential Information in order to perform the services or conduct the operations required or expected of them in the business, and (ii) in good faith by Employee in connection with the performance of Employee’s job duties to persons who are authorized to receive such information by the Company or its Affiliates.  Employee shall have no obligation to keep confidential any Confidential Information, if and to the extent disclosure of any such information is specifically required by law; provided, however, that in the event disclosure is required by applicable law, Employee shall provide the Company with prompt notice of such requirement, prior to making any disclosure, so that it may seek an appropriate protective order.

Employee agrees that all Confidential Information of the Company and its Affiliates (whether now or hereafter existing) conceived, discovered or made by him during employment exclusively belongs to the Company or its Affiliates (and not to Employee). Employee will promptly disclose such Confidential Information to the Company and

4

perform all actions reasonably requested by the Company to establish and confirm such exclusive ownership.  For purposes of this Section 9, the term “Confidential Information” shall mean and include any information disclosed to Employee any time during Employee’s employment with the Company or its Affiliates or thereafter which is not generally known to the public, including, but not limited to, information concerning the Company’s or its Affiliates’ assets and valuations, business plans, methods of operation, management, information systems, procedures, processes, practices, policies, plans, programs, personnel and/or reports or other information prepared by appraisers, consultants, advisors, bankers or attorneys.

10.Restrictive Covenants.

(a)Non-Competition.  Employee agrees that for a period of 12 months following any Termination of Employment voluntarily by Employee (other than due to Disability),  Employee shall not, without the prior written consent of the Company’s General Counsel, participate, whether as a consultant, employee, contractor, partner, owner (ownership of less than 5% of the outstanding stock of a publicly traded company will not be considered ownership under this provision), co-owner, or otherwise, with any business, corporation, group, entity or individual that is or intends to be engaged in the business activity of supplying  electricity  in any area of Arizona for which the Company or its Affiliates is authorized to supply electricity.

(b)Employee Non-Solicitation.  Employee agrees that for a period of 12 months following Employee’s termination of employment for any reason, Employee will not encourage, induce, or otherwise solicit, or actively assist any other person or organization to encourage, induce or otherwise solicit, directly or indirectly, any employee of the Company or any of its Affiliates to terminate his or her employment with the Company or its Affiliates, or otherwise interfere with the advantageous business relationship of the Company and its Affiliates with their employees.

(c)[No Pledging or Hedging. Employee agrees that during his or her term of employment and for a period of 90 days thereafter, Employee will not pledge, margin, hypothecate, hedge, or otherwise grant an economic interest in any shares of Company stock received by Employee pursuant to this Award (net of shares sold or surrendered to meet tax withholding or exercise requirements).  This restriction shall extend to the purchase or creation of any short sales, zero-cost collars, forward sales contracts, puts, calls, options or other derivative securities in respect of any shares of Company stock.]

(d)Remedies.  If Employee fails to comply with Sections 9, 10(a), [or] 10(b) [or 10(c)] in a material respect, the Company may (i) cause any of Employee’s unvested Restricted Stock Units and related Dividend Equivalents to be cancelled and forfeited, (ii) refuse to deliver shares of Stock or cash in exchange for vested Restricted Stock Units or Dividend Equivalents, and/or (iii) pursue any other rights and remedies the Company may have pursuant to this Award Agreement or the Plan at law or in equity including, specifically, injunctive relief.

11.Non-Transferability.  Neither this Award nor any rights under this Award Agreement may be assigned, transferred, or in any manner encumbered except as provided in the Plan.

12.Definitions: Copy of Plan and Plan Prospectus.  To the extent not specifically defined in this Award Agreement, all capitalized terms used in this Award Agreement will have

5

the same meanings ascribed to them in the Plan.  By signing this Award Agreement, Employee acknowledges receipt of a copy of the Plan and the related Plan Prospectus.

13.Amendment.  Except as provided below, any amendments to this Award Agreement must be made by a written agreement executed by the Company and Employee.  The Company may amend this Award Agreement unilaterally, without the consent of Employee, if the change (i) is required by law or regulation, (ii) does not adversely affect in any material way the rights of Employee, or (iii) is required to cause the benefits under the Plan to qualify as performance-based compensation within the meaning of Section 162(m) of the Code or to comply with the provisions of Section 409A of the Code and applicable regulations or other interpretive authority.  Additional rules relating to amendments to the Plan or any Award Agreement to assure compliance with Section 409A of the Code are set forth in Section 17.15 of the Plan.

IN WITNESS WHEREOF, the Company has caused this Award Agreement to be executed, as of the Date of Grant, by an authorized representative of the Company and this Award Agreement has been executed by Employee.

PINNACLE WEST CAPITAL CORPORATION

By:

Its:

Date:

EMPLOYEE

By:

Date:

6

Pinnacle West Capital Corporation

RESTRICTED STOCK UNIT AWARD
ELECTION FORM

(applies to Award Agreement dated       /    /        )

INFORMATION ABOUT YOU

Last First Middle Initial Employee ID#

1.  PAYMENT ELECTION
In accordance with the terms of the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan and pursuant to Section 4(b) of the Award Agreement, I hereby elect to receive payment for the Restricted Stock Units and Dividend Equivalents that vest on the dates set forth below in the following form (place an “X” in the “Stock” column or in the “50% Cash/50% Stock” column for each of the years and types of Awards set forth below):
	Restricted Stock Units and Dividend Equivalents
Vesting Date	Stock	50% Cash/ 50% Stock
/    /	¨	¨
/    /	¨	¨
/    /	¨	¨
/    /	¨	¨

2.  TAX WITHHOLDING ELECTION
I hereby elect to satisfy any tax withholding obligation associated with my receipt of Stock or Stock and cash in exchange for my Restricted Stock Units and Dividend Equivalents in the following form (place an “X” in the “Check” column or in the “Withholding” column):
Check	Withholding
(I will write a check for my taxes that are due and deliver it to the Company within one (1) day of the release date of my Stock or cash payment)	(The Company should withhold shares of my Stock or cash payment
	to cover my taxes)
o
	o
To the extent permitted by law, I hereby elect Federal tax withholding of: ¨ minimum withholding rate in effect at the time of release (currently 25%); ¨              percent (within the range of 25% and 39.6%); or ¨ maximum withholding rate in effect at the time of a release (currently 39.6%).
PARTICIPANT NAME (PLEASE PRINT)
	DATE
PARTICIPANT SIGNATURE

IMPORTANT NOTE: Please complete and return this Election Form to Jennifer Mellegers at Mail Station 9996 by                  ,         

7

EX-12.1

Exhibit 12.1

PINNACLE WEST CAPITAL CORPORATION
RATIO OF EARNINGS TO FIXED CHARGES
(dollars in thousands)

	2013		2012		2011		2010		2009
Earnings:
Income from continuing operations attributable to common shareholders	$	406,074	$	387,380	$	328,110	$	324,688	$	236,839
Income taxes	230,591		237,317		183,604		160,869		138,551
Fixed charges	206,089		219,437		246,462		248,664		241,807
Total earnings	$	842,754	$	844,134	$	758,176	$	734,221	$	617,197
Fixed Charges:
Interest expense	$	201,888	$	214,616	$	241,995	$	244,174	$	237,766
Estimated interest portion of annual rents	4,201		4,821		4,467		4,490		4,041
Total fixed charges	$	206,089	$	219,437	$	246,462	$	248,664	$	241,807
Ratio of Earnings to Fixed Charges (rounded down)	4.08		3.84		3.07		2.95		2.55

EX-12.2

Exhibit 12.2

ARIZONA PUBLIC SERVICE COMPANY
RATIO OF EARNINGS TO FIXED CHARGES
(dollars in thousands)

	2013		2012		2011		2010		2009
Earnings:
Income from continuing operations attributable to common shareholders	$	424,969	$	395,497	$	336,249	$	335,663	$	251,225
Income taxes	245,095		244,396		192,542		170,465		152,574
Fixed charges	202,457		214,227		238,286		234,184		227,274
Total earnings	$	872,521	$	854,120	$	767,077	$	740,312	$	631,073
Fixed Charges:
Interest charges	$	194,616	$	205,533	$	229,326	$	225,269	$	218,969
Amortization of debt discount	4,046		4,215		4,616		4,559		4,675
Estimated interest portion of annual rents	3,795		4,479		4,344		4,356		3,630
Total fixed charges	$	202,457	$	214,227	$	238,286	$	234,184	$	227,274
Ratio of Earnings to Fixed Charges (rounded down)	4.30		3.98		3.21		3.16		2.77

EX-12.3

Exhibit 12.3

PINNACLE WEST CAPITAL CORPORATION
RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED
STOCK DIVIDEND REQUIREMENTS
(dollars in thousands)

	2013		2012		2011		2010		2009
Earnings:
Income from continuing operations attributable to common shareholders	$	406,074	$	387,380	$	328,110	$	324,688	$	236,839
Income taxes	230,591		237,317		183,604		160,869		138,551
Fixed charges	206,089		219,437		246,462		248,664		241,807
Total earnings	$	842,754	$	844,134	$	758,176	$	734,221	$	617,197
Fixed Charges:
Interest expense	$	201,888	$	214,616	$	241,995	$	244,174	$	237,766
Estimated interest portion of annual rents	4,201		4,821		4,467		4,490		4,041
Total fixed charges	$	206,089	$	219,437	$	246,462	$	248,664	$	241,807
Preferred Stock Dividend Requirements:
Income before income taxes attributable to common shareholders	$	636,665	$	624,697	$	511,714	$	485,557	$	375,390
Net income from continuing operations attributable to common shareholders	406,074		387,380		328,110		324,688		236,839
Ratio of income before income taxes to net income	1.57		1.61		1.56		1.50		1.59
Preferred stock dividends	—		—		—		—		—
Preferred stock dividend requirements — ratio (above) times preferred stock dividends	$	—	$	—	$	—	$	—	$	—
Fixed Charges and Preferred Stock Dividend Requirements:
Fixed charges	$	206,089	$	219,437	$	246,462	$	248,664	$	241,807
Preferred stock dividend requirements	—		—		—		—		—
Total	$	206,089	$	219,437	$	246,462	$	248,664	$	241,807
Ratio of Earnings to Fixed Charges (rounded down)	4.08		3.84		3.07		2.95		2.55

EX-21.1

Exhibit 21.1

SUBSIDIARIES LIST - 2014

Arizona Public Service Company

*All other subsidiaries of Pinnacle West Capital Corporation and all subsidiaries of Arizona Public Service Company have been omitted as they do not constitute significant subsidiaries within the meaning of Rule 1-02(w) of Regulation S-X.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-180897 and 333-175195 on Form S-3; and in Registration Statement Nos. 333-143432, 333-182427 and 333-157151 on Form S-8 of our report dated February 21, 2014, relating to the consolidated financial statements and financial statement schedules of Pinnacle West Capital Corporation, and the effectiveness of Pinnacle West Capital Corporation’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of Pinnacle West Capital Corporation for the year ended December 31, 2013.

/s/ Deloitte & Touche LLP

Phoenix, Arizona

February 21, 2014

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-180897-01 on Form S-3; and in Registration Statement Nos. 333-46161 and 333-158774 on Form S-8 of our report dated February 21, 2014, relating to the consolidated financial statements and financial statement schedule of Arizona Public Service Company and the effectiveness of Arizona Public Service Company’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of Arizona Public Service Company for the year ended December 31, 2013.

/s/ Deloitte & Touche LLP

Phoenix, Arizona
February 21, 2014

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Donald E. Brandt, certify that:

1.I have reviewed this Annual Report on Form 10-K of Pinnacle West Capital Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the

audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:February 21, 2014

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and Chief Executive Officer

2

EX-31.2

Exhibit 31.2

CERTIFICATION

I, James R. Hatfield, certify that:

1.I have reviewed this Annual Report on Form 10-K of Pinnacle West Capital Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the

audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:February 21, 2014

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and

Chief Financial Officer

2

EX-31.3

Exhibit 31.3

CERTIFICATION

I, Donald E. Brandt, certify that:

1.I have reviewed this Annual Report on Form 10-K of Arizona Public Service Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the

audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:      February 21, 2014

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and Chief Executive Officer

2

EX-31.4

Exhibit 31.4

CERTIFICATION

I, James R. Hatfield, certify that:

1.I have reviewed this Annual Report on Form 10-K of Arizona Public Service Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the

audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:February 21, 2014

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and

Chief Financial Officer

2

EX-32.1

Exhibit 32.1

CERTIFICATION
OF
CHIEF EXECUTIVE OFFICER
AND
CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Donald E. Brandt, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report on Form 10-K of Pinnacle West Capital Corporation for the year ended December 31, 2013 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Annual Report on Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.

Date:February 21, 2014

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and

Chief Executive Officer

I, James R. Hatfield, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report on Form 10-K of Pinnacle West Capital Corporation for the year ended December 31, 2013 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Annual Report on Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.

Date:February 21, 2014

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and

Chief Financial Officer

EX-32.2

Exhibit 32.2

CERTIFICATION
OF
CHIEF EXECUTIVE OFFICER
AND
CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Donald E. Brandt, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report on Form 10-K of Arizona Public Service Company for the year ended December 31, 2013 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Annual Report on Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.

Date:February 21, 2014

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and

Chief Executive Officer

I, James R. Hatfield, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report on Form 10-K of Arizona Public Service Company for the year ended December 31, 2013 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Annual Report on Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.

Date:February 21, 2014

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and

Chief Financial Officer

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Long-Term Debt and Liquidity Matters (Tables)

12 Months Ended

Dec. 31, 2013

Long-Term Debt and Liquidity Matters

Components of long-term debt on the Consolidated Balance Sheets

The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2013 and 2012 (dollars in thousands):

	Maturity	Interest	December 31,
	Dates (a)	Rates	2013			2012
APS
Pollution Control Bonds:
Variable	2029-2038	(b)	$	75,580		$	75,580
Fixed	2024-2034	1.25%-6.00%	426,125			490,275
Total Pollution Control Bonds			501,705			565,855
Senior unsecured notes	2014-2042	4.50%-8.75%	2,675,000			2,575,000
Palo Verde sale leaseback lessor notes	2015	8.00%	38,869			65,547
Unamortized discount			(8,732		)	(9,486		)
Unamortized premium			5,047			—
Total APS long-term debt			3,211,889			3,196,916
Less current maturities	(d)		540,424			122,828
Total APS long-term debt less current maturities			2,671,465			3,074,088
Pinnacle West
Term loan	2015	(c)	125,000			125,000
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES			$	2,796,465		$	3,199,088

(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 0.03%-0.06% at December 31, 2013 and 0.13%-0.15% at December 31, 2012.

(c) The weighted-average interest rate was 1.269% at December 31, 2013 and 1.312% at December 31, 2012.

(d) Current maturities include $215 million of pollution control bonds expected to be remarketed in 2014 and $300 million in senior unsecured notes that mature in 2014.

Principal payments due on Pinnacle West's and APS's total long-term debt

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
2014	$	540	$	540
2015	470		345
2016	358		358
2017	—		—
2018	32		32
Thereafter	1,940		1,940
Total	$	3,340	$	3,215

Schedule of estimated fair value of long-term debt, including current maturities

The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

	As of December 31, 2013				As of December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	125	$	125	$	125
APS	3,212		3,454		3,197		3,750
Total	$	3,337	$	3,579	$	3,322	$	3,875

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Other Income and Other Expense (APSC) (Tables)

12 Months Ended

Dec. 31, 2013

Detail of other income and other expense

The following table provides detail of other income and other expense for 2013, 2012 and 2011 (dollars in thousands):

	2013			2012			2011
Other income:
Interest income	$	1,629		$	1,239		$	1,850
Investment gains — net	—			—			1,165
Miscellaneous	75			367			96
Total other income	$	1,704		$	1,606		$	3,111
Other expense:
Non-operating costs	$	(8,207	)	$	(7,777	)	$	(7,037	)
Investment loss — net	(3,711		)	(2,453		)	—
Miscellaneous	(4,106		)	(9,612		)	(3,414		)
Total other expense	$	(16,024	)	$	(19,842	)	$	(10,451	)

ARIZONA PUBLIC SERVICE COMPANY

Detail of other income and other expense

The following table provides detail of APS’s other income and other expense for 2013, 2012 and 2011 (dollars in thousands):

	2013			2012			2011
Other income:
Interest income	$	1,234		$	310		$	406
Investment gains — net	—			—			1,418
Miscellaneous	2,662			2,558			3,247
Total other income	$	3,896		$	2,868		$	5,071
Other expense:
Non-operating costs (a)	$	(9,626	)	$	(8,706	)	$	(8,810	)
Asset dispositions	(4,992		)	(1,511		)	(1,352		)
Miscellaneous	(5,831		)	(10,933		)	(5,166		)
Total other expense	$	(20,449	)	$	(21,150	)	$	(15,328	)

(a) As defined by FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).

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Changes in Accumulated Other Comprehensive Loss (Tables)

12 Months Ended

Dec. 31, 2013

Changes in Accumulated Other Comprehensive Loss

Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, by component

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands):

	Year Ended December 31, 2013
	Derivative  Instruments			Pension and  Other  Postretirement  Benefits			Total
Beginning balance	$	(49,592	)	$	(64,416	)	$	(114,008	)
OCI (loss) before reclassifications	(213		)	5,594			5,381
Amounts reclassified from accumulated other comprehensive loss	26,747		(a)	3,827		(b)	30,574
Net current period OCI	26,534			9,421			35,955
Ending balance	$	(23,058	)	$	(54,995	)	$	(78,053	)

(a) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 17.

(b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 8.

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2013

Earnings Per Share

Schedule of earnings per weighted average common share outstanding

	2013		2012			2011
Basic earnings per share:
Income from continuing operations attributable to common shareholders	$	3.69	$	3.54		$	3.01
Income (loss) from discontinued operations	—		(0.06		)	0.10
Earnings per share – basic	$	3.69	$	3.48		$	3.11
Diluted earnings per share:
Income from continuing operations attributable to common shareholders	$	3.66	$	3.50		$	2.99
Income (loss) from discontinued operations	—		(0.05		)	0.10
Earnings per share – diluted	$	3.66	$	3.45		$	3.09

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Retirement Plans and Other Benefits (Details) (USD $)	1 Months Ended	12 Months Ended
	Jul. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Retirement Plans and Other Benefits
Amount of pension and other postretirement benefit costs deferred			$ 14,000,000	$ 11,000,000
Regulatory asset amortization period	3 years
Amortization of regulatory assets		8,000,000	4,000,000
Amounts recognized on the Consolidated Balance Sheets
Noncurrent liability		(513,628,000)	(1,058,755,000)
Pension Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost - benefits earned during the period		64,195,000	63,502,000	57,605,000
Interest cost on benefit obligation		112,392,000	119,586,000	124,727,000
Expected return on plan assets		(146,333,000)	(140,979,000)	(133,678,000)
Amortization of prior service cost (credit)		1,097,000	1,143,000	1,400,000
Amortization of net actuarial loss		39,852,000	44,250,000	25,956,000
Net periodic benefit cost		71,203,000	87,502,000	76,010,000
Portion of cost charged to expense		38,968,000	36,333,000	29,312,000
Change in Benefit Obligation
Benefit obligation at the beginning of the period		2,850,846,000	2,699,126,000
Service cost		64,195,000	63,502,000	57,605,000
Interest cost		112,392,000	119,586,000	124,727,000
Benefit payments		(125,269,000)	(113,632,000)
Actuarial (gain) loss		(255,634,000)	82,264,000
Benefit obligation at the end of the period		2,646,530,000	2,850,846,000	2,699,126,000
Change in Plan Assets
Balance at the beginning of the period		2,079,181,000	1,850,550,000
Actual return on plan assets		150,546,000	259,363,000
Employer contributions		140,500,000	65,000,000	0
Benefit payments		(106,106,000)	(95,732,000)
Balance at the end of the period		2,264,121,000	2,079,181,000	1,850,550,000
Funded Status at the end of the period		(382,409,000)	(771,665,000)
Projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets
Projected benefit obligation		2,646,530,000	2,850,846,000
Accumulated benefit obligation		2,469,889,000	2,646,306,000
Fair value of plan assets		2,264,121,000	2,079,181,000
Amounts recognized on the Consolidated Balance Sheets
Current liability		(10,860,000)	(19,107,000)
Noncurrent liability		(371,549,000)	(752,558,000)
Net amount recognized		(382,409,000)	(771,665,000)
Other Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost - benefits earned during the period		23,597,000	27,163,000	21,856,000
Interest cost on benefit obligation		41,536,000	46,467,000	46,807,000
Expected return on plan assets		(45,717,000)	(45,793,000)	(41,536,000)
Amortization of transition obligation			452,000	452,000
Amortization of prior service cost (credit)		(179,000)	(179,000)	(179,000)
Amortization of net actuarial loss		11,310,000	20,233,000	15,015,000
Net periodic benefit cost		30,547,000	48,343,000	42,415,000
Portion of cost charged to expense		18,469,000	19,321,000	15,208,000
Change in Benefit Obligation
Benefit obligation at the beginning of the period		990,418,000	1,047,094,000
Service cost		23,597,000	27,163,000	21,856,000
Interest cost		41,536,000	46,467,000	46,807,000
Benefit payments		(26,675,000)	(26,279,000)
Actuarial (gain) loss		(138,458,000)	(104,027,000)
Benefit obligation at the end of the period		890,418,000	990,418,000	1,047,094,000
Change in Plan Assets
Balance at the beginning of the period		684,221,000	608,663,000
Actual return on plan assets		76,995,000	83,567,000
Employer contributions		14,438,000	22,707,000	19,000,000
Benefit payments		(27,315,000)	(30,716,000)
Balance at the end of the period		748,339,000	684,221,000	608,663,000
Funded Status at the end of the period		(142,079,000)	(306,197,000)
Amounts recognized on the Consolidated Balance Sheets
Noncurrent liability		(142,079,000)	(306,197,000)
Net amount recognized		$ (142,079,000)	$ (306,197,000)

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Summary of Significant Accounting Policies (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Balance Sheets
Long-term debt less current maturities	$ 2,796,465	$ 3,199,088
Cash Flows from Operating Activities
Deferred income taxes	249,296	187,023	117,952
Deferred investment tax credit	52,542	41,579	58,240
Income tax receivable	(133,094)	(4,043)	3,983
Accrued taxes	6,059	12,736	8,085
As previously reported
Balance Sheets
Long-term debt less current maturities		3,160,219
Cash Flows from Operating Activities
Deferred income taxes		228,602	176,192
Accrued taxes and income tax receivable		8,693	12,068
As previously reported | Palo Verde Sale Leaseback
Balance Sheets
Long-term debt less current maturities		38,869
Reclassifications to conform to current year presentation
Balance Sheets
Long-term debt less current maturities		38,869
Cash Flows from Operating Activities
Deferred income taxes		(41,579)	(58,240)
Deferred investment tax credit		41,579	58,240
Accrued taxes and income tax receivable		(8,693)	(12,068)
Income tax receivable		(4,043)	3,983
Accrued taxes		12,736	8,085
Reclassifications to conform to current year presentation | Palo Verde Sale Leaseback
Balance Sheets
Long-term debt less current maturities		$ (38,869)

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Commitments and Contingencies (Details 3) (USD $) In Millions, unless otherwise specified	0 Months Ended	12 Months Ended
	May 23, 2013 Four Corners New Mexico Tax Matter	Dec. 31, 2013 Four Corners ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2013 Four Corners ARIZONA PUBLIC SERVICE COMPANY New Mexico Tax Matter	Dec. 31, 2013 Navajo Plant ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2013 Cholla ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2013 Cholla Units 1-3 ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters
Expected environmental cost		$ 350		$ 200	$ 200	$ 120
Share of Cost of Control of Four Corners Units 4 and 5		63.00%
Coal severance surtax, penalty, and interest	30
Share of the assessment			$ 12

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CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (APSC) (USD $) In Thousands, unless otherwise specified	Total	ARIZONA PUBLIC SERVICE COMPANY	COMMON STOCK	COMMON STOCK ARIZONA PUBLIC SERVICE COMPANY	ADDITIONAL PAID-IN CAPITAL ARIZONA PUBLIC SERVICE COMPANY	RETAINED EARNINGS	RETAINED EARNINGS ARIZONA PUBLIC SERVICE COMPANY	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) ARIZONA PUBLIC SERVICE COMPANY	NONCONTROLLING INTERESTS	NONCONTROLLING INTERESTS ARIZONA PUBLIC SERVICE COMPANY	COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER ARIZONA PUBLIC SERVICE COMPANY
Balance at Dec. 31, 2010			$ 2,421,372			$ 1,423,961	$ 1,403,390	$ (159,767)	$ (136,295)	$ 91,899	$ 91,084
Increase (Decrease) in Shareholders' Equity
Net income attributable to common shareholders	339,473	336,249				339,473	336,249					339,473	336,249
Dividends on common stock						(228,951)	(228,900)
Net income attributable to noncontrolling interests	27,467	27,524								(27,467)	27,524
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER
Other comprehensive income attributable to common shareholders	7,605	10,704						7,604	10,704			7,605	10,704
Total comprehensive income attributable to common shareholders	347,078	346,953										347,078	346,953
Net capital activities by noncontrolling interests										(10,630)	(10,209)
Other							1
Balance at Dec. 31, 2011	3,930,586	4,051,406	2,444,247	178,162	2,379,696	1,534,483	1,510,740	(152,163)	(125,591)	108,736	108,399
Increase (Decrease) in Shareholders' Equity
Net income attributable to common shareholders	(8,257)	(4,105)
Balance at Mar. 31, 2012
Balance at Dec. 31, 2011	3,930,586	4,051,406	2,444,247	178,162	2,379,696	1,534,483	1,510,740	(152,163)	(125,591)	108,736	108,399
Increase (Decrease) in Shareholders' Equity
Net income attributable to common shareholders	381,542	395,497				381,542	395,497					381,542	395,497
Dividends on common stock						(291,923)	(282,000)
Net income attributable to noncontrolling interests	31,622	31,613								(31,622)	31,613
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER
Other comprehensive income attributable to common shareholders	38,155	36,496						38,155	36,496			38,155	36,496
Total comprehensive income attributable to common shareholders	419,697	431,993										419,697	431,993
Net capital activities by noncontrolling interests										(10,875)	(10,529)
Balance at Dec. 31, 2012	4,102,289	4,222,483	2,466,923	178,162	2,379,696	1,624,102	1,624,237	(114,008)	(89,095)	129,483	129,483
Balance at Sep. 30, 2012
Increase (Decrease) in Shareholders' Equity
Net income attributable to common shareholders	22,631	26,843
Balance at Dec. 31, 2012	4,102,289	4,222,483	2,466,923	178,162	2,379,696
Increase (Decrease) in Shareholders' Equity
Net income attributable to common shareholders	24,444	26,042
Balance at Mar. 31, 2013
Balance at Dec. 31, 2012	4,102,289	4,222,483	2,466,923	178,162	2,379,696	1,624,102	1,624,237	(114,008)	(89,095)	129,483	129,483
Increase (Decrease) in Shareholders' Equity
Net income attributable to common shareholders	406,074	424,969				406,074	424,969					406,074	424,969
Dividends on common stock						(244,903)	(244,800)
Net income attributable to noncontrolling interests	33,892	33,892								(33,892)	33,892
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER
Other comprehensive income attributable to common shareholders	35,955	35,723						35,955	35,723			35,955	35,723
Total comprehensive income attributable to common shareholders	442,029	460,692										442,029	460,692
Net capital activities by noncontrolling interests										(17,385)	(17,385)
Other							(8)
Balance at Dec. 31, 2013	4,340,460	4,454,874	2,491,558	178,162	2,379,696	1,785,273	1,804,398	(78,053)	(53,372)	145,990	145,990
Balance at Sep. 30, 2013
Increase (Decrease) in Shareholders' Equity
Net income attributable to common shareholders	24,260	30,024
Balance at Dec. 31, 2013	$ 4,340,460	$ 4,454,874	$ 2,491,558	$ 178,162	$ 2,379,696

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Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Selected Quarterly Financial Data (Unaudited)

Schedule of quarterly financial information

Consolidated quarterly financial information for 2013 and 2012 is provided in the tables below (dollars in thousands, except per share amounts). 

	2013 Quarter Ended								2013
	March 31,		June 30,		Sept. 30,		Dec. 31,		Total
Operating revenues	$	686,652	$	915,822	$	1,152,392	$	699,762	$	3,454,628
Operations and maintenance	223,250		229,300		233,323		238,854		924,727
Operating income	86,923		259,812		415,688		83,900		846,323
Income taxes	12,469		77,043		131,912		9,167		230,591
Income from continuing operations	32,836		139,598		234,718		32,814		439,966
Net income attributable to common shareholders	24,444		131,207		226,163		24,260		406,074
Earnings Per Share:
Income from continuing operations attributable to common shareholders — Basic	$	0.22	$	1.19	$	2.06	$	0.22	$	3.69
Net income attributable to common shareholders — Basic	0.22		1.19		2.06		0.22		3.69
Income from continuing operations attributable to common shareholders — Diluted	0.22		1.18		2.04		0.22		3.66
Net income attributable to common shareholders — Diluted	0.22		1.18		2.04		0.22		3.66

	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

XML

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES

12 Months Ended

Dec. 31, 2013

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES

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:
2013	$	3,340	$	4,923	$	—	$	5,060	$	3,203
2012	3,748		5,290		—		5,698		3,340
2011	4,709		5,672		—		6,633		3,748

XML

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Changes attributable to:
Asset retirement obligations, current	$ 32,896,000
ARIZONA PUBLIC SERVICE COMPANY
Change in asset retirement obligations
Asset retirement obligations at the beginning of year	357,000,000	280,000,000
Changes attributable to:
Accretion expense	24,000,000	19,000,000
Settlements	(12,000,000)
Assumed SCE's obligation	34,000,000
Estimated cash flow revisions	(56,000,000)	58,000,000
Asset retirement obligations at the end of year	347,000,000	357,000,000
Asset retirement obligations, current	$ 33,000,000

XML

Other Income and Other Expense (APSC) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other income:
Interest income	$ 1,629	$ 1,239	$ 1,850
Investment gains - net			1,165
Miscellaneous	75	367	96
Total other income	1,704	1,606	3,111
Other expense:
Non-operating costs	(8,207)	(7,777)	(7,037)
Miscellaneous	(4,106)	(9,612)	(3,414)
Total other expense	(16,024)	(19,842)	(10,451)
ARIZONA PUBLIC SERVICE COMPANY
Other income:
Interest income	1,234	310	406
Investment gains - net			1,418
Miscellaneous	2,662	2,558	3,247
Total other income	3,896	2,868	5,071
Other expense:
Non-operating costs	(9,626)	(8,706)	(8,810)
Asset dispositions	(4,992)	(1,511)	(1,352)
Miscellaneous	(5,831)	(10,933)	(5,166)
Total other expense	$ (20,449)	$ (21,150)	$ (15,328)

XML

Retirement Plans and Other Benefits (Details 4) (USD $)	12 Months Ended							1 Months Ended	12 Months Ended				12 Months Ended							12 Months Ended				12 Months Ended					12 Months Ended
	Dec. 31, 2013 Pinnacle West	Dec. 31, 2012 Pinnacle West	Dec. 31, 2011 Pinnacle West	Dec. 31, 2013 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2013 Pension Benefits	Dec. 31, 2012 Pension Benefits	Dec. 31, 2011 Pension Benefits	Jan. 31, 2014 Pension Benefits Subsequent event	Dec. 31, 2013 Pension Benefits Expected contributions	Dec. 31, 2013 Pension Benefits Expected contributions Maximum	Dec. 31, 2013 Pension Benefits Pinnacle West	Dec. 31, 2012 Pension Benefits Pinnacle West	Dec. 31, 2013 Pension Benefits ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2012 Pension Benefits ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2011 Pension Benefits ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2013 Pension Benefits Significant Unobservable Inputs (Level 3) Pinnacle West	Dec. 31, 2012 Pension Benefits Significant Unobservable Inputs (Level 3) Pinnacle West	Dec. 31, 2013 Pension Benefits Short-term investments and other Pinnacle West	Dec. 31, 2012 Pension Benefits Short-term investments and other Pinnacle West	Dec. 31, 2013 Pension Benefits Short-term investments and other Significant Unobservable Inputs (Level 3)	Dec. 31, 2012 Pension Benefits Short-term investments and other Significant Unobservable Inputs (Level 3)	Dec. 31, 2013 Pension Benefits Short-term investments and other Significant Unobservable Inputs (Level 3) Pinnacle West	Dec. 31, 2012 Pension Benefits Short-term investments and other Significant Unobservable Inputs (Level 3) Pinnacle West	Dec. 31, 2013 Other Benefits	Dec. 31, 2012 Other Benefits	Dec. 31, 2011 Other Benefits	Dec. 31, 2013 Other Benefits Pinnacle West	Dec. 31, 2012 Other Benefits Pinnacle West	Dec. 31, 2013 Other Benefits ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2012 Other Benefits ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2011 Other Benefits ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2013 Other Benefits Short-term investments and other Pinnacle West	Dec. 31, 2012 Other Benefits Short-term investments and other Pinnacle West
Changes in fair value for assets that are measured at fair value on a recurring basis
Balance at the beginning of the period					$ 2,079,181,000	$ 1,850,550,000					$ 2,264,121,000	$ 2,079,181,000				$ 8,660,000	$ 2,419,000	$ 49,970,000	$ 29,278,000	$ 2,419,000		$ 8,660,000	$ 2,419,000	$ 684,221,000	$ 608,663,000		$ 748,339,000	$ 684,221,000				$ 10,844,000	$ 7,788,000
Actual return on assets still held																				(498,000)	(668,000)
Purchases, sales, and settlements																				6,739,000	3,087,000
Balance at the end of the period					2,264,121,000	2,079,181,000	1,850,550,000				2,264,121,000	2,079,181,000				8,660,000	2,419,000	49,970,000	29,278,000	8,660,000	2,419,000	8,660,000	2,419,000	748,339,000	684,221,000	608,663,000	748,339,000	684,221,000				10,844,000	7,788,000
Contributions
Employer's contributions under the plan					140,500,000	65,000,000	0	70,000,000					140,000,000	64,000,000	0									14,438,000	22,707,000	19,000,000			14,000,000	22,000,000	19,000,000
Minimum Contributions under MAP-21
Minimum contributions under MAP-21					141,000,000
2014					0
2015					19,000,000
2016					122,000,000
Expected employer's contributions
Expected employer's contributions									300,000,000
2014									175,000,000															10,000,000
2015										100,000,000														10,000,000
2016										25,000,000														10,000,000
Estimated Future Benefit Payments
2014					129,159,000																			28,664,000
2015					143,452,000																			31,804,000
2016					149,105,000																			34,933,000
2017					162,678,000																			37,966,000
2018					169,064,000																			40,972,000
Years 2019-2023					972,826,000																			245,366,000
Employee Savings Plan Benefits
APS's employees share of total cost of the plans (as a percent)				99.00%
Expenses recorded for the defined contribution savings plan	$ 9,000,000	$ 8,000,000	$ 8,000,000

XML

Derivative Accounting (Details 4) (Commodity Contracts, USD $)	12 Months Ended
	Dec. 31, 2013 item
Commodity Contracts
Credit Risk and Credit-Related Contingent Features
Concentration of credit risk, number of counterparties	2
Concentration of risk with two counterparties, as a percentage of risk management assets	92.00%
Risk management activities-derivative instruments: Commodity Contracts	$ 41,000,000
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	123,000,000
Cash Collateral Posted	19,000,000
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered	66,000,000
Additional collateral to counterparties for energy related non-derivative instrument contracts	$ 180,000,000

XML

Regulatory Matters (Details) (USD $)	12 Months Ended						0 Months Ended	1 Months Ended			1 Months Ended	0 Months Ended	1 Months Ended	3 Months Ended		12 Months Ended					0 Months Ended	12 Months Ended	0 Months Ended	12 Months Ended		1 Months Ended			12 Months Ended		0 Months Ended	1 Months Ended	12 Months Ended		1 Months Ended	0 Months Ended	1 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 APS	Dec. 31, 2012 APS	Dec. 31, 2011 APS	Dec. 03, 2013 APS ACC RES implementation plan covering 2014-2018 timeframe	Jan. 31, 2012 Filing with the Arizona Corporation Commission APS ACC Retail rate case filing	Jun. 30, 2011 Filing with the Arizona Corporation Commission APS ACC Retail rate case filing	Jan. 06, 2012 Filing with the Arizona Corporation Commission APS ACC Retail rate case filing	Jan. 31, 2012 Filing with the Arizona Corporation Commission APS ACC Retail rate case filing Maximum	Dec. 30, 2013 Filing with the Arizona Corporation Commission APS ACC Residential customers rate case filing	Dec. 31, 2009 2008 General Retail Rate Case On-Going Impacts APS ACC	Jun. 30, 2010 2008 General Retail Rate Case On-Going Impacts APS ACC 2008 General retail rate case	Dec. 30, 2009 2008 General Retail Rate Case On-Going Impacts APS ACC 2008 General retail rate case item	Dec. 31, 2013 Cost Recovery Mechanisms Power Supply Adjustor (PSA)	Oct. 30, 2013 Cost Recovery Mechanisms APS 2013 DSMAC	Dec. 31, 2012 Cost Recovery Mechanisms APS 2013 DSMAC	Dec. 31, 2013 Cost Recovery Mechanisms APS Power Supply Adjustor (PSA)	Dec. 31, 2013 Cost Recovery Mechanisms APS Power Supply Adjustor (PSA) Maximum	Feb. 12, 2013 Cost Recovery Mechanisms APS Lost Fixed Cost Recovery Mechanism	Dec. 31, 2013 Cost Recovery Mechanisms APS Lost Fixed Cost Recovery Mechanism	Mar. 02, 2014 Cost Recovery Mechanisms APS Lost Fixed Cost Recovery Mechanism Subsequent event	Dec. 31, 2013 Cost Recovery Mechanisms APS ACC RES	Jun. 02, 2012 Cost Recovery Mechanisms APS ACC 2013 DSMAC	Jun. 30, 2012 Cost Recovery Mechanisms APS ACC 2012 DSMAC	Apr. 30, 2012 Cost Recovery Mechanisms APS ACC 2012 DSMAC	Jun. 30, 2011 Cost Recovery Mechanisms APS ACC 2012 DSMAC	Dec. 31, 2009 Cost Recovery Mechanisms APS ACC 2012 DSMAC	Jun. 02, 2011 Cost Recovery Mechanisms APS ACC 2012 DSMAC	Jul. 12, 2013 Cost Recovery Mechanisms APS ACC RES implementation plan covering 2014-2018 timeframe	Feb. 28, 2013 Cost Recovery Mechanisms APS ACC Power Supply Adjustor (PSA)	Dec. 31, 2013 Cost Recovery Mechanisms APS ACC Power Supply Adjustor (PSA)	Dec. 31, 2012 Cost Recovery Mechanisms APS ACC Power Supply Adjustor (PSA)	Feb. 28, 2014 Cost Recovery Mechanisms APS ACC Power Supply Adjustor (PSA) Subsequent event	Jun. 01, 2013 Cost Recovery Mechanisms APS FERC Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters	Jun. 30, 2012 Cost Recovery Mechanisms APS FERC Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters
Regulatory Matters
Net retail rate increase									$ 95,500,000
Approximate percentage of increase in the average retail customer bill									6.60%
Approximate percentage of increase in the average retail customer bill under proposed Four Corners rate filing												2.00%
Settlement Agreement
Net change in base rates								0
Non-fuel base rate increase								116,300,000
Fuel-related base rate decrease								153,100,000
Current base fuel rate (in dollars per kWh)								0.03757
Approved base fuel rate (in dollars per kWh)								0.03207
Estimated amount of transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates								36,800,000
Authorized return on common equity (as a percent)								10.00%
Percentage of debt in capital structure								46.10%
Percentage of common equity in capital structure								53.90%
Deferral of property taxes in 2012, if Arizona property tax rates increase (as a percent)										25.00%
Deferral of property taxes in 2013, if Arizona property tax rates increase (as a percent)										50.00%
Deferral of property taxes for 2014 and subsequent years, if Arizona property tax rates increase (as a percent)										75.00%
Deferral of property taxes in all years, if Arizona property tax rates decrease (as a percent)										100.00%
Annual cost recovery due to modifications to the Environmental Improvement Surcharge											5,000,000
Elimination of the sharing provision of fuel and purchased power costs								9
Period to process the subsequent rate cases								12 months
ACC staff sufficiency findings, general period of time								30 days
2008 General Retail Rate Case on-going impacts
Number of other parties to the settlement agreement															21
Minimum amount of reduction of average annual operational expenses from 2010 through 2014													30,000,000
Authorization and requirements of equity infusions into APS beginning June 1, 2009 through December 31, 2014													700,000,000
Equity infusions into APS														253,000,000
Change in regulatory asset
Plan term																								5 years
Amount of proposed budget																	68,900,000	87,600,000													143,000,000
Percentage of cumulative energy savings for prior year																														3.00%
Percentage of annual energy savings to meet energy efficiency goal for 2011																														2.75%
Period of energy savings goal																												2 years
Demand-side management adjustor charge (DSMAC)																											72,000,000
Period beginning March 1, 2012, over which the costs will be recovered																											12 months
Costs already being recovered in general rates																										10,000,000
Amortization of recovery of demand-side management adjustor charge included in costs already been recovered																													5,000,000
Percentage of cumulative energy savings for current year																									5.00%
Beginning balance																																	73,000,000	28,000,000
Deferred fuel and purchased power costs-current period	(21,678,000)	(71,573,000)	(69,166,000)	(21,678,000)	(71,573,000)	(69,166,000)																											(21,000,000)	(72,000,000)
Amounts (charged) credited to customers	(31,190,000)	116,716,000	155,157,000	(31,190,000)	116,716,000	155,157,000																											(31,000,000)	117,000,000
Ending balance																																	21,000,000	73,000,000
Percentage of sale of distributed energy system's output at a market-based price for installing new rooftop solar system to all new residential customers																															100.00%
Charge on future customers who install rooftop solar panels (in dollars per kWh)							0.70
Estimated monthly collection due to charge on future customers who install rooftop solar panels							4.90
PSA rate (in dollars per kWh)																																			0.001557
PSA rate for prior year (in dollars per kWh)																																0.001329
Increase or decrease in PSA charge (in dollars per kWh)																			0.000228	0.004
Forward component of increase in PSA (in dollars per kWh)																0.001277
Historical component of increase in PSA (in dollars per kWh)																0.000280
Increase in annual wholesale transmission rates																																				26,000,000	16,000,000
Fixed costs recoverable per residential power lost (in dollars per kWh)																						0.031
Fixed costs recoverable per non-residential power lost (in dollars per kWh)																						0.023
Amount of adjustment approved representing prorated sales losses																					$ 5,100,000		$ 25,300,000

XML

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES (APSC)

12 Months Ended

Dec. 31, 2013

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES

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:
2013	$	3,340	$	4,923	$	—	$	5,060	$	3,203
2012	3,748		5,290		—		5,698		3,340
2011	4,709		5,672		—		6,633		3,748

ARIZONA PUBLIC SERVICE COMPANY

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES

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:
2013	$	3,340	$	4,923	$	—	$	5,060	$	3,203
2012	3,748		5,290		—		5,698		3,340
2011	4,376		5,751		—		6,379		3,748

XML

Commitments and Contingencies (Details) (ARIZONA PUBLIC SERVICE COMPANY, USD $)	0 Months Ended	12 Months Ended
	Apr. 02, 2013	Dec. 31, 2013 item	Dec. 31, 2008 item	Dec. 31, 1986 item
ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station
Estimated share of the costs related to on-site interim storage of spent nuclear fuel		$ 122,000,000
Regulatory liability of amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage		42,000,000
Maximum insurance against public liability per occurrence for a nuclear incident		13,600,000,000
Maximum available nuclear liability insurance		375,000,000
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program		13,200,000,000
Maximum assessment per reactor for each nuclear incident		127,300,000
Annual limit per incident with respect to maximum assessment		19,000,000
Number of VIE lessor trusts		3	3	3
Maximum potential retrospective assessment per incident of APS		111,000,000
Annual payment limitation with respect to maximum potential retrospective assessment		16,400,000
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde		2,750,000,000
Sublimit for non-nuclear property damage losses which has been imposed to the primary policy offered	1,500,000,000
Sublimit for non-nuclear losses which has been imposed to the accidental outage policy	327,600,000
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment		18,000,000
Collateral assurance provided based on rating triggers		$ 48,000,000
Period to provide collateral assurance based on rating triggers		20 days

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Derivative Accounting (Details)	Dec. 31, 2013
Derivative Accounting
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment	100.00%
Commodity - Power
Outstanding gross notional amount of derivatives
Outstanding gross notional amount of derivative instruments	5,765
Commodity - Gas
Outstanding gross notional amount of derivatives
Outstanding gross notional amount of derivative instruments	108
ARIZONA PUBLIC SERVICE COMPANY
Derivative Accounting
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment before accounting treatment change	90.00%
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment	100.00%

XML

Fair Value Measurements (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Assets
Nuclear decommissioning trust	$ 642,007,000	$ 570,625,000
Total assets	41,000,000	62,000,000
Liabilities
Risk management activities-derivative instruments: Commodity Contracts	(102,207,000)	(159,005,000)
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Cash Equivalents		16,000,000
Nuclear decommissioning trust	107,000,000	110,000,000
Total assets	107,000,000	126,000,000
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury
Assets
Nuclear decommissioning trust	107,000,000	104,000,000
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust		6,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2)
Assets
Risk management activities-derivative instruments: Commodity Contracts	9,000,000	22,000,000
Nuclear decommissioning trust	538,000,000	465,000,000
Total assets	547,000,000	487,000,000
Liabilities
Risk management activities-derivative instruments: Commodity Contracts	(33,000,000)	(96,000,000)
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | US commingled equity funds
Assets
Nuclear decommissioning trust	272,000,000	204,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust	11,000,000	13,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Corporate debt
Assets
Nuclear decommissioning trust	88,000,000	80,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Mortgage-backed securities
Assets
Nuclear decommissioning trust	85,000,000	83,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Municipality bonds
Assets
Nuclear decommissioning trust	71,000,000	74,000,000
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Other
Assets
Nuclear decommissioning trust	11,000,000	11,000,000
Fair value measurement on a recurring basis | Significant Unobservable Inputs (Level 3)
Assets
Risk management activities-derivative instruments: Commodity Contracts	41,000,000	62,000,000
Total assets	41,000,000	62,000,000
Liabilities
Risk management activities-derivative instruments: Commodity Contracts	(90,000,000)	(110,000,000)
Fair value measurement on a recurring basis | Other
Assets
Risk management activities-derivative instruments: Commodity Contracts	(9,000,000)	(22,000,000)
Nuclear decommissioning trust	(3,000,000)	(4,000,000)
Total assets	(12,000,000)	(26,000,000)
Liabilities
Risk management activities-derivative instruments: Commodity Contracts	21,000,000	47,000,000
Fair value measurement on a recurring basis | Other | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust	(3,000,000)	(4,000,000)
Fair value measurement on a recurring basis | Fair Value
Assets
Cash Equivalents		16,000,000
Risk management activities-derivative instruments: Commodity Contracts	41,000,000	62,000,000
Nuclear decommissioning trust	642,000,000	571,000,000
Total assets	683,000,000	649,000,000
Liabilities
Risk management activities-derivative instruments: Commodity Contracts	(102,000,000)	(159,000,000)
Fair value measurement on a recurring basis | Fair Value | US commingled equity funds
Assets
Nuclear decommissioning trust	272,000,000	204,000,000
Fair value measurement on a recurring basis | Fair Value | U.S. Treasury
Assets
Nuclear decommissioning trust	107,000,000	104,000,000
Fair value measurement on a recurring basis | Fair Value | Cash and cash equivalent funds
Assets
Nuclear decommissioning trust	8,000,000	15,000,000
Fair value measurement on a recurring basis | Fair Value | Corporate debt
Assets
Nuclear decommissioning trust	88,000,000	80,000,000
Fair value measurement on a recurring basis | Fair Value | Mortgage-backed securities
Assets
Nuclear decommissioning trust	85,000,000	83,000,000
Fair value measurement on a recurring basis | Fair Value | Municipality bonds
Assets
Nuclear decommissioning trust	71,000,000	74,000,000
Fair value measurement on a recurring basis | Fair Value | Other
Assets
Nuclear decommissioning trust	$ 11,000,000	$ 11,000,000

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Derivative Accounting (Details 2) (Commodity Contracts, USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Designated as Hedging Instruments
Gains and losses from derivative instruments
Loss Recognized in OCI on Derivative Instruments (Effective Portion)	$ (353,000)	$ (37,663,000)	$ (94,660,000)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized)	(44,219,000)	(99,007,000)	(117,189,000)
Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)		117,000	(211,000)
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges	0	1,800,000	0
Estimated net loss before income taxes to be reclassified from accumulated other comprehensive income	21,000,000
Not Designated as Hedging Instruments
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income from Derivative Instruments	(10,160,000)	(2,644,000)	(52,140,000)
Not Designated as Hedging Instruments | Revenue
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income from Derivative Instruments	289,000	103,000	(27,000)
Not Designated as Hedging Instruments | Fuel and purchased power
Gains and losses from derivative instruments
Net Gain (Loss) Recognized in Income from Derivative Instruments	$ (10,449,000)	$ (2,747,000)	$ (52,113,000)

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Commitments and Contingencies (Details 2) (ARIZONA PUBLIC SERVICE COMPANY, USD $)	0 Months Ended	1 Months Ended	12 Months Ended		12 Months Ended						0 Months Ended
	Jan. 22, 2014 item	Sep. 30, 2011 kV item MW	Dec. 31, 2013 item	Sep. 08, 2011	Dec. 31, 2013 Coal take-or-pay commitments	Dec. 31, 2012 Coal take-or-pay commitments	Dec. 31, 2011 Coal take-or-pay commitments	Dec. 31, 2013 Renewable energy credits	Dec. 31, 2013 Coal Mine Reclamation Obligations	Dec. 31, 2012 Coal Mine Reclamation Obligations	Aug. 06, 2013 Contaminated groundwater wells item
Contractual Obligations
2014			$ 729,000,000		$ 152,000,000			$ 48,000,000	$ 1,000,000
2015			628,000,000		157,000,000			42,000,000	1,000,000
2016			638,000,000		166,000,000			42,000,000	8,000,000
2017			613,000,000		180,000,000			42,000,000	14,000,000
2018			580,000,000		175,000,000			42,000,000	14,000,000
Thereafter			8,700,000,000		2,539,000,000			453,000,000	170,000,000
Total commitments					3,400,000,000				207,000,000	119,000,000
Total net present value of commitments					2,200,000,000
Actual purchases under commitment obligations					188,000,000	196,000,000	191,000,000
Superfund
Costs related to investigation and study under Superfund site			2,000,000
Number of defendants against whom Roosevelt Irrigation District ("RID") filed lawsuit											24
Southwest Power Outage
Capacity of transmission line that tripped out of service (in kV)		500
Period, after the transmission line went off-line, over which generation and transmission resources for the Yuma area were lost		10 minutes
Number of customers losing service in Yuma area		69,700
Capacity of firm load that were reported to have been affected due to outages affecting portions of southern Arizona, southern California and northern Mexico (in MW)		7,900
Number of customers that were reported to have been affected due to outages		2,700,000
Number of alleged entities	6
Number of Reliability Standard Requirements Violations alleged	7
Maximum possible fine per violation per day that the violation is found to have been in existence				1,000,000
Financial Assurances
Outstanding letters of credit to support existing variable interest rate pollution control bonds			76,000,000
Number of letters of credit expiring in 2015			1
Number of letters of credit expiring in 2016			2
Letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions			32,000,000
Outstanding letters of credit to support natural gas tolling contract obligations			$ 55,000,000

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Retirement Plans and Other Benefits (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Details related to accumulated other comprehensive loss
Accumulated other comprehensive loss	$ 54,995,000	$ 64,416,000
Weighted-average assumptions used to determine benefit obligations
Rate of compensation increase (as a percent)	4.00%	4.00%
Initial healthcare cost trend rate (as a percent)	7.50%	7.50%
Ultimate healthcare cost trend rate (as a percent)	5.00%	5.00%	5.00%
Number of years to ultimate trend rate	4 years	4 years	4 years
Weighted-average assumptions used to determine net periodic benefit costs
Rate of compensation increase (as a percent)	4.00%	4.00%	4.00%
Expected long-term return on plan assets	7.00%	7.75%	7.75%
Initial healthcare cost trend rate (as a percent)	7.50%	7.50%	8.00%
Ultimate healthcare cost trend rate (as a percent)	5.00%	5.00%	5.00%
Number of years to ultimate trend rate	4 years	4 years	4 years
Pension Benefits
Details related to accumulated other comprehensive loss
Net actuarial loss	344,540,000	644,239,000
Prior service cost (credit)	2,072,000	3,169,000
APS's portion recorded as a regulatory asset	(265,107,000)	(550,471,000)
Income tax benefit	(32,204,000)	(38,303,000)
Accumulated other comprehensive loss	49,301,000	58,634,000
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
Net actuarial loss	8,363,000
Prior service cost (credit)	874,000
Total amounts estimated to be amortized from accumulated other comprehensive loss and regulatory assets in 2014	9,237,000
Weighted-average assumptions used to determine benefit obligations
Discount rate (as a percent)	4.88%	4.01%
Weighted-average assumptions used to determine net periodic benefit costs
Discount rate (as a percent)	4.01%	4.42%	5.31%
Expected long-term return on plan assets for next fiscal year (as a percent)	6.90%
Other Benefits
Details related to accumulated other comprehensive loss
Net actuarial loss	57,816,000	238,862,000
Prior service cost (credit)	(296,000)	(475,000)
APS's portion recorded as a regulatory asset	(49,298,000)	(230,020,000)
Income tax benefit	(2,528,000)	(2,585,000)
Accumulated other comprehensive loss	5,694,000	5,782,000
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
Prior service cost (credit)	(179,000)
Total amounts estimated to be amortized from accumulated other comprehensive loss and regulatory assets in 2014	(179,000)
Weighted-average assumptions used to determine benefit obligations
Discount rate (as a percent)	5.10%	4.20%
Weighted-average assumptions used to determine net periodic benefit costs
Discount rate (as a percent)	4.20%	4.59%	5.49%
Expected long-term return on plan assets for next fiscal year (as a percent)	7.10%
Effects of one percentage point change in the assumed initial and ultimate health care cost trend rates
Effect of 1% increase on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	13,000,000
Effect of 1% decrease on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	(10,000,000)
Effect of 1% increase on service and interest cost components of net periodic other postretirement benefit costs	14,000,000
Effect of 1% decrease on service and interest cost components of net periodic other postretirement benefit costs	(11,000,000)
Effect of 1% increase on the accumulated other postretirement benefit obligation	149,000,000
Effect of 1% decrease on the accumulated other postretirement benefit obligation	$ (120,000,000)

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Earnings Per Share

12 Months Ended

Dec. 31, 2013

Earnings Per Share

Earnings Per Share

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, 2013, 2012 and 2011:

	2013		2012			2011
Basic earnings per share:
Income from continuing operations attributable to common shareholders	$	3.69	$	3.54		$	3.01
Income (loss) from discontinued operations	—		(0.06		)	0.10
Earnings per share – basic	$	3.69	$	3.48		$	3.11
Diluted earnings per share:
Income from continuing operations attributable to common shareholders	$	3.66	$	3.50		$	2.99
Income (loss) from discontinued operations	—		(0.05		)	0.10
Earnings per share – diluted	$	3.66	$	3.45		$	3.09

Dilutive stock options and performance shares (which are contingently issuable) increased average common shares outstanding by approximately 822,000 shares in 2013, 1,017,000 shares in 2012 and 811,000 shares in 2011.  Total average common shares outstanding for the purposes of calculating diluted earnings per share were 110,805,943 shares in 2013, 110,527,311 shares in 2012 and 109,864,243 shares in 2011.

For the years ended 2013, 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.

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Derivative Accounting (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Accounting

Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position)

As of December 31, 2013, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

Commodity	Quantity
Power	5,765	GWh
Gas	108	Bcfs (a)

(a) “Bcf” is Billion Cubic Feet.

Gains and losses from derivative instruments in designated cash flow accounting hedges relationships

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, 2013, 2012 and 2011 (dollars in thousands):

		Year Ended
	Financial Statement	December 31,
Commodity Contracts	Location	2013			2012			2011
Loss Recognized in OCI on Derivative Instruments (Effective Portion)	OCI — derivative instruments	$	(353	)	$	(37,663	)	$	(94,660	)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	(44,219		)	(99,007		)	(117,189		)
Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Fuel and purchased power (b)	—			117			(211		)

(a) During the years ended December 31, 2013, 2012, and 2011, we had zero, $1.8 million, and zero losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

(b) Amounts are before the effect of PSA deferrals.

Gains and losses from derivative instruments not designated as accounting hedges instruments

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2013, 2012 and 2011 (dollars in thousands):

		Year Ended
	Financial Statement	December 31,
Commodity Contracts	Location	2013			2012			2011
Net Gain (Loss) Recognized in Income	Operating revenues (a)	$	289		$	103		$	(27	)
Net Loss Recognized in Income	Fuel and purchased power (a)	(10,449		)	(2,747		)	(52,113		)
Total		$	(10,160	)	$	(2,644	)	$	(52,140	)

(a) Amounts are before the effect of PSA deferrals.

Schedule of the entity's fair value of risk management activities reported on a gross basis and the impacts of offsetting

As of December 31, 2013:(dollars in thousands)	Gross  Recognized  Derivatives(a)			Amounts  Offset (b)			NetRecognizedDerivatives			Other(c)			Amount  Reported on  Balance Sheet
Current Assets	$	24,587		$	(7,425	)	$	17,162		$	7		$	17,169
Investments and Other Assets	25,364			(1,549		)	23,815			—			23,815
Total Assets	49,951			(8,974		)	40,977			7			40,984
Current Liabilities	(50,540		)	26,166			(24,374		)	(7,518		)	(31,892		)
Deferred Credits and Other	(72,123		)	1,808			(70,315		)	—			(70,315		)
Total Liabilities	(122,663		)	27,974			(94,689		)	(7,518		)	(102,207		)
Total	$	(72,712	)	$	19,000		$	(53,712	)	$	(7,511	)	$	(61,223	)

(a) All of our gross recognized derivative instruments were subject to master netting arrangements.

(b) Includes cash collateral provided to counterparties of $19,000.

(c) Represents cash collateral and margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $7,518, and cash margin provided to counterparties of $7.

As of December 31, 2012:(dollars in thousands)	GrossRecognizedDerivatives(a)			Amounts Offset  (b)			NetRecognizedDerivatives			Other(c)			AmountReported onBalance Sheet
Current Assets	$	42,495		$	(17,797	)	$	24,698		$	1,001		$	25,699
Investments and Other Assets	41,563			(5,672		)	35,891			—			35,891
Total Assets	84,058			(23,469		)	60,589			1,001			61,590
Current Liabilities	(105,324		)	57,046			(48,278		)	(25,463		)	(73,741		)
Deferred Credits and Other	(100,986		)	15,722			(85,264		)	—			(85,264		)
Total Liabilities	(206,310		)	72,768			(133,542		)	(25,463		)	(159,005		)
Total	$	(122,252	)	$	49,299		$	(72,953	)	$	(24,462	)	$	(97,415	)

(a) All of our gross recognized derivative instruments were subject to master netting arrangements.

(b) Includes cash collateral provided to counterparties of $49,299.

(c) Represents cash collateral relating to non-derivative instruments or derivatives qualifying for scope exceptions.  Includes cash collateral provided to counterparties of $1,001, and cash collateral received from counterparties of $25,463.  This amount is not subject to offsetting.

Information about derivative instruments that have credit-risk-related contingent features

The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2013 (dollars in millions):

	December 31, 2013
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	123
Cash Collateral Posted	19
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)	66

(a) This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.

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Leases (Tables)

12 Months Ended

Dec. 31, 2013

Leases

Estimated future minimum lease payments for Pinnacle West's and APS's operating leases, excluding purchased power agreements

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
2014	$	20	$	17
2015	17		14
2016	6		5
2017	5		5
2018	4		4
Thereafter	59		59
Total future lease commitments	$	111	$	104

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Jointly-Owned Facilities (Details) (ARIZONA PUBLIC SERVICE COMPANY, USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Palo Verde Units 1 and 3
Interests in jointly-owned facilities
Percent Owned	29.10%
Plant in Service	$ 1,701,844
Accumulated Depreciation	1,027,523
Construction Work in Progress	22,400
Palo Verde Unit 2
Interests in jointly-owned facilities
Percent Owned	16.80%
Plant in Service	543,972
Accumulated Depreciation	338,918
Construction Work in Progress	10,095
Palo Verde Common
Interests in jointly-owned facilities
Percent Owned	28.00%
Plant in Service	538,818
Accumulated Depreciation	219,801
Construction Work in Progress	81,599
Palo Verde Sale Leaseback
Interests in jointly-owned facilities
Plant in Service	351,050
Accumulated Depreciation	225,925
Four Corners Units 4, 5 and Common
Interests in jointly-owned facilities
Percent Owned	63.00%
Plant in Service	809,946
Accumulated Depreciation	608,194
Construction Work in Progress	14,434
Navajo Generating Station Units 1, 2 and 3
Interests in jointly-owned facilities
Percent Owned	14.00%
Plant in Service	270,448
Accumulated Depreciation	150,501
Construction Work in Progress	2,864
Cholla common facilities
Interests in jointly-owned facilities
Percent Owned	63.30%
Plant in Service	148,299
Accumulated Depreciation	47,851
Construction Work in Progress	7,159
ANPP 500kV System
Interests in jointly-owned facilities
Percent Owned	34.20%
Plant in Service	98,145
Accumulated Depreciation	32,350
Construction Work in Progress	1,095
Navajo Southern System
Interests in jointly-owned facilities
Percent Owned	22.20%
Plant in Service	58,702
Accumulated Depreciation	16,937
Construction Work in Progress	518
Palo Verde - Yuma 500kV System
Interests in jointly-owned facilities
Percent Owned	18.00%
Plant in Service	12,115
Accumulated Depreciation	4,656
Construction Work in Progress	11,786
Four Corners Switchyards
Interests in jointly-owned facilities
Percent Owned	48.10%
Plant in Service	33,460
Accumulated Depreciation	9,052
Construction Work in Progress	185
Phoenix - Mead System
Interests in jointly-owned facilities
Percent Owned	17.10%
Plant in Service	39,758
Accumulated Depreciation	12,140
Palo Verde - Estrella 500kV System
Interests in jointly-owned facilities
Percent Owned	50.00%
Plant in Service	89,571
Accumulated Depreciation	14,883
Construction Work in Progress	21
Morgan-Pinnacle Peak System
Interests in jointly-owned facilities
Percent Owned	64.50%
Plant in Service	130,132
Accumulated Depreciation	6,651
Construction Work in Progress	1,042
Round Valley System
Interests in jointly-owned facilities
Percent Owned	50.00%
Plant in Service	488
Accumulated Depreciation	268
Palo Verde - Morgan System
Interests in jointly-owned facilities
Percent Owned	90.00%
Construction Work in Progress	$ 36,601

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SCHEDULE II - RESERVE FOR UNCOLLECTIBLES (Details) (Reserve for uncollectibles., Pinnacle West, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reserve for uncollectibles. | Pinnacle West
Changes in reserve for uncollectibles
Balance at beginning of period	$ 3,340	$ 3,748	$ 4,709
Additions, Charged to cost and expenses	4,923	5,290	5,672
Deductions	5,060	5,698	6,633
Balance at end of period	$ 3,203	$ 3,340	$ 3,748

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Taxes

Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year

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):

	2013			2012			2011
Total unrecognized tax benefits, January 1	$	133,422		$	136,005		$	127,595
Additions for tax positions of the current year	3,516			5,167			10,915
Additions for tax positions of prior years	13,158			—			—
Reductions for tax positions of prior years for:
Changes in judgment	(108,099		)	(7,729		)	(1,555		)
Settlements with taxing authorities	—			—			(124		)
Lapses of applicable statute of limitations	—			(21		)	(826		)
Total unrecognized tax benefits, December 31	$	41,997		$	133,422		$	136,005

Components of income tax expense

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

	Year Ended December 31,
	2013			2012			2011
Current:
Federal	$	(81,784	)	$	(3,493	)	$	(310	)
State	10,537			8,395			15,140
Total current	(71,247		)	4,902			14,830
Deferred:
Federal	279,973			200,322			159,566
State	21,865			28,280			16,626
Total deferred	301,838			228,602			176,192
Total income tax expense	230,591			233,504			191,022
Less: income tax expense (benefit) on discontinued operations	—			(3,813		)	7,418
Income tax expense — continuing operations	$	230,591		$	237,317		$	183,604

Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations

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,
	2013			2012			2011
Federal income tax expense at 35% statutory rate	$	234,695		$	229,709		$	188,733
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	21,387			23,819			19,594
Credits and favorable adjustments related to prior years resolved in current year	(3,356		)	—			—
Medicare Subsidy Part-D	823			483			823
Allowance for equity funds used during construction (see Note 1)	(6,997		)	(6,158		)	(6,881		)
Palo Verde VIE noncontrolling interest (see Note 19)	(11,862		)	(11,065		)	(9,636		)
Other	(4,099		)	529			(9,029		)
Income tax expense — continuing operations	$	230,591		$	237,317		$	183,604

Net deferred income tax liability recognized on the Consolidated Balance Sheets

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

	December 31,
	2013			2012
Current asset	$	91,152		$	152,191
Long-term liability	(2,351,882		)	(2,151,371		)
Deferred income taxes — net	$	(2,260,730	)	$	(1,999,180	)

Components of the net deferred income tax liability

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

	December 31,
	2013			2012
DEFERRED TAX ASSETS
Risk management activities	$	44,920		$	72,243
Regulatory liabilities:
Asset retirement obligation and removal costs	235,959			238,669
Unamortized investment tax credits	82,116			53,837
Other	42,609			33,764
Pension and other postretirement liabilities	198,642			408,764
Renewable energy incentives	65,434			66,941
Credit and loss carryforwards	133,070			139,022
Other	148,492			68,844
Total deferred tax assets	951,242			1,082,084
DEFERRED TAX LIABILITIES
Plant-related	(2,903,730		)	(2,584,166		)
Risk management activities	(16,191		)	(23,940		)
Regulatory assets:
Allowance for equity funds used during construction	(43,058		)	(37,899		)
Deferred fuel and purchased power	(8,282		)	(28,858		)
Deferred fuel and purchased power — mark-to-market	(13,343		)	(15,796		)
Pension and other postretirement benefits	(129,250		)	(316,757		)
Other	(93,202		)	(68,170		)
Other	(4,916		)	(5,678		)
Total deferred tax liabilities	(3,211,972		)	(3,081,264		)
Deferred income taxes — net	$	(2,260,730	)	$	(1,999,180	)

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Palo Verde Sale Leaseback Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2013

Palo Verde Sale Leaseback Variable Interest Entities

Amounts relating to the VIEs included in Consolidated Balance Sheets

Our Consolidated Balance Sheets at December 31, 2013 and December 31, 2012 include the following amounts relating to the VIEs (in millions):

	December 31, 2013		December 31, 2012
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	125	$	129
Current maturities of long-term debt	26		27
Long-term debt excluding current maturities	13		39
Equity-Noncontrolling interests	146		129

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Long-Term Debt and Liquidity Matters (Details 2) (USD $)	Dec. 31, 2013
ARIZONA PUBLIC SERVICE COMPANY
Principal payments due on long-term debt
2014	$ 540,000,000
2015	345,000,000
2016	358,000,000
2018	32,000,000
Thereafter	1,940,000,000
Total	3,215,000,000
Pinnacle West
Principal payments due on long-term debt
2014	540,000,000
2015	470,000,000
2016	358,000,000
2018	32,000,000
Thereafter	1,940,000,000
Total	$ 3,340,000,000

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Selected Quarterly Financial Data (Unaudited) (APSC) (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of quarterly financial information

Consolidated quarterly financial information for 2013 and 2012 is provided in the tables below (dollars in thousands, except per share amounts). 

	2013 Quarter Ended								2013
	March 31,		June 30,		Sept. 30,		Dec. 31,		Total
Operating revenues	$	686,652	$	915,822	$	1,152,392	$	699,762	$	3,454,628
Operations and maintenance	223,250		229,300		233,323		238,854		924,727
Operating income	86,923		259,812		415,688		83,900		846,323
Income taxes	12,469		77,043		131,912		9,167		230,591
Income from continuing operations	32,836		139,598		234,718		32,814		439,966
Net income attributable to common shareholders	24,444		131,207		226,163		24,260		406,074
Earnings Per Share:
Income from continuing operations attributable to common shareholders — Basic	$	0.22	$	1.19	$	2.06	$	0.22	$	3.69
Net income attributable to common shareholders — Basic	0.22		1.19		2.06		0.22		3.69
Income from continuing operations attributable to common shareholders — Diluted	0.22		1.18		2.04		0.22		3.66
Net income attributable to common shareholders — Diluted	0.22		1.18		2.04		0.22		3.66

	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

ARIZONA PUBLIC SERVICE COMPANY

Schedule of quarterly financial information

Quarterly financial information for 2013 and 2012 is as follows (dollars in thousands):

	2013 Quarter Ended,								2013
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	685,827	$	915,065	$	1,151,535	$	698,824	$	3,451,251
Operations and maintenance	220,752		224,950		222,617		229,505		897,824
Operating income	74,862		183,728		284,251		79,024		621,865
Net income attributable to common shareholder	26,042		133,949		234,954		30,024		424,969

	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

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Income Taxes (Details) (USD $)	3 Months Ended	12 Months Ended				12 Months Ended	0 Months Ended	3 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Maximum	Dec. 31, 2013 Palo Verde VIE	Sep. 13, 2013 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2013 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2013 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2011 ARIZONA PUBLIC SERVICE COMPANY	Sep. 30, 2013 ARIZONA PUBLIC SERVICE COMPANY	Sep. 30, 2009 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2013 ARIZONA PUBLIC SERVICE COMPANY Maximum
Income Taxes
Long-term income tax receivables			$ 70,389,000							$ 70,784,000			$ 71,000,000
Decrease in uncertain tax positions	67,000,000											67,000,000
Income tax receivable that will be reclassified from long term to short-term		137,000,000							138,000,000
Anticipated refund reduction amount		(4,000,000)						(4,000,000)	(4,000,000)
Decrease in long term deferred tax liability due to adoption of regulations	(84,000,000)						(84,000,000)
Decrease in long term deferred tax liability due to rate changes		(75,000,000)						(2,000,000)	(2,000,000)
Period over which deferred income tax liability would have been repaid		20 years					20 years
Income tax expense associates with the VIE's						0
Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year
Total unrecognized tax benefits at the beginning of the year		133,422,000	136,005,000	127,595,000					133,241,000	135,824,000	126,698,000
Additions for tax positions of the current year		3,516,000	5,167,000	10,915,000					3,516,000	5,167,000	10,915,000
Additions for tax positions of prior years		13,158,000							13,158,000
Reductions for tax positions of prior years for:
Changes in judgment		(108,099,000)	(7,729,000)	(1,555,000)					(107,918,000)	(7,729,000)	(1,555,000)
Settlements with taxing authorities				(124,000)							(124,000)
Lapses of applicable statute of limitations			(21,000)	(826,000)						(21,000)	(110,000,000)
Total unrecognized tax benefits at the end of the year		41,997,000	133,422,000	136,005,000				41,997,000	41,997,000	133,241,000	135,824,000
Unrecognized tax benefits if recognized, would decrease effective tax rate		10,000,000	10,000,000	8,000,000				10,000,000	10,000,000	10,000,000	8,000,000
Pre-tax interest expense (benefit) related to unrecognized tax benefits		4,000,000	4,000,000	3,000,000					4,000,000	4,000,000	3,000,000
Accrued liabilities for interest related to unrecognized tax benefits			13,000,000	9,000,000	1,000,000					13,000,000	9,000,000			1,000,000
Interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS		$ 5,000,000						$ 5,000,000	$ 5,000,000

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Measurements

Fair value of assets and liabilities that are measured at fair value on a recurring basis

The following table presents the fair value at December 31, 2013 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, 2013
Assets
Risk management activities — derivative instruments:
Commodity Contracts	$	—	$	9		$	41		$	(9	) (b)	$	41
Nuclear decommissioning trust:
U.S. commingled equity funds	—		272			—			—			272
Fixed income securities:
U.S. Treasury	107		—			—			—			107
Cash and cash equivalent funds	—		11			—			(3		) (c)	8
Corporate debt	—		88			—			—			88
Mortgage-backed securities	—		85			—			—			85
Municipality bonds	—		71			—			—			71
Other	—		11			—			—			11
Subtotal nuclear decommissioning trust	107		538			—			(3		)	642
Total	$	107	$	547		$	41		$	(12	)	$	683
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(33	)	$	(90	)	$	21	(b)	$	(102	)

(a) Primarily consists of heat rate options and other long-dated electricity contracts.

(b) Represents counterparty netting, margin and collateral.  See Note 17.

(c) Represents nuclear decommissioning trust net pending securities sales and purchases.

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):

	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 17.

(c) Represents nuclear decommissioning trust net pending securities sales and purchases.

Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments

	December 31, 2013 Fair Value (millions)				Valuation	Significant		Weighted-
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range	Average
Electricity:
Forward Contracts (a)	$	40	$	66	Discounted cash flows	Electricity forward price (per MWh)	$24.89 - $65.04	$	41.09
Option Contracts (b)	—		19		Option model	Electricity forward price (per MWh)	$39.91 - $85.41	$	58.70
						Natural gas forward price (per MMbtu)	$3.57 - $3.80	$	3.71
						Electricity price volatilities	35% - 94%	59		%
						Natural gas price volatilities	22% - 36%	27		%
Natural Gas:
Forward Contracts (a)	1		5		Discounted cash flows	Natural gas forward price (per MMbtu)	$3.47 - $4.31	$	3.87
Total	$	41	$	90

(a) Includes swaps and physical and financial contracts.

(b) Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities.

	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.

Changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs

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, 2013 and 2012 (dollars in millions):

	Year Ended December 31,
Commodity Contracts	2013			2012
Net derivative balance at beginning of period	$	(48	)	$	(51	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			2
Included in OCI	—			(3		)
Deferred as a regulatory asset or liability	(10		)	7
Settlements	10			(5		)
Transfers into Level 3 from Level 2	—			(2		)
Transfers from Level 3 into Level 2	(1		)	4
Net derivative balance at end of period	$	(49	)	$	(48	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—

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CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (USD $) In Thousands, unless otherwise specified	Total	COMMON STOCK (Note 7)	TREASURY STOCK (Note 7)	RETAINED EARNINGS	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	NONCONTROLLING INTERESTS	COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
Balance at Dec. 31, 2010		$ 2,421,372	$ (2,239)	$ 1,423,961	$ (159,767)	$ 91,899
Increase (Decrease) in Shareholders' Equity
Issuance of common stock		22,875
Purchase of treasury stock			(3,720)
Reissuance of treasury stock used for stock compensation			1,242
Net income attributable to common shareholders	339,473			339,473			339,473
Common stock dividends declared ($2.23, $2.67, and $ 2.10 per share)				(228,951)
Net income attributable to noncontrolling interests	(27,467)					27,467
Net capital activities by noncontrolling interests						(10,630)
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER
Other comprehensive income attributable to common shareholders	7,605				7,604		7,605
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	347,078						347,078
Balance at Dec. 31, 2011	3,930,586	2,444,247	(4,717)	1,534,483	(152,163)	108,736
Increase (Decrease) in Shareholders' Equity
Issuance of common stock		22,676
Purchase of treasury stock			(4,607)
Reissuance of treasury stock used for stock compensation			5,113
Net income attributable to common shareholders	381,542			381,542			381,542
Common stock dividends declared ($2.23, $2.67, and $ 2.10 per share)				(291,923)
Net income attributable to noncontrolling interests	(31,622)					31,622
Net capital activities by noncontrolling interests						(10,875)
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER
Other comprehensive income attributable to common shareholders	38,155				38,155		38,155
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	419,697						419,697
Balance at Dec. 31, 2012	4,102,289	2,466,923	(4,211)	1,624,102	(114,008)	129,483
Increase (Decrease) in Shareholders' Equity
Issuance of common stock		24,635
Purchase of treasury stock			(9,727)
Reissuance of treasury stock used for stock compensation			9,630
Net income attributable to common shareholders	406,074			406,074			406,074
Common stock dividends declared ($2.23, $2.67, and $ 2.10 per share)				(244,903)
Net income attributable to noncontrolling interests	(33,892)					33,892
Net capital activities by noncontrolling interests						(17,385)
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER
Other comprehensive income attributable to common shareholders	35,955				35,955		35,955
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	442,029						442,029
Balance at Dec. 31, 2013	$ 4,340,460	$ 2,491,558	$ (4,308)	$ 1,785,273	$ (78,053)	$ 145,990

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Income Taxes (APSC) (Details 3) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory liabilities:
Asset retirement obligation and removal costs	$ 235,959	$ 238,669
Unamortized investment tax credits	82,116	53,837
Other	42,609	33,764
Risk management activities	44,920	72,243
Pension and other postretirement liabilities	198,642	408,764
Renewable energy incentives	65,434	66,941
Credit and loss carryforwards	133,070	139,022
Other	148,492	68,844
Total deferred tax assets	951,242	1,082,084
DEFERRED TAX LIABILITIES
Plant-related	(2,903,730)	(2,584,166)
Risk management activities	(16,191)	(23,940)
Regulatory assets:
Allowance for equity funds used during construction	(43,058)	(37,899)
Deferred fuel and purchased power	(8,282)	(28,858)
Deferred fuel and purchased power - mark-to-market	(13,343)	(15,796)
Pension and other postretirement benefits	(129,250)	(316,757)
Other	(93,202)	(68,170)
Other	(4,916)	(5,678)
Total deferred tax liabilities	(3,211,972)	(3,081,264)
Deferred income taxes - net	(2,260,730)	(1,999,180)
ARIZONA PUBLIC SERVICE COMPANY
Regulatory liabilities:
Asset retirement obligation and removal costs	235,959	238,669
Unamortized investment tax credits	82,116	53,837
Other	42,609	33,764
Risk management activities	44,920	72,243
Pension and other postretirement liabilities	186,213	392,486
Renewable energy incentives	65,434	66,941
Credit and loss carryforwards	38,183	52,441
Other	166,781	111,327
Total deferred tax assets	862,215	1,021,708
DEFERRED TAX LIABILITIES
Plant-related	(2,903,730)	(2,584,166)
Risk management activities	(16,191)	(23,940)
Regulatory assets:
Allowance for equity funds used during construction	(43,058)	(37,899)
Deferred fuel and purchased power	(8,282)	(28,858)
Deferred fuel and purchased power - mark-to-market	(13,343)	(15,796)
Pension and other postretirement benefits	(129,250)	(316,757)
Other	(93,202)	(68,170)
Other	(4,916)	(5,678)
Total deferred tax liabilities	(3,211,972)	(3,081,264)
Deferred income taxes - net	$ (2,349,757)	$ (2,059,556)

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Income Taxes (Details 2) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current:
Federal									$ (81,784)	$ (3,493)	$ (310)
State									10,537	8,395	15,140
Total current									(71,247)	4,902	14,830
Deferred:
Federal									279,973	200,322	159,566
State									21,865	28,280	16,626
Total deferred									301,838	228,602	176,192
Total income tax expense									230,591	233,504	191,022
Less: income tax expense (benefit) on discontinued operations										(3,813)	7,418
Income tax expense - continuing operations	$ 9,167	$ 131,912	$ 77,043	$ 12,469	$ 18,157	$ 147,116	$ 76,689	$ (4,645)	$ 230,591	$ 237,317	$ 183,604

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Jointly-Owned Facilities (Tables)

12 Months Ended

Dec. 31, 2013

Jointly-Owned Facilities

APS's interests in jointly-owned facilities recorded on the Consolidated Balance Sheets

The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2013 (dollars in thousands):

	Percent Owned		Plant in Service		Accumulated Depreciation		Construction Work in Progress
Generating facilities:
Palo Verde Units 1 and 3	29.1	%	$	1,701,844	$	1,027,523	$	22,400
Palo Verde Unit 2 (a)	16.8	%	543,972		338,918		10,095
Palo Verde Common	28.0	% (b)	538,818		219,801		81,599
Palo Verde Sale Leaseback		(a)	351,050		225,925		—
Four Corners Units 4, 5 and Common (d)	63.0	%	809,946		608,194		14,434
Navajo Generating Station Units 1, 2 and 3	14.0	%	270,448		150,501		2,864
Cholla common facilities (c)	63.3	% (b)	148,299		47,851		7,159
Transmission facilities:
ANPP 500kV System	34.2	% (b)	98,145		32,350		1,095
Navajo Southern System	22.2	% (b)	58,702		16,937		518
Palo Verde — Yuma 500kV System	18.0	% (b)	12,115		4,656		11,786
Four Corners Switchyards	48.1	% (b)	33,460		9,052		185
Phoenix — Mead System	17.1	% (b)	39,758		12,140		—
Palo Verde — Estrella 500kV System	50.0	% (b)	89,571		14,883		21
Morgan — Pinnacle Peak System	64.5	% (b)	130,132		6,651		1,042
Round Valley System	50.0	% (b)	488		268		—
Palo Verde — Morgan System	90.0	% (b)	—		—		36,601

(a) See Note 19.

(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.

(d) See Note 3.

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Palo Verde Sale Leaseback Variable Interest Entities

12 Months Ended

Dec. 31, 2013

Palo Verde Sale Leaseback Variable Interest Entities

Palo Verde Sale Leaseback Variable Interest Entities

19. 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 during 2014 and 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 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 2013, 2012 and 2011 of $34 million, $32 million and $28 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, 2013 and December 31, 2012 include the following amounts relating to the VIEs (in millions):

	December 31, 2013		December 31, 2012
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	125	$	129
Current maturities of long-term debt	26		27
Long-term debt excluding current maturities	13		39
Equity-Noncontrolling interests	146		129

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 Palo Verde 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, 2013, APS would have been required to pay the noncontrolling equity participants approximately $133 million and assume $39 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.

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Other Income and Other Expense

12 Months Ended

Dec. 31, 2013

Other Income and Other Expense

Other Income and Other Expense

18. Other Income and Other Expense

The following table provides detail of other income and other expense for 2013, 2012 and 2011 (dollars in thousands):

	2013			2012			2011
Other income:
Interest income	$	1,629		$	1,239		$	1,850
Investment gains — net	—			—			1,165
Miscellaneous	75			367			96
Total other income	$	1,704		$	1,606		$	3,111
Other expense:
Non-operating costs	$	(8,207	)	$	(7,777	)	$	(7,037	)
Investment loss — net	(3,711		)	(2,453		)	—
Miscellaneous	(4,106		)	(9,612		)	(3,414		)
Total other expense	$	(16,024	)	$	(19,842	)	$	(10,451	)

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (APSC) (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net unrealized loss, tax benefit	$ 140	$ 14,900	$ 37,389
Reclassification of net realized loss, tax benefit	17,472	39,120	46,288
Pension and other postretirement benefits activity, tax (expense) benefit	(6,156)	(651)	3,935
ARIZONA PUBLIC SERVICE COMPANY
Net unrealized loss, tax benefit	140	14,888	37,397
Reclassification of net realized loss, tax benefit	17,472	39,119	46,298
Pension and other postretirement benefits activity, tax (expense) benefit	$ (6,003)	$ 408	$ 1,910

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Summary of Significant Accounting Policies (Details 2) (USD $)	12 Months Ended								36 Months Ended	12 Months Ended	36 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 ARIZONA PUBLIC SERVICE COMPANY item	Dec. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2011 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2008 ARIZONA PUBLIC SERVICE COMPANY item	Dec. 31, 1986 ARIZONA PUBLIC SERVICE COMPANY item	Dec. 31, 2013 Minimum	Dec. 31, 2013 Maximum	Dec. 31, 2013 Maximum	Dec. 31, 2013 Fossil plant	Dec. 31, 2013 Nuclear plant	Dec. 31, 2013 Other generation	Dec. 31, 2013 Transmission	Dec. 31, 2013 Distribution	Dec. 31, 2013 Other:
Approximate remaining average useful lives of utility property
Average useful life												18 years	26 years	26 years	37 years	34 years	7 years
Extension period of operating licenses for each of the three Palo Verde units							20 years
Number of VIE lessor trusts				3			3	3
Depreciation rates (as a percent)	3.00%	2.71%	2.98%						0.45%		12.08%
Allowance for Funds Used During Construction
Composite rate used to calculate AFUDC (as a percent)	8.56%	8.60%	10.25%
Nuclear Fuel
Charges for the permanent disposal of spent nuclear fuel (in dollars per kWh)				0.001
Cash paid during the year for:
Income taxes, net of refunds	$ 18,537,000	$ 2,543,000	$ 10,324,000	$ 7,524,000	$ 1,196,000	$ 25,975,000
Interest, net of amounts capitalized	184,010,000	200,923,000	217,789,000	180,757,000	196,038,000	210,995,000
Significant non-cash investing and financing activities:
Accrued capital expenditures	33,184,000	26,208,000	27,245,000	33,184,000	26,208,000	27,245,000
Dividends declared but not paid	62,528,000	59,789,000		62,500,000	59,800,000
Liabilities assumed relating to acquisition of SCE Four Corners' interest (see Note 3)	145,609,000			145,609,000
Intangible Assets
Amortization expense	53,000,000	50,000,000	47,000,000
Estimated amortization expense on existing intangible assets over the next five years
2014	47,000,000
2015	38,000,000
2016	29,000,000
2017	19,000,000
2018	$ 7,000,000
Weighted average remaining amortization period for intangible assets	6 years
Investments
Ownership percentage for classification as cost method investments by El Dorado										20.00%

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies.

Summary of estimated coal take-or-pay commitments

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

			Years Ended December 31,
	2014		2015		2016		2017		2018		Thereafter
Coal take-or-pay commitments (a)	$	152	$	157	$	166	$	180	$	175	$	2,539

(a) Total take-or-pay commitments are approximately $3.4 billion.  The total net present value of these commitments is approximately $2.2 billion.

Summary of actual take-or-pay commitments

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,
	2013		2012		2011
Total purchases	$	188	$	196	$	191

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Nuclear Decommissioning Trusts

12 Months Ended

Dec. 31, 2013

Nuclear Decommissioning Trusts

Nuclear Decommissioning Trusts

20. 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 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, 2013 and December 31, 2012 (dollars in millions):

	Fair Value			Total  Unrealized  Gains		Total  Unrealized  Losses
December 31, 2013
Equity securities	$	272		$	129	$	—
Fixed income securities	373			11		(6		)
Net payables (a)	(3		)	—		—
Total	$	642		$	140	$	(6	)

	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	$	—

(a) Net payables relate to pending purchases and sales of securities.

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,
	2013			2012			2011
Realized gains	$	6		$	7		$	8
Realized losses	(7		)	(4		)	(5		)
Proceeds from the sale of securities (a)	446			418			498

(a) Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2013 is as follows (dollars in millions):

	Fair Value
Less than one year	$	9
1 year – 5 years	109
5 years – 10 years	108
Greater than 10 years	147
Total	$	373

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Changes in Accumulated Other Comprehensive Loss

12 Months Ended

Dec. 31, 2013

Changes in Accumulated Other Comprehensive Loss

Changes in Accumulated Other Comprehensive Loss

21. Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands):

	Year Ended December 31, 2013
	Derivative  Instruments			Pension and  Other  Postretirement  Benefits			Total
Beginning balance	$	(49,592	)	$	(64,416	)	$	(114,008	)
OCI (loss) before reclassifications	(213		)	5,594			5,381
Amounts reclassified from accumulated other comprehensive loss	26,747		(a)	3,827		(b)	30,574
Net current period OCI	26,534			9,421			35,955
Ending balance	$	(23,058	)	$	(54,995	)	$	(78,053	)

(a) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 17.

(b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 8.

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$ 439,966	$ 413,164	$ 366,940
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sale of energy-related products and services business			(10,404)
Depreciation and amortization including nuclear fuel	492,322	481,262	493,784
Deferred fuel and purchased power	21,678	71,573	69,166
Deferred fuel and purchased power amortization	31,190	(116,716)	(155,157)
Allowance for equity funds used during construction	(25,581)	(22,436)	(23,707)
Deferred income taxes	249,296	187,023	117,952
Deferred investment tax credit	52,542	41,579	58,240
Change in derivative instruments fair value	534	(749)	4,064
Changes in current assets and liabilities:
Customer and other receivables	(44,991)	14,587	40,626
Accrued unbilled revenues	(1,951)	30,394	(21,947)
Materials, supplies and fossil fuel	(11,878)	(23,043)	(23,398)
Income tax receivable	(133,094)	(4,043)	3,983
Other current assets	(17,913)	(27,352)	(3,079)
Accounts payable	45,414	(96,600)	58,346
Accrued taxes	6,059	12,736	8,085
Other current liabilities	(7,513)	23,869	20,358
Change in margin and collateral accounts - assets	993	2,216	33,349
Change in margin and collateral accounts - liabilities	12,355	137,785	29,731
Change in long term income tax receivable	137,270	(1,756)	(3,530)
Change in unrecognized tax benefits	(91,425)	(2,583)	8,410
Change in other regulatory liabilities	64,473	13,539	37,009
Change in other long-term assets	(41,757)	6,872	(41,722)
Change in other long-term liabilities	(24,682)	29,801	58,484
Net cash flow provided by operating activities	1,153,307	1,171,122	1,125,583
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,016,322)	(889,551)	(884,350)
Contributions in aid of construction	41,090	49,876	38,096
Allowance for borrowed funds used during construction	(14,861)	(14,971)	(18,358)
Proceeds from sale of energy-related products and services business	0		45,111
Proceeds from nuclear decommissioning trust sales	446,025	417,603	497,780
Investment in nuclear decommissioning trust	(463,274)	(434,852)	(513,799)
Proceeds from sale of life insurance policies			55,444
Other	(2,059)	(1,099)	(1,931)
Net cash flow used for investing activities	(1,009,401)	(872,994)	(782,007)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	136,307	476,081	470,353
Repayment of long-term debt	(122,828)	(654,286)	(655,169)
Short-term borrowings and payments - net	60,950	92,175	(16,600)
Dividends paid on common stock	(235,244)	(225,075)	(221,728)
Common stock equity issuance	17,319	15,955	15,841
Distributions to noncontrolling interests	(17,385)	(10,529)	(10,210)
Other	299	170	(2,668)
Net cash flow used for financing activities	(160,582)	(305,509)	(420,181)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(16,676)	(7,381)	(76,605)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	26,202	33,583	110,188
CASH AND CASH EQUIVALENTS AT END OF YEAR	$ 9,526	$ 26,202	$ 33,583

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

12 Months Ended

Dec. 31, 2013

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

	Year Ended December 31,
	2013			2012			2011
Operating revenues	$	799		$	6,133		$	1,034
Operating expenses	24,930			12,125			8,811
Operating loss	(24,131		)	(5,992		)	(7,777		)
Other
Equity in earnings of subsidiaries	420,926			391,528			335,859
Other expense	(1,999		)	(2,001		)	(1,481		)
Total	418,927			389,527			334,378
Interest expense	3,226			4,868			8,053
Income from continuing operations	391,570			378,667			318,548
Income tax benefit	(14,504		)	(7,079		)	(8,938		)
Income from continuing operations — net of income taxes	406,074			385,746			327,486
Income (loss) from discontinued operations — net of income taxes	—			(4,204		)	11,987
Net income attributable to common shareholders	406,074			381,542			339,473
Other comprehensive income — attributable to common shareholders	35,955			38,155			7,605
Total comprehensive income — attributable to common shareholders	$	442,029		$	419,697		$	347,078

See Notes to Pinnacle West’s Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED BALANCE SHEETS

(in thousands)

	December 31,
	2013			2012
ASSETS
Current assets
Cash and cash equivalents	$	5,798		$	22,679
Accounts receivable	80,108			92,906
Current deferred income taxes	93,185			77,771
Income tax receivable	1,853			3,350
Other current assets	242			25
Total current assets	181,186			196,731
Investments and other assets
Investments in subsidiaries	4,455,049			4,223,301
Other assets	13,789			13,833
Total investments and other assets	4,468,838			4,237,134
Total Assets	$	4,650,024		$	4,433,865
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	3,279		$	5,735
Accrued taxes	8,538			8,239
Common dividends payable	62,528			59,789
Other current liabilities	31,295			41,000
Total current liabilities	105,640			114,763
Long-term debt less current maturities	125,000			125,000
Deferred credits and other
Deferred income taxes	4,158			17,395
Pension and other postretirement liabilities	37,611			41,199
Other	37,155			33,219
Total deferred credits and other	78,924			91,813
Common stock equity
Common stock	2,487,250			2,462,712
Accumulated other comprehensive loss	(78,053		)	(114,008		)
Retained earnings	1,785,273			1,624,102
Total Pinnacle West Shareholders’ equity	4,194,470			3,972,806
Noncontrolling interests	145,990			129,483
Total Equity	4,340,460			4,102,289
Total Liabilities and Equity	$	4,650,024		$	4,433,865

See Notes to Pinnacle West’s Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2013			2012			2011
Cash flows from operating activities
Net income	$	406,074		$	381,542		$	339,473
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries — net	(420,926		)	(391,528		)	(335,859		)
Depreciation and amortization	95			94			97
Gain on sale of energy-related business	—			—			(10,404		)
Deferred income taxes	(28,806		)	(15,135		)	7,387
Accounts receivable	21,671			28,763			(24,201		)
Accounts payable	(2,449		)	879			(2,677		)
Accrued taxes and income tax receivables — net	1,402			(3,103		)	7,512
Dividends received from subsidiaries	242,100			222,200			228,900
Other	(15,065		)	(4,589		)	19,270
Net cash flow provided by operating activities	204,096			219,123			229,498
Cash flows from investing activities
Investments in subsidiaries	(3,400		)	—			—
Repayments of loans from subsidiaries	2,149			996			61,143
Proceeds from sale of energy-related products and services business	—			—			45,111
Advances of loans to subsidiaries	(2,099		)	(1,200		)	(64,970		)
Proceeds from sale of life insurance policies	—			—			9,357
Net cash flow provided by (used for) investing activities	(3,350		)	(204		)	50,641
Cash flows from financing activities
Issuance of long-term debt	—			125,000			175,000
Short-term borrowings and payments — net	—			—			(16,600		)
Dividends paid on common stock	(235,244		)	(225,075		)	(221,728		)
Repayment of long-term debt	—			(125,000		)	(225,000		)
Common stock equity issuance	17,319			15,955			15,841
Other	298			170			(2,667		)
Net cash flow used for financing activities	(217,627		)	(208,950		)	(275,154		)
Net increase (decrease) in cash and cash equivalents	(16,881		)	9,969			4,985
Cash and cash equivalents at beginning of year	22,679			12,710			7,725
Cash and cash equivalents at end of year	$	5,798		$	22,679		$	12,710

See Notes to Pinnacle West’s Consolidated Financial Statements.

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Earnings Per Share (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Basic earnings per share:
Income from continuing operations attributable to common shareholders (in dollars per share)	$ 0.22	$ 2.06	$ 1.19	$ 0.22	$ 0.24	$ 2.23	$ 1.12	$ (0.07)	$ 3.69	$ 3.54	$ 3.01
Income (loss) from discontinued operations (in dollars per share)										$ (0.06)	$ 0.10
Earnings per share - basic (in dollars per share)	$ 0.22	$ 2.06	$ 1.19	$ 0.22	$ 0.21	$ 2.23	$ 1.12	$ (0.08)	$ 3.69	$ 3.48	$ 3.11
Diluted earnings per share:
Income from continuing operations attributable to common shareholders (in dollars per share)	$ 0.22	$ 2.04	$ 1.18	$ 0.22	$ 0.24	$ 2.21	$ 1.12	$ (0.07)	$ 3.66	$ 3.50	$ 2.99
Income (loss) from discontinued operations (in dollars per share)										$ (0.05)	$ 0.10
Earnings per share - diluted (in dollars per share)	$ 0.22	$ 2.04	$ 1.18	$ 0.22	$ 0.20	$ 2.21	$ 1.11	$ (0.08)	$ 3.66	$ 3.45	$ 3.09
Dilutive stock options and performance shares									822,000	1,017,000	811,000
Total average common shares outstanding for the purposes of calculating diluted earnings per share									110,806,000	110,527,000	109,864,000
Options to purchase shares of common stock outstanding excluded from computation of diluted earnings per share due to its antidilutive effect									0	0	0

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Income Taxes (APSC) (Details) (USD $)	3 Months Ended	12 Months Ended					0 Months Ended	3 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Palo Verde VIE	Dec. 31, 2013 Maximum	Sep. 13, 2013 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2013 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2013 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2011 ARIZONA PUBLIC SERVICE COMPANY	Sep. 30, 2013 ARIZONA PUBLIC SERVICE COMPANY	Sep. 30, 2009 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2013 ARIZONA PUBLIC SERVICE COMPANY Maximum
Income taxes
Long-term income tax receivables			$ 70,389,000							$ 70,784,000			$ 71,000,000
Decrease in uncertain tax positions	67,000,000											67,000,000
Income tax receivable that will be reclassified from long term to short-term		137,000,000							138,000,000
Anticipated refund reduction amount		(4,000,000)						(4,000,000)	(4,000,000)
Decrease in long term deferred tax liability due to adoption of regulations	(84,000,000)						(84,000,000)
Decrease in long term deferred tax liability due to rate changes		(75,000,000)						(2,000,000)	(2,000,000)
Period over which deferred income tax liability would have been repaid		20 years					20 years
Income tax expense associates with the VIE's					0
Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year
Total unrecognized tax benefits at the beginning of the year		133,422,000	136,005,000	127,595,000					133,241,000	135,824,000	126,698,000
Additions for tax positions of the current year		3,516,000	5,167,000	10,915,000					3,516,000	5,167,000	10,915,000
Additions for tax positions of prior years		13,158,000							13,158,000
Reductions for tax positions of prior years for:
Changes in judgment		(108,099,000)	(7,729,000)	(1,555,000)					(107,918,000)	(7,729,000)	(1,555,000)
Settlements with taxing authorities				(124,000)							(124,000)
Lapses of applicable statute of limitations			(21,000)	(826,000)						(21,000)	(110,000,000)
Total unrecognized tax benefits at the end of the year		41,997,000	133,422,000	136,005,000				41,997,000	41,997,000	133,241,000	135,824,000
Unrecognized tax benefits if recognized, would decrease effective tax rate		10,000,000	10,000,000	8,000,000				10,000,000	10,000,000	10,000,000	8,000,000
Pre-tax interest benefit related to unrecognized tax benefits		4,000,000	4,000,000	3,000,000					4,000,000	4,000,000	3,000,000
Accrued liabilities for interest related to unrecognized tax benefits			13,000,000	9,000,000		1,000,000				13,000,000	9,000,000			1,000,000
Interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS		$ 5,000,000						$ 5,000,000	$ 5,000,000

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Common Stock and Treasury Stock (Tables)

12 Months Ended

Dec. 31, 2013

Common Stock and Treasury Stock

Schedule of common stock and treasury stock activity

Our common stock and treasury stock activity during each of the three years 2013, 2012 and 2011 is as follows (dollars in thousands):

	Common Stock			Treasury Stock
	Shares	Amount		Shares		Amount
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 (a)	—	—		(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 (a)	—	—		(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		)
Common stock issuance	442,746	24,635		—		—
Purchase of treasury stock (a)	—	—		(174,290	)	(9,727		)
Reissuance of treasury stock for stock compensation	—	—		170,538		9,630
Balance at December 31, 2013	110,280,703	$	2,491,558	(98,944	)	$	(4,308	)

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

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Nuclear Decommissioning Trusts (Tables)

12 Months Ended

Dec. 31, 2013

Nuclear Decommissioning Trusts

Fair value of APS's nuclear decommissioning trust fund assets

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, 2013 and December 31, 2012 (dollars in millions):

	Fair Value			Total  Unrealized  Gains		Total  Unrealized  Losses
December 31, 2013
Equity securities	$	272		$	129	$	—
Fixed income securities	373			11		(6		)
Net payables (a)	(3		)	—		—
Total	$	642		$	140	$	(6	)

	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	$	—

(a) Net payables relate to pending purchases and sales of securities.

Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds

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,
	2013			2012			2011
Realized gains	$	6		$	7		$	8
Realized losses	(7		)	(4		)	(5		)
Proceeds from the sale of securities (a)	446			418			498

(a) Proceeds are reinvested in the trust.

Fair value of fixed income securities, summarized by contractual maturities

The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2013 is as follows (dollars in millions):

	Fair Value
Less than one year	$	9
1 year – 5 years	109
5 years – 10 years	108
Greater than 10 years	147
Total	$	373

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Retirement Plans and Other Benefits (Details 3) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	$ 2,264,121	$ 2,079,181	$ 1,850,550
Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	2,264,121	2,079,181
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	490,559	807,879
Pension Benefits | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	1,764,652	1,268,946
Pension Benefits | Significant Unobservable Inputs (Level 3) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	8,660	2,419
Pension Benefits | Counterparty Netting and Other | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	250	(63)
Pension Benefits | Fixed income securities.
Retirement Plans and Other Benefits
Actual asset allocation (as a percent)	55.00%
Target asset allocation
Target allocation (as a percent)	58.00%
Target allocation, minimum (as a percent)	55.00%
Target allocation, maximum (as a percent)	61.00%
Pension Benefits | Return-generating assets
Retirement Plans and Other Benefits
Actual asset allocation (as a percent)	45.00%
Target asset allocation
Target allocation (as a percent)	42.00%
Target allocation, minimum (as a percent)	45.00%
Target allocation, maximum (as a percent)	39.00%
Pension Benefits | Cash and cash equivalent funds | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	504	579
Pension Benefits | Cash and cash equivalent funds | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	504	579
Pension Benefits | Corporate debt | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	898,621	607,749
Pension Benefits | Corporate debt | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	898,621	607,749
Pension Benefits | U.S. Treasury | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	231,590	232,161
Pension Benefits | U.S. Treasury | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	231,590	232,161
Pension Benefits | Other | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	84,011	67,992
Pension Benefits | Other | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	84,011	67,992
Pension Benefits | Developed equities
Target asset allocation
Target allocation (as a percent)	22.00%
Pension Benefits | Emerging equities
Target asset allocation
Target allocation (as a percent)	6.00%
Pension Benefits | Alternative investments
Target asset allocation
Target allocation (as a percent)	14.00%
Pension Benefits | U.S. Companies, Equities | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	239,036	531,291
Pension Benefits | U.S. Companies, Equities | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	239,036	531,291
Pension Benefits | International Companies, Equities | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	19,429	43,848
Pension Benefits | International Companies, Equities | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	19,429	43,848
Pension Benefits | U.S. Equities | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	116,150	176,694
Pension Benefits | U.S. Equities | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	116,150	176,694
Pension Benefits | International Equities | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	367,551	271,735
Pension Benefits | International Equities | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	367,551	271,735
Pension Benefits | FIXED INCOME | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	137,520
Pension Benefits | FIXED INCOME | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	137,520
Pension Benefits | Real estate | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	119,739	117,854
Pension Benefits | Real estate | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	119,739	117,854
Pension Benefits | Short-term investments and other | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	49,970	29,278
Pension Benefits | Short-term investments and other | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	41,060	26,922
Pension Benefits | Short-term investments and other | Significant Unobservable Inputs (Level 3)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	8,660	2,419
Pension Benefits | Short-term investments and other | Significant Unobservable Inputs (Level 3) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	8,660	2,419
Pension Benefits | Short-term investments and other | Counterparty Netting and Other | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	250	(63)
Other Benefits
Retirement Plans and Other Benefits
Actual asset allocation (as a percent)	62.00%
Target asset allocation
Target allocation (as a percent)	75.00%
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	748,339	684,221	608,663
Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	748,339	684,221
Other Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	371,777	333,146
Other Benefits | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	374,132	350,029
Other Benefits | Counterparty Netting and Other | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	2,430	1,046
Other Benefits | Fixed income securities.
Retirement Plans and Other Benefits
Actual asset allocation (as a percent)	38.00%
Target asset allocation
Target allocation (as a percent)	25.00%
Other Benefits | Cash and cash equivalent funds | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets		60
Other Benefits | Cash and cash equivalent funds | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets		60
Other Benefits | Corporate debt | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	153,888	163,306
Other Benefits | Corporate debt | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	153,888	163,306
Other Benefits | U.S. Treasury | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	98,704	112,558
Other Benefits | U.S. Treasury | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	98,704	112,558
Other Benefits | Other | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	27,936	33,998
Other Benefits | Other | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	27,936	33,998
Other Benefits | U.S. Companies, Equities | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	252,181	205,714
Other Benefits | U.S. Companies, Equities | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	252,181	205,714
Other Benefits | International Companies, Equities | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	20,892	14,412
Other Benefits | International Companies, Equities | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	20,892	14,412
Other Benefits | U.S. Equities | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	80,751	60,038
Other Benefits | U.S. Equities | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	80,751	60,038
Other Benefits | International Equities | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	92,382	76,969
Other Benefits | International Equities | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	92,382	76,969
Other Benefits | Real estate | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	10,761	9,378
Other Benefits | Real estate | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	10,761	9,378
Other Benefits | Short-term investments and other | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	10,844	7,788
Other Benefits | Short-term investments and other | Significant Other Observable Inputs (Level 2) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	8,414	6,340
Other Benefits | Short-term investments and other | Counterparty Netting and Other | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	2,430	1,046
Other Benefits | Short-term investments | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets		$ 402

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CONSOLIDATED STATEMENTS OF INCOME
OPERATING REVENUES	$ 3,454,628	$ 3,301,804	$ 3,241,379
OPERATING EXPENSES
Fuel and purchased power	1,095,709	994,790	1,009,464
Operations and maintenance	924,727	884,769	904,286
Depreciation and amortization	415,708	404,336	427,054
Taxes other than income taxes	164,167	159,323	147,408
Other expenses	7,994	6,831	6,659
Total	2,608,305	2,450,049	2,494,871
OPERATING INCOME	846,323	851,755	746,508
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction (Note 1)	25,581	22,436	23,707
Other income (Note 18)	1,704	1,606	3,111
Other expense (Note 18)	(16,024)	(19,842)	(10,451)
Total	11,261	4,200	16,367
INTEREST EXPENSE
Interest charges	201,888	214,616	241,995
Allowance for borrowed funds used during construction (Note 1)	(14,861)	(14,971)	(18,358)
Total	187,027	199,645	223,637
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	670,557	656,310	539,238
INCOME TAXES (Note 4)	230,591	237,317	183,604
INCOME FROM CONTINUING OPERATIONS	439,966	418,993	355,634
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $--, $(3,813) and $7,418 (Note 1)		(5,829)	11,306
NET INCOME	439,966	413,164	366,940
Less: Net income attributable to noncontrolling interests (Note 19)	33,892	31,622	27,467
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	406,074	381,542	339,473
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares)	109,984	109,510	109,053
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares)	110,806	110,527	109,864
EARNINGS PER WEIGHTED - AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders - basic (in dollars per share)	$ 3.69	$ 3.54	$ 3.01
Net income attributable to common shareholders - basic (in dollars per share)	$ 3.69	$ 3.48	$ 3.11
Income from continuing operations attributable to common shareholders - diluted (in dollars per share)	$ 3.66	$ 3.50	$ 2.99
Net income attributable to common shareholders - diluted (in dollars per share)	$ 3.66	$ 3.45	$ 3.09
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	406,074	387,380	328,110
Discontinued operations, net of tax		(5,838)	11,363
Net income attributable to common shareholders	$ 406,074	$ 381,542	$ 339,473

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligations

Change in asset retirement obligations

The following schedule shows the change in our asset retirement obligations for 2013 and 2012 (dollars in millions):

	2013			2012
Asset retirement obligations at the beginning of year	$	357		$	280
Changes attributable to:
Accretion expense	24			19
Settlements	(12		)	—
Assumed SCE’s obligation	34			—
Estimated cash flow revisions	(56		)	58
Asset retirement obligations at the end of year	$	347		$	357

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Details 3) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities
Net Income	$ 439,966	$ 413,164	$ 366,940
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	492,322	481,262	493,784
Deferred income taxes	249,296	187,023	117,952
Accounts receivable	44,991	(14,587)	(40,626)
Accounts payable	45,414	(96,600)	58,346
Net cash flow provided by operating activities	1,153,307	1,171,122	1,125,583
Cash flows from investing activities
Proceeds from sale of energy-related products and services business	0		45,111
Net cash flow used for investing activities	(1,009,401)	(872,994)	(782,007)
Cash flows from financing activities
Issuance of long-term debt	136,307	476,081	470,353
Short-term borrowings and payments - net	60,950	92,175	(16,600)
Dividends paid on common stock	(235,244)	(225,075)	(221,728)
Repayment of long-term debt	(122,828)	(654,286)	(655,169)
Common stock equity issuance	17,319	15,955	15,841
Other	299	170	(2,668)
Net cash flow used for financing activities	(160,582)	(305,509)	(420,181)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(16,676)	(7,381)	(76,605)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	26,202	33,583	110,188
CASH AND CASH EQUIVALENTS AT END OF YEAR	9,526	26,202	33,583
Pinnacle West
Cash flows from operating activities
Net Income	406,074	381,542	339,473
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries - net	(420,926)	(391,528)	(335,859)
Depreciation and amortization	95	94	97
Gain on sale of energy-related business			(10,404)
Deferred income taxes	(28,806)	(15,135)	7,387
Accounts receivable	(21,671)	(28,763)	24,201
Accounts payable	(2,449)	879	(2,677)
Accrued taxes and income tax receivable - net	1,402	(3,103)	7,512
Dividends received from subsidiaries	242,100	222,200	228,900
Other	(15,065)	(4,589)	19,270
Net cash flow provided by operating activities	204,096	219,123	229,498
Cash flows from investing activities
Investments in subsidiaries	(3,400)
Repayments of loans from subsidiaries	2,149	996	61,143
Proceeds from sale of energy-related products and services business			45,111
Advances of loans to subsidiaries	(2,099)	(1,200)	(64,970)
Proceeds from sale of life insurance policies			9,357
Net cash flow used for investing activities	(3,350)	(204)	50,641
Cash flows from financing activities
Issuance of long-term debt		125,000	175,000
Short-term borrowings and payments - net			(16,600)
Dividends paid on common stock	(235,244)	(225,075)	(221,728)
Repayment of long-term debt		(125,000)	(225,000)
Common stock equity issuance	17,319	15,955	15,841
Other	298	170	(2,667)
Net cash flow used for financing activities	(217,627)	(208,950)	(275,154)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(16,881)	9,969	4,985
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	22,679	12,710	7,725
CASH AND CASH EQUIVALENTS AT END OF YEAR	$ 5,798	$ 22,679	$ 12,710

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Changes in Accumulated Other Comprehensive Loss (APSC) (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, by component

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands):

	Year Ended December 31, 2013
	Derivative  Instruments			Pension and  Other  Postretirement  Benefits			Total
Beginning balance	$	(49,592	)	$	(64,416	)	$	(114,008	)
OCI (loss) before reclassifications	(213		)	5,594			5,381
Amounts reclassified from accumulated other comprehensive loss	26,747		(a)	3,827		(b)	30,574
Net current period OCI	26,534			9,421			35,955
Ending balance	$	(23,058	)	$	(54,995	)	$	(78,053	)

(a) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 17.

(b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 8.

ARIZONA PUBLIC SERVICE COMPANY

Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, by component

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands):

	Year Ended December 31, 2013
	Derivative  Instruments			Pension and  Other  Postretirement  Benefits			Total
Beginning balance	$	(49,592	)	$	(39,503	)	$	(89,095	)
OCI (loss) before reclassifications	(214		)	5,387			5,173
Amounts reclassified from accumulated other comprehensive loss	26,747		(a)	3,803		(b)	30,550
Net current period OCI	26,533			9,190			35,723
Ending balance	$	(23,059	)	$	(30,313	)	$	(53,372	)

(a) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 17.

(b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 8.

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
CURRENT ASSETS
Cash and cash equivalents	$ 9,526	$ 26,202
Customer and other receivables	299,904	277,225
Accrued unbilled revenues	96,796	94,845
Allowance for doubtful accounts	(3,203)	(3,340)
Materials and supplies (at average cost)	221,682	218,096
Fossil fuel (at average cost)	38,028	31,334
Deferred income taxes (Note 4)	91,152	152,191
Income tax receivable (Note 4)	135,517	2,423
Assets from risk management activities (Note 17)	17,169	25,699
Deferred fuel and purchased power regulatory asset (Note 3)	20,755	72,692
Other regulatory assets (Note 3)	76,388	71,257
Other current assets	39,895	37,102
Total current assets	1,043,609	1,005,726
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 17)	23,815	35,891
Nuclear decommissioning trust (Notes 14 and 20)	642,007	570,625
Other assets	60,875	62,694
Total investments and other assets	726,697	669,210
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 10)
Plant in service and held for future use	15,200,464	14,346,367
Accumulated depreciation and amortization	(5,300,219)	(4,929,613)
Net	9,900,245	9,416,754
Construction work in progress	581,369	565,716
Palo Verde sale leaseback, net of accumulated depreciation of $225,925 and $222,055 (Note 19)	125,125	128,995
Intangible assets, net of accumulated amortization of $439,703 and $411,543	157,689	162,150
Nuclear fuel, net of accumulated amortization of $146,057 and $133,950	124,557	122,778
Total property, plant and equipment	10,888,985	10,396,393
DEFERRED DEBITS
Regulatory assets (Notes 1, 3 and 4)	711,712	1,099,900
Income tax receivable (Note 4)		70,389
Other	137,683	137,997
Total deferred debits	849,395	1,308,286
TOTAL ASSETS	13,508,686	13,379,615
CURRENT LIABILITIES
Accounts payable	284,516	221,312
Accrued taxes (Note 4)	130,998	124,939
Accrued interest	48,351	49,380
Common dividends payable	62,528	59,789
Short-term borrowings (Note 5)	153,125	92,175
Current maturities of long-term debt (Note 6)	540,424	122,828
Customer deposits	76,101	79,689
Liabilities from risk management activities (Note 17)	31,892	73,741
Liability for asset retirements (Note 12)	32,896
Regulatory liabilities (Note 3)	99,273	88,116
Other current liabilities	158,540	171,573
Total current liabilities	1,618,644	1,083,542
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)	2,796,465	3,199,088
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)	2,351,882	2,151,371
Regulatory liabilities (Notes 1, 3 and 4)	801,297	759,201
Liability for asset retirements (Note 12)	313,833	357,097
Liabilities for pension and other postretirement benefits (Note 8)	513,628	1,058,755
Liabilities from risk management activities (Note 17)	70,315	85,264
Customer advances	114,480	109,359
Coal mine reclamation	207,453	118,860
Deferred investment tax credit	152,361	99,819
Unrecognized tax benefits (Note 4)	42,209	71,135
Other	185,659	183,835
Total deferred credits and other	4,753,117	4,994,696
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY (Note 7)
Common stock, no par value; authorized 150,000,000 shares, issued 110,280,703 at end of 2013 and 109,837,957 at end of 2012	2,491,558	2,466,923
Treasury stock at cost; 98,944 shares at end of 2013 and 95,192 shares at end of 2012	(4,308)	(4,211)
Total common stock	2,487,250	2,462,712
Retained earnings	1,785,273	1,624,102
Accumulated other comprehensive loss:
Pension and other postretirement benefits (Note 8)	(54,995)	(64,416)
Derivative instruments (Note 17)	(23,058)	(49,592)
Total accumulated other comprehensive loss	(78,053)	(114,008)
Total shareholders' equity	4,194,470	3,972,806
Noncontrolling interests (Note 19)	145,990	129,483
Total equity	4,340,460	4,102,289
TOTAL LIABILITIES AND EQUITY	$ 13,508,686	$ 13,379,615

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CONDENSED STATEMENTS OF INCOME
Operating revenues	$ 699,762	$ 1,152,392	$ 915,822	$ 686,652	$ 693,122	$ 1,109,475	$ 878,576	$ 620,631	$ 3,454,628	$ 3,301,804	$ 3,241,379
Operating expenses									2,608,305	2,450,049	2,494,871
OPERATING INCOME	83,900	415,688	259,812	86,923	101,289	447,970	254,489	48,007	846,323	851,755	746,508
Other
Total									11,261	4,200	16,367
Interest expense									201,888	214,616	241,995
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES									670,557	656,310	539,238
Income tax benefit	9,167	131,912	77,043	12,469	18,157	147,116	76,689	(4,645)	230,591	237,317	183,604
INCOME FROM CONTINUING OPERATIONS	32,814	234,718	139,598	32,836	34,905	252,874	130,930	284	439,966	418,993	355,634
Income (loss) from discontinued operations - net of income taxes										(5,829)	11,306
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	24,260	226,163	131,207	24,444	22,631	244,823	122,345	(8,257)	406,074	381,542	339,473
Other comprehensive income attributable to common shareholders									35,955	38,155	7,605
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS									442,029	419,697	347,078
Pinnacle West
CONDENSED STATEMENTS OF INCOME
Operating revenues									799	6,133	1,034
Operating expenses									24,930	12,125	8,811
OPERATING INCOME									(24,131)	(5,992)	(7,777)
Other
Equity in earnings of subsidiaries									420,926	391,528	335,859
Other expense									(1,999)	(2,001)	(1,481)
Total									418,927	389,527	334,378
Interest expense									3,226	4,868	8,053
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES									391,570	378,667	318,548
Income tax benefit									(14,504)	(7,079)	(8,938)
INCOME FROM CONTINUING OPERATIONS									406,074	385,746	327,486
Income (loss) from discontinued operations - net of income taxes										(4,204)	11,987
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS									406,074	381,542	339,473
Other comprehensive income attributable to common shareholders									35,955	38,155	7,605
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS									$ 442,029	$ 419,697	$ 347,078

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Regulatory Matters (Details 3) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Detail of regulatory assets
Regulatory assets, current	$ 97,000,000	$ 144,000,000
Regulatory assets, non-current	711,712,000	1,099,900,000
Pension and other postretirement benefits
Detail of regulatory assets
Regulatory assets, non-current	314,000,000	780,000,000
Income taxes - AFUDC equity
Detail of regulatory assets
Regulatory assets, current	4,000,000	4,000,000
Regulatory assets, non-current	105,000,000	92,000,000
Deferred fuel and purchased power - mark-to-market
Detail of regulatory assets
Regulatory assets, current	5,000,000	19,000,000
Regulatory assets, non-current	29,000,000	21,000,000
Transmission vegetation management
Detail of regulatory assets
Regulatory assets, current	9,000,000	9,000,000
Regulatory assets, non-current	14,000,000	23,000,000
Coal reclamation
Detail of regulatory assets
Regulatory assets, current	8,000,000	8,000,000
Regulatory assets, non-current	18,000,000	24,000,000
Palo Verde VIE
Detail of regulatory assets
Regulatory assets, non-current	41,000,000	38,000,000
Deferred compensation
Detail of regulatory assets
Regulatory assets, non-current	34,000,000	34,000,000
Deferred fuel and purchased power
Detail of regulatory assets
Regulatory assets, current	21,000,000	73,000,000
Tax expense of Medicare subsidy
Detail of regulatory assets
Regulatory assets, current	2,000,000	2,000,000
Regulatory assets, non-current	15,000,000	17,000,000
Loss on reacquired debt
Detail of regulatory assets
Regulatory assets, current	1,000,000	2,000,000
Regulatory assets, non-current	17,000,000	18,000,000
Income taxes - investment tax credit basis adjustment
Detail of regulatory assets
Regulatory assets, current	1,000,000	1,000,000
Regulatory assets, non-current	39,000,000	26,000,000
Pension and other postretirement benefits deferral
Detail of regulatory assets
Regulatory assets, current	8,000,000	8,000,000
Regulatory assets, non-current	4,000,000	13,000,000
Four Corners cost deferral
Detail of regulatory assets
Regulatory assets, non-current	37,000,000
Lost fixed cost recovery
Detail of regulatory assets
Regulatory assets, current	25,000,000	7,000,000
Transmission cost adjustor
Detail of regulatory assets
Regulatory assets, current	8,000,000	10,000,000
Regulatory assets, non-current	2,000,000
Retired power plant costs
Detail of regulatory assets
Regulatory assets, current	3,000,000
Regulatory assets, non-current	18,000,000
Other
Detail of regulatory assets
Regulatory assets, current	2,000,000	1,000,000
Regulatory assets, non-current	$ 25,000,000	$ 14,000,000

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (APSC) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
NET INCOME	$ 439,966	$ 413,164	$ 366,940
Derivative instruments:
Net unrealized loss, net of tax benefit of $140, $14,888, and $37,397 (Note 17)	(213)	(22,763)	(57,271)
Reclassification of net realized loss, net of tax benefit of $17,472, $39,119 and $46,298 (Note 17)	26,747	59,887	70,902
Pension and other postretirement benefits activity, net of tax (expense) benefit of $(6,003), $408 and $1,910 (Note 8)	9,421	1,031	(6,026)
Total other comprehensive income	35,955	38,155	7,605
COMPREHENSIVE INCOME	475,921	451,319	374,545
Less: Comprehensive income attributable to noncontrolling interests	33,892	31,622	27,467
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	442,029	419,697	347,078
ARIZONA PUBLIC SERVICE COMPANY
NET INCOME	458,861	427,110	363,773
Derivative instruments:
Net unrealized loss, net of tax benefit of $140, $14,888, and $37,397 (Note 17)	(214)	(22,775)	(57,262)
Reclassification of net realized loss, net of tax benefit of $17,472, $39,119 and $46,298 (Note 17)	26,747	59,888	70,891
Pension and other postretirement benefits activity, net of tax (expense) benefit of $(6,003), $408 and $1,910 (Note 8)	9,190	(617)	(2,925)
Total other comprehensive income	35,723	36,496	10,704
COMPREHENSIVE INCOME	494,584	463,606	374,477
Less: Comprehensive income attributable to noncontrolling interests	33,892	31,613	27,524
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 460,692	$ 431,993	$ 346,953

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies

Schedule of impacts of the reclassifications of prior years (previously reported)

The following tables show the impacts of the reclassifications of prior years (previously reported) amounts (dollars in thousands):

Balance Sheets - December 31, 2012	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Long-Term Debt less Current Maturities —
Long-term debt less current maturities	$	3,160,219	$	38,869		$	3,199,088
Long-Term Debt less Current Maturities —
Palo Verde sale leaseback lessor notes less
current maturities	38,869		(38,869		)	—

Statement of Cash Flows for the Year Ended December 31, 2012	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
Deferred income taxes	$	228,602	$	(41,579	)	$	187,023
Deferred investment tax credit	—		41,579			41,579
Accrued taxes and income tax receivable	8,693		(8,693		)	—
Income tax receivable	—		(4,043		)	(4,043		)
Accrued taxes	—		12,736			12,736

Statement of Cash Flows for the Year Ended December 31, 2011	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
Deferred income taxes	$	176,192	$	(58,240	)	$	117,952
Deferred investment tax credit	—		58,240			58,240
Accrued taxes and income tax receivable	12,068		(12,068		)	—
Income tax receivable	—		3,983			3,983
Accrued taxes	—		8,085			8,085

Summary of supplemental cash flow information

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

	Years ended December 31,
	2013		2012		2011
Cash paid during the period for:
Income taxes, net of refunds	$	18,537	$	2,543	$	10,324
Interest, net of amounts capitalized	184,010		200,923		217,789
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	33,184	$	26,208	$	27,245
Dividends declared but not paid	62,528		59,789		—
Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 3)	145,609		—		—

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Lines of Credit and Short-Term Borrowings (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Lines of Credit and Short-Term Borrowings
Amount Committed	$ 1,200,000,000	$ 1,200,000,000
Unused Amount	1,047,000,000	1,108,000,000
Long term debt
Lines of Credit and Short-Term Borrowings
Amount Committed	847,000,000	908,000,000
Number of credit facilities	2	2
Pinnacle West
Lines of Credit and Short-Term Borrowings
Outstanding amount of debt	3,340,000,000
Pinnacle West | Long term debt
Lines of Credit and Short-Term Borrowings
Outstanding amount of debt	0	0
Pinnacle West | Revolving credit facility maturing in 2016
Lines of Credit and Short-Term Borrowings
Amount Committed	200,000,000	200,000,000
Unused Amount	200,000,000	200,000,000
Commitment Fees (as a percent)	0.175%	0.225%
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders	300,000,000	300,000,000
Pinnacle West | Commercial Paper
Lines of Credit and Short-Term Borrowings
Amount Committed	200,000,000	200,000,000
Outstanding amount of debt	0	0
Pinnacle West | Letters of credit
Lines of Credit and Short-Term Borrowings
Outstanding amount of debt	0	0
ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Amount Committed	1,000,000,000
Outstanding amount of debt	3,215,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders	700,000,000	700,000,000
ARIZONA PUBLIC SERVICE COMPANY | ACC
Debt Provisions
Percentage of APS's capitalization used in calculation of short-term debt authorization	7.00%
Required amount to be used in purchases of natural gas and power which is used in calculation of short-term debt authorization	500,000,000
Long-term debt authorization before increase	4,200,000,000
Long-term debt authorization	5,100,000,000
ARIZONA PUBLIC SERVICE COMPANY | Long term debt
Lines of Credit and Short-Term Borrowings
Maximum commercial paper support available under credit facility	250,000,000	250,000,000
ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facility maturing in 2016
Lines of Credit and Short-Term Borrowings
Amount Committed	500,000,000	500,000,000
Unused Amount	347,000,000	408,000,000
Commitment Fees (as a percent)	0.125%	0.175%
ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facility maturing in 2015
Lines of Credit and Short-Term Borrowings
Amount Committed		500,000,000
Unused Amount		500,000,000
Commitment Fees (as a percent)		0.20%
ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facility maturing in 2018
Lines of Credit and Short-Term Borrowings
Amount Committed	500,000,000
Unused Amount	500,000,000
Commitment Fees (as a percent)	0.125%
ARIZONA PUBLIC SERVICE COMPANY | Commercial Paper
Lines of Credit and Short-Term Borrowings
Outstanding amount of debt	153,000,000	92,000,000
ARIZONA PUBLIC SERVICE COMPANY | Letters of credit
Lines of Credit and Short-Term Borrowings
Outstanding amount of debt	$ 0	$ 0

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligations

Asset Retirement Obligations

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.  During the fourth quarter of 2013, a new decommissioning study with updated cash flow estimates was completed for Palo Verde.

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 costs estimates and related cash flows.  In the fourth quarter of 2013, APS finalized the transaction to acquire SCE’s interest in Four Corners.  As part of that transaction, APS assumed SCE’s asset retirement obligation.  Also, APS retired Four Corners Units 1-3 on December 30, 2013.  Decommissioning activities began for Units 1-3 in January 2014.  An update was made to the timing of the Units 1-3 decommissioning cash out flows to coincide with the expected decommissioning activities.

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 2013 and 2012 (dollars in millions):

	2013			2012
Asset retirement obligations at the beginning of year	$	357		$	280
Changes attributable to:
Accretion expense	24			19
Settlements	(12		)	—
Assumed SCE’s obligation	34			—
Estimated cash flow revisions	(56		)	58
Asset retirement obligations at the end of year	$	347		$	357

Decommissioning activities for Four Corners Units 1-3 will begin in January 2014; thus, $33 million of the total asset retirement obligation of $347 million at December 31, 2013, is classified as a current liability on the balance sheet.

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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Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2013

Regulatory Matters

Schedule of changes in the deferred fuel and purchased power regulatory asset

The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2013 and 2012 (dollars in millions):

	Twelve Months Ended December 31,
	2013			2012
Beginning balance	$	73		$	28
Deferred fuel and purchased power costs - current period	(21		)	(72		)
Amounts (charged) credited to customers	(31		)	117
Ending balance	$	21		$	73

Schedule of regulatory assets

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

	Remaining Amortization		December 31, 2013				December 31, 2012
	Period		Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	(a	)	$	—	$	314	$	—	$	780
Income taxes — AFUDC equity	2043		4		105		4		92
Deferred fuel and purchased power — mark-to-market (Note 17)	2016		5		29		19		21
Transmission vegetation management	2016		9		14		9		23
Coal reclamation	2038		8		18		8		24
Palo Verde VIEs (Note 19)	2046		—		41		—		38
Deferred compensation	2036		—		34		—		34
Deferred fuel and purchased power (b) (c)	2014		21		—		73		—
Tax expense of Medicare subsidy	2023		2		15		2		17
Loss on reacquired debt	2034		1		17		2		18
Income taxes — investment tax credit basis adjustment	2043		1		39		1		26
Pension and other postretirement benefits deferral	2015		8		4		8		13
Four Corners cost deferral	2024		—		37		—		—
Lost fixed cost recovery	2014		25		—		7		—
Transmission cost adjustor	2015		8		2		10		—
Retired power plant costs	2020		3		18		—		—
Other	Various		2		25		1		14
Total regulatory assets (d)			$	97	$	712	$	144	$	1,100

(a) This asset represents the future recovery of under-funded pension and other postretirement benefit obligations 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.  See Note 8 for further discussion.

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

(c) Subject to a carrying charge.

(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.”

Schedule of regulatory liabilities

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

	Remaining Amortization		December 31, 2013				December 31, 2012
	Period		Current		Non-Current		Current		Non-Current
Removal costs	(a	)	$	28	$	303	$	27	$	321
Asset retirement obligations	(a	)	—		266		—		256
Renewable energy standard (b)	2015		33		15		43		—
Income taxes — change in rates	2043		—		74		—		66
Spent nuclear fuel	2047		6		36		10		36
Deferred gains on utility property	2019		2		10		2		12
Income taxes — deferred investment tax credit	2043		3		79		2		52
Demand side management (b)	2014		27		—		4		—
Other	Various		—		18		—		16
Total regulatory liabilities			$	99	$	801	$	88	$	759

(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.

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CONSOLIDATED STATEMENTS OF INCOME (APSC) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
OPERATING EXPENSES
Fuel and purchased power	$ 1,095,709	$ 994,790	$ 1,009,464
Operations and maintenance	924,727	884,769	904,286
Depreciation and amortization	415,708	404,336	427,054
Taxes other than income taxes	164,167	159,323	147,408
Total	2,608,305	2,450,049	2,494,871
OPERATING INCOME	846,323	851,755	746,508
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction (Note 1)	25,581	22,436	23,707
Other income (Note S-3)	1,704	1,606	3,111
Other expense (Note S-3)	(16,024)	(19,842)	(10,451)
Total	11,261	4,200	16,367
INTEREST EXPENSE
Allowance for borrowed funds used during construction (Note 1)	(14,861)	(14,971)	(18,358)
Total	187,027	199,645	223,637
NET INCOME	439,966	413,164	366,940
Less: Net income attributable to noncontrolling interests (Note 19)	33,892	31,622	27,467
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	406,074	381,542	339,473
ARIZONA PUBLIC SERVICE COMPANY
ELECTRIC OPERATING REVENUES	3,451,251	3,293,489	3,237,241
OPERATING EXPENSES
Fuel and purchased power	1,095,709	994,790	1,009,464
Operations and maintenance	897,824	873,916	895,917
Depreciation and amortization	415,612	404,242	426,958
Income taxes (Notes 4 and S-1)	256,864	256,600	204,066
Taxes other than income taxes	163,377	158,412	146,453
Total	2,829,386	2,687,960	2,682,858
OPERATING INCOME	621,865	605,529	554,383
OTHER INCOME (DEDUCTIONS)
Income taxes (Notes 4 and S-1)	11,769	12,204	11,524
Allowance for equity funds used during construction (Note 1)	25,581	22,436	23,707
Other income (Note S-3)	3,896	2,868	5,071
Other expense (Note S-3)	(20,449)	(21,150)	(15,328)
Total	20,797	16,358	24,974
INTEREST EXPENSE
Interest on long-term debt	188,011	198,398	218,981
Interest on short-term borrowings	6,605	7,135	10,345
Debt discount, premium and expense	4,046	4,215	4,616
Allowance for borrowed funds used during construction (Note 1)	(14,861)	(14,971)	(18,358)
Total	183,801	194,777	215,584
NET INCOME	458,861	427,110	363,773
Less: Net income attributable to noncontrolling interests (Note 19)	33,892	31,613	27,524
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 424,969	$ 395,497	$ 336,249

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Fair Value Measurements

12 Months Ended

Dec. 31, 2013

Fair Value Measurements

Fair Value Measurements

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.

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.

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 20 for additional discussion about our nuclear decommissioning trust.

Fair Value Tables

The following table presents the fair value at December 31, 2013 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, 2013
Assets
Risk management activities — derivative instruments:
Commodity Contracts	$	—	$	9		$	41		$	(9	) (b)	$	41
Nuclear decommissioning trust:
U.S. commingled equity funds	—		272			—			—			272
Fixed income securities:
U.S. Treasury	107		—			—			—			107
Cash and cash equivalent funds	—		11			—			(3		) (c)	8
Corporate debt	—		88			—			—			88
Mortgage-backed securities	—		85			—			—			85
Municipality bonds	—		71			—			—			71
Other	—		11			—			—			11
Subtotal nuclear decommissioning trust	107		538			—			(3		)	642
Total	$	107	$	547		$	41		$	(12	)	$	683
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(33	)	$	(90	)	$	21	(b)	$	(102	)

(a) Primarily consists of heat rate options and other long-dated electricity contracts.

(b) Represents counterparty netting, margin and collateral.  See Note 17.

(c) Represents nuclear decommissioning trust net pending securities sales and purchases.

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):

	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 17.

(c) Represents nuclear decommissioning trust net pending securities sales and purchases.

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).

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 volatilities.  If electricity prices and electricity price 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 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 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 tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2013 and December 31, 2012:

	December 31, 2013 Fair Value (millions)				Valuation	Significant		Weighted-
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range	Average
Electricity:
Forward Contracts (a)	$	40	$	66	Discounted cash flows	Electricity forward price (per MWh)	$24.89 - $65.04	$	41.09
Option Contracts (b)	—		19		Option model	Electricity forward price (per MWh)	$39.91 - $85.41	$	58.70
						Natural gas forward price (per MMbtu)	$3.57 - $3.80	$	3.71
						Electricity price volatilities	35% - 94%	59		%
						Natural gas price volatilities	22% - 36%	27		%
Natural Gas:
Forward Contracts (a)	1		5		Discounted cash flows	Natural gas forward price (per MMbtu)	$3.47 - $4.31	$	3.87
Total	$	41	$	90

(a) Includes swaps and physical and financial contracts.

(b) Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities.

	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.

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, 2013 and 2012 (dollars in millions):

	Year Ended December 31,
Commodity Contracts	2013			2012
Net derivative balance at beginning of period	$	(48	)	$	(51	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			2
Included in OCI	—			(3		)
Deferred as a regulatory asset or liability	(10		)	7
Settlements	10			(5		)
Transfers into Level 3 from Level 2	—			(2		)
Transfers from Level 3 into Level 2	(1		)	4
Net derivative balance at end of period	$	(49	)	$	(48	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—

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.  See Note 6 for our long-term debt fair values.

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Long-Term Debt and Liquidity Matters (Details 3) (ARIZONA PUBLIC SERVICE COMPANY, Subsequent event, USD $) In Millions, unless otherwise specified	0 Months Ended
	Jan. 10, 2014 item
SCE | Four Corners Units 4 and 5
Long-Term Debt and Liquidity Matters
Ownership interest acquired	48.00%
Number of tax-exempt indebtedness series re-acquired	2
4.70% unsecured senior notes that mature on January 15, 2044
Long-Term Debt and Liquidity Matters
Interest rate (as a percent)	4.70%
Notes issued	$ 250

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Changes in Accumulated Other Comprehensive Loss (APSC)

12 Months Ended

Dec. 31, 2013

Changes in Accumulated Other Comprehensive Loss

21. Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands):

	Year Ended December 31, 2013
	Derivative  Instruments			Pension and  Other  Postretirement  Benefits			Total
Beginning balance	$	(49,592	)	$	(64,416	)	$	(114,008	)
OCI (loss) before reclassifications	(213		)	5,594			5,381
Amounts reclassified from accumulated other comprehensive loss	26,747		(a)	3,827		(b)	30,574
Net current period OCI	26,534			9,421			35,955
Ending balance	$	(23,058	)	$	(54,995	)	$	(78,053	)

(a) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 17.

(b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 8.

ARIZONA PUBLIC SERVICE COMPANY

Changes in Accumulated Other Comprehensive Loss

S-4. Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands):

	Year Ended December 31, 2013
	Derivative  Instruments			Pension and  Other  Postretirement  Benefits			Total
Beginning balance	$	(49,592	)	$	(39,503	)	$	(89,095	)
OCI (loss) before reclassifications	(214		)	5,387			5,173
Amounts reclassified from accumulated other comprehensive loss	26,747		(a)	3,803		(b)	30,550
Net current period OCI	26,533			9,190			35,723
Ending balance	$	(23,059	)	$	(30,313	)	$	(53,372	)

(a) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 17.

(b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 8.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 10)
Accumulated depreciation of Palo Verde sale leaseback	$ 225,925	$ 222,055
Accumulated amortization on intangible assets	439,703	411,543
Accumulated amortization on nuclear fuel	$ 146,057	$ 133,950
EQUITY (Note 7)
Common stock, par value
Common stock, authorized shares	150,000,000	150,000,000
Common stock, issued shares	110,280,703	109,837,957
Treasury stock at cost, shares	98,944	95,192

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CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
CONSOLIDATED STATEMENTS OF INCOME
Income tax expense (benefit) on discontinued operations	$ (3,813)	$ 7,418

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Common Stock and Treasury Stock

12 Months Ended

Dec. 31, 2013

Common Stock and Treasury Stock

Common Stock and Treasury Stock

7. Common Stock and Treasury Stock

Our common stock and treasury stock activity during each of the three years 2013, 2012 and 2011 is as follows (dollars in thousands):

	Common Stock			Treasury Stock
	Shares	Amount		Shares		Amount
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 (a)	—	—		(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 (a)	—	—		(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		)
Common stock issuance	442,746	24,635		—		—
Purchase of treasury stock (a)	—	—		(174,290	)	(9,727		)
Reissuance of treasury stock for stock compensation	—	—		170,538		9,630
Balance at December 31, 2013	110,280,703	$	2,491,558	(98,944	)	$	(4,308	)

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

At December 31, 2013, 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.

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CONSOLIDATED STATEMENTS OF CASH FLOWS (APSC) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 439,966	$ 413,164	$ 366,940
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	492,322	481,262	493,784
Deferred fuel and purchased power	21,678	71,573	69,166
Deferred fuel and purchased power amortization	31,190	(116,716)	(155,157)
Allowance for equity funds used during construction	(25,581)	(22,436)	(23,707)
Deferred income taxes	249,296	187,023	117,952
Deferred investment tax credit	52,542	41,579	58,240
Change in derivative instruments fair value	534	(749)	4,064
Changes in current assets and liabilities:
Customer and other receivables	(44,991)	14,587	40,626
Accrued unbilled revenues	(1,951)	30,394	(21,947)
Materials, supplies and fossil fuel	(11,878)	(23,043)	(23,398)
Income tax receivable	(133,094)	(4,043)	3,983
Other current assets	(17,913)	(27,352)	(3,079)
Accounts payable	45,414	(96,600)	58,346
Accrued taxes	6,059	12,736	8,085
Other current liabilities	(7,513)	23,869	20,358
Change in margin and collateral accounts - assets	993	2,216	33,349
Change in margin and collateral accounts - liabilities	12,355	137,785	29,731
Change in long-term regulatory liabilities	64,473	13,539	37,009
Change in long-term income tax receivable	137,270	(1,756)	(3,530)
Change in unrecognized tax benefits	(91,425)	(2,583)	8,410
Change in other long-term assets	(41,757)	6,872	(41,722)
Change in other long-term liabilities	(24,682)	29,801	58,484
Net cash flow provided by operating activities	1,153,307	1,171,122	1,125,583
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,016,322)	(889,551)	(884,350)
Contributions in aid of construction	41,090	49,876	38,096
Allowance for borrowed funds used during construction	(14,861)	(14,971)	(18,358)
Proceeds from nuclear decommissioning trust sales	446,025	417,603	497,780
Investment in nuclear decommissioning trust	(463,274)	(434,852)	(513,799)
Proceeds from sale of life insurance policies			55,444
Other	(2,059)	(1,099)	(1,931)
Net cash flow used for investing activities	(1,009,401)	(872,994)	(782,007)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	136,307	476,081	470,353
Repayment of long-term debt	(122,828)	(654,286)	(655,169)
Short-term borrowings and payments - net	60,950	92,175	(16,600)
Dividends paid on common stock	(235,244)	(225,075)	(221,728)
Noncontrolling interests	(17,385)	(10,529)	(10,210)
Net cash flow used for financing activities	(160,582)	(305,509)	(420,181)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(16,676)	(7,381)	(76,605)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	26,202	33,583	110,188
CASH AND CASH EQUIVALENTS AT END OF YEAR	9,526	26,202	33,583
Cash paid during the year for:
Income taxes, net of refunds	18,537	2,543	10,324
Interest, net of amounts capitalized	184,010	200,923	217,789
Significant non-cash investing and financing activities:
Accrued capital expenditures	33,184	26,208	27,245
Dividends declared but not paid	62,528	59,789
Liabilities assumed related to acquisition of SCE's Four Corners' interest	145,609
ARIZONA PUBLIC SERVICE COMPANY
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	458,861	427,110	363,773
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	492,226	481,168	493,653
Deferred fuel and purchased power	21,678	71,573	69,166
Deferred fuel and purchased power amortization	31,190	(116,716)	(155,157)
Allowance for equity funds used during construction	(25,581)	(22,436)	(23,707)
Deferred income taxes	278,101	202,159	110,565
Deferred investment tax credit	52,542	41,579	58,240
Change in derivative instruments fair value	534	(749)	4,064
Changes in current assets and liabilities:
Customer and other receivables	(46,552)	12,914	34,913
Accrued unbilled revenues	(1,951)	30,394	(21,947)
Materials, supplies and fossil fuel	(11,878)	(23,043)	(23,398)
Income tax receivable	(134,590)	(2,280)	2,869
Other current assets	(17,112)	(27,745)	(5,473)
Accounts payable	47,870	(97,395)	73,369
Accrued taxes	5,760	7,330	2,234
Other current liabilities	(9,005)	6,070	18,762
Change in margin and collateral accounts - assets	993	2,216	33,349
Change in margin and collateral accounts - liabilities	12,355	137,785	29,731
Change in long-term regulatory liabilities	64,473	13,539	37,009
Change in long-term income tax receivable	137,665	(1,756)	(3,530)
Change in unrecognized tax benefits	(91,244)	(2,583)	9,125
Change in other long-term assets	(46,043)	1,391	(41,788)
Change in other long-term liabilities	(25,601)	34,854	61,990
Net cash flow provided by operating activities	1,194,691	1,175,379	1,127,812
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,016,322)	(889,551)	(878,546)
Contributions in aid of construction	41,090	49,876	38,096
Allowance for borrowed funds used during construction	(14,861)	(14,971)	(18,358)
Proceeds from nuclear decommissioning trust sales	446,025	417,603	497,780
Investment in nuclear decommissioning trust	(463,274)	(434,852)	(513,799)
Proceeds from sale of life insurance policies			44,183
Other	(2,067)	(1,099)	(3,306)
Net cash flow used for investing activities	(1,009,409)	(872,994)	(833,950)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	136,307	351,081	295,353
Repayment of long-term debt	(122,828)	(529,286)	(430,169)
Short-term borrowings and payments - net	60,950	92,175
Dividends paid on common stock	(242,100)	(222,200)	(228,900)
Noncontrolling interests	(17,385)	(10,529)	(10,210)
Net cash flow used for financing activities	(185,056)	(318,759)	(373,926)
NET DECREASE IN CASH AND CASH EQUIVALENTS	226	(16,374)	(80,064)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	3,499	19,873	99,937
CASH AND CASH EQUIVALENTS AT END OF YEAR	3,725	3,499	19,873
Cash paid during the year for:
Income taxes, net of refunds	7,524	1,196	25,975
Interest, net of amounts capitalized	180,757	196,038	210,995
Significant non-cash investing and financing activities:
Accrued capital expenditures	33,184	26,208	27,245
Dividends declared but not paid	62,500	59,800
Liabilities assumed related to acquisition of SCE's Four Corners' interest	$ 145,609

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Changes in Accumulated Other Comprehensive Loss (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	$ (114,008)
OCI (loss) before reclassifications	5,381
Amounts reclassified from accumulated other comprehensive loss	30,574
Other comprehensive income (loss) attributable to common shareholders	35,955	38,155	7,605
Ending balance	(78,053)	(114,008)
Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(49,592)
OCI (loss) before reclassifications	(213)
Amounts reclassified from accumulated other comprehensive loss	26,747
Other comprehensive income (loss) attributable to common shareholders	26,534
Ending balance	(23,058)
Pension and other postretirement benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(64,416)
OCI (loss) before reclassifications	5,594
Amounts reclassified from accumulated other comprehensive loss	3,827
Other comprehensive income (loss) attributable to common shareholders	9,421
Ending balance	$ (54,995)

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Palo Verde Sale Leaseback Variable Interest Entities (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 item	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2008 item	Dec. 31, 1986 item
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	$ 33,892,000	$ 31,622,000	$ 27,467,000
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	125,125,000	128,995,000
Current maturities of long-term debt	540,424,000	122,828,000
Long-term debt excluding current maturities	13,420,000	38,869,000
Equity-Noncontrolling interests	145,990,000	129,483,000
ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Sale Leaseback Variable Interest Entities
Number of VIE lessor trusts	3			3	3
Annual lease payments	49,000,000
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	33,892,000	31,613,000	27,524,000
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	125,125,000	128,995,000
Current maturities of long-term debt	540,424,000	122,828,000
Long-term debt excluding current maturities	13,420,000	38,869,000
Equity-Noncontrolling interests	145,990,000	129,483,000
ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payment if lease is extended	23,000,000
Number of options	2
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts	34,000,000	32,000,000	28,000,000
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	125,000,000	129,000,000
Current maturities of long-term debt	26,000,000	27,000,000
Long-term debt excluding current maturities	13,000,000	39,000,000
Equity-Noncontrolling interests	146,000,000	129,000,000
Maximum payment to the VIEs' noncontrolling equity participants upon the occurrence of certain unlikely events	133,000,000
VIE debt to be assumed upon the occurrence of certain unlikely events	$ 39,000,000

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Changes in Accumulated Other Comprehensive Loss (APSC) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	$ (114,008)
OCI (loss) before reclassifications	5,381
Amounts reclassified from accumulated other comprehensive loss	30,574
Other comprehensive income (loss) attributable to common shareholders	35,955	38,155	7,605
Ending balance	(78,053)	(114,008)
Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(49,592)
OCI (loss) before reclassifications	(213)
Amounts reclassified from accumulated other comprehensive loss	26,747
Other comprehensive income (loss) attributable to common shareholders	26,534
Ending balance	(23,058)
Pension and other postretirement benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(64,416)
OCI (loss) before reclassifications	5,594
Amounts reclassified from accumulated other comprehensive loss	3,827
Other comprehensive income (loss) attributable to common shareholders	9,421
Ending balance	(54,995)
ARIZONA PUBLIC SERVICE COMPANY
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(89,095)
OCI (loss) before reclassifications	5,173
Amounts reclassified from accumulated other comprehensive loss	30,550
Other comprehensive income (loss) attributable to common shareholders	35,723	36,496	10,704
Ending balance	(53,372)	(89,095)
ARIZONA PUBLIC SERVICE COMPANY | Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(49,592)
OCI (loss) before reclassifications	(214)
Amounts reclassified from accumulated other comprehensive loss	26,747
Other comprehensive income (loss) attributable to common shareholders	26,533
Ending balance	(23,059)
ARIZONA PUBLIC SERVICE COMPANY | Pension and other postretirement benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(39,503)
OCI (loss) before reclassifications	5,387
Amounts reclassified from accumulated other comprehensive loss	3,803
Other comprehensive income (loss) attributable to common shareholders	9,190
Ending balance	$ (30,313)

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 14, 2014	Jun. 30, 2013
Document and Entity Information
Entity Registrant Name	PINNACLE WEST CAPITAL CORP
Entity Central Index Key	0000764622
Document Type	10-K
Document Period End Date	Dec. 31, 2013
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 6,078,967,225
Entity Common Stock, Shares Outstanding		110,194,366
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY

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Retirement Plans and Other Benefits

12 Months Ended

Dec. 31, 2013

Retirement Plans and Other Benefits

Retirement Plans and Other Benefits

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 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 an other 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 further 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 $8 million during 2013 and $4 million during 2012.

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):

	Pension									Other Benefits
	2013			2012			2011			2013			2012			2011
Service cost-benefits earned during the period	$	64,195		$	63,502		$	57,605		$	23,597		$	27,163		$	21,856
Interest cost on benefit obligation	112,392			119,586			124,727			41,536			46,467			46,807
Expected return on plan assets	(146,333		)	(140,979		)	(133,678		)	(45,717		)	(45,793		)	(41,536		)
Amortization of:
Transition obligation	—			—			—			—			452			452
Prior service cost (credit)	1,097			1,143			1,400			(179		)	(179		)	(179		)
Net actuarial loss	39,852			44,250			25,956			11,310			20,233			15,015
Net periodic benefit cost	$	71,203		$	87,502		$	76,010		$	30,547		$	48,343		$	42,415
Portion of cost charged to expense	$	38,968		$	36,333		$	29,312		$	18,469		$	19,321		$	15,208

The following table shows the plans’ changes in the benefit obligations and funded status for the years 2013 and 2012 (dollars in thousands):

	Pension						Other Benefits
	2013			2012			2013			2012
Change in Benefit Obligation
Benefit obligation at January 1	$	2,850,846		$	2,699,126		$	990,418		$	1,047,094
Service cost	64,195			63,502			23,597			27,163
Interest cost	112,392			119,586			41,536			46,467
Benefit payments	(125,269		)	(113,632		)	(26,675		)	(26,279		)
Actuarial (gain) loss	(255,634		)	82,264			(138,458		)	(104,027		)
Benefit obligation at December 31	2,646,530			2,850,846			890,418			990,418
Change in Plan Assets
Fair value of plan assets at January 1	2,079,181			1,850,550			684,221			608,663
Actual return on plan assets	150,546			259,363			76,995			83,567
Employer contributions	140,500			65,000			14,438			22,707
Benefit payments	(106,106		)	(95,732		)	(27,315		)	(30,716		)
Fair value of plan assets at December 31	2,264,121			2,079,181			748,339			684,221
Funded Status at December 31	$	(382,409	)	$	(771,665	)	$	(142,079	)	$	(306,197	)

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, 2013 and 2012 (dollars in thousands):

	2013		2012
Projected benefit obligation	$	2,646,530	$	2,850,846
Accumulated benefit obligation	2,469,889		2,646,306
Fair value of plan assets	2,264,121		2,079,181

The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2013 and 2012 (dollars in thousands):

	Pension						Other Benefits
	2013			2012			2013			2012
Current liability	$	(10,860	)	$	(19,107	)	$	—		$	—
Noncurrent liability	(371,549		)	(752,558		)	(142,079		)	(306,197		)
Net amount recognized	$	(382,409	)	$	(771,665	)	$	(142,079	)	$	(306,197	)

The following table shows the details related to accumulated other comprehensive loss as of December 31, 2013 and 2012 (dollars in thousands):

	Pension						Other Benefits
	2013			2012			2013			2012
Net actuarial loss	$	344,540		$	644,239		$	57,816		$	238,862
Prior service cost (credit)	2,072			3,169			(296		)	(475		)
APS’s portion recorded as a regulatory asset	(265,107		)	(550,471		)	(49,298		)	(230,020		)
Income tax benefit	(32,204		)	(38,303		)	(2,528		)	(2,585		)
Accumulated other comprehensive loss	$	49,301		$	58,634		$	5,694		$	5,782

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 2014 (dollars in thousands):

	Pension		Other Benefits
Net actuarial loss	$	8,363	$	—
Prior service cost (credit)	874		(179		)
Total amounts estimated to be amortized from accumulated other comprehensive loss and regulatory assets in 2014	$	9,237	$	(179	)

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:

	Benefit Obligations As of December 31,				Benefit Costs For the Years Ended December 31,
	2013		2012		2013		2012		2011
Discount rate – pension	4.88	%	4.01	%	4.01	%	4.42	%	5.31	%
Discount rate – other benefits	5.10	%	4.20	%	4.20	%	4.59	%	5.49	%
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		7.00	%	7.75	%	7.75	%
Initial healthcare cost trend rate	7.50	%	7.50	%	7.50	%	7.50	%	8.00	%
Ultimate healthcare 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 2014, we are assuming a 6.9% long-term rate of return for pension assets and 7.1% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

The assumed healthcare cost trend rates shown above have a significant effect on the amounts reported for the healthcare plans.  In selecting our healthcare trend rates, we consider past performance and forecasts of healthcare costs.  A one percentage point change in the assumed initial and ultimate healthcare 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	$	13	$	(10	)
Effect on service and interest cost components of net periodic other postretirement benefit costs	14		(11		)
Effect on the accumulated other postretirement benefit obligation	149		(120		)

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 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 include investments in real estate, 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 2013, the long-term fixed income assets had a target allocation of 58% with a permissible range of 55% to 61% and the return-generating assets had a target allocation of 42% with a permissible range of 45% to 39%.  The return-generating assets have additional target allocations, as a percent of total plan assets, of 22% 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, 2013, long-term fixed income assets represented 55% of total pension plan assets, and return-generating assets represented 45% 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 generally 25% of fixed income assets and 75% of non-fixed income assets.  This asset allocation target mix does not vary with the plan’s funded status.  As of December 31, 2013, investment in fixed income assets represented 38% of the other postretirement benefit plan total assets, and non-fixed income assets represented 62% 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 fixed income securities, 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.

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).  Common and collective 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, 2013, 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, 2013, 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)		Significant Unobservable Inputs (Level 3)			Other (c)		Balance at December 31, 2013
Pension Plan:
Assets:
Cash and cash equivalents	$	504	$	—	$	—		$	—	$	504
Fixed Income Securities:
Corporate	—		898,621		—			—		898,621
U.S. Treasury	231,590		—		—			—		231,590
Other (b)	—		84,011		—			—		84,011
Equities:
U.S. Companies	239,036		—		—			—		239,036
International Companies	19,429		—		—			—		19,429
Common and collective trusts:
U.S. Equities	—		116,150		—			—		116,150
International Equities	—		367,551		—			—		367,551
Fixed Income			137,520							137,520
Real estate	—		119,739		—			—		119,739
Short-term investments and other	—		41,060		8,660		(a)	250		49,970
Total Pension Plan	$	490,559	$	1,764,652	$	8,660		$	250	$	2,264,121
Other Benefits:
Assets:
Fixed Income Securities:
Corporate	$	—	$	153,888	$	—		$	—	$	153,888
U.S. Treasury	98,704		—		—			—		98,704
Other (b)	—		27,936		—			—		27,936
Equities:
U.S. Companies	252,181		—		—			—		252,181
International Companies	20,892		—		—			—		20,892
Common and collective trusts:
U.S. Equities	—		80,751		—			—		80,751
International Equities	—		92,382		—			—		92,382
Real Estate	—		10,761		—			—		10,761
Short-term investments and other	—		8,414		—			2,430		10,844
Total Other Benefits	$	371,777	$	374,132	$	—		$	2,430	$	748,339

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

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

(c)           Represents plan receivables and payables.

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):

	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.

(c)           Represents plan receivables and payables.

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, 2013 and 2012 (dollars in thousands):

	Pension
Short-Term Investments and Other	2013			2012
Beginning balance at January 1	$	2,419		$	—
Actual return on assets still held at December 31	(498		)	(668		)
Purchases, sales, and settlements	6,739			3,087
Transfers in and/or out of Level 3	—			—
Ending balance at December 31	$	8,660		$	2,419

Contributions

Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  We made contributions to our pension plan totaling $141 million in 2013, $65 million in 2012, and zero in 2011.  The minimum contributions for the pension plan total $141 million for the next three years under the recently enacted Moving Ahead for Progress in the 21st Century Act (zero in 2014, $19 million in 2015, and $122 million in 2016).  Instead, we expect to make voluntary contributions totaling $300 million for the next three years ($175 million in 2014, of which $70 million was already contributed in early 2014, up to $100 million in 2015, and up to $25 million in 2016).  With regard to contributions to our other postretirement benefit plans, we made a contribution of approximately $14 million in 2013, $23 million in 2012, and $19 million in 2011.  The contributions to our other postretirement benefit plans for 2014, 2015 and 2016 are expected to be approximately $10 million each year.  APS funds its share of the contributions.  APS’s share of the pension plan contribution was $140 million in 2013, $64 million in 2012, and zero in 2011.  APS’s share of the contributions to the other postretirement benefit plan was $14 million in 2013, $22 million in 2012, and $19 million in 2011.

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
2014	$	129,159	$	28,664
2015	143,452		31,804
2016	149,105		34,933
2017	162,678		37,966
2018	169,064		40,972
Years 2019-2023	972,826		245,366

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

Employee Savings Plan Benefits

Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries.  In 2013, 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 $9 million for 2013, $8 million for 2012, and $8 million for 2011.

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Selected Quarterly Financial Data (Unaudited) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Consolidated quarterly financial information
Operating revenues	$ 699,762	$ 1,152,392	$ 915,822	$ 686,652	$ 693,122	$ 1,109,475	$ 878,576	$ 620,631	$ 3,454,628	$ 3,301,804	$ 3,241,379
Operations and maintenance	238,854	233,323	229,300	223,250	237,141	220,729	216,236	210,663	924,727	884,769	904,286
Operating income	83,900	415,688	259,812	86,923	101,289	447,970	254,489	48,007	846,323	851,755	746,508
Income Taxes	9,167	131,912	77,043	12,469	18,157	147,116	76,689	(4,645)	230,591	237,317	183,604
Income from continuing operations	32,814	234,718	139,598	32,836	34,905	252,874	130,930	284	439,966	418,993	355,634
Net income attributable to common shareholders	$ 24,260	$ 226,163	$ 131,207	$ 24,444	$ 22,631	$ 244,823	$ 122,345	$ (8,257)	$ 406,074	$ 381,542	$ 339,473
Earnings Per Share:
Income from continuing operations attributable to common shareholders - Basic (in dollars per share)	$ 0.22	$ 2.06	$ 1.19	$ 0.22	$ 0.24	$ 2.23	$ 1.12	$ (0.07)	$ 3.69	$ 3.54	$ 3.01
Net income attributable to common shareholders - Basic (in dollars per share)	$ 0.22	$ 2.06	$ 1.19	$ 0.22	$ 0.21	$ 2.23	$ 1.12	$ (0.08)	$ 3.69	$ 3.48	$ 3.11
Income from continuing operations attributable to common shareholders - Diluted (in dollars per share)	$ 0.22	$ 2.04	$ 1.18	$ 0.22	$ 0.24	$ 2.21	$ 1.12	$ (0.07)	$ 3.66	$ 3.50	$ 2.99
Net income attributable to common shareholders - Diluted (in dollars per share)	$ 0.22	$ 2.04	$ 1.18	$ 0.22	$ 0.20	$ 2.21	$ 1.11	$ (0.08)	$ 3.66	$ 3.45	$ 3.09

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Other Income and Other Expense (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other income:
Interest income	$ 1,629	$ 1,239	$ 1,850
Investment gains - net			1,165
Miscellaneous	75	367	96
Total other income	1,704	1,606	3,111
Other expense:
Non-operating costs	(8,207)	(7,777)	(7,037)
Investment loss - net	(3,711)	(2,453)
Miscellaneous	(4,106)	(9,612)	(3,414)
Total other expense	$ (16,024)	$ (19,842)	$ (10,451)

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$ 439,966	$ 413,164	$ 366,940
Derivative instruments:
Net unrealized loss, net of tax benefit of $140, $14,900, and $37,389 (Note 17)	(213)	(22,763)	(57,271)
Reclassification of net realized loss, net of tax benefit of $17,472, $39,120, and $46,288 (Note 17)	26,747	59,887	70,902
Pension and other postretirement benefits activity, net of tax (expense) benefit of $(6,156), $(651), and $3,935 (Note 8)	9,421	1,031	(6,026)
Total other comprehensive income	35,955	38,155	7,605
COMPREHENSIVE INCOME	475,921	451,319	374,545
Less: Comprehensive income attributable to noncontrolling interests	33,892	31,622	27,467
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 442,029	$ 419,697	$ 347,078

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New Accounting Standards

12 Months Ended

Dec. 31, 2013

New Accounting Standards

New Accounting Standards

2. New Accounting Standards

During 2013, we adopted, on a retrospective basis, new guidance relating to balance sheet offsetting disclosures.  The new guidance requires enhanced disclosures regarding an entity’s ability to offset certain instruments on the balance sheet and how offsetting impacts the balance sheet.  The adoption of this guidance resulted in expanded disclosures relating to our derivative instruments (see Note 17), but did not impact our financial statement results.

During 2013, we also adopted, on a prospective basis, new guidance relating to reporting amounts reclassified from accumulated other comprehensive income.  This guidance requires new disclosures relating to accumulated other comprehensive income and how reclassifications from accumulated other comprehensive income impact net income.  As a result of adopting this new guidance, we have included a new footnote disclosure to provide the information required by the new standard (see Notes 21 and S-4).  The adoption of this guidance did not impact our financial statement results.

In July 2013, new guidance was issued which will generally require entities to present unrecognized tax benefits as a reduction to any available deferred tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward.  The intent of this guidance is to eliminate diversity in practice in the presentation of certain unrecognized tax benefits.  The new guidance is effective for us during the first quarter of 2014, and is permitted to be adopted using either a prospective or retrospective application.  Currently, we do not present unrecognized tax benefits as a reduction to deferred tax asset carryforwards on the balance sheet.  As a result, the adoption of this new guidance will impact our balance sheet presentation; however, we do not expect these presentation changes to be material to our balance sheet.  The adoption of this new guidance will not impact our results of operations or cash flows.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

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 and essentially all of these assets were sold in 2009 and 2010.  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 reported as discontinued operations.  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 reported as discontinued operations.  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 19).

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.

Certain line items are presented in more detail on the Consolidated Balance Sheets and Consolidated Statements of Cash Flows than was presented in the prior years.  Other line items are more condensed than the previous presentation.  The prior year amounts were reclassified to conform to the current year presentation.  These reclassifications had no impact on total assets or net cash flow provided by operating activities.  The following tables show the impacts of the reclassifications of prior years (previously reported) amounts (dollars in thousands):

Balance Sheets - December 31, 2012	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Long-Term Debt less Current Maturities —
Long-term debt less current maturities	$	3,160,219	$	38,869		$	3,199,088
Long-Term Debt less Current Maturities —
Palo Verde sale leaseback lessor notes less
current maturities	38,869		(38,869		)	—

Statement of Cash Flows for the Year Ended December 31, 2012	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
Deferred income taxes	$	228,602	$	(41,579	)	$	187,023
Deferred investment tax credit	—		41,579			41,579
Accrued taxes and income tax receivable	8,693		(8,693		)	—
Income tax receivable	—		(4,043		)	(4,043		)
Accrued taxes	—		12,736			12,736

Statement of Cash Flows for the Year Ended December 31, 2011	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
Deferred income taxes	$	176,192	$	(58,240	)	$	117,952
Deferred investment tax credit	—		58,240			58,240
Accrued taxes and income tax receivable	12,068		(12,068		)	—
Income tax receivable	—		3,983			3,983
Accrued taxes	—		8,085			8,085

Accounting Records and Use of Estimates

Our accounting records are maintained in accordance with 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.

Regulatory Accounting

APS is regulated by the ACC and 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 Arizona 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 by customer class 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 Settlement Agreement (see Note 3).  Effective July 1, 2012, as a result of the 2012 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.

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.

Property, Plant and Equipment

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 calculated 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, 2013 were as follows:

· Fossil plant — 18 years;

· Nuclear plant — 26 years;

· Other generation — 26 years;

· Transmission — 37 years;

· Distribution — 34 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 use of the new Palo Verde nuclear plant lives, effective January 1, 2012.

Pursuant to an ACC order, we defer operating costs related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  See Note 3 for further discussion.  These costs are deferred on the depreciation line of the Consolidated Statements of Income.

For the years 2011 through 2013, the depreciation rates ranged from a low of 0.45% to a high of 12.08%.  The weighted-average rate was 3.00% for 2013, 2.71% for 2012, and 2.98% for 2011.

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 8.56% for 2013, 8.60% for 2012, and 10.25% for 2011.  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.

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 17 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 an other postretirement benefit plan for the employees of Pinnacle West and our subsidiaries that provides 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 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,
	2013		2012		2011
Cash paid during the period for:
Income taxes, net of refunds	$	18,537	$	2,543	$	10,324
Interest, net of amounts capitalized	184,010		200,923		217,789
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	33,184	$	26,208	$	27,245
Dividends declared but not paid	62,528		59,789		—
Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 3)	145,609		—		—

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 $53 million in 2013, $50 million in 2012, and $47 million in 2011.  Estimated amortization expense on existing intangible assets over the next five years is $47 million in 2014, $38 million in 2015, $29 million in 2016, $19 million in 2017, and $7 million in 2018.  At December 31, 2013, 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 20 for more information on these investments.

Business Segments

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. All other segment activities are insignificant.

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Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2013

Selected Quarterly Financial Data (Unaudited)

Selected Quarterly Financial Data (Unaudited)

13. Selected Quarterly Financial Data (Unaudited)

Consolidated quarterly financial information for 2013 and 2012 is provided in the tables below (dollars in thousands, except per share amounts).  Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.

	2013 Quarter Ended								2013
	March 31,		June 30,		Sept. 30,		Dec. 31,		Total
Operating revenues	$	686,652	$	915,822	$	1,152,392	$	699,762	$	3,454,628
Operations and maintenance	223,250		229,300		233,323		238,854		924,727
Operating income	86,923		259,812		415,688		83,900		846,323
Income taxes	12,469		77,043		131,912		9,167		230,591
Income from continuing operations	32,836		139,598		234,718		32,814		439,966
Net income attributable to common shareholders	24,444		131,207		226,163		24,260		406,074
Earnings Per Share:
Income from continuing operations attributable to common shareholders — Basic	$	0.22	$	1.19	$	2.06	$	0.22	$	3.69
Net income attributable to common shareholders — Basic	0.22		1.19		2.06		0.22		3.69
Income from continuing operations attributable to common shareholders — Diluted	0.22		1.18		2.04		0.22		3.66
Net income attributable to common shareholders — Diluted	0.22		1.18		2.04		0.22		3.66

	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

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Leases

12 Months Ended

Dec. 31, 2013

Leases

Leases

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 $18 million in 2013, $19 million in 2012, and $21 million in 2011.  APS’s lease expense was $15 million in 2013, $16 million in 2012, and $18 million in 2011.

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
2014	$	20	$	17
2015	17		14
2016	6		5
2017	5		5
2018	4		4
Thereafter	59		59
Total future lease commitments	$	111	$	104

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 VIEs 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 19 for a discussion of VIEs.

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Stock-Based Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified		12 Months Ended																													1 Months Ended
	May 16, 2012 2012 grant	Dec. 31, 2013 Restricted stock unit awards	Dec. 31, 2013 Restricted stock units and stock grants	Dec. 31, 2012 Restricted stock units and stock grants	Dec. 31, 2011 Restricted stock units and stock grants	Dec. 31, 2011 Restricted stock units and stock grants 2007 grant	Dec. 31, 2012 Restricted stock units and stock grants 2008 grant	Dec. 31, 2011 Restricted stock units and stock grants 2008 grant	Dec. 31, 2013 Restricted stock units and stock grants 2009 grant	Dec. 31, 2012 Restricted stock units and stock grants 2009 grant	Dec. 31, 2011 Restricted stock units and stock grants 2009 grant	Dec. 31, 2013 Restricted stock units and stock grants 2010 grant	Dec. 31, 2012 Restricted stock units and stock grants 2010 grant	Dec. 31, 2011 Restricted stock units and stock grants 2010 grant	Dec. 31, 2013 Restricted stock units and stock grants 2011 grant	Dec. 31, 2012 Restricted stock units and stock grants 2011 grant	Dec. 31, 2013 Restricted stock units and stock grants 2012 grant	Dec. 31, 2013 Performance Share Awards	Dec. 31, 2012 Performance Share Awards	Dec. 31, 2011 Performance Share Awards	Dec. 31, 2013 Performance Share Awards 2007 grant item	Dec. 31, 2013 Performance Share Awards 2011 grant item	Dec. 31, 2013 Performance Share Awards 2011 grant Maximum	Dec. 31, 2013 Performance Share Awards 2011 grant Minimum	Dec. 31, 2013 Performance Share Awards 2012 grant item	Dec. 31, 2013 Performance Share Awards 2012 grant Maximum	Dec. 31, 2013 Performance Share Awards 2012 grant Minimum	Dec. 31, 2013 Performance Share Awards 2013 grant item	Dec. 31, 2013 Performance Share Awards 2013 grant Maximum	Dec. 31, 2013 Performance Share Awards 2013 grant Minimum	Dec. 31, 2012 Retention Units
Stock-Based Compensation
Common shares to be available for grant under the 2012 Long Term Incentive Plan	4,595,500
Percentage of cash that the participant may elect as a deferral under the first option available under the plan		50.00%
Percentage of fully transferable shares of stock that the participant may elect as a deferral for the first option available under the plan		50.00%
The number of shares used to determine the cash award payable to an employee for each unit earned		1
Percentage of cash that the participant may elect as a dividend equivalent deferral under the first option available under the plan		50.00%
Percentage of fully transferable shares of stock that the participant may elect as a dividend equivalent deferral for the first option available under the plan		50.00%
Vesting period		4 years
Additional shares to be granted as retention award if performance requirements are met																															33,745
Percentage of awards vesting on February 15, 2013		50.00%
Percentage of awards vesting on February 15, 2014		25.00%
Percentage of awards vesting on February 15, 2015		25.00%
Stocks granted and the weighted average fair value
Units granted (in shares)			129,620	202,278	292,242													176,332	185,878	175,072
Grant date fair value (in dollars per share)			$ 55.21	$ 49.31	$ 41.98													$ 55.45	$ 47.40	$ 41.71
Nonvested shares
Balance at the beginning of the period (in shares)			480,753															347,690
Granted (in shares)			129,620															176,332													50,617
Increase in performance factor (in shares)																		40,183
Vested (in shares)			191,988															200,915
Forfeited (in shares)			20,409															18,894
Balance at the end of the period (in shares)			397,976	480,753														344,396	347,690
Weighted-Average Grant-Date Fair Value
Balance at the beginning of the period (in dollars per share)			$ 43.58															$ 44.67
Granted (in dollars per share)			$ 55.21	$ 49.31	$ 41.98													$ 55.45	$ 47.40	$ 41.71
Increase in performance factor (in dollars per share)																		$ 41.71
Vested (in dollars per share)			$ 40.33															$ 41.71
Forfeited (in dollars per share)			$ 45.70															$ 48.11
Balance at the end of the period (in dollars per share)			$ 47.74	$ 43.58														$ 51.13	$ 44.67
Cash required to settle the payment for grant						$ 1.0	$ 1.9	$ 1.6	$ 3.0	$ 1.7	$ 1.5	$ 2.3	$ 0.6	$ 0.6	$ 2.5	$ 0.7	$ 2.2
Additional disclosures
Percentage of the awards that vest based on a percentile ranking of total shareholder return																						50.00%			50.00%			50.00%
Percentage of the awards that vest based on non-financial separate performance metrics																						50.00%			50.00%			50.00%
Number of performance element criteria																					2
Number of non-financial separate performance metrics based on which awards vest																						6			6			6
Performance period																					3 years	3 years			3 years			3 years
Exact number of shares issued as a percentage of the target award																							200.00%	0.00%		200.00%	0.00%		200.00%	0.00%
Percentage of fully transferable shares of stock that the participant may elect as a deferral for the second option available under the plan		50.00%
Percentage of fully transferable shares of stock that the participant may elect as a dividend equivalent deferral for the second option available under the plan		50.00%

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Lines of Credit and Short-Term Borrowings

12 Months Ended

Dec. 31, 2013

Lines of Credit and Short-Term Borrowings

Lines of Credit and Short-Term Borrowings

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, 2013 (dollars in millions):

Credit Facility	Expiration	Amount Committed		Unused Amount (a)		Commitment Fees
Pinnacle West Revolving Credit Facility	November 2016	$	200	$	200	0.175	%
APS Revolving Credit Facility	November 2016	500		347		0.125	%
APS Revolving Credit Facility	April 2018	500		500		0.125	%
Total		$	1,200	$	1,047

(a) At December 31, 2013, APS had $153 million of outstanding commercial paper.  Accordingly, at such date, the total combined amount available under its two $500 million credit facilities was $847 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, 2013, 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, 2013, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit and no commercial paper borrowings.

APS

On April 9, 2013, APS refinanced its $500 million revolving credit facility that would have matured in February 2015, with a new $500 million facility.  The new revolving credit facility matures in April 2018.

At December 31, 2013, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that was refinanced in April 2013 (see above) and a $500 million credit 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 can use these facilities to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

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, 2013, APS had no outstanding borrowings or letters of credit under its revolving credit facilities.  In addition, APS had commercial paper borrowings of $153 million at December 31, 2013.

See “Financial Assurances” in Note 11 for a 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, 2012 (dollars in millions):

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 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 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 a 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, subject to specified parameters and procedures, it (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.

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Regulatory Matters (Details 4) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Detail of regulatory liabilities
Regulatory liabilities, current	$ 99,000,000	$ 88,000,000
Regulatory liabilities, non-current	801,297,000	759,201,000
Removal costs
Detail of regulatory liabilities
Regulatory liabilities, current	28,000,000	27,000,000
Regulatory liabilities, non-current	303,000,000	321,000,000
Asset retirement obligations
Detail of regulatory liabilities
Regulatory liabilities, non-current	266,000,000	256,000,000
Renewable energy standard
Detail of regulatory liabilities
Regulatory liabilities, current	33,000,000	43,000,000
Regulatory liabilities, non-current	15,000,000
Income taxes - change in rates
Detail of regulatory liabilities
Regulatory liabilities, non-current	74,000,000	66,000,000
Spent nuclear fuel
Detail of regulatory liabilities
Regulatory liabilities, current	6,000,000	10,000,000
Regulatory liabilities, non-current	36,000,000	36,000,000
Deferred gains on utility property
Detail of regulatory liabilities
Regulatory liabilities, current	2,000,000	2,000,000
Regulatory liabilities, non-current	10,000,000	12,000,000
Income taxes-deferred investment tax credit
Detail of regulatory liabilities
Regulatory liabilities, current	3,000,000	2,000,000
Regulatory liabilities, non-current	79,000,000	52,000,000
Demand side management
Detail of regulatory liabilities
Regulatory liabilities, current	27,000,000	4,000,000
Other
Detail of regulatory liabilities
Regulatory liabilities, non-current	$ 18,000,000	$ 16,000,000

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Income Taxes (APSC) (Tables)

12 Months Ended

Dec. 31, 2013

Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year

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):

	2013			2012			2011
Total unrecognized tax benefits, January 1	$	133,422		$	136,005		$	127,595
Additions for tax positions of the current year	3,516			5,167			10,915
Additions for tax positions of prior years	13,158			—			—
Reductions for tax positions of prior years for:
Changes in judgment	(108,099		)	(7,729		)	(1,555		)
Settlements with taxing authorities	—			—			(124		)
Lapses of applicable statute of limitations	—			(21		)	(826		)
Total unrecognized tax benefits, December 31	$	41,997		$	133,422		$	136,005

Components of income tax expense

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

	Year Ended December 31,
	2013			2012			2011
Current:
Federal	$	(81,784	)	$	(3,493	)	$	(310	)
State	10,537			8,395			15,140
Total current	(71,247		)	4,902			14,830
Deferred:
Federal	279,973			200,322			159,566
State	21,865			28,280			16,626
Total deferred	301,838			228,602			176,192
Total income tax expense	230,591			233,504			191,022
Less: income tax expense (benefit) on discontinued operations	—			(3,813		)	7,418
Income tax expense — continuing operations	$	230,591		$	237,317		$	183,604

Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations

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,
	2013			2012			2011
Federal income tax expense at 35% statutory rate	$	234,695		$	229,709		$	188,733
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	21,387			23,819			19,594
Credits and favorable adjustments related to prior years resolved in current year	(3,356		)	—			—
Medicare Subsidy Part-D	823			483			823
Allowance for equity funds used during construction (see Note 1)	(6,997		)	(6,158		)	(6,881		)
Palo Verde VIE noncontrolling interest (see Note 19)	(11,862		)	(11,065		)	(9,636		)
Other	(4,099		)	529			(9,029		)
Income tax expense — continuing operations	$	230,591		$	237,317		$	183,604

Net deferred income tax liability recognized on the Balance Sheets

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

	December 31,
	2013			2012
Current asset	$	91,152		$	152,191
Long-term liability	(2,351,882		)	(2,151,371		)
Deferred income taxes — net	$	(2,260,730	)	$	(1,999,180	)

Components of the net deferred income tax liability

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

	December 31,
	2013			2012
DEFERRED TAX ASSETS
Risk management activities	$	44,920		$	72,243
Regulatory liabilities:
Asset retirement obligation and removal costs	235,959			238,669
Unamortized investment tax credits	82,116			53,837
Other	42,609			33,764
Pension and other postretirement liabilities	198,642			408,764
Renewable energy incentives	65,434			66,941
Credit and loss carryforwards	133,070			139,022
Other	148,492			68,844
Total deferred tax assets	951,242			1,082,084
DEFERRED TAX LIABILITIES
Plant-related	(2,903,730		)	(2,584,166		)
Risk management activities	(16,191		)	(23,940		)
Regulatory assets:
Allowance for equity funds used during construction	(43,058		)	(37,899		)
Deferred fuel and purchased power	(8,282		)	(28,858		)
Deferred fuel and purchased power — mark-to-market	(13,343		)	(15,796		)
Pension and other postretirement benefits	(129,250		)	(316,757		)
Other	(93,202		)	(68,170		)
Other	(4,916		)	(5,678		)
Total deferred tax liabilities	(3,211,972		)	(3,081,264		)
Deferred income taxes — net	$	(2,260,730	)	$	(1,999,180	)

ARIZONA PUBLIC SERVICE COMPANY

Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year

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):

	2013			2012			2011
Total unrecognized tax benefits, January 1	$	133,241		$	135,824		$	126,698
Additions for tax positions of the current year	3,516			5,167			10,915
Additions for tax positions of prior years	13,158			—			—
Reductions for tax positions of prior years for:
Changes in judgment	(107,918		)	(7,729		)	(1,555		)
Settlements with taxing authorities	—			—			(124		)
Lapses of applicable statute of limitations	—			(21		)	(110		)
Total unrecognized tax benefits, December 31	$	41,997		$	133,241		$	135,824

Components of income tax expense

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

	Year Ended December 31,
	2013			2012			2011
Current:
Federal	$	(97,531	)	$	(11,650	)	$	4,633
State	11,983			12,308			19,104
Total current	(85,548		)	658			23,737
Deferred:
Federal	305,389			216,367			154,632
State	25,254			27,371			14,173
Total deferred	330,643			243,738			168,805
Total income tax expense	$	245,095		$	244,396		$	192,542

Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations

The following chart compares APS’s pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):

	Year Ended December 31,
	2013			2012			2011
Federal income tax expense at 35% statutory rate	$	246,384		$	235,027		$	194,710
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	23,970			25,379			21,139
Credits and favorable adjustments related to prior years resolved in current year	(3,231		)	—			—
Medicare Subsidy Part-D	823			483			823
Allowance for equity funds used during construction (see Note 1)	(6,997		)	(6,158		)	(6,880		)
Palo Verde VIE noncontrolling interest (see Note 19)	(11,862		)	(11,065		)	(9,633		)
Other	(3,992		)	730			(7,617		)
Income tax expense	$	245,095		$	244,396		$	192,542

Net deferred income tax liability recognized on the Balance Sheets

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

	December 31,
	2013			2012
Current asset (liability)	$	(2,033	)	$	74,420
Long-term liability	(2,347,724		)	(2,133,976		)
Deferred income taxes — net	$	(2,349,757	)	$	(2,059,556	)

Components of the net deferred income tax liability

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

	December 31,
	2013			2012
DEFERRED TAX ASSETS
Regulatory liabilities:
Asset retirement obligation and removal costs	$	235,959		$	238,669
Unamortized investment tax credits	82,116			53,837
Other	42,609			33,764
Risk management activities	44,920			72,243
Pension and other postretirement liabilities	186,213			392,486
Renewable energy incentives	65,434			66,941
Credit and loss carryforwards	38,183			52,441
Other	166,781			111,327
Total deferred tax assets	862,215			1,021,708
DEFERRED TAX LIABILITIES
Plant-related	(2,903,730		)	(2,584,166		)
Risk management activities	(16,191		)	(23,940		)
Regulatory assets:
Allowance for equity funds used during construction	(43,058		)	(37,899		)
Deferred fuel and purchased power	(8,282		)	(28,858		)
Deferred fuel and purchased power — mark-to-market	(13,343		)	(15,796		)
Pension and other postretirement benefits	(129,250		)	(316,757		)
Other	(93,202		)	(68,170		)
Other	(4,916		)	(5,678		)
Total deferred tax liabilities	(3,211,972		)	(3,081,264		)
Deferred income taxes — net	$	(2,349,757	)	$	(2,059,556	)

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Regulatory Matters

12 Months Ended

Dec. 31, 2013

Regulatory Matters

Regulatory Matters

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 by approximately 6.6%.  On January 6, 2012, APS and other parties to the general retail rate case entered into the 2012 Settlement Agreement detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications.

Settlement Agreement

The 2012 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 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 2012 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 2012 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 2012 Settlement Agreement.

Other key provisions of the 2012 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;

· 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 acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners (APS made its filing under this provision on December 30, 2013, which would result in an average bill impact to residential customers of approximately 2% if approved as requested);

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

· Modifications to the Environmental Improvement Surcharge 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 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 2009 Settlement Agreement discussed below;

· Allowing a negative credit that existed 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 2012 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 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs 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 the 2009 Settlement Agreement entered into by APS and twenty-one other parties.  The 2009 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 $700 million during the period beginning June 1, 2009 through December 31, 2014 and compliance with various financial conditions, including the maintenance of a prescribed capital structure (APS was able to meet these conditions without the need for additional equity infusions beyond the $253 million infused into APS in the second quarter of 2010); and

· Renewable energy programs that require APS to expand its use of renewable energy through 2015, as well as allow for concurrent recovery of renewable energy expenses.

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 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million.  In a final order dated January 7, 2014, the ACC approved the requested budget.  Also in 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits.  On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules so that utilities can establish compliance without using renewable energy credits.

On July 12, 2013, APS filed an application with the ACC proposing a solution to fix the cost shift brought by the current net metering rules.  In its application, APS requested that the ACC cause all new residential customers installing new rooftop solar systems to either:  (i) take electric service under APS’s demand-based ECT-2 rate and remain eligible for net metering; or (ii) take service under the customer’s existing rate as if no distributed energy system was installed and receive a bill credit for 100% of the distributed energy system’s output at a market-based price.  APS also proposed that the ACC:  (i) grandfather current rates and use of net metering for existing and immediately pending distributed energy customers; and (ii) continue using direct cash incentives for new distributed energy installations.

On December 3, 2013, the ACC issued its order on APS’s net metering proposal.  The ACC instituted a charge on future customers who install rooftop solar panels and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid. The new policy will be in effect until the next APS rate case.

In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid.  ACC professional staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists. The fixed charge does not increase APS’s revenue, but instead will modestly reduce the impact of the cost shift on non-solar customers. The ACC acknowledged that the new charge addresses only a portion of the cost shift.

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.

On June 1, 2011, APS filed its 2012 Demand Side Management Implementation Plan consistent with the ACC’s Electric Energy Efficiency Rules, 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 2009 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.  This amount was recovered by the then existing DSMAC over a twelve-month period beginning March 1, 2012.  This amount does not include $10 million already being recovered in general retail base rates, but does include amortization of 2009 costs (approximately $5 million of the $72 million).

On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan.  In 2013, the standards 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.

The ACC Staff recommendation and proposed order, issued on October 30, 2013, largely recommended continuing the status quo, although at lower funding levels.  ACC Staff recommended approval of all existing cost-effective energy efficiency and demand response programs and a budget of $68.9 million going forward.  APS expects to receive a decision from the ACC in early 2014.

On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified or abolished.  This spring the ACC will hold a series of three workshops to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

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 1st (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;

· 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 for 2013 and 2012 (dollars in millions):

	Twelve Months Ended December 31,
	2013			2012
Beginning balance	$	73		$	28
Deferred fuel and purchased power costs - current period	(21		)	(72		)
Amounts (charged) credited to customers	(31		)	117
Ending balance	$	21		$	73

The PSA rate for the PSA year beginning February 1, 2014 is $0.001557 per kWh, as compared to $0.001329 per kWh for the prior year.  This represents a $0.000228 per kWh increase over the 2013 PSA charge.  This new rate is comprised of a forward component of $0.001277 per kWh and a historical component of $0.000280 per kWh.  Any uncollected (overcollected) deferrals during the 2014 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2015.

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.  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 2012 Settlement Agreement (discussed above), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

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- or under-collected amounts.

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.

Effective June 1, 2013, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $26 million for the twelve-month period beginning June 1, 2013 in accordance with the FERC-approved formula.  Pursuant to the 2012 Settlement Agreement (discussed above), an adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2013.

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 APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement 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 APS’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 a LFCR adjustment every January thereafter.  On February 12, 2013, the ACC approved a LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the 2012 Settlement Agreement went into effect on July 1, 2012.  APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014.  APS anticipates that the ACC will consider whether to approve APS’s LFCR adjustment prior to the end of March 2014.

Deregulation

On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.  The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state.  One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution.  On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Constitutional authority before any further examination of this matter.  The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.  The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry.  Workshops in this docket are expected to be held in 2014.

Four Corners

On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners.  As a result of this purchase, APS now owns 63% of Units 4 and 5.  APS has a total entitlement from Four Corners of 970 MW.  The final purchase price for the interest was approximately $182 million.  APS acquired assets and assumed certain of SCE’s decommissioning and mine reclamation obligations.  We have recognized plant-in-service, net of accumulated depreciation, of $316 million, which includes an acquisition adjustment of $255 million.  In addition, we have recognized a liability of $34 million for the decommissioning obligations, $93 million for the mine reclamation obligations, $18 million of other various liabilities, and $11 million of construction work in progress relating to this purchase.  These amounts are subject to revision during the measurement period, not to exceed one year, to the extent additional information is obtained about the facts and circumstances that existed as of the acquisition date.  While we expect the ACC to approve the recovery of the acquisition adjustment, should recovery be disallowed, it will be reclassified from plant-in-service to goodwill, subject to impairment testing.  The decommissioning and mine reclamation obligations were recognized at their fair value.  Because APS’s rates are regulated, APS expects to recover the costs of the acquired plant assets, including a return on its investment based on its cost of capital.  APS believes this return is consistent with what a market participant would consider to be fair value in APS’s regulatory environment.  Accordingly, APS believes the cost of the plant assets approximate their fair value.

The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  APS made its filing under this provision on December 30, 2013.  This includes deferral for future recovery of all non-fuel operating cost for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Four Corners Units 1-3.  The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Four Corners Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Four Corners Units 1-3 was $37 million as of December 31, 2013.

As part of APS’s acquisition of SCE’s interest in Units 4 and 5 of Four Corners, APS and SCE agreed, via a “Transmission Termination Agreement,” that upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination.  APS and SCE negotiated an alternate arrangement under which SCE will assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group for transmission of the additional power received from Four Corners.  This arrangement becomes effective upon FERC approval and will remain in effect until the net payments received by SCE in connection with the assignments reach $40 million, at which time the arrangement and the Transmission Agreement will terminate.  APS believes that FERC will approve the alternate arrangement as filed but, if not approved, SCE and APS will again be subject to the terms of the Transmission Termination Agreement.  As we previously disclosed, APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement.  If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration.  APS is unable to predict the outcome of this matter if it proceeds to arbitration.

Regulatory Assets and Liabilities

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

	Remaining Amortization		December 31, 2013				December 31, 2012
	Period		Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	(a	)	$	—	$	314	$	—	$	780
Income taxes — AFUDC equity	2043		4		105		4		92
Deferred fuel and purchased power — mark-to-market (Note 17)	2016		5		29		19		21
Transmission vegetation management	2016		9		14		9		23
Coal reclamation	2038		8		18		8		24
Palo Verde VIEs (Note 19)	2046		—		41		—		38
Deferred compensation	2036		—		34		—		34
Deferred fuel and purchased power (b) (c)	2014		21		—		73		—
Tax expense of Medicare subsidy	2023		2		15		2		17
Loss on reacquired debt	2034		1		17		2		18
Income taxes — investment tax credit basis adjustment	2043		1		39		1		26
Pension and other postretirement benefits deferral	2015		8		4		8		13
Four Corners cost deferral	2024		—		37		—		—
Lost fixed cost recovery	2014		25		—		7		—
Transmission cost adjustor	2015		8		2		10		—
Retired power plant costs	2020		3		18		—		—
Other	Various		2		25		1		14
Total regulatory assets (d)			$	97	$	712	$	144	$	1,100

(a) This asset represents the future recovery of under-funded pension and other postretirement benefit obligations 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.  See Note 8 for further discussion.

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

(c) Subject to a carrying charge.

(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, 2013				December 31, 2012
	Period		Current		Non-Current		Current		Non-Current
Removal costs	(a	)	$	28	$	303	$	27	$	321
Asset retirement obligations	(a	)	—		266		—		256
Renewable energy standard (b)	2015		33		15		43		—
Income taxes — change in rates	2043		—		74		—		66
Spent nuclear fuel	2047		6		36		10		36
Deferred gains on utility property	2019		2		10		2		12
Income taxes — deferred investment tax credit	2043		3		79		2		52
Demand side management (b)	2014		27		—		4		—
Other	Various		—		18		—		16
Total regulatory liabilities			$	99	$	801	$	88	$	759

(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.

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Income Taxes

12 Months Ended

Dec. 31, 2013

Income Taxes

Income Taxes

4.             Income Taxes

Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes.  The tax effect of these differences is recorded as deferred taxes.  We calculate deferred taxes using 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 ITCs 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 $70 million long-term income tax receivable on the Consolidated Balance Sheets as of December 31, 2012 represented the anticipated refund related to an APS tax accounting method change approved by the IRS in the third quarter of 2009.  On July 9, 2013, IRS guidance was released which provided clarification regarding the timing and amount of this cash receipt.  As a result of this guidance, uncertain tax positions decreased $67 million during the third quarter.  This decrease in uncertain tax positions resulted in a corresponding increase to the total anticipated refund due from the IRS and an offsetting increase in long-term deferred tax liabilities.  Additionally, as a result of this IRS guidance, the resulting $137 million anticipated refund was reclassified to current income tax receivable.

During the year ended December 31, 2013, the IRS finalized the examination of tax returns for the years ended December 31, 2008 and 2009, and the $137 million anticipated refund was reduced by approximately $4 million to reflect the outcome of this examination.  On December 17, 2013, the Joint Committee on Taxation approved the anticipated refund.  Cash related to this refund was received in the first quarter of 2014.

On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property.  These final regulations apply to tax years beginning on or after January 1, 2014.  Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS, resulting in a cumulative effect adjustment.  To account for the adoption of these regulations, plant-related long-term deferred tax liabilities decreased by $84 million, with the offsetting decrease to current deferred income tax assets.  Prior to the issuance of these regulations, this $84 million would have been repaid over 20 years through lower tax depreciation deductions.

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 19).  As a result, there is no income tax expense associated with the VIEs recorded on the Consolidated Statements of Income.

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):

	2013			2012			2011
Total unrecognized tax benefits, January 1	$	133,422		$	136,005		$	127,595
Additions for tax positions of the current year	3,516			5,167			10,915
Additions for tax positions of prior years	13,158			—			—
Reductions for tax positions of prior years for:
Changes in judgment	(108,099		)	(7,729		)	(1,555		)
Settlements with taxing authorities	—			—			(124		)
Lapses of applicable statute of limitations	—			(21		)	(826		)
Total unrecognized tax benefits, December 31	$	41,997		$	133,422		$	136,005

Included in the balances of unrecognized tax benefits at December 31, 2013, 2012 and 2011 were approximately $10 million, $10 million and $8 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, 2010 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 2010.

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 benefit of $4 million for 2013, a pre-tax expense of $4 million for 2012, and a pre-tax expense of $3 million for 2011.

The total amount of accrued liabilities for interest recognized in the Consolidated Balance Sheets related to unrecognized tax benefits was less than $1 million as of December 31, 2013, $13 million as of December 31, 2012 and $9 million as of December 31, 2011.  To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate.  Additionally, as of December 31, 2013, 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,
	2013			2012			2011
Current:
Federal	$	(81,784	)	$	(3,493	)	$	(310	)
State	10,537			8,395			15,140
Total current	(71,247		)	4,902			14,830
Deferred:
Federal	279,973			200,322			159,566
State	21,865			28,280			16,626
Total deferred	301,838			228,602			176,192
Total income tax expense	230,591			233,504			191,022
Less: income tax expense (benefit) on discontinued operations	—			(3,813		)	7,418
Income tax expense — continuing operations	$	230,591		$	237,317		$	183,604

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,
	2013			2012			2011
Federal income tax expense at 35% statutory rate	$	234,695		$	229,709		$	188,733
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	21,387			23,819			19,594
Credits and favorable adjustments related to prior years resolved in current year	(3,356		)	—			—
Medicare Subsidy Part-D	823			483			823
Allowance for equity funds used during construction (see Note 1)	(6,997		)	(6,158		)	(6,881		)
Palo Verde VIE noncontrolling interest (see Note 19)	(11,862		)	(11,065		)	(9,636		)
Other	(4,099		)	529			(9,029		)
Income tax expense — continuing operations	$	230,591		$	237,317		$	183,604

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

	December 31,
	2013			2012
Current asset	$	91,152		$	152,191
Long-term liability	(2,351,882		)	(2,151,371		)
Deferred income taxes — net	$	(2,260,730	)	$	(1,999,180	)

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, 2013 APS has recorded a regulatory liability of $75 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five-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 New Mexico. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability.  As of December 31, 2013, APS has recorded a regulatory liability of $2 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

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

	December 31,
	2013			2012
DEFERRED TAX ASSETS
Risk management activities	$	44,920		$	72,243
Regulatory liabilities:
Asset retirement obligation and removal costs	235,959			238,669
Unamortized investment tax credits	82,116			53,837
Other	42,609			33,764
Pension and other postretirement liabilities	198,642			408,764
Renewable energy incentives	65,434			66,941
Credit and loss carryforwards	133,070			139,022
Other	148,492			68,844
Total deferred tax assets	951,242			1,082,084
DEFERRED TAX LIABILITIES
Plant-related	(2,903,730		)	(2,584,166		)
Risk management activities	(16,191		)	(23,940		)
Regulatory assets:
Allowance for equity funds used during construction	(43,058		)	(37,899		)
Deferred fuel and purchased power	(8,282		)	(28,858		)
Deferred fuel and purchased power — mark-to-market	(13,343		)	(15,796		)
Pension and other postretirement benefits	(129,250		)	(316,757		)
Other	(93,202		)	(68,170		)
Other	(4,916		)	(5,678		)
Total deferred tax liabilities	(3,211,972		)	(3,081,264		)
Deferred income taxes — net	$	(2,260,730	)	$	(1,999,180	)

As of December 31, 2013, the deferred tax assets for credit and loss carryforwards relate to federal general business credits of $131 million which first begin to expire in 2031, and other federal and state loss carryforwards of $2 million which first begin to expire in 2018.

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Long-Term Debt and Liquidity Matters

12 Months Ended

Dec. 31, 2013

Long-Term Debt and Liquidity Matters

Long-Term Debt and Liquidity Matters

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, 2013 and 2012 (dollars in thousands):

	Maturity	Interest	December 31,
	Dates (a)	Rates	2013			2012
APS
Pollution Control Bonds:
Variable	2029-2038	(b)	$	75,580		$	75,580
Fixed	2024-2034	1.25%-6.00%	426,125			490,275
Total Pollution Control Bonds			501,705			565,855
Senior unsecured notes	2014-2042	4.50%-8.75%	2,675,000			2,575,000
Palo Verde sale leaseback lessor notes	2015	8.00%	38,869			65,547
Unamortized discount			(8,732		)	(9,486		)
Unamortized premium			5,047			—
Total APS long-term debt			3,211,889			3,196,916
Less current maturities	(d)		540,424			122,828
Total APS long-term debt less current maturities			2,671,465			3,074,088
Pinnacle West
Term loan	2015	(c)	125,000			125,000
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES			$	2,796,465		$	3,199,088

(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 0.03%-0.06% at December 31, 2013 and 0.13%-0.15% at December 31, 2012.

(c) The weighted-average interest rate was 1.269% at December 31, 2013 and 1.312% at December 31, 2012.

(d) Current maturities include $215 million of pollution control bonds expected to be remarketed in 2014 and $300 million in senior unsecured notes that mature in 2014.

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
2014	$	540	$	540
2015	470		345
2016	358		358
2017	—		—
2018	32		32
Thereafter	1,940		1,940
Total	$	3,340	$	3,215

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, 2013				As of December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	125	$	125	$	125	$	125
APS	3,212		3,454		3,197		3,750
Total	$	3,337	$	3,579	$	3,322	$	3,875

Credit Facilities and Debt Issuances

APS

On March 22, 2013, APS issued an additional $100 million par amount of its outstanding 4.50% unsecured senior notes that mature on April 1, 2042.  The net proceeds from the sale were used to repay short-term commercial paper borrowings and replenish cash used to redeem certain tax-exempt indebtedness in November 2012.

On May 1, 2013, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series C, due 2029.  On May 28, 2013, we remarketed the bonds.  The interest rate for these bonds was set to a new term rate.  The new term rate for these bonds ends, subject to a mandatory tender, on May 30, 2018.  During this time, the bonds will bear interest at a rate of 1.75% per annum.  These bonds are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2013 and were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.

On July 12, 2013, APS purchased all $33 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 1994 Series A, due 2029.  On January 15, 2014, these bonds were canceled.  These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.

On October 11, 2013, APS purchased all $32 million of the City of Farmington, New Mexico Pollution Control Revenue Bonds, 1994 Series C, due 2024.  On January 15, 2014, these bonds were canceled.  These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.

On January 10, 2014, APS issued $250 million of 4.70% unsecured senior notes that mature on January 15, 2044.  The proceeds from the sale were used to repay commercial paper which was used to fund the purchase price and costs associated with the acquisition of SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners and to replenish cash used to re-acquire two series of tax-exempt indebtedness.

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

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, 2013, the ratio was approximately 47% 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.

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, 2013, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.3 billion, and total capitalization was approximately $7.5 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.0 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.

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Income Taxes (Details 4) (USD $)	Dec. 31, 2013	Dec. 31, 2012
DEFERRED TAX ASSETS
Risk management activities	$ 44,920,000	$ 72,243,000
Regulatory liabilities:
Asset retirement obligation and removal costs	235,959,000	238,669,000
Unamortized investment tax credits	82,116,000	53,837,000
Other	42,609,000	33,764,000
Pension and other postretirement liabilities	198,642,000	408,764,000
Renewable energy incentives	65,434,000	66,941,000
Credit and loss carryforwards	133,070,000	139,022,000
Other	148,492,000	68,844,000
Total deferred tax assets	951,242,000	1,082,084,000
DEFERRED TAX LIABILITIES
Plant-related	(2,903,730,000)	(2,584,166,000)
Risk management activities	(16,191,000)	(23,940,000)
Regulatory assets:
Allowance for equity funds used during construction	(43,058,000)	(37,899,000)
Deferred fuel and purchased power	(8,282,000)	(28,858,000)
Deferred fuel and purchased power - mark-to-market	(13,343,000)	(15,796,000)
Pension and other postretirement benefits	(129,250,000)	(316,757,000)
Other	(93,202,000)	(68,170,000)
Other	(4,916,000)	(5,678,000)
Total deferred tax liabilities	(3,211,972,000)	(3,081,264,000)
Deferred income taxes - net	(2,260,730,000)	(1,999,180,000)
Amount of federal general business credits carryforwards which begin to expire in 2031	131,000,000
Amount of federal and state loss carryforwards which will begin to expire in 2018	$ 2,000,000

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SCHEDULE II - RESERVE FOR UNCOLLECTIBLES (APSC) (Details) (Reserve for uncollectibles., ARIZONA PUBLIC SERVICE COMPANY, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reserve for uncollectibles. | ARIZONA PUBLIC SERVICE COMPANY
Changes in reserve for uncollectibles
Balance at beginning of period	$ 3,340	$ 3,748	$ 4,376
Additions, Charged to cost and expenses	4,923	5,290	5,751
Deductions	5,060	5,698	6,379
Balance at end of period	$ 3,203	$ 3,340	$ 3,748

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Stock-Based Compensation (Details 2) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Additional disclosures
Total unrecognized compensation cost related to nonvested share-based compensation arrangements granted	$ 17
Expected weighted-average period of recognition of unrecognized compensation cost	2 years
Total fair value of shares vested	20	19	14
Compensation cost that has been charged against income	25	32	23
Total income tax benefit recognized	10	13	9
ARIZONA PUBLIC SERVICE COMPANY
Additional disclosures
Compensation cost that has been charged against income	25	32	22
Stock Options
Stock option activity under prior equity incentive plans
Outstanding at the beginning of the period (in shares)	7,925
Exercised (in shares)	3,625
Forfeited or expired (in shares)	4,300
Outstanding at the end of the period (in shares)		7,925
Weighted-Average Exercise Price
Outstanding at the beginning of the period (in dollars per share)	$ 32.29
Exercised (in dollars per share)	$ 32.29
Forfeited or expired (in dollars per share)	$ 32.29
Outstanding at the end of the period (in dollars per share)		$ 32.29
Additional disclosures
Cash received from options exercised	$ 0.1	$ 0.5	$ 1.8

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Long-Term Debt and Liquidity Matters (Details) (USD $)																12 Months Ended				12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Maximum	Dec. 31, 2013 Pinnacle West	Dec. 31, 2012 Pinnacle West	Dec. 31, 2013 APS	Dec. 31, 2012 APS	Dec. 31, 2013 APS ACC	Dec. 31, 2013 APS ACC Minimum	Dec. 31, 2013 Pollution Control Bonds - Variable APS	Dec. 31, 2012 Pollution Control Bonds - Variable APS	Dec. 31, 2013 Pollution Control Bonds - Variable APS Maximum	Dec. 31, 2012 Pollution Control Bonds - Variable APS Maximum	Dec. 31, 2013 Pollution Control Bonds - Variable APS Minimum	Dec. 31, 2012 Pollution Control Bonds - Variable APS Minimum	Dec. 31, 2013 Pollution Control Bonds - Fixed APS	Dec. 31, 2012 Pollution Control Bonds - Fixed APS	Dec. 31, 2013 Total Pollution Control Bonds APS	Dec. 31, 2012 Total Pollution Control Bonds APS	Dec. 31, 2013 Senior unsecured notes APS	Dec. 31, 2012 Senior unsecured notes APS	Dec. 31, 2013 Palo Verde sale leaseback lessor notes APS	Dec. 31, 2012 Palo Verde sale leaseback lessor notes APS	Dec. 31, 2013 Term loan facility Pinnacle West	Dec. 31, 2012 Term loan facility Pinnacle West	Mar. 22, 2013 4.50% unsecured senior notes that mature on April 1, 2042 APS	May 01, 2013 Pollution Control Revenue Refunding Bonds, 2009 Series C APS	Jul. 12, 2013 Pollution Control Revenue Refunding Bonds, 1994 Series A APS	Oct. 11, 2013 Pollution Control Revenue Refunding Bonds, 1994 Series C APS Subsequent event
Long-Term Debt and Liquidity Matters
Long-term debt redemption				$ 3,340,000,000		$ 3,215,000,000				$ 75,580,000	$ 75,580,000					$ 426,125,000	$ 490,275,000	$ 501,705,000	$ 565,855,000	$ 2,675,000,000	$ 2,575,000,000						$ 32,000,000	$ 33,000,000	$ 32,000,000
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	13,420,000	38,869,000				13,420,000	38,869,000															38,869,000	65,547,000
Unamortized discount						(8,732,000)	(9,486,000)
Unamortized premium						5,047,000
Long-term debt	3,337,000,000	3,322,000,000																						125,000,000	125,000,000
Long-term debt				125,000,000	125,000,000	3,211,889,000	3,196,916,000
Less current maturities						(540,424,000)	(122,828,000)			(215,000,000)										(300,000,000)
Total long-term debt less current maturities						2,671,465,000	3,074,088,000
Interest rate (as a percent)																						8.00%				4.50%	1.75%
Long-term debt less current maturities	2,796,465,000	3,199,088,000		125,000,000	125,000,000
Interest Rates, low end of range (as a percent)																1.25%	1.25%			4.50%	4.50%
Interest Rates, high end of range (as a percent)																6.00%	6.00%			8.75%	8.75%
Weighted-average interest rate (as a percent)												0.06%	0.15%	0.03%	0.13%									1.269%	1.312%
Estimated fair value of long-term debt, including current maturities
Carrying Amount				125,000,000	125,000,000	3,211,889,000	3,196,916,000
Long-term debt	3,337,000,000	3,322,000,000																						125,000,000	125,000,000
Fair Value	3,579,000,000	3,875,000,000		125,000,000	125,000,000	3,454,000,000	3,750,000,000
Notes issued																										100,000,000
Debt Provisions
Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)				47.00%		45.00%
Ratio of consolidated debt to consolidated capitalization (as a percent)			65.00%
Required common equity ratio ordered by ACC (as a percent)									40.00%
Total shareholder equity	4,194,470,000	3,972,806,000		4,194,470,000	3,972,806,000	4,308,884,000	4,093,000,000	4,300,000,000
Total capitalization								7,500,000,000
Dividend restrictions, shareholder equity required								$ 3,000,000,000

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CONSOLIDATED BALANCE SHEETS (APSC) (Parenthetical) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, and 10)
Accumulated depreciation of Palo Verde sale leaseback	$ 225,925	$ 222,055
Accumulated amortization on intangible assets	439,703	411,543
Accumulated amortization on nuclear fuel	146,057	133,950
ARIZONA PUBLIC SERVICE COMPANY
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, and 10)
Accumulated depreciation of Palo Verde sale leaseback	225,925	222,055
Accumulated amortization on intangible assets	439,703	411,543
Accumulated amortization on nuclear fuel	$ 146,057	$ 133,950

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Income Taxes (Details 3) (USD $)	3 Months Ended								12 Months Ended			0 Months Ended			3 Months Ended	12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 13, 2013 ARIZONA PUBLIC SERVICE COMPANY	Apr. 04, 2013 ARIZONA PUBLIC SERVICE COMPANY	Feb. 17, 2011 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2013 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2013 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2011 ARIZONA PUBLIC SERVICE COMPANY
Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations
Federal income tax rate (as a percent)									35.00%	35.00%	35.00%					35.00%	35.00%	35.00%
Federal income tax expense at 35% statutory rate									$ 234,695,000	$ 229,709,000	$ 188,733,000					$ 246,384,000	$ 235,027,000	$ 194,710,000
State income tax net of federal income tax benefit									21,387,000	23,819,000	19,594,000					23,970,000	25,379,000	21,139,000
Credits and favorable adjustments related to prior years resolved in current year									(3,356,000)							(3,231,000)
Medicare Subsidy Part-D									823,000	483,000	823,000					823,000	483,000	823,000
Allowance for equity funds used during construction									(6,997,000)	(6,158,000)	(6,881,000)					(6,997,000)	(6,158,000)	(6,880,000)
Palo Verde VIE noncontrolling interest									(11,862,000)	(11,065,000)	(9,636,000)					(11,862,000)	(11,065,000)	(9,633,000)
Other									(4,099,000)	529,000	(9,029,000)					(3,992,000)	730,000	(7,617,000)
Income tax expense - continuing operations	9,167,000	131,912,000	77,043,000	12,469,000	18,157,000	147,116,000	76,689,000	(4,645,000)	230,591,000	237,317,000	183,604,000					245,095,000	244,396,000	192,542,000
Net deferred income tax liability recognized on the Consolidated Balance Sheets
Current asset (liability)	91,152,000				152,191,000				91,152,000	152,191,000					(2,033,000)	(2,033,000)	74,420,000
Long-term liability	(2,351,882,000)				(2,151,371,000)				(2,351,882,000)	(2,151,371,000)					(2,347,724,000)	(2,347,724,000)	(2,133,976,000)
Deferred income taxes - net	(2,260,730,000)				(1,999,180,000)				(2,260,730,000)	(1,999,180,000)					(2,349,757,000)	(2,349,757,000)	(2,059,556,000)
Income Taxes, additional disclosures
Phase-in period of corporate income tax rate reductions beginning in 2014													5 years	4 years
Decrease in long term deferred tax liability due to adoption of regulations		(84,000,000)										(84,000,000)
Decrease in long term deferred tax liability due to rate changes									$ (75,000,000)						$ (2,000,000)	$ (2,000,000)

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Nuclear Decommissioning Trusts (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Nuclear decommissioning trust fund assets
Fair Value	$ 642,007,000	$ 570,625,000
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Proceeds from the sale of securities	446,025,000	417,603,000	497,780,000
Fair value of fixed income securities, summarized by contractual maturities
Total	642,007,000	570,625,000
ARIZONA PUBLIC SERVICE COMPANY
Nuclear decommissioning trust fund assets
Fair Value	642,007,000	570,625,000
Unrealized Gains	140,000,000	91,000,000
Unrealized Losses	(6,000,000)
Net payables for securities purchases	(3,000,000)	(4,000,000)
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	6,000,000	7,000,000	8,000,000
Realized losses	(7,000,000)	(4,000,000)	(5,000,000)
Proceeds from the sale of securities	446,025,000	417,603,000	497,780,000
Fair value of fixed income securities, summarized by contractual maturities
Total	642,007,000	570,625,000
ARIZONA PUBLIC SERVICE COMPANY | Equity Securities
Nuclear decommissioning trust fund assets
Fair Value	272,000,000	204,000,000
Unrealized Gains	129,000,000	67,000,000
Fair value of fixed income securities, summarized by contractual maturities
Total	272,000,000	204,000,000
ARIZONA PUBLIC SERVICE COMPANY | Fixed income securities.
Nuclear decommissioning trust fund assets
Fair Value	373,000,000	371,000,000
Unrealized Gains	11,000,000	24,000,000
Unrealized Losses	(6,000,000)
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	9,000,000
1 year - 5 years	109,000,000
5 years - 10 years	108,000,000
Greater than 10 years	147,000,000
Total	$ 373,000,000	$ 371,000,000

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies

Description of Business and Basis of Presentation

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 and essentially all of these assets were sold in 2009 and 2010.  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 reported as discontinued operations.  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 reported as discontinued operations.  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 19).

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.

Certain line items are presented in more detail on the Consolidated Balance Sheets and Consolidated Statements of Cash Flows than was presented in the prior years.  Other line items are more condensed than the previous presentation.  The prior year amounts were reclassified to conform to the current year presentation.  These reclassifications had no impact on total assets or net cash flow provided by operating activities.  The following tables show the impacts of the reclassifications of prior years (previously reported) amounts (dollars in thousands):

Balance Sheets - December 31, 2012	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Long-Term Debt less Current Maturities —
Long-term debt less current maturities	$	3,160,219	$	38,869		$	3,199,088
Long-Term Debt less Current Maturities —
Palo Verde sale leaseback lessor notes less
current maturities	38,869		(38,869		)	—

Statement of Cash Flows for the Year Ended December 31, 2012	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
Deferred income taxes	$	228,602	$	(41,579	)	$	187,023
Deferred investment tax credit	—		41,579			41,579
Accrued taxes and income tax receivable	8,693		(8,693		)	—
Income tax receivable	—		(4,043		)	(4,043		)
Accrued taxes	—		12,736			12,736

Statement of Cash Flows for the Year Ended December 31, 2011	As previously reported		Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
Deferred income taxes	$	176,192	$	(58,240	)	$	117,952
Deferred investment tax credit	—		58,240			58,240
Accrued taxes and income tax receivable	12,068		(12,068		)	—
Income tax receivable	—		3,983			3,983
Accrued taxes	—		8,085			8,085

Accounting Records and Use of Estimates

Accounting Records and Use of Estimates

Our accounting records are maintained in accordance with 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.

Regulatory Accounting

Regulatory Accounting

APS is regulated by the ACC and 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 Arizona 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

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 by customer class 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 Settlement Agreement (see Note 3).  Effective July 1, 2012, as a result of the 2012 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.

Allowance for Doubtful Accounts

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.

Property, Plant and Equipment

Property, Plant and Equipment

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 calculated 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, 2013 were as follows:

· Fossil plant — 18 years;

· Nuclear plant — 26 years;

· Other generation — 26 years;

· Transmission — 37 years;

· Distribution — 34 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 use of the new Palo Verde nuclear plant lives, effective January 1, 2012.

Pursuant to an ACC order, we defer operating costs related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  See Note 3 for further discussion.  These costs are deferred on the depreciation line of the Consolidated Statements of Income.

For the years 2011 through 2013, the depreciation rates ranged from a low of 0.45% to a high of 12.08%.  The weighted-average rate was 3.00% for 2013, 2.71% for 2012, and 2.98% for 2011.

Allowance for Funds Used During Construction

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 8.56% for 2013, 8.60% for 2012, and 10.25% for 2011.  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

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

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.

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

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 17 for additional information about our derivative instruments.

Loss Contingencies and Environmental Liabilities

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

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 an other postretirement benefit plan for the employees of Pinnacle West and our subsidiaries that provides 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

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 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

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

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,
	2013		2012		2011
Cash paid during the period for:
Income taxes, net of refunds	$	18,537	$	2,543	$	10,324
Interest, net of amounts capitalized	184,010		200,923		217,789
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	33,184	$	26,208	$	27,245
Dividends declared but not paid	62,528		59,789		—
Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 3)	145,609		—		—

Intangible Assets

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 $53 million in 2013, $50 million in 2012, and $47 million in 2011.  Estimated amortization expense on existing intangible assets over the next five years is $47 million in 2014, $38 million in 2015, $29 million in 2016, $19 million in 2017, and $7 million in 2018.  At December 31, 2013, the weighted-average remaining amortization period for intangible assets was 6 years.

Investments

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 20 for more information on these investments.

Business Segments

Business Segments

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. All other segment activities are insignificant.

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Other Income and Other Expense (Tables)

12 Months Ended

Dec. 31, 2013

Other Income and Other Expense

Detail of other income and other expense

The following table provides detail of other income and other expense for 2013, 2012 and 2011 (dollars in thousands):

	2013			2012			2011
Other income:
Interest income	$	1,629		$	1,239		$	1,850
Investment gains — net	—			—			1,165
Miscellaneous	75			367			96
Total other income	$	1,704		$	1,606		$	3,111
Other expense:
Non-operating costs	$	(8,207	)	$	(7,777	)	$	(7,037	)
Investment loss — net	(3,711		)	(2,453		)	—
Miscellaneous	(4,106		)	(9,612		)	(3,414		)
Total other expense	$	(16,024	)	$	(19,842	)	$	(10,451	)

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies.

Commitments and Contingencies

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 United States Court of Federal Claims.  The lawsuit seeks to recover 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 NWPA.  This lawsuit is currently pending in the Court of Federal Claims.

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, 2013, APS had a regulatory liability of $42 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

Nuclear Insurance

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act (“Price-Anderson Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial 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 $13.6 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 $13.2 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 $127.3 million, subject to an annual limit of $19 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 $111 million, with an annual payment limitation of approximately $16.4 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”).  Effective April 1, 2013, a sublimit of $1.5 billion for non-nuclear property damage losses site-wide has been imposed on the NEIL property policies.  Effective April 1, 2013, a sublimit of $327.6 million per unit has been imposed on the non-nuclear losses covered by the NEIL accidental outage policy, potentially subject to further limitations.  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 2014 and 2043 that include required purchase provisions.  APS estimates the contract requirements to be approximately $729 million in 2014; $628 million in 2015; $638 million in 2016; $613 million in 2017; $580 million in 2018; and $8.7 billion thereafter.  These fuel and purchased power commitments include the amounts incurred from acquiring SCE’s interest in Four Corners.  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 for coal supply include take-or-pay provisions.  The current coal contracts with take-or-pay provisions have terms that expire in 2031.

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

			Years Ended December 31,
	2014		2015		2016		2017		2018		Thereafter
Coal take-or-pay commitments (a)	$	152	$	157	$	166	$	180	$	175	$	2,539

(a) Total take-or-pay commitments are approximately $3.4 billion.  The total net present value of these commitments is approximately $2.2 billion.

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,
	2013		2012		2011
Total purchases	$	188	$	196	$	191

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 $48 million in 2014; $42 million in 2015; $42 million in 2016; $42 million in 2017; $42 million in 2018; and $453 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 recorded a final coal mine reclamation obligation of approximately $207 million at December 31, 2013 and $119 million at December 31, 2012.  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 2014; $1 million in 2015; $8 million in 2016; $14 million in 2017; $14 million in 2018; and $170 million thereafter.  Any amendments to current coal supply agreements may change the timing of the reimbursement.

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 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.

On August 6, 2013, RID filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

Southwest Power Outage

Regulatory.  On September 8, 2011 at approximately 3:30 PM, a 500kV 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.  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 9:15 PM on September 8.  Service to customers affected by the wider regional outages was restored by approximately 3:25 AM on September 9.

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.

On January 22, 2014, following non-public preliminary investigations, FERC Staff issued a Notice of Alleged Violations naming six entities involved in the event, including APS.  FERC Staff alleges that each of the named entities violated varying numbers of NERC Reliability Standards.  APS is alleged to have violated seven Reliability Standard Requirements.  The allegations of violations are preliminary determinations by FERC Staff and do not constitute findings by FERC itself that any violations have occurred.

APS intends to work with FERC Staff to resolve the matter.  If violations of the 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.  APS cannot predict the timing or financial or operational impacts that may result from the Staff’s Notice of Alleged Violations, including any payments that may result from a settlement if one is reached, or any claims that may be made as a result of the outages.

Litigation.  On September 6, 2013, a purported consumer class action complaint was filed in Federal District Court in San Diego, California, naming APS and Pinnacle West as defendants and seeking damages for loss of perishable inventory and sales as a result of interruption of electrical service.  APS and Pinnacle West filed a motion to dismiss, which the court granted on December 9, 2013.  On January 13, 2014, the plaintiffs appealed the lower court’s decision.

Clean Air Act Citizen 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 NSR 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 environmental 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.  The case is being held in abeyance while the parties seek to negotiate a settlement.  On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay.  At such time as the stay is lifted, APS and the other Four Corners participants may reinstate their motions to dismiss without risk of default.  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 CCRs.  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 the 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 BART to lessen the impacts of emissions on visibility surrounding the plants.  Based on EPA’s final standards, APS’s 63% share of the cost of these controls for Four Corners Units 4 and 5 would be approximately $350 million.  APS’s share of costs for upgrades at Navajo, based on EPA’s FIP proposal, could be up to approximately $200 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 $200 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 $120 million for Cholla Units 2 and 3.  No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules.  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, GHG emissions, and other rules or matters involving the Clean Air Act, Clean Water Act, ESA, 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.

Regional Haze Rules — Cholla

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.  We expect briefing in the case to be completed on February 21, 2014.

New Mexico Tax Matter

On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the “Assessment”).  APS’s share of the Assessment is approximately $12 million.  For procedural reasons, on behalf of the Four Corners co-owners, including APS, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013.  The New Mexico Taxation and Revenue Department denied the refund claim.  On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial.  APS believes the Assessment and the refund claim denial are without merit, but cannot predict the timing or outcome of this litigation.

Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes.  At December 31, 2013, 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 19 for further details on the Palo Verde sale leaseback transactions).  These letters of credit will expire on December 31, 2015, and totaled approximately $32 million at December 31, 2013.  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, 2013, $55 million of such letters of credit were outstanding that will expire in 2014 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.

Pinnacle West has issued parental guarantees and surety bonds for APS which were not material at December 31, 2013.

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Income Taxes (APSC) (Details 2) (USD $)	3 Months Ended								12 Months Ended			0 Months Ended			3 Months Ended	12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 13, 2013 ARIZONA PUBLIC SERVICE COMPANY	Apr. 04, 2013 ARIZONA PUBLIC SERVICE COMPANY	Feb. 17, 2011 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2013 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2013 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2012 ARIZONA PUBLIC SERVICE COMPANY	Dec. 31, 2011 ARIZONA PUBLIC SERVICE COMPANY
Current:
Federal									$ (81,784,000)	$ (3,493,000)	$ (310,000)					$ (97,531,000)	$ (11,650,000)	$ 4,633,000
State									10,537,000	8,395,000	15,140,000					11,983,000	12,308,000	19,104,000
Total current									(71,247,000)	4,902,000	14,830,000					(85,548,000)	658,000	23,737,000
Deferred:
Federal									279,973,000	200,322,000	159,566,000					305,389,000	216,367,000	154,632,000
State									21,865,000	28,280,000	16,626,000					25,254,000	27,371,000	14,173,000
Total deferred																330,643,000	243,738,000	168,805,000
Income tax expense - continuing operations	9,167,000	131,912,000	77,043,000	12,469,000	18,157,000	147,116,000	76,689,000	(4,645,000)	230,591,000	237,317,000	183,604,000					245,095,000	244,396,000	192,542,000
Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations
Federal income tax rate (as a percent)									35.00%	35.00%	35.00%					35.00%	35.00%	35.00%
Federal income tax expense at 35% statutory rate									234,695,000	229,709,000	188,733,000					246,384,000	235,027,000	194,710,000
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit									21,387,000	23,819,000	19,594,000					23,970,000	25,379,000	21,139,000
Credits and favorable adjustments related to prior years resolved in current year									(3,356,000)							(3,231,000)
Medicare Subsidy Part-D									823,000	483,000	823,000					823,000	483,000	823,000
Allowance for equity funds used during construction									(6,997,000)	(6,158,000)	(6,881,000)					(6,997,000)	(6,158,000)	(6,880,000)
Palo Verde VIE noncontrolling interest									(11,862,000)	(11,065,000)	(9,636,000)					(11,862,000)	(11,065,000)	(9,633,000)
Other									(4,099,000)	529,000	(9,029,000)					(3,992,000)	730,000	(7,617,000)
Income tax expense - continuing operations	9,167,000	131,912,000	77,043,000	12,469,000	18,157,000	147,116,000	76,689,000	(4,645,000)	230,591,000	237,317,000	183,604,000					245,095,000	244,396,000	192,542,000
Net deferred income tax liability recognized on the Consolidated Balance Sheets
Current asset (liability)	91,152,000				152,191,000				91,152,000	152,191,000					(2,033,000)	(2,033,000)	74,420,000
Long-term liability	(2,351,882,000)				(2,151,371,000)				(2,351,882,000)	(2,151,371,000)					(2,347,724,000)	(2,347,724,000)	(2,133,976,000)
Deferred income taxes - net	(2,260,730,000)				(1,999,180,000)				(2,260,730,000)	(1,999,180,000)					(2,349,757,000)	(2,349,757,000)	(2,059,556,000)
Income Taxes, additional disclosures
Phase-in period of corporate income tax rate reductions beginning in 2014													5 years	4 years
Decrease in long term deferred tax liability due to adoption of regulations		(84,000,000)										(84,000,000)
Decrease in long term deferred tax liability due to rate changes									$ (75,000,000)						$ (2,000,000)	$ (2,000,000)

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Stock-Based Compensation

12 Months Ended

Dec. 31, 2013

Stock-Based Compensation

Stock-Based Compensation

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 since 2012 were issued under the 2012 Plan, and 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 in 2013, 2012 and 2011, provided the members of the Board of 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.  The members of the Board of Directors who elect to defer may elect to receive payment in either stock, or 50% in cash and 50% in stock.  The members of the Board of Directors may elect to receive payments either as of the last business day of the month following the month in which they separate from service on the Board of Directors, 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 Directors 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 have been 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.  From 2010 through 2013, officers and key employees elected to receive payment in either stock, or 50% in cash and 50% in stock.

Restricted stock unit awards vest and settle over a four-year period.  In addition, officers and key employees accrue dividend rights on 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 through 2013 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.

In December 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 will accrue notional dividends equal to the amount of dividends that would have been received if the Chairman of the Board, President and Chief Executive Officer had directly owned one share of Pinnacle West common stock for each restricted stock unit held from the grant date to each dividend payment 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 vested 50% on February 15, 2013.  The remaining grant will vest 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 they would have received if they had directly owned one share of Pinnacle West common stock for each restricted stock unit held 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 2013, 2012 and 2011:

	2013		2012		2011
Units granted	129,620		202,278		292,242
Grant date fair value (a)	$	55.21	$	49.31	$	41.98

(a) Weighted-average grant date fair value.

The following table is a summary of the status of restricted stock units and stock grants, as of December 31, 2013 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, 2013	480,753	$	43.58
Granted	129,620	55.21
Vested	191,988	40.33
Forfeited	20,409	45.70
Nonvested at December 31, 2013	397,976	47.74

The amount of cash required to settle the payments on restricted stock units is (dollars in millions):

Year	2013		2012		2011
2007 Grant	$	—	$	—	$	1.0
2008 Grant	—		1.9		1.6
2009 Grant	3.0		1.7		1.5
2010 Grant	2.3		0.6		0.6
2011 Grant	2.5		0.7		—
2012 Grant	2.2		—		—

Performance Share Awards

Performance share awards have been granted to officers and key employees under the 2012 Plan since 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 2013, 2012 and 2011 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% is 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 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 2013, 2012 and 2011:

	2013		2012		2011
Units granted (a)	176,332		185,878		175,072
Grant date fair value (b)	$	55.45	$	47.40	$	41.71

(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, 2013 and changes during the year:

Nonvested shares (a)	Shares	Weighted-Average Grant Date Fair Value
Nonvested at January 1, 2013	347,690	$	44.67
Granted	176,332	55.45
Increase in performance factor	40,183	41.71
Vested	200,915	41.71
Forfeited	18,894	48.11
Nonvested at December 31, 2013	344,396	51.13

(a) Nonvested shares are reflected at 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.

Stock Options

The Company has not granted stock options since 2004 and has no stock options outstanding.

The following table summarizes the option activity under prior equity incentive plans for the year ended December 31, 2013:

Options	Shares	Weighted- Average  Exercise  Price
Outstanding at January 1, 2013	7,925	$	32.29
Exercised	3,625	32.29
Forfeited or expired	4,300	32.29
Outstanding at December 31, 2013	—	—

Cash received from options exercised under our share-based payment arrangements was $0.1 million for 2013, $0.5 million for 2012, and $1.8 million for 2011.  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, 2013, 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 2013, 2012 and 2011 was $20 million, $19 million and $14 million, respectively.

The compensation cost that has been charged against Pinnacle West’s income for share-based compensation plans was $25 million in 2013, $32 million in 2012, and $23 million in 2011.  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 $10 million in 2013, $13 million in 2012, and $9 million in 2011.  APS’s share of compensation cost that has been charged against income was $25 million in 2013, $32 million in 2012, and $22 million in 2011.

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.

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Details 2) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Current assets
Cash and cash equivalents	$ 9,526	$ 26,202	$ 33,583	$ 110,188
Accounts receivable	299,904	277,225
Current deferred income taxes	91,152	152,191
Income tax receivable	135,517	2,423
Other current assets	39,895	37,102
Total current assets	1,043,609	1,005,726
Investments and other assets
Other assets	60,875	62,694
Total investments and other assets	726,697	669,210
TOTAL ASSETS	13,508,686	13,379,615
Current liabilities
Accounts payable	284,516	221,312
Accrued taxes (Note 4)	130,998	124,939
Common dividends payable	62,528	59,789
Other current liabilities	158,540	171,573
Total current liabilities	1,618,644	1,083,542
Long-term debt less current maturities	2,796,465	3,199,088
Deferred credits and other
Deferred income taxes (Note 4)	2,351,882	2,151,371
Pension and other postretirement liabilities	513,628	1,058,755
Other	185,659	183,835
Total deferred credits and other	4,753,117	4,994,696
Common stock equity
Common stock	2,491,558	2,466,923
Accumulated other comprehensive loss	(78,053)	(114,008)
Retained earnings	1,785,273	1,624,102
Total shareholders' equity	4,194,470	3,972,806
Noncontrolling interests	145,990	129,483
Total equity	4,340,460	4,102,289	3,930,586
TOTAL LIABILITIES AND EQUITY	13,508,686	13,379,615
Pinnacle West
Current assets
Cash and cash equivalents	5,798	22,679	12,710	7,725
Accounts receivable	80,108	92,906
Current deferred income taxes	93,185	77,771
Income tax receivable	1,853	3,350
Other current assets	242	25
Total current assets	181,186	196,731
Investments and other assets
Investments in subsidiaries	4,455,049	4,223,301
Other assets	13,789	13,833
Total investments and other assets	4,468,838	4,237,134
TOTAL ASSETS	4,650,024	4,433,865
Current liabilities
Accounts payable	3,279	5,735
Accrued taxes (Note 4)	8,538	8,239
Common dividends payable	62,528	59,789
Other current liabilities	31,295	41,000
Total current liabilities	105,640	114,763
Long-term debt less current maturities	125,000	125,000
Deferred credits and other
Deferred income taxes (Note 4)	4,158	17,395
Pension and other postretirement liabilities	37,611	41,199
Other	37,155	33,219
Total deferred credits and other	78,924	91,813
Common stock equity
Common stock	2,487,250	2,462,712
Accumulated other comprehensive loss	(78,053)	(114,008)
Retained earnings	1,785,273	1,624,102
Total shareholders' equity	4,194,470	3,972,806
Noncontrolling interests	145,990	129,483
Total equity	4,340,460	4,102,289
TOTAL LIABILITIES AND EQUITY	$ 4,650,024	$ 4,433,865

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Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2013

Stock-Based Compensation

Summary of granted restricted stock units and stock grants and the weighted average fair value

	2013		2012		2011
Units granted	129,620		202,278		292,242
Grant date fair value (a)	$	55.21	$	49.31	$	41.98

(a) Weighted-average grant date fair value.

Summary of the status of restricted stock units and stock grants and changes during the year

Nonvested shares	Shares	Weighted-Average Grant Date Fair Value
Nonvested at January 1, 2013	480,753	$	43.58
Granted	129,620	55.21
Vested	191,988	40.33
Forfeited	20,409	45.70
Nonvested at December 31, 2013	397,976	47.74

Schedule of amount of cash required to settle the payments on restricted stock units

The amount of cash required to settle the payments on restricted stock units is (dollars in millions):

Year	2013		2012		2011
2007 Grant	$	—	$	—	$	1.0
2008 Grant	—		1.9		1.6
2009 Grant	3.0		1.7		1.5
2010 Grant	2.3		0.6		0.6
2011 Grant	2.5		0.7		—
2012 Grant	2.2		—		—

Summary of the performance shares granted and the weighted average fair value

	2013		2012		2011
Units granted (a)	176,332		185,878		175,072
Grant date fair value (b)	$	55.45	$	47.40	$	41.71

(a) Reflects the target payout level.

(b) Weighted-average grant date fair value.

Summary of the status of performance shares and changes during the year

Nonvested shares (a)	Shares	Weighted-Average Grant Date Fair Value
Nonvested at January 1, 2013	347,690	$	44.67
Granted	176,332	55.45
Increase in performance factor	40,183	41.71
Vested	200,915	41.71
Forfeited	18,894	48.11
Nonvested at December 31, 2013	344,396	51.13

(a) Nonvested shares are reflected at 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.

Summary of stock option activity under prior equity incentive plans

Options	Shares	Weighted- Average  Exercise  Price
Outstanding at January 1, 2013	7,925	$	32.29
Exercised	3,625	32.29
Forfeited or expired	4,300	32.29
Outstanding at December 31, 2013	—	—

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Income Taxes (APSC)

12 Months Ended

Dec. 31, 2013

Income Taxes

4.             Income Taxes

Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes.  The tax effect of these differences is recorded as deferred taxes.  We calculate deferred taxes using 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 ITCs 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 $70 million long-term income tax receivable on the Consolidated Balance Sheets as of December 31, 2012 represented the anticipated refund related to an APS tax accounting method change approved by the IRS in the third quarter of 2009.  On July 9, 2013, IRS guidance was released which provided clarification regarding the timing and amount of this cash receipt.  As a result of this guidance, uncertain tax positions decreased $67 million during the third quarter.  This decrease in uncertain tax positions resulted in a corresponding increase to the total anticipated refund due from the IRS and an offsetting increase in long-term deferred tax liabilities.  Additionally, as a result of this IRS guidance, the resulting $137 million anticipated refund was reclassified to current income tax receivable.

During the year ended December 31, 2013, the IRS finalized the examination of tax returns for the years ended December 31, 2008 and 2009, and the $137 million anticipated refund was reduced by approximately $4 million to reflect the outcome of this examination.  On December 17, 2013, the Joint Committee on Taxation approved the anticipated refund.  Cash related to this refund was received in the first quarter of 2014.

On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property.  These final regulations apply to tax years beginning on or after January 1, 2014.  Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS, resulting in a cumulative effect adjustment.  To account for the adoption of these regulations, plant-related long-term deferred tax liabilities decreased by $84 million, with the offsetting decrease to current deferred income tax assets.  Prior to the issuance of these regulations, this $84 million would have been repaid over 20 years through lower tax depreciation deductions.

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 19).  As a result, there is no income tax expense associated with the VIEs recorded on the Consolidated Statements of Income.

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):

	2013			2012			2011
Total unrecognized tax benefits, January 1	$	133,422		$	136,005		$	127,595
Additions for tax positions of the current year	3,516			5,167			10,915
Additions for tax positions of prior years	13,158			—			—
Reductions for tax positions of prior years for:
Changes in judgment	(108,099		)	(7,729		)	(1,555		)
Settlements with taxing authorities	—			—			(124		)
Lapses of applicable statute of limitations	—			(21		)	(826		)
Total unrecognized tax benefits, December 31	$	41,997		$	133,422		$	136,005

Included in the balances of unrecognized tax benefits at December 31, 2013, 2012 and 2011 were approximately $10 million, $10 million and $8 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, 2010 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 2010.

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 benefit of $4 million for 2013, a pre-tax expense of $4 million for 2012, and a pre-tax expense of $3 million for 2011.

The total amount of accrued liabilities for interest recognized in the Consolidated Balance Sheets related to unrecognized tax benefits was less than $1 million as of December 31, 2013, $13 million as of December 31, 2012 and $9 million as of December 31, 2011.  To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate.  Additionally, as of December 31, 2013, 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,
	2013			2012			2011
Current:
Federal	$	(81,784	)	$	(3,493	)	$	(310	)
State	10,537			8,395			15,140
Total current	(71,247		)	4,902			14,830
Deferred:
Federal	279,973			200,322			159,566
State	21,865			28,280			16,626
Total deferred	301,838			228,602			176,192
Total income tax expense	230,591			233,504			191,022
Less: income tax expense (benefit) on discontinued operations	—			(3,813		)	7,418
Income tax expense — continuing operations	$	230,591		$	237,317		$	183,604

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,
	2013			2012			2011
Federal income tax expense at 35% statutory rate	$	234,695		$	229,709		$	188,733
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	21,387			23,819			19,594
Credits and favorable adjustments related to prior years resolved in current year	(3,356		)	—			—
Medicare Subsidy Part-D	823			483			823
Allowance for equity funds used during construction (see Note 1)	(6,997		)	(6,158		)	(6,881		)
Palo Verde VIE noncontrolling interest (see Note 19)	(11,862		)	(11,065		)	(9,636		)
Other	(4,099		)	529			(9,029		)
Income tax expense — continuing operations	$	230,591		$	237,317		$	183,604

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

	December 31,
	2013			2012
Current asset	$	91,152		$	152,191
Long-term liability	(2,351,882		)	(2,151,371		)
Deferred income taxes — net	$	(2,260,730	)	$	(1,999,180	)

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, 2013 APS has recorded a regulatory liability of $75 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five-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 New Mexico. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability.  As of December 31, 2013, APS has recorded a regulatory liability of $2 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

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

	December 31,
	2013			2012
DEFERRED TAX ASSETS
Risk management activities	$	44,920		$	72,243
Regulatory liabilities:
Asset retirement obligation and removal costs	235,959			238,669
Unamortized investment tax credits	82,116			53,837
Other	42,609			33,764
Pension and other postretirement liabilities	198,642			408,764
Renewable energy incentives	65,434			66,941
Credit and loss carryforwards	133,070			139,022
Other	148,492			68,844
Total deferred tax assets	951,242			1,082,084
DEFERRED TAX LIABILITIES
Plant-related	(2,903,730		)	(2,584,166		)
Risk management activities	(16,191		)	(23,940		)
Regulatory assets:
Allowance for equity funds used during construction	(43,058		)	(37,899		)
Deferred fuel and purchased power	(8,282		)	(28,858		)
Deferred fuel and purchased power — mark-to-market	(13,343		)	(15,796		)
Pension and other postretirement benefits	(129,250		)	(316,757		)
Other	(93,202		)	(68,170		)
Other	(4,916		)	(5,678		)
Total deferred tax liabilities	(3,211,972		)	(3,081,264		)
Deferred income taxes — net	$	(2,260,730	)	$	(1,999,180	)

As of December 31, 2013, the deferred tax assets for credit and loss carryforwards relate to federal general business credits of $131 million which first begin to expire in 2031, and other federal and state loss carryforwards of $2 million which first begin to expire in 2018.

ARIZONA PUBLIC SERVICE COMPANY

Income Taxes

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.

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 currently enacted 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 ITCs and the change in income tax rates.

In accordance with regulatory requirements, APS ITCs 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 as of December 31, 2012 represented the anticipated refund related to an APS tax accounting method change approved by the IRS in the third quarter of 2009.  On July 9, 2013, IRS guidance was released which provided clarification regarding the timing and amount of this cash receipt.  As a result of this guidance, uncertain tax positions decreased $67 million during the third quarter.  This decrease in uncertain tax positions resulted in a corresponding increase to the total anticipated refund due from the IRS and an offsetting increase in long-term deferred tax liabilities.  Additionally, as a result of this IRS guidance, the $138 million anticipated refund was reclassified to current income tax receivable.

During the year ended December 31, 2013, the IRS finalized the examination of tax returns for the years ended December 31, 2008 and 2009, and the $138 million anticipated refund was reduced by approximately $2 million to reflect the outcome of this examination.  On December 17, 2013, the Joint Committee on Taxation approved the anticipated refund.  Cash related to this refund was received in the first quarter of 2014.

On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property.  These final regulations apply to tax years beginning on or after January 1, 2014.  Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS resulting in a cumulative effect adjustment.  To account for the adoption of these regulations plant-related long-term deferred tax liabilities decreased by $84 million, with the offsetting decrease to current deferred income tax assets.  Prior to the issuance of these regulations, this $84 million would have been repaid over 20 years through lower tax depreciation deductions.

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 19).  As a result, there is no income tax expense associated with the VIEs recorded on APS’s Consolidated Statements of Income.

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):

	2013			2012			2011
Total unrecognized tax benefits, January 1	$	133,241		$	135,824		$	126,698
Additions for tax positions of the current year	3,516			5,167			10,915
Additions for tax positions of prior years	13,158			—			—
Reductions for tax positions of prior years for:
Changes in judgment	(107,918		)	(7,729		)	(1,555		)
Settlements with taxing authorities	—			—			(124		)
Lapses of applicable statute of limitations	—			(21		)	(110		)
Total unrecognized tax benefits, December 31	$	41,997		$	133,241		$	135,824

Included in the balance of unrecognized tax benefits at December 31, 2013, 2012 and 2011 were approximately $10 million, $10 million and $8 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, 2010 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 2010.

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 benefit of $4 million for 2013, a pre-tax expense of $4 million for 2012 and a pre-tax expense of $3 million for 2011.

The total amount of accrued liabilities for interest recognized in the Balance Sheets related to unrecognized tax benefits was less than $1 million as of December 31, 2013, $13 million as of December 31, 2012 and $9 million as of December 31, 2011.  To the extent that matters are settled favorably, this amount could be reversed and decrease our effective tax rate.  Additionally, as of December 31, 2013, 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):

	Year Ended December 31,
	2013			2012			2011
Current:
Federal	$	(97,531	)	$	(11,650	)	$	4,633
State	11,983			12,308			19,104
Total current	(85,548		)	658			23,737
Deferred:
Federal	305,389			216,367			154,632
State	25,254			27,371			14,173
Total deferred	330,643			243,738			168,805
Total income tax expense	$	245,095		$	244,396		$	192,542

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):

	Year Ended December 31,
	2013			2012			2011
Federal income tax expense at 35% statutory rate	$	246,384		$	235,027		$	194,710
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	23,970			25,379			21,139
Credits and favorable adjustments related to prior years resolved in current year	(3,231		)	—			—
Medicare Subsidy Part-D	823			483			823
Allowance for equity funds used during construction (see Note 1)	(6,997		)	(6,158		)	(6,880		)
Palo Verde VIE noncontrolling interest (see Note 19)	(11,862		)	(11,065		)	(9,633		)
Other	(3,992		)	730			(7,617		)
Income tax expense	$	245,095		$	244,396		$	192,542

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

	December 31,
	2013			2012
Current asset (liability)	$	(2,033	)	$	74,420
Long-term liability	(2,347,724		)	(2,133,976		)
Deferred income taxes — net	$	(2,349,757	)	$	(2,059,556	)

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, 2013, APS has recorded a regulatory liability of $75 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five-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 New Mexico.  In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability.  As of December 31, 2013, APS has recorded a regulatory liability of $2 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

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

	December 31,
	2013			2012
DEFERRED TAX ASSETS
Regulatory liabilities:
Asset retirement obligation and removal costs	$	235,959		$	238,669
Unamortized investment tax credits	82,116			53,837
Other	42,609			33,764
Risk management activities	44,920			72,243
Pension and other postretirement liabilities	186,213			392,486
Renewable energy incentives	65,434			66,941
Credit and loss carryforwards	38,183			52,441
Other	166,781			111,327
Total deferred tax assets	862,215			1,021,708
DEFERRED TAX LIABILITIES
Plant-related	(2,903,730		)	(2,584,166		)
Risk management activities	(16,191		)	(23,940		)
Regulatory assets:
Allowance for equity funds used during construction	(43,058		)	(37,899		)
Deferred fuel and purchased power	(8,282		)	(28,858		)
Deferred fuel and purchased power — mark-to-market	(13,343		)	(15,796		)
Pension and other postretirement benefits	(129,250		)	(316,757		)
Other	(93,202		)	(68,170		)
Other	(4,916		)	(5,678		)
Total deferred tax liabilities	(3,211,972		)	(3,081,264		)
Deferred income taxes — net	$	(2,349,757	)	$	(2,059,556	)

As of December 31, 2013, the deferred tax assets for credit and loss carryforwards relate primarily to federal general business credits which first begin to expire in 2031.

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Retirement Plans and Other Benefits (Tables)

12 Months Ended

Dec. 31, 2013

Retirement Plans and Other Benefits

Schedule of 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 or amortized to the regulatory asset)

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):

	Pension									Other Benefits
	2013			2012			2011			2013			2012			2011
Service cost-benefits earned during the period	$	64,195		$	63,502		$	57,605		$	23,597		$	27,163		$	21,856
Interest cost on benefit obligation	112,392			119,586			124,727			41,536			46,467			46,807
Expected return on plan assets	(146,333		)	(140,979		)	(133,678		)	(45,717		)	(45,793		)	(41,536		)
Amortization of:
Transition obligation	—			—			—			—			452			452
Prior service cost (credit)	1,097			1,143			1,400			(179		)	(179		)	(179		)
Net actuarial loss	39,852			44,250			25,956			11,310			20,233			15,015
Net periodic benefit cost	$	71,203		$	87,502		$	76,010		$	30,547		$	48,343		$	42,415
Portion of cost charged to expense	$	38,968		$	36,333		$	29,312		$	18,469		$	19,321		$	15,208

Schedule of changes in the benefit obligations and funded status

The following table shows the plans’ changes in the benefit obligations and funded status for the years 2013 and 2012 (dollars in thousands):

	Pension						Other Benefits
	2013			2012			2013			2012
Change in Benefit Obligation
Benefit obligation at January 1	$	2,850,846		$	2,699,126		$	990,418		$	1,047,094
Service cost	64,195			63,502			23,597			27,163
Interest cost	112,392			119,586			41,536			46,467
Benefit payments	(125,269		)	(113,632		)	(26,675		)	(26,279		)
Actuarial (gain) loss	(255,634		)	82,264			(138,458		)	(104,027		)
Benefit obligation at December 31	2,646,530			2,850,846			890,418			990,418
Change in Plan Assets
Fair value of plan assets at January 1	2,079,181			1,850,550			684,221			608,663
Actual return on plan assets	150,546			259,363			76,995			83,567
Employer contributions	140,500			65,000			14,438			22,707
Benefit payments	(106,106		)	(95,732		)	(27,315		)	(30,716		)
Fair value of plan assets at December 31	2,264,121			2,079,181			748,339			684,221
Funded Status at December 31	$	(382,409	)	$	(771,665	)	$	(142,079	)	$	(306,197	)

Schedule of projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets

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, 2013 and 2012 (dollars in thousands):

	2013		2012
Projected benefit obligation	$	2,646,530	$	2,850,846
Accumulated benefit obligation	2,469,889		2,646,306
Fair value of plan assets	2,264,121		2,079,181

Schedule of amounts recognized on the Consolidated Balance Sheets

The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2013 and 2012 (dollars in thousands):

	Pension						Other Benefits
	2013			2012			2013			2012
Current liability	$	(10,860	)	$	(19,107	)	$	—		$	—
Noncurrent liability	(371,549		)	(752,558		)	(142,079		)	(306,197		)
Net amount recognized	$	(382,409	)	$	(771,665	)	$	(142,079	)	$	(306,197	)

Schedule of accumulated other comprehensive loss

The following table shows the details related to accumulated other comprehensive loss as of December 31, 2013 and 2012 (dollars in thousands):

	Pension						Other Benefits
	2013			2012			2013			2012
Net actuarial loss	$	344,540		$	644,239		$	57,816		$	238,862
Prior service cost (credit)	2,072			3,169			(296		)	(475		)
APS’s portion recorded as a regulatory asset	(265,107		)	(550,471		)	(49,298		)	(230,020		)
Income tax benefit	(32,204		)	(38,303		)	(2,528		)	(2,585		)
Accumulated other comprehensive loss	$	49,301		$	58,634		$	5,694		$	5,782

Schedule of estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost

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 2014 (dollars in thousands):

	Pension		Other Benefits
Net actuarial loss	$	8,363	$	—
Prior service cost (credit)	874		(179		)
Total amounts estimated to be amortized from accumulated other comprehensive loss and regulatory assets in 2014	$	9,237	$	(179	)

Schedule of weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs

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:

	Benefit Obligations As of December 31,				Benefit Costs For the Years Ended December 31,
	2013		2012		2013		2012		2011
Discount rate – pension	4.88	%	4.01	%	4.01	%	4.42	%	5.31	%
Discount rate – other benefits	5.10	%	4.20	%	4.20	%	4.59	%	5.49	%
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		7.00	%	7.75	%	7.75	%
Initial healthcare cost trend rate	7.50	%	7.50	%	7.50	%	7.50	%	8.00	%
Ultimate healthcare 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

Schedule of effects of one percentage point change in the assumed initial and ultimate health care cost trend rates

A one percentage point change in the assumed initial and ultimate healthcare 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	$	13	$	(10	)
Effect on service and interest cost components of net periodic other postretirement benefit costs	14		(11		)
Effect on the accumulated other postretirement benefit obligation	149		(120		)

Schedule of fair value of pension plan and other postretirement benefit plan assets, by asset category

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2013, 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)		Significant Unobservable Inputs (Level 3)			Other (c)		Balance at December 31, 2013
Pension Plan:
Assets:
Cash and cash equivalents	$	504	$	—	$	—		$	—	$	504
Fixed Income Securities:
Corporate	—		898,621		—			—		898,621
U.S. Treasury	231,590		—		—			—		231,590
Other (b)	—		84,011		—			—		84,011
Equities:
U.S. Companies	239,036		—		—			—		239,036
International Companies	19,429		—		—			—		19,429
Common and collective trusts:
U.S. Equities	—		116,150		—			—		116,150
International Equities	—		367,551		—			—		367,551
Fixed Income			137,520							137,520
Real estate	—		119,739		—			—		119,739
Short-term investments and other	—		41,060		8,660		(a)	250		49,970
Total Pension Plan	$	490,559	$	1,764,652	$	8,660		$	250	$	2,264,121
Other Benefits:
Assets:
Fixed Income Securities:
Corporate	$	—	$	153,888	$	—		$	—	$	153,888
U.S. Treasury	98,704		—		—			—		98,704
Other (b)	—		27,936		—			—		27,936
Equities:
U.S. Companies	252,181		—		—			—		252,181
International Companies	20,892		—		—			—		20,892
Common and collective trusts:
U.S. Equities	—		80,751		—			—		80,751
International Equities	—		92,382		—			—		92,382
Real Estate	—		10,761		—			—		10,761
Short-term investments and other	—		8,414		—			2,430		10,844
Total Other Benefits	$	371,777	$	374,132	$	—		$	2,430	$	748,339

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

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

(c)           Represents plan receivables and payables.

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):

	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.

(c)           Represents plan receivables and payables.

Schedule of changes in fair value for assets that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3)

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, 2013 and 2012 (dollars in thousands):

	Pension
Short-Term Investments and Other	2013			2012
Beginning balance at January 1	$	2,419		$	—
Actual return on assets still held at December 31	(498		)	(668		)
Purchases, sales, and settlements	6,739			3,087
Transfers in and/or out of Level 3	—			—
Ending balance at December 31	$	8,660		$	2,419

Schedule of estimated future benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter

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
2014	$	129,159	$	28,664
2015	143,452		31,804
2016	149,105		34,933
2017	162,678		37,966
2018	169,064		40,972
Years 2019-2023	972,826		245,366

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Other Income and Other Expense (APSC)

12 Months Ended

Dec. 31, 2013

Other Income and Other Expense

18. Other Income and Other Expense

The following table provides detail of other income and other expense for 2013, 2012 and 2011 (dollars in thousands):

	2013			2012			2011
Other income:
Interest income	$	1,629		$	1,239		$	1,850
Investment gains — net	—			—			1,165
Miscellaneous	75			367			96
Total other income	$	1,704		$	1,606		$	3,111
Other expense:
Non-operating costs	$	(8,207	)	$	(7,777	)	$	(7,037	)
Investment loss — net	(3,711		)	(2,453		)	—
Miscellaneous	(4,106		)	(9,612		)	(3,414		)
Total other expense	$	(16,024	)	$	(19,842	)	$	(10,451	)

ARIZONA PUBLIC SERVICE COMPANY

Other Income and Other Expense

S-3. Other Income and Other Expense

The following table provides detail of APS’s other income and other expense for 2013, 2012 and 2011 (dollars in thousands):

	2013			2012			2011
Other income:
Interest income	$	1,234		$	310		$	406
Investment gains — net	—			—			1,418
Miscellaneous	2,662			2,558			3,247
Total other income	$	3,896		$	2,868		$	5,071
Other expense:
Non-operating costs (a)	$	(9,626	)	$	(8,706	)	$	(8,810	)
Asset dispositions	(4,992		)	(1,511		)	(1,352		)
Miscellaneous	(5,831		)	(10,933		)	(5,166		)
Total other expense	$	(20,449	)	$	(21,150	)	$	(15,328	)

(a) As defined by FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net unrealized loss, tax benefit	$ 140	$ 14,900	$ 37,389
Reclassification of net realized loss, tax benefit	17,472	39,120	46,288
Pension and other postretirement benefits activity, tax (expense) benefit	$ (6,156)	$ (651)	$ 3,935

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Derivative Accounting (Details 3) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Liabilities
Amount Reported on Balance Sheet	$ (102,207)	$ (159,005)
Commodity Contracts
Assets
Amount Reported on Balance Sheet	41,000
Assets and Liabilities
Gross Recognized Derivatives	(72,712)	(122,252)
Amounts Offset	19,000	49,299
Net Recognized Derivatives	(53,712)	(72,953)
Other	(7,511)	(24,462)
Amount Reported on Balance Sheet	(61,223)	(97,415)
Commodity Contracts | Current Assets
Assets
Gross Recognized Derivatives	24,587	42,495
Amounts Offset	(7,425)	(17,797)
Net Recognized Derivatives	17,162	24,698
Other	7	1,001
Amount Reported on Balance Sheet	17,169	25,699
Commodity Contracts | Investments and Other Assets
Assets
Gross Recognized Derivatives	25,364	41,563
Amounts Offset	(1,549)	(5,672)
Net Recognized Derivatives	23,815	35,891
Amount Reported on Balance Sheet	23,815	35,891
Commodity Contracts | Total Assets
Assets
Gross Recognized Derivatives	49,951	84,058
Amounts Offset	(8,974)	(23,469)
Net Recognized Derivatives	40,977	60,589
Other	7	1,001
Amount Reported on Balance Sheet	40,984	61,590
Commodity Contracts | Current Liabilities
Liabilities
Gross Recognized Derivatives	(50,540)	(105,324)
Amounts Offset	26,166	57,046
Net Recognized Derivatives	(24,374)	(48,278)
Other	(7,518)	(25,463)
Amount Reported on Balance Sheet	(31,892)	(73,741)
Commodity Contracts | Deferred Credits and Other
Liabilities
Gross Recognized Derivatives	(72,123)	(100,986)
Amounts Offset	1,808	15,722
Net Recognized Derivatives	(70,315)	(85,264)
Amount Reported on Balance Sheet	(70,315)	(85,264)
Commodity Contracts | Total Liabilities
Liabilities
Gross Recognized Derivatives	(122,663)	(206,310)
Amounts Offset	27,974	72,768
Net Recognized Derivatives	(94,689)	(133,542)
Other	(7,518)	(25,463)
Amount Reported on Balance Sheet	(102,207)	(159,005)
Designated as Hedging Instruments
Liabilities
Amount Reported on Balance Sheet	$ 5,000	$ 5,000

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CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
Common stock dividends declared (in dollars per share)	$ 2.23	$ 2.67	$ 2.10

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Regulatory Matters (Details 2) (Four Corners, SCE, USD $) In Millions, unless otherwise specified		0 Months Ended
	Dec. 31, 2013	Dec. 30, 2013 APS MW
Acquisition
Total Entitlement		970
Ownership interest acquired		48.00%
Percent Owned		63.00%
Purchase price		$ 182
Plant-in-service		316
Acquisition adjustment		255
Decommissioning obligations		34
Mine reclamation obligations		93
Other various liabilities		18
Construction work in progress		11
Deferral balance related to the acquisition of SCE's interest in Units 4 and 5 and the closure of Four Corners Units 1-3	37
Capacity rights over the Arizona Transmission System assign to third-parties		1,555
Capacity rights related to marketing and trading group for transmission of the additional power received assign to third-parties		300
Net receipt due to negotiation of alternate arrangement		$ 40

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Fair Value Measurements (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 41	$ 62
Liabilities	90	110
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
Net derivative balance at beginning of period	(48)	(51)
Total net gains (losses) realized/unrealized:
Included in earnings		2
Included in OCI		(3)
Deferred as a regulatory asset or liability	(10)	7
Settlements	10	(5)
Transfers into Level 3 from Level 2		(2)
Transfers from Level 3 into Level 2	(1)	4
Net derivative balance at end of period	(49)	(48)
Transfers in or out of Level 1 to or from any other hierarchy level	0
Electricity forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	40	57
Liabilities	66	82
Electricity forward contracts | Minimum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	24.89	23.06
Electricity forward contracts | Maximum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	65.04	64.20
Electricity forward contracts | Weighted Average | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	41.09	43.16
Option Contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Liabilities	19	27
Option Contracts | Minimum | Option model
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	39.91	36.66
Implied electricity price volatilities (as a percent)	35.00%	15.00%
Natural gas forward price (per MMbtu)	3.57	4.10
Implied natural gas price volatilities (as a percent)	22.00%	17.00%
Option Contracts | Maximum | Option model
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	85.41	92.19
Implied electricity price volatilities (as a percent)	94.00%	66.00%
Natural gas forward price (per MMbtu)	3.80	4.25
Implied natural gas price volatilities (as a percent)	36.00%	36.00%
Option Contracts | Weighted Average | Option model
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh)	58.70	60.97
Implied electricity price volatilities (as a percent)	59.00%	39.00%
Natural gas forward price (per MMbtu)	3.71	4.20
Implied natural gas price volatilities (as a percent)	27.00%	23.00%
Natural gas forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	1	5
Liabilities	$ 5	$ 1
Natural gas forward contracts | Minimum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Natural gas forward price (per MMbtu)	3.47	3.25
Natural gas forward contracts | Maximum | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Natural gas forward price (per MMbtu)	4.31	4.44
Natural gas forward contracts | Weighted Average | Discounted cash flows
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Natural gas forward price (per MMbtu)	3.87	3.93

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Selected Quarterly Financial Data (Unaudited) (APSC)

12 Months Ended

Dec. 31, 2013

Selected Quarterly Financial Data (Unaudited)

13. Selected Quarterly Financial Data (Unaudited)

Consolidated quarterly financial information for 2013 and 2012 is provided in the tables below (dollars in thousands, except per share amounts).  Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.

	2013 Quarter Ended								2013
	March 31,		June 30,		Sept. 30,		Dec. 31,		Total
Operating revenues	$	686,652	$	915,822	$	1,152,392	$	699,762	$	3,454,628
Operations and maintenance	223,250		229,300		233,323		238,854		924,727
Operating income	86,923		259,812		415,688		83,900		846,323
Income taxes	12,469		77,043		131,912		9,167		230,591
Income from continuing operations	32,836		139,598		234,718		32,814		439,966
Net income attributable to common shareholders	24,444		131,207		226,163		24,260		406,074
Earnings Per Share:
Income from continuing operations attributable to common shareholders — Basic	$	0.22	$	1.19	$	2.06	$	0.22	$	3.69
Net income attributable to common shareholders — Basic	0.22		1.19		2.06		0.22		3.69
Income from continuing operations attributable to common shareholders — Diluted	0.22		1.18		2.04		0.22		3.66
Net income attributable to common shareholders — Diluted	0.22		1.18		2.04		0.22		3.66

	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

ARIZONA PUBLIC SERVICE COMPANY

Selected Quarterly Financial Data (Unaudited)

S-2. Selected Quarterly Financial Data (Unaudited)

Quarterly financial information for 2013 and 2012 is as follows (dollars in thousands):

	2013 Quarter Ended,								2013
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	685,827	$	915,065	$	1,151,535	$	698,824	$	3,451,251
Operations and maintenance	220,752		224,950		222,617		229,505		897,824
Operating income	74,862		183,728		284,251		79,024		621,865
Net income attributable to common shareholder	26,042		133,949		234,954		30,024		424,969

	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

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Common Stock and Treasury Stock (Details) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in equity
Balance	$ 4,340,460	$ 4,102,289	$ 3,930,586
Balance at the end of the period (in shares)	110,280,703	109,837,957
Pinnacle West
Changes in equity
Balance	4,340,460	4,102,289
Serial preferred stock authorized	10,000,000
Par value (in dollars per share)	$ 0
Preferred stock outstanding	0
ARIZONA PUBLIC SERVICE COMPANY
Changes in equity
Balance	4,454,874	4,222,483	4,051,406
Serial preferred stock authorized	15,535,000
Preferred stock outstanding	0
Par value of type 1 preferred stock authorized (in dollars per share)	$ 25
Par value of type 2 preferred stock authorized (in dollars per share)	$ 50
Par value of type 3 preferred stock authorized (in dollars per share)	$ 100
Common Stock
Changes in equity
Balance	2,466,923	2,444,247	2,421,372
Balance at the beginning of the period (in shares)	109,837,957	109,356,974	108,820,067
Common stock issuance	24,635	22,676	22,875
Common stock issuance (in shares)	442,746	480,983	536,907
Balance	2,491,558	2,466,923	2,444,247
Balance at the end of the period (in shares)	110,280,703	109,837,957	109,356,974
Common Stock | ARIZONA PUBLIC SERVICE COMPANY
Changes in equity
Balance	178,162	178,162	178,162
Treasury Stock
Changes in equity
Balance	(4,211)	(4,717)	(2,239)
Balance at the beginning of the period (in shares)	(95,192)	(111,161)	(50,410)
Purchase of treasury stock	(9,727)	(4,607)	(3,720)
Purchase of treasury stock (in shares)	(174,290)	(89,629)	(88,440)
Reissuance of treasury stock used for stock compensation	9,630	5,113	1,242
Reissuance of treasury stock for stock compensation (in shares)	170,538	105,598	27,689
Balance	$ (4,308)	$ (4,211)	$ (4,717)
Balance at the end of the period (in shares)	(98,944)	(95,192)	(111,161)

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Derivative Accounting

12 Months Ended

Dec. 31, 2013

Derivative Accounting

Derivative Accounting

17. 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 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.  When amounts have been reclassified from accumulated OCI to earnings, they will be subject to deferral in accordance with the PSA.  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, after May 31, 2012, effectiveness testing is no longer being performed for these contracts.

Prior to the 2012 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 2012 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.

As of December 31, 2013, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

Commodity	Quantity
Power	5,765	GWh
Gas	108	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, 2013, 2012 and 2011 (dollars in thousands):

		Year Ended
	Financial Statement	December 31,
Commodity Contracts	Location	2013			2012			2011
Loss Recognized in OCI on Derivative Instruments (Effective Portion)	OCI — derivative instruments	$	(353	)	$	(37,663	)	$	(94,660	)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	(44,219		)	(99,007		)	(117,189		)
Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Fuel and purchased power (b)	—			117			(211		)

(a) During the years ended December 31, 2013, 2012, and 2011, we had zero, $1.8 million, and zero losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

(b) Amounts are before the effect of PSA deferrals.

During the next twelve months, we estimate that a net loss of $21 million before income taxes will be reclassified from accumulated OCI 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, 2013, 2012 and 2011 (dollars in thousands):

		Year Ended
	Financial Statement	December 31,
Commodity Contracts	Location	2013			2012			2011
Net Gain (Loss) Recognized in Income	Operating revenues (a)	$	289		$	103		$	(27	)
Net Loss Recognized in Income	Fuel and purchased power (a)	(10,449		)	(2,747		)	(52,113		)
Total		$	(10,160	)	$	(2,644	)	$	(52,140	)

(a) Amounts are before the effect of PSA deferrals.

Derivative Instruments in the Consolidated Balance Sheets

Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty.  Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements.  Transactions with counterparties that have master netting arrangements are offset and reported net on the Consolidated Balance Sheets.  Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Consolidated Balance Sheets.

We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default.  Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement.  These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit).  These types of transactions are excluded from the offsetting tables presented below.

The significant majority of our derivative instruments are not currently designated as hedging instruments.  The Consolidated Balance Sheets as of December 31, 2013 and December 31, 2012, include gross liabilities of $5 million of derivative instruments designated as hedging instruments.

The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of December 31, 2013 and 2012.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets.

As of December 31, 2013:(dollars in thousands)	Gross  Recognized  Derivatives(a)			Amounts  Offset (b)			NetRecognizedDerivatives			Other(c)			Amount  Reported on  Balance Sheet
Current Assets	$	24,587		$	(7,425	)	$	17,162		$	7		$	17,169
Investments and Other Assets	25,364			(1,549		)	23,815			—			23,815
Total Assets	49,951			(8,974		)	40,977			7			40,984
Current Liabilities	(50,540		)	26,166			(24,374		)	(7,518		)	(31,892		)
Deferred Credits and Other	(72,123		)	1,808			(70,315		)	—			(70,315		)
Total Liabilities	(122,663		)	27,974			(94,689		)	(7,518		)	(102,207		)
Total	$	(72,712	)	$	19,000		$	(53,712	)	$	(7,511	)	$	(61,223	)

(a) All of our gross recognized derivative instruments were subject to master netting arrangements.

(b) Includes cash collateral provided to counterparties of $19,000.

(c) Represents cash collateral and margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $7,518, and cash margin provided to counterparties of $7.

As of December 31, 2012:(dollars in thousands)	GrossRecognizedDerivatives(a)			Amounts Offset  (b)			NetRecognizedDerivatives			Other(c)			AmountReported onBalance Sheet
Current Assets	$	42,495		$	(17,797	)	$	24,698		$	1,001		$	25,699
Investments and Other Assets	41,563			(5,672		)	35,891			—			35,891
Total Assets	84,058			(23,469		)	60,589			1,001			61,590
Current Liabilities	(105,324		)	57,046			(48,278		)	(25,463		)	(73,741		)
Deferred Credits and Other	(100,986		)	15,722			(85,264		)	—			(85,264		)
Total Liabilities	(206,310		)	72,768			(133,542		)	(25,463		)	(159,005		)
Total	$	(122,252	)	$	49,299		$	(72,953	)	$	(24,462	)	$	(97,415	)

(a) All of our gross recognized derivative instruments were subject to master netting arrangements.

(b) Includes cash collateral provided to counterparties of $49,299.

(c) Represents cash collateral relating to non-derivative instruments or derivatives qualifying for scope exceptions.  Includes cash collateral provided to counterparties of $1,001, and cash collateral received from counterparties of $25,463.  This amount is not subject to offsetting.

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 92% of Pinnacle West’s $41 million of risk management assets as of December 31, 2013.  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, 2013 (dollars in millions):

	December 31, 2013
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	123
Cash Collateral Posted	19
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)	66

(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 $180 million if our debt credit ratings were to fall below investment grade.

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Selected Quarterly Financial Data (Unaudited) (APSC) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Consolidated quarterly financial information
Operating revenues	$ 699,762	$ 1,152,392	$ 915,822	$ 686,652	$ 693,122	$ 1,109,475	$ 878,576	$ 620,631	$ 3,454,628	$ 3,301,804	$ 3,241,379
Operations and maintenance	238,854	233,323	229,300	223,250	237,141	220,729	216,236	210,663	924,727	884,769	904,286
Operating income	83,900	415,688	259,812	86,923	101,289	447,970	254,489	48,007	846,323	851,755	746,508
Net income (loss) attributable to common shareholder	24,260	226,163	131,207	24,444	22,631	244,823	122,345	(8,257)	406,074	381,542	339,473
ARIZONA PUBLIC SERVICE COMPANY
Consolidated quarterly financial information
Operating revenues	698,824	1,151,535	915,065	685,827	687,031	1,108,623	877,587	620,248	3,451,251	3,293,489
Operations and maintenance	229,505	222,617	224,950	220,752	233,320	218,403	213,746	208,447	897,824	873,916	895,917
Operating income	79,024	284,251	183,728	74,862	77,768	296,945	176,821	53,995	621,865	605,529	554,383
Net income (loss) attributable to common shareholder	$ 30,024	$ 234,954	$ 133,949	$ 26,042	$ 26,843	$ 247,831	$ 124,928	$ (4,105)	$ 424,969	$ 395,497	$ 336,249

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Leases (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013 item	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2008 item	Dec. 31, 1986 item
Leases
Lease expense	$ 18	$ 19	$ 21
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
2014	20
2015	17
2016	6
2017	5
2018	4
Thereafter	59
Total future lease commitments	111
APS
Leases
Lease expense	15	16	18
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
2014	17
2015	14
2016	5
2017	5
2018	4
Thereafter	59
Total future lease commitments	$ 104
Number of VIE lessor trusts	3			3	3
Palo Verde Lessor Trusts
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
Number of VIE lessor trusts					3

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Lines of Credit and Short-Term Borrowings (Tables)

12 Months Ended

Dec. 31, 2013

Lines of Credit and Short-Term Borrowings

Schedule of consolidated credit facilities and amounts available and outstanding

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2013 (dollars in millions):

Credit Facility	Expiration	Amount Committed		Unused Amount (a)		Commitment Fees
Pinnacle West Revolving Credit Facility	November 2016	$	200	$	200	0.175	%
APS Revolving Credit Facility	November 2016	500		347		0.125	%
APS Revolving Credit Facility	April 2018	500		500		0.125	%
Total		$	1,200	$	1,047

(a) At December 31, 2013, APS had $153 million of outstanding commercial paper.  Accordingly, at such date, the total combined amount available under its two $500 million credit facilities was $847 million.

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

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.

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Jointly-Owned Facilities

12 Months Ended

Dec. 31, 2013

Jointly-Owned Facilities

Jointly-Owned Facilities

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 for providing our own financing.  Our share of operating expenses and utility plant costs related to these facilities is accounted for using proportional consolidation.  The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2013 (dollars in thousands):

	Percent Owned		Plant in Service		Accumulated Depreciation		Construction Work in Progress
Generating facilities:
Palo Verde Units 1 and 3	29.1	%	$	1,701,844	$	1,027,523	$	22,400
Palo Verde Unit 2 (a)	16.8	%	543,972		338,918		10,095
Palo Verde Common	28.0	% (b)	538,818		219,801		81,599
Palo Verde Sale Leaseback		(a)	351,050		225,925		—
Four Corners Units 4, 5 and Common (d)	63.0	%	809,946		608,194		14,434
Navajo Generating Station Units 1, 2 and 3	14.0	%	270,448		150,501		2,864
Cholla common facilities (c)	63.3	% (b)	148,299		47,851		7,159
Transmission facilities:
ANPP 500kV System	34.2	% (b)	98,145		32,350		1,095
Navajo Southern System	22.2	% (b)	58,702		16,937		518
Palo Verde — Yuma 500kV System	18.0	% (b)	12,115		4,656		11,786
Four Corners Switchyards	48.1	% (b)	33,460		9,052		185
Phoenix — Mead System	17.1	% (b)	39,758		12,140		—
Palo Verde — Estrella 500kV System	50.0	% (b)	89,571		14,883		21
Morgan — Pinnacle Peak System	64.5	% (b)	130,132		6,651		1,042
Round Valley System	50.0	% (b)	488		268		—
Palo Verde — Morgan System	90.0	% (b)	—		—		36,601

(a) See Note 19.

(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.

(d) See Note 3.

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CONSOLIDATED BALANCE SHEETS (APSC) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 10)
Plant in service and held for future use	$ 15,200,464	$ 14,346,367
Accumulated depreciation and amortization	(5,300,219)	(4,929,613)
Net	9,900,245	9,416,754
Construction work in progress	581,369	565,716
Palo Verde sale leaseback, net of accumulated depreciation of $225,925 and $222,055 (Note 19)	125,125	128,995
Intangible assets, net of accumulated amortization of $439,703 and $411,543	157,689	162,150
Nuclear fuel, net of accumulated amortization of $146,057 and $133,950	124,557	122,778
Total property, plant and equipment	10,888,985	10,396,393
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 14 and 20)	642,007	570,625
Assets from risk management activities (Note 17)	23,815	35,891
Other assets	60,875	62,694
Total investments and other assets	726,697	669,210
CURRENT ASSETS
Cash and cash equivalents	9,526	26,202
Customer and other receivables	299,904	277,225
Accrued unbilled revenues	96,796	94,845
Allowance for doubtful accounts	(3,203)	(3,340)
Materials and supplies (at average cost)	221,682	218,096
Fossil fuel (at average cost)	38,028	31,334
Income tax receivable	135,517	2,423
Assets from risk management activities (Note 17)	17,169	25,699
Deferred fuel and purchased power regulatory asset (Note 3)	20,755	72,692
Other regulatory assets (Note 3)	76,388	71,257
Deferred income taxes (Notes 4 and S-1)	91,152	152,191
Other current assets	39,895	37,102
Total current assets	1,043,609	1,005,726
DEFERRED DEBITS
Regulatory assets (Notes 1, 3, 4 and S-1)	711,712	1,099,900
Income tax receivable (Notes 4 and S-1)		70,389
Other	137,683	137,997
Total deferred debits	849,395	1,308,286
TOTAL ASSETS	13,508,686	13,379,615
CAPITALIZATION
Common stock	2,487,250	2,462,712
Retained earnings	1,785,273	1,624,102
Accumulated other comprehensive (loss):
Pension and other postretirement benefits (Note 8)	(54,995)	(64,416)
Derivative instruments (Note 17)	(23,058)	(49,592)
Total shareholders' equity	4,194,470	3,972,806
Noncontrolling interests (Note 19)	145,990	129,483
Total equity	4,340,460	4,102,289
Long-term debt less current maturities (Note 6)		3,160,219
CURRENT LIABILITIES
Short-term borrowings (Note 5)	153,125	92,175
Current maturities of long-term debt (Note 6)	540,424	122,828
Accounts payable	284,516	221,312
Accrued taxes (Notes 4 and S-1)	130,998	124,939
Accrued interest	48,351	49,380
Common dividends payable	62,528	59,789
Customer deposits	76,101	79,689
Liabilities from risk management activities (Note 17)	31,892	73,741
Regulatory liabilities (Note 3)	99,273	88,116
Other current liabilities	158,540	171,573
Total current liabilities	1,618,644	1,083,542
DEFERRED CREDITS AND OTHER
Deferred income taxes (Notes 4 and S-1)	2,351,882	2,151,371
Regulatory liabilities (Notes 1, 3, 4, and S-1)	801,297	759,201
Liability for asset retirements (Note 12)	313,833	357,097
Liabilities for pension and other postretirement benefits (Note 8)	513,628	1,058,755
Liabilities from risk management activities (Note 17)	70,315	85,264
Customer advances	114,480	109,359
Coal mine reclamation	207,453	118,860
Deferred investment tax credit	152,361	99,819
Unrecognized tax benefits (Notes 4 and S-1)	42,209	71,135
Other	185,659	183,835
Total deferred credits and other	4,753,117	4,994,696
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	13,508,686	13,379,615
ARIZONA PUBLIC SERVICE COMPANY
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 10)
Plant in service and held for future use	15,196,598	14,342,501
Accumulated depreciation and amortization	(5,296,501)	(4,925,990)
Net	9,900,097	9,416,511
Construction work in progress	581,369	565,716
Palo Verde sale leaseback, net of accumulated depreciation of $225,925 and $222,055 (Note 19)	125,125	128,995
Intangible assets, net of accumulated amortization of $439,703 and $411,543	157,534	161,995
Nuclear fuel, net of accumulated amortization of $146,057 and $133,950	124,557	122,778
Total property, plant and equipment	10,888,682	10,395,995
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 14 and 20)	642,007	570,625
Assets from risk management activities (Note 17)	23,815	35,891
Other assets	33,709	31,650
Total investments and other assets	699,531	638,166
CURRENT ASSETS
Cash and cash equivalents	3,725	3,499
Customer and other receivables	299,055	274,815
Accrued unbilled revenues	96,796	94,845
Allowance for doubtful accounts	(3,203)	(3,340)
Materials and supplies (at average cost)	221,682	218,096
Fossil fuel (at average cost)	38,028	31,334
Income tax receivable	135,179	589
Assets from risk management activities (Note 17)	17,169	25,699
Deferred fuel and purchased power regulatory asset (Note 3)	20,755	72,692
Other regulatory assets (Note 3)	76,388	71,257
Deferred income taxes (Notes 4 and S-1)	(2,033)	74,420
Deferred income taxes (Notes 4 and S-1)	0	74,420
Other current assets	39,153	37,077
Total current assets	944,727	900,983
DEFERRED DEBITS
Regulatory assets (Notes 1, 3, 4 and S-1)	711,712	1,099,900
Income tax receivable (Notes 4 and S-1)		70,784
Unamortized debt issue costs	21,860	22,492
Other	114,865	114,222
Total deferred debits	848,437	1,307,398
TOTAL ASSETS	13,381,377	13,242,542
CAPITALIZATION
Common stock	178,162	178,162
Additional paid-in capital	2,379,696	2,379,696
Retained earnings	1,804,398	1,624,237
Accumulated other comprehensive (loss):
Pension and other postretirement benefits (Note 8)	(30,313)	(39,503)
Derivative instruments (Note 17)	(23,059)	(49,592)
Total shareholders' equity	4,308,884	4,093,000
Noncontrolling interests (Note 19)	145,990	129,483
Total equity	4,454,874	4,222,483
Long-term debt less current maturities (Note 6)	2,671,465	3,074,088
Total capitalization	7,126,339	7,296,571
CURRENT LIABILITIES
Short-term borrowings (Note 5)	153,125	92,175
Current maturities of long-term debt (Note 6)	540,424	122,828
Accounts payable	281,237	215,577
Accrued taxes (Notes 4 and S-1)	122,460	116,700
Accrued interest	48,132	49,135
Common dividends payable	62,500	59,800
Customer deposits	76,101	79,689
Deferred income taxes	2,033
Liabilities from risk management activities (Note 17)	31,892	73,741
Liabilities for asset retirements (Note 12)	32,896
Regulatory liabilities (Note 3)	99,273	88,116
Other current liabilities	130,774	145,326
Total current liabilities	1,580,847	1,043,087
DEFERRED CREDITS AND OTHER
Deferred income taxes (Notes 4 and S-1)	2,347,724	2,133,976
Regulatory liabilities (Notes 1, 3, 4, and S-1)	801,297	759,201
Liability for asset retirements (Note 12)	313,833	357,097
Liabilities for pension and other postretirement benefits (Note 8)	476,017	1,017,556
Liabilities from risk management activities (Note 17)	70,315	85,264
Customer advances	114,480	109,359
Coal mine reclamation	207,453	118,860
Deferred investment tax credit	152,361	99,819
Unrecognized tax benefits (Notes 4 and S-1)	42,209	70,932
Other	148,502	150,820
Total deferred credits and other	4,674,191	4,902,884
TOTAL LIABILITIES AND EQUITY	$ 13,381,377	$ 13,242,542

CORRESP

LAW DEPARTMENT

Shirley A. Baum

Associate General Counsel

Direct Line: (602) 250-3706

February 21, 2014

Securities and Exchange Commission

100 F Street, N.E.

Washington, D.C.  20549

RE:Pinnacle West Capital Corporation Annual Report on Form 10-K

for the Fiscal Year Ended December 31, 2013

File No. 1-8962 and 1-4473

Ladies and Gentlemen:

Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, as amended, enclosed please find a complete copy of the Pinnacle West Capital Corporation and the Arizona Public Service Company Annual Report on Form 10-K (the “Form 10-K”) for the fiscal year ended December 31, 2013, including financial statements and exhibits, filed as a part thereof.  In 2013, there were no material changes in accounting principles or practices that impacted Pinnacle West Capital Corporation’s and Arizona Public Service Company’s consolidated financial statements.

If you have any questions with respect to the enclosed Form 10-K, please contact me at (602) 250-3706.

Sincerely,

/s/ Shirley A. Baum

Shirley A. Baum

SAB:bjd

Enclosure

APS · El Dorado

Pinnacle West Capital Corporation Law Department, 400 North Fifth Street, Station 8695, Post Office Box 53999 Phoenix, AZ 85072-3999

Phone:  602 250-3630, Fax: (602) 250-3393, E-mail:  shirley.baum@pinnaclewest.com