10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2017

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, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth 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)
	Emerging growth 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)
	Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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	$9,461,736,502.18 as of June 30, 2017
ARIZONA PUBLIC SERVICE COMPANY	$0 as of June 30, 2017

The number of shares outstanding of each registrant’s common stock as of February 16, 2018

PINNACLE WEST CAPITAL CORPORATION	111,799,789 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 16, 2018 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		ii
FORWARD-LOOKING STATEMENTS		1
PART I		2
Item 1.	Business	2
Item 1A.	Risk Factors	28
Item 1B.	Unresolved Staff Comments	40
Item 2.	Properties	41
Item 3.	Legal Proceedings	44
Item 4.	Mine Safety Disclosures	44
Executive Officers of Pinnacle West		45
PART II		46
Item 5.	Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	46
Item 6.	Selected Financial Data	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	81
Item 8.	Financial Statements and Supplementary Data	82
	Pinnacle West Financial Statements	86
	APS Financial Statements	95
	Combined Notes to Consolidated Financial Statements	101
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	179
Item 9A.	Controls and Procedures	179
Item 9B.	Other Information	180
PART III		180
Item 10.	Directors, Executive Officers and Corporate Governance of Pinnacle West	180
Item 11.	Executive Compensation	180
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	181
Item 13.	Certain Relationships and Related Transactions, and Director Independence	182
Item 14.	Principal Accountant Fees and Services	183
PART IV		184
Item 15.	Exhibits and Financial Statement Schedules	184
SIGNATURES		205

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 Combined Notes to Consolidated Financial Statements.

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GLOSSARY OF NAMES AND TECHNICAL TERMS

4CA	4C Acquisition, LLC, a wholly-owned subsidiary of Pinnacle West
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
ARO	Asset retirement obligations
ASU	Accounting Standards Update
BART	Best available retrofit technology
Base Fuel Rate	The portion of APS’s retail base rates attributable to fuel and purchased power costs
BCE	Bright Canyon Energy Corporation, a subsidiary of the Company
BHP Billiton	BHP Billiton New Mexico Coal, Inc.
BNCC	BHP Navajo Coal Company
CAISO	California Independent System Operator
CCR	Coal combustion residuals
Cholla	Cholla Power Plant
dc	Direct Current
distributed energy systems	Small-scale renewable energy technologies that are located on customers’ properties, such as rooftop solar systems
DOE	United States Department of Energy
DOI	United States Department of the Interior
DOJ	United States Department of Justice
DSM	Demand side management
EES	Energy Efficiency Standard
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
NERC	North American Electric Reliability Corporation
NRC	United States Nuclear Regulatory Commission
NTEC	Navajo Transitional Energy Company, LLC
OCI	Other comprehensive income
OSM	Office of Surface Mining Reclamation and Enforcement
Palo Verde	Palo Verde Generating Station or PVGS
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
TCA	Transmission cost adjustor
TEAM	Tax expense adjustor mechanism
VIE	Variable interest entity

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FORWARD-LOOKING STATEMENTS

This document contains forward-looking statements based on current expectations.  These forward-looking statements are often identified by words such as “estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume,” “project” 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, seasonality, 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, ballot initiatives and regulation, including those relating to environmental requirements, regulatory policy, 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 and of debt and equity capital investment;

• 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, including in real estate markets;

• the development of new technologies which may affect electric sales or delivery;

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

• environmental, economic and other concerns surrounding coal-fired generation, including regulation of greenhouse gas emissions;

• 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 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; 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 subsidiaries are El Dorado, BCE and 4CA.  Additional information related to these subsidiaries 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 6,236 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 2017, no single purchaser or user of energy accounted for more than 2.4% of our electric revenues.

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

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 used to supply energy to Native Load customers during 2017 were as follows:

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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 located in the northwestern corner of New Mexico, and was originally a 5-unit coal-fired power plant.  APS owns 100% of Units 1, 2 and 3, which were retired as of December 30, 2013. APS operates the plant and owns 63% of Four Corners Units 4 and 5 following the acquisition of SCE’s interest in Units 4 and 5 described below.  APS has a total entitlement from Four Corners of 970 MW. Additionally, 4CA, a wholly-owned subsidiary of Pinnacle West, owns 7% of Units 4 and 5 following its acquisition of El Paso's interest in these units described below.

On December 30, 2013, APS purchased SCE’s 48% interest in each of Units 4 and 5 of Four Corners. The final purchase price for the interest was approximately $182 million. In connection with APS’s prior general 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 23, 2014, the ACC approved rate adjustments related to APS’s acquisition of SCE’s interest in Four Corners resulting in a revenue increase of $57.1 million on an annual basis. This decision was appealed and on September 26, 2017, the Court of Appeals affirmed the ACC's decision on the Four Corners rate adjustment.

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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 served 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 was retained by NTEC under contract as the mine manager and operator through 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 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 agreed to assume the 7% shortfall obligation. (See Note 10 for a discussion of a pending arbitration related to the 2016 Coal Supply Agreement.) On February 17, 2015, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in each of Units 4 and 5 of Four Corners. 4CA purchased the El Paso interest on July 6, 2016. The purchase price was immaterial in amount, and 4CA assumed El Paso's reclamation and decommissioning obligations associated with the 7% interest.

NTEC had the option to purchase the 7% interest within a certain timeframe pursuant to an option granted to NTEC. On December 29, 2015, NTEC provided notice of its intent to exercise the option. The purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction.

The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% shortfall obligations in the event NTEC does not purchase the interest. At this time, since NTEC has not yet purchased the 7% interest, the alternate pricing provisions are applicable to 4CA as the holder of the 7% interest. These terms include a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales. Such payments are due to 4CA at the end of each calendar year. A $10 million payment was due to 4CA at December 31, 2017, which NTEC satisfied by directing to 4CA a prepayment from APS of a portion of a future mine reclamation obligation. The balance of the amount under this formula at December 31, 2017 is approximately $20 million, which is due to 4CA at December 31, 2018. In future years there may be similar payments due from NTEC to 4CA under this formula. 4CA believes NTEC should continue to satisfy its contractual obligations related to these payments; however, if NTEC fails to meet its contractual obligations when due, 4CA will consider appropriate measures and potential impacts to the Company's financial statements.

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 required the approval of the DOI, as did a related federal rights-of-way grant.  A federal environmental review was undertaken as part of the DOI review process, and culminated in the issuance by DOI of a record of decision on July 17, 2015 justifying the agency action extending the life of the plant and the adjacent mine.  

On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine.  The lawsuit alleges that these federal agencies violated both the Endangered Species Act ("ESA") and the National Environmental Policy Act ("NEPA") in providing the federal approvals necessary to extend operations at Four Corners and the adjacent Navajo Mine past July 6, 2016.  APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016.

On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the

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district court order dismissing their lawsuit. We cannot predict whether this appeal will be successful and, if it is successful, the outcome of further district court proceedings.

Cholla — Cholla was originally a 4-unit coal-fired power plant, which is 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.  On September 11, 2014, APS announced that it would close its 260 MW Unit 2 at Cholla and cease burning coal at Units 1 and 3 by the mid-2020s if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit, which was later addressed in the 2017 Settlement Agreement. (See Note 3 for details related to the resulting regulatory asset and allowed recovery set forth in the 2017 Settlement Agreement.) APS believes that the environmental benefits of this proposal are greater in the long-term than the benefits that would have resulted from adding the emissions control equipment. APS closed Unit 2 on October 1, 2015. Following the closure of Unit 2, APS has a total entitlement from Cholla of 387 MW.  In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017.

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 coal transportation contract that runs through 2019.

Navajo Plant — 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 co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant will remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that will allow for decommissioning activities to begin after the plant ceases operations in December 2019. Various stakeholders including regulators, tribal representatives, the plant's coal supplier and DOI have been meeting to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. Although we cannot predict whether any alternate plans will be found that would be acceptable to all of the stakeholders and feasible to implement, we believe it is probable that the Navajo Plant will cease operations in 2019.

APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant (see Note 3 for details related to the resulting regulatory asset) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and which may be material.

On February 14, 2017, the ACC opened a docket titled "ACC Investigation Concerning the Future of the Navajo Generating Station" with the stated goal of engaging stakeholders and negotiating a sustainable pathway for the Navajo Plant to continue operating in some form after December 2019. APS cannot predict the outcome of this proceeding.

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”

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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 10 for information regarding APS’s coal mine reclamation obligations.

Nuclear

Palo Verde 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.  The leaseback was originally scheduled to expire at the end of 2015 and contained options to renew the leases or to purchase the leased property for fair market value at the end of the lease terms.  On July 7, 2014, APS exercised the fixed rate lease renewal options.  The exercise of the renewal options resulted in APS retaining the assets through 2023 under one lease and 2033 under the other two leases. At the end of the lease renewal periods, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors. See Note 18 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 2023 and 50% of its requirements for 2024 and 2025. Additionally, Palo Verde has multiple contracts in various phases of negotiation to procure an additional 2.5 million pounds of uranium concentrates (equivalent to 1.5 years supply). Once these new contracts are completed, Palo Verde will have 100% of uranium concentrates assured through 2026.

The Palo Verde participants have also contracted for 100% of its requirements for conversion services through 2021 and 46% of its requirements for 2022 through 2025. Additionally, Palo Verde has two contracts in negotiation to procure an additional 2.9 million kilograms of elemental uranium of conversion services (equivalent to 4.3 years supply). Once these new contracts are completed, Palo Verde will have 100% of conversion services assured through 2027.

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The Palo Verde participants have also contracted for 100% of its requirements for enrichment services through 2020 and 20% of its enrichment services for 2021 through 2026. Additionally, Palo Verde has several contracts in negotiation to procure an additional 2.3 million separative work units of enrichment services (equivalent to 4.3 years supply). Once these new contracts are completed, Palo Verde will have 100% of enrichment services assured through 2021, 90% in 2022 and 80% in 2023 through 2026.

The Palo Verde participants have contracted for 100% of its requirements for fuel fabrication through 2024.

Spent Nuclear Fuel and Waste Disposal — The Nuclear Waste Policy Act of 1982 (“NWPA”) required the DOE to accept, transport, and dispose of spent nuclear fuel and high level waste generated by the nation’s nuclear power plants by 1998.  The DOE’s obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (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 United States Court of Federal Claims ("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 in the Court of Federal Claims. This lawsuit sought to recover damages incurred due to DOE’s breach of the Standard Contract for failing to accept Palo Verde’s 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. On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on the amount of reported net income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which has been extended to December 31, 2019.

APS has submitted three claims pursuant to the terms of the August 18, 2014 settlement agreement, for three separate time periods during July 1, 2011 through June 30, 2016. The DOE has approved and paid $65.2 million for these claims (APS’s share is $19 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. APS's next claim pursuant to the terms of the August 18, 2014 settlement agreement was submitted to the DOE in the fourth quarter of 2017 in the amount of $9 million (APS's share is $2.6 million). In February 2018, the DOE approved this claim.

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

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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 found that the DOE did not conduct a legally adequate fee assessment and 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. On May 16, 2014, the DOE notified all commercial nuclear power plant operators who are party to a Standard Contract that it reduced the one-mill fee to zero, thus effectively terminating the one-mill fee.

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.

On October 16, 2014, the NRC issued Volume 3 of the safety evaluation report developed as part of the Yucca Mountain construction authorization application. This volume addresses repository safety after permanent closure, and its issuance is a key milestone in the Yucca Mountain licensing process. Volume 3 contains the staff’s finding that the DOE’s repository design meets the requirements that apply after the repository is permanently closed, including but not limited to the post-closure performance objectives in NRC’s regulations.

On December 18, 2014, the NRC issued Volume 4 of the safety evaluation report developed as part of the Yucca Mountain construction authorization application. This volume covers administrative and programmatic requirements for the repository. It documents the staff’s evaluation of whether the DOE’s research and development and performance confirmation programs, as well as other administrative controls and systems, meet applicable NRC requirements. Volume 4 contains the staff’s finding that most administrative and programmatic requirements in NRC regulations are met, except for certain requirements relating to ownership of land and water rights.

Publication of Volumes 3 and 4 does not signal whether or when the NRC might authorize construction of the repository.

Waste Confidenceand Continued Storage — 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 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 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

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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 Generic Environmental Impact Statement (“GEIS”) to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel. Renamed as the Continued Storage Rule, the NRC’s decision adopted the findings of the GEIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. Although Palo Verde had not been involved in any licensing actions affected by the D.C. Circuit’s June 8, 2012, decision, the NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The final Continued Storage Rule was subject to continuing legal challenges before the NRC and the Court of Appeals. In June 2016, the D.C. Circuit issued its final decision, rejecting all remaining legal challenges to the Continued Storage Rule. On August 8, 2016, the D.C. Circuit denied a petition for rehearing.

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).  Based on current nuclear decommissioning trust asset balances, site specific decommissioning cost studies, anticipated future contributions to the decommissioning trusts, and return projections on the asset portfolios over the expected remaining operating life of the facility, we are on track to meet the current site specific decommissioning costs for Palo Verde at the time the units are expected to be decommissioned. See Note 19 for additional information about APS’s nuclear decommissioning trusts.

Palo Verde Liability and Insurance Matters — See “Palo Verde Generating Station — Nuclear Insurance” in Note 10 for a discussion of the insurance maintained by the Palo Verde participants, including APS, for Palo Verde.

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, Fairview, located in the town of Douglas, Arizona.  APS owns and operates each of these plants with the exception of one oil-only combustion

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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 five 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 located in the metropolitan Phoenix area.  In early 2014, APS announced a project to modernize the plant, which involves retiring two older 110 MW steam units, adding five 102 MW combustion turbines and maintaining two existing 55 MW combustion turbines.  In total, this increases the capacity of the site by 290 MW, to 620 MW, with completion targeted by summer 2019.  (See Note 3 for rate recovery as part of the 2017 Rate Case Decision). On September 9, 2016, Maricopa County issued a final permit decision that authorizes construction of the Ocotillo modernization project and construction began in early 2017.

Solar Facilities

APS developed utility scale solar resources through the 170 MW ACC-approved AZ Sun Program.  APS invested approximately $675 million in its AZ Sun Program. These facilities are owned by APS and are located in multiple locations throughout Arizona. In addition to the AZ Sun Program, APS developed the 40MW Red Rock Solar Plant, which it owns and operates. Two of our large customers purchase renewable energy credits from APS that is equivalent to the amount of renewable energy that Red Rock is projected to generate.

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, was 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.  The pilot program is now complete, and as part of the 2017 Rate Case Decision, the participants have been transferred to the Solar Partner Program described below. Additionally, APS owns 12 MW of solar photovoltaic systems installed across Arizona through the ACC-approved Schools and Government Program.

In December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid.  The first stage of the program, called the "Solar Partner Program," placed 8 MW of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016.  The costs for this program have been included in APS's rate base as part of the 2017 Rate Case Decision.

In APS's 2017 Rate Case Decision, the ACC approved the "APS Solar Communities" program. APS Solar Communities is a three-year program requiring APS to spend $10-15 million in capital costs each year to install utility-owned distributed generation systems on low to moderate income residential homes, buildings of non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES.

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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 16.)  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 as of December 31, 2017 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 June 14, 2020	60
Exchange Agreement (b)	May 15 to September 15 annually through February 2021	480
Tolling Agreement	Summer seasons through October 2019	560
Demand Response Agreement (c)	Summer seasons through 2024	25
Tolling Agreement	Summer seasons from Summer 2020 through Summer 2025	565
Tolling Agreement	June 1 through September 30, 2020-2026	570
Renewable Energy (d)	Various	629

(a) 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.

(b) 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).

(c) The capacity under this agreement may be increased in 10 MW increments in years 2017 through 2024, up to a maximum of 50 MW.

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

Current and Future Resources

Current Demand and Reserve Margin

Electric power demand is generally seasonal.  In Arizona, demand for power peaks during the hot summer months.  APS’s 2017 peak one-hour demand on its electric system was recorded on June 20, 2017 at 7,363 MW, compared to the 2016 peak of 7,051 MW recorded on June 19, 2016.  APS’s reserve margin at the time of the 2017 peak demand, calculated using system load serving capacity, was 15%.  For 2018, due to expiring purchase contracts, APS is procuring market resources to maintain its minimum 15% planning reserve criteria.

Future Resources and Resource Plan

APS filed its preliminary 2017 Integrated Resource Plan on March 1, 2016 and an updated preliminary 2017 Integrated Resource Plan on September 30, 2016. APS also held stakeholder meetings in February and November 2016 in addition to an ACC-led Integrated Resource Plan workshop in July 2016. The preliminary Integrated Resource Plan and associated stakeholder meetings are part of a modified planning process that allows time to incorporate implications of the Clean Power Plan as well as input from stakeholder meetings. The final Integrated Resource Plan was submitted on April 10, 2017. The ACC has not yet completed its review of the final Integrated Resource Plan.

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On September 11, 2014, APS announced that it would close Cholla Unit 2 and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017. (See "Business of Arizona Public Service Company - Energy Sources and Resource Planning - Generation Facilities - Coal-Fueled Generating Facilities - Cholla" above for information regarding the Cholla Plant).

See "Business of Arizona Public Service Company - Energy Sources and Resource Planning - Generation Facilities - Coal-Fueled Generating Facilities" above for information regarding future plans for the Four Corners Plant, Navajo Plant and Ocotillo Plant." See Business of Arizona Public Service Company - Energy Sources and Resource Planning - Purchased Power Contracts" above for information regarding future plans for purchased power contracts.

Energy Imbalance Market

In 2015, APS and the CAISO, the operator for the majority of California's transmission grid, signed an agreement for APS to begin participation in the Energy Imbalance Market (“EIM”). APS's participation in the EIM began on October 1, 2016.  The EIM allows for rebalancing supply and demand in 15-minute blocks with dispatching every five minutes before the energy is needed, instead of the traditional one hour blocks.  APS expects that its participation in EIM will lower its fuel costs, improve visibility and situational awareness for system operations in the Western Interconnection power grid, and improve integration of APS’s renewable resources.

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 8% of retail electric sales in 2018 and increases annually until it reaches 15% in 2025.  In APS’s 2009 general retail rate case settlement agreement (the “2009 Settlement Agreement”), APS committed to use its best efforts to have 1,700 GWh of new renewable resources in service by year-end 2015 in addition to its RES renewable resource commitments. APS met its settlement commitment and overall RES target for 2017.

A component of the RES is focused on stimulating development of distributed energy 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 8% in 2018.  The following table summarizes the RES requirement standard (not including the additional commitment required by the 2009 Settlement Agreement) and its timing:

	2018	2020	2025
RES as a % of retail electric sales	8%	10%	15%
Percent of RES to be supplied from distributed energy resources	30%	30%	30%

On April 21, 2015, the RES rules were amended to require utilities to report on all eligible renewable resources in their service territory, irrespective of whether the utility owns renewable energy credits associated with such renewable energy. The rules allow the ACC to consider such information in determining whether APS has satisfied the requirements of the RES. See "Renewable Energy Ballot Initiative" and "Clean

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Resource Energy Standard and Tariff" in Note 3 for information regarding two additional renewable energy standards proposals.

Renewable Energy Portfolio.  To date, APS has a diverse portfolio of existing and planned renewable resources totaling 1,655 MW, including solar, wind, geothermal, biomass and biogas.  Of this portfolio, 1,583 MW are currently in operation and 72 MW are under contract for development or are under construction.  Renewable resources in operation include 239 MW of facilities owned by APS, 629 MW of long-term purchased power agreements, and an estimated 682 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.  See "Energy Sources and Resource Planning - Generation Facilities - Solar Facilities" above for information regarding APS-owned solar facilities.

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The following table summarizes APS’s renewable energy sources currently in operation and under development as of December 31, 2017.  Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the projects to the electric grid.

	Location	Actual/ Target Commercial Operation Date	Term (Years)	Net Capacity In Operation (MW AC)	Net Capacity Planned/Under Development (MW AC)
APS Owned
Solar:
AZ Sun Program:
Paloma	Gila Bend, AZ	2011		17
Cotton Center	Gila Bend, AZ	2011		17
Hyder Phase 1	Hyder, AZ	2011		11
Hyder Phase 2	Hyder, AZ	2012		5
Chino Valley	Chino Valley, AZ	2012		19
Hyder II	Hyder, AZ	2013		14
Foothills	Yuma, AZ	2013		35
Gila Bend	Gila Bend, AZ	2014		32
Luke AFB	Glendale, AZ	2015		10
Desert Star	Buckeye, AZ	2015		10
Subtotal AZ Sun Program				170	—
Multiple Facilities	AZ	Various		4
Red Rock	Red Rock, AZ	2016		40
Distributed Energy:
APS Owned (a)	AZ	Various		25
Total APS Owned				239	—
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	—
Distributed Energy
Solar (b)
Third-party Owned	AZ	Various		682	72
Agreement 1	Bagdad, AZ	2011	25	15
Agreement 2	AZ	2011-2012	20-21	18
Total Distributed Energy				715	72
Total Renewable Portfolio				1,583	72

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(a) Includes Flagstaff Community Power Project, APS School and Government Program and APS Solar Partner Program.

(b) Includes rooftop solar facilities owned by third parties. Distributed generation is produced in DC and is converted to AC for reporting purposes.

Additionally, in early February 2018, APS entered into a 15-year power purchase agreement for a 65 MW solar facility that charges a 50 MW solar-fueled battery. Service under the agreement is scheduled to begin in 2021.

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 EES of 22% cumulative annual energy savings by 2020.  This standard was adopted and became effective on January 1, 2011.  This standard will likely impact Arizona’s future energy resource needs.  (See Note 3 for energy efficiency and other demand side management obligations).

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. APS cannot predict when, and the extent to which, additional electric service providers will enter or re-enter APS’s service territory.

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 was 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 docket on November 4, 2013 to explore technological

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advances and innovative changes within the electric utility industry.  A series of workshops in this docket were held in 2014 and another in February of 2015. No further workshops are scheduled and no actions were taken as a result of these workshops.

Wholesale

FERC regulates rates for wholesale power sales and transmission services.  (See Note 3 for information regarding APS’s transmission rates.)  During 2017, approximately 3.8% 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.

Subpoena from Arizona Corporation Commissioner Robert Burns   

On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer.

On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay APS's obligations to comply with the subpoenas and decline to decide APS's motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed.

On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC staff.  As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns' suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel. On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the complaint. On February 15, 2018, the Superior Court dismissed Commissioner Burns’ complaint. The matter is subject to appeal. APS and Pinnacle West cannot predict the outcome of this matter.

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In addition to the Superior Court proceedings discussed above, on August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the 2017 Rate Case Decision so that alleged issues of disqualification and bias on the part of the other Commissioners could be fully investigated. APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition.

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 doubtful whether the 115^th Congress will consider a climate change bill. In the event climate change legislation ultimately passes, the actual economic and operational impact of such legislation on APS depends on a variety of factors, none of which can be fully known until a law is written and 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.

Regulatory Initiatives. In 2009, EPA determined that GHG emissions endanger public health and welfare. 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. APS will generally be required to consider the impact of GHG emissions as part of its traditional New Source Review ("NSR") analysis for new major sources and major modifications to existing plants.

On June 2, 2014, EPA issued two proposed rules to regulate GHG emissions from modified and reconstructed electric generating units ("EGUs") pursuant to Section 111(b) of the Clean Air Act and existing fossil fuel-fired power plants pursuant to Clean Air Act Section 111(d).

On August 3, 2015, EPA finalized carbon pollution standards for EGUs. Shortly thereafter, a coalition of states, industry groups and electric utilities challenged the legality of these standards, including EPA's Clean Power Plan for existing EGUs, in the U.S. Court of Appeals for the D.C. Circuit. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations under the Clean Power Plan. On March 28, 2017, President Trump issued an Executive Order that, among other things, instructs EPA to reevaluate Agency regulations concerning carbon emissions from EGUs and take appropriate action to suspend, revise or rescind the August 2015 carbon pollution standards for EGUs, including the Clean Power Plan. Also on March 28, 2017, DOJ, on behalf of

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EPA, filed a motion with the U.S. Court of Appeals for the D.C. Circuit Court to hold the ongoing litigation over the Clean Power Plan in abeyance pending EPA action in accordance with the Executive Order. At this time, the D.C. Circuit Court proceedings evaluating the legality of the Clean Power Plan remain on hold.

Based upon EPA's reevaluation of the August 2015 carbon pollution standards and the legal basis for these regulations, on October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan. That proposal relies on EPA's current view as to the Agency's legal authority under Clean Air Act Section 111(d), which (in contrast to the Clean Power Plan) would limit the scope of any future Section 111(d) regulations to measures undertaken exclusively at a power plant's source of GHG emissions. On December 18, 2017, EPA issued an Advanced Notice of Proposed Rulemaking through which EPA is soliciting comments as to potential replacements for the Clean Power Plan that would be consistent with EPA's current legal interpretation of the Clean Air Act.

We cannot predict the outcome of EPA's regulatory actions related to the August 2015 carbon pollution standards for EGU's, including any actions related to EPA's repeal proposal for the Clean Power Plan or additional rulemaking actions to develop regulations replacing the Clean Power Plan. In addition, we cannot predict whether the D.C. Circuit Court will continue to hold the litigation challenging the original Clean Power Plan in abeyance in light of EPA's repeal proposal.

Company Response to Climate Change Initiatives. We have undertaken a number of initiatives that 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.

APS prepares an annual 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 or otherwise a part of this report.

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 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.

Cholla. APS believed that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of selective catalytic reduction ("SCR") controls, was unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan ("SIP") and promulgating a Federal Implementation Plan ("FIP") that was inconsistent with the state’s considered BART determinations under the regional haze program.  In September 2014, APS met with EPA to propose a compromise BART strategy. APS would permanently close Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result

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in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP.

On October 16, 2015, ADEQ issued a revised operating permit for Cholla, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to EPA, which would incorporate the new permit terms.  On June 30, 2016, EPA issued a proposed rule approving a revision to the Arizona SIP that incorporates APS’s compromise approach for compliance with the regional haze program.  In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017.

Four Corners. Based on EPA’s final standards, APS's 63% share of the cost of required controls for Four Corners Units 4 and 5 is approximately $400 million.  (See Note 3 for information regarding the related rate recovery.) In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. NTEC has the option to purchase the interest within a certain timeframe pursuant to an option granted to NTEC. In December 2015, NTEC notified APS of its intent to exercise the option. The purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction. The cost of the pollution controls related to the 7% interest is approximately $45 million, which will be assumed by the ultimate owner of the 7% interest.

Navajo Plant. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s FIP, could be up to approximately $200 million; however, given the future plans for the Navajo Plant, we do not expect to incur these costs.  See "Energy Sources and Resource Planning - Generation Facilities - Coal-Fueled Generating Facilities - Navajo Generating Station" above and "Navajo Plant" in Note 3 for information regarding future plans for the Navajo Plant.

Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act ("RCRA") and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity.

While EPA has chosen to regulate the disposal of CCR in landfills and surface impoundments as non-hazardous waste under the final rule, the agency makes clear that it will continue to evaluate any risks associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future.

On December 16, 2016, President Obama signed the Water Infrastructure Improvements for the Nation ("WIIN") Act into law, which contains a number of provisions requiring EPA to modify the self-implementing provisions of the Agency's current CCR rules under Subtitle D. Such modifications include new EPA authority to directly enforce the CCR rules through the use of administrative orders and providing states, like Arizona, where the Cholla facility is located, the option of developing CCR disposal unit permitting programs, subject to EPA approval. For facilities in states that do not develop state-specific permitting programs, EPA is required to develop a federal permit program, pending the availability of congressional appropriations. By contrast, for facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation,

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where the Navajo Plant and Four Corners facilities are located, EPA is required to develop a federal permit program regardless of appropriated funds.

ADEQ has initiated a process to evaluate how to develop a state CCR permitting program that would cover EGUs, including Cholla. While APS has been working with ADEQ on the development of this program, we are unable to predict when Arizona will be able to finalize and secure EPA approval for a state-specific CCR permitting program. With respect to the Navajo Nation, APS recently filed a comment letter with EPA seeking clarification as to when and how EPA would be initiating permit proceedings for facilities on the reservation, including Four Corners. We are unable to predict at this time when EPA will be issuing CCR management permits for the facilities on the Navajo Nation. At this time, it remains unclear how the CCR provisions of the WIIN Act will affect APS and its management of CCR.

Based upon utility industry petitions for EPA to reconsider the RCRA Subtitle D regulations for CCR, which were premised in part on the CCR provisions of the 2016 WIIN Act, on September 13, 2017 EPA agreed to evaluate whether to revise these federal CCR regulations. At this time, it is not clear whether EPA will initiate further notice-and-comment rulemaking to revise the federal CCR rules, nor is it clear what aspects of the federal CCR rules might be changed as a result of this process. With respect to ongoing litigation initiated by industry and environmental groups challenging the legality of these federal CCR regulations, on September 27, 2017, the United States Court of Appeals for the D.C. Circuit, the court overseeing these judicial challenges, ordered EPA to file by November 15, 2017 a list of federal regulatory provisions addressing CCR that are or likely will be revised through EPA’s reconsideration proceedings. While this filing identified certain provisions of the federal CCR regulations that EPA intends to revise, including allowances for risk-based groundwater protection standards for regulated CCR constituents for which no federal maximum contaminant level has been set, it is not clear at this time which specific provisions of the federal CCR rules will be modified, how they will be modified, or when such modification will occur.

Pursuant to a June 24, 2016 order by the D.C. Circuit Court of Appeals in the litigation by industry and environmental groups challenging EPA’s CCR regulations, within the next two years EPA is required to complete a rulemaking proceeding concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules.  EPA is not required to take final action approving the inclusion of boron, but EPA must propose and consider its inclusion.  Should EPA take final action adding boron to the list of groundwater constituents that might trigger corrective action, any resulting corrective action measures may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities.  At this time APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings.

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $22 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $20 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. By October 17, 2017, electric utility companies that own or operate CCR disposal units, such as APS, must have collected sufficient groundwater sampling data to initiate a detection monitoring program.  To the extent that certain threshold constituents are identified through this initial detection monitoring at levels above the CCR rule’s standards, the rule requires the initiation of an assessment monitoring program by April 15, 2018.  If this assessment monitoring program reveals concentrations of certain constituents above the CCR rule standards that trigger remedial obligations, a corrective measures evaluation must be completed by January 2019. Depending upon the results of such groundwater monitoring and data evaluations at each of Cholla, Four Corners and the

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Navajo Plant, we may be required to take corrective actions, the costs of which we are unable to reasonably estimate at this time.

Effluent Limitation Guidelines. On September 30, 2015, EPA finalized revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil-fired EGUs.  EPA’s final regulation targets metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities, and coal ash disposal leachate.  Based upon an earlier set of preferred alternatives, the final effluent limitations generally require chemical precipitation and biological treatment for flue gas desulfurization scrubber wastewater, “zero discharge” from fly ash and bottom ash handling, and impoundment for coal ash disposal leachate. 

On August 11, 2017, EPA announced that it would be initiating rulemaking proceedings to potentially revise the September 2015 effluent limitation guidelines. On September 18, 2017, EPA finalized a regulation postponing the earliest date on which compliance with the effluent limitation guidelines for these waste-streams would be required from November 1, 2018 until November 1, 2020. Until EPA issues a proposal describing how it intends to change the effluent limitation guidelines for bottom ash transport water and flue gas desulfurization wastewater, it is unclear how EPA’s reconsideration process will affect how the Four Corners plant manages these waste-streams. We expect that compliance with these limitations will be required in connection with National Pollution Discharge Elimination System ("NPDES") discharge permit renewals.  Until a draft NPDES permit for Four Corners is proposed during the revised compliance timeframe (i.e., from November 1, 2020 through December 31, 2023), we are uncertain what will be required to control these discharges in compliance with the revised finalized effluent limitations at that facility. Cholla and the Navajo Plant do not require NPDES permitting.

Ozone National Ambient Air Quality Standards. On October 1, 2015, EPA finalized revisions to the primary ground-level ozone national ambient air quality standards (“NAAQS”) at a level of 70 parts per billion (“ppb”).  With ozone standards becoming more stringent, our fossil generation units will come under increasing pressure to reduce emissions of nitrogen oxides and volatile organic compounds, and to generate emission offsets for new projects or facility expansions located in ozone nonattainment areas.  EPA was expected to designate attainment and nonattainment areas relative to the new 70 ppb standard by October 1, 2017.  To date, EPA has only taken action to designate areas of the U.S. that are in attainment with the 2015 NAAQS for ozone. EPA’s failure to take action relative to nonattainment designations is currently subject to on-going judicial review by certain states and environmental groups. At this time, it remains unclear when EPA will ultimately make a complete designation of all attainment and nonattainment areas within the U.S. Depending on when EPA approves attainment designations for the Arizona and Navajo Nation jurisdictions in which our fossil generation units are located, revisions to SIPs and FIPs, respectively, implementing required controls to achieve the new 70 ppb standard are expected to be in place between 2020 and 2021.  At this time, because proposed SIPs and FIPs implementing the revised ozone NAAQSs have yet to be released, APS is unable to predict what impact the adoption of these standards may have on the Company. APS will continue to monitor these standards as they are implemented within the jurisdictions affecting APS.

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 52^nd Street Superfund Site, Operable Unit 3 ("OU3") in Phoenix, Arizona.  APS has facilities that are within this Superfund site.  APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater

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remedial investigation and feasibility study ("RI/FS").  Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS, APS anticipates finalizing the RI/FS in the summer or fall of 2018. 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.  As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the ADEQ sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area.  APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID contractors filed ancillary lawsuits for recovery of costs against APS and the other defendants. Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS’s exposure or risk related to these matters. In addition, on March 15, 2017, the Arizona District Court granted partial summary judgment to RID for one element of RID's lawsuit against APS and the other defendants. On May 12, 2017, the court denied a motion for reconsideration as to this order. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

Manufactured Gas PlantSites.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.

Federal Agency Environmental Lawsuit Related to Four Corners

On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine.  The lawsuit alleges that these federal agencies violated both ESA and NEPA in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016.  APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016.

On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. We cannot predict whether this appeal will be successful and, if it is successful, the outcome of further district court proceedings.

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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, SRP, 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. The Four Corners region, in which Four Corners is located, has historically experienced drought conditions that may affect the water supply for the plants if adequate moisture is not received in the watershed that supplies the area. However, during the past 12 months the region has received snowfall and precipitation sufficient to recover the Navajo Reservoir to an optimum operating level, reducing the probability of shortage in future years. Although the watershed and reservoirs are in a good condition at this time, APS is continuing to work with area stakeholders to implement agreements to minimize the effect, if any, on future drought conditions that could have an impact on operations of its plants.

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 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

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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 adjudication. 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, including a number of gas-fired power plants located within Maricopa and Pinal Counties. 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.

At this time, the lower court proceedings in the Gila River adjudication are in the process of determining the specific hydro-geologic testing protocols for determining which groundwater wells located outside of the subflow zone of the Gila River should be subject to the adjudication court’s jurisdiction. Discovery as to this issue is ongoing at this time, and a hearing to determine this jurisdictional test question will be held in March of 2018. Further proceedings thereafter will be dedicated to determining the specific hydro-geologic testing protocols for subflow depletion determinations. At this time, APS cannot predict the outcome of these proceedings.

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

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

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BUSINESS OF OTHER SUBSIDIARIES

Bright Canyon Energy

On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE.  BCE's focus is on new growth opportunities that leverage the Company’s core expertise in the electric energy industry.  BCE’s first initiative is a 50/50 joint venture with BHE U.S. Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company.  The joint venture, named TransCanyon, is pursuing independent transmission opportunities within the eleven states that comprise the Western Electricity Coordinating Council, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the venture partners’ utility affiliates.  TransCanyon continues to pursue transmission development opportunities in the western United States consistent with its strategy.

On March 29, 2016, TransCanyon entered into a strategic alliance agreement with Pacific Gas and Electric Company ("PG&E") to jointly pursue competitive transmission opportunities solicited by the CAISO, the operator for the majority of California's transmission grid. TransCanyon and PG&E intend to jointly engage in the development of future transmission infrastructure and compete to develop, build, own and operate transmission projects approved by the CAISO.

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, 2017, El Dorado had total assets of approximately $12 million. 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. 

4CA

See "Business of Arizona Public Service Company - Energy Sources and Resource Planning - Generating Facilities - Coal-Fueled Generating Facilities - Four Corners" above for information regarding 4CA. As of December 31, 2017, 4CA had total assets of approximately $108 million. 

OTHER INFORMATION

Subpoenas

Pinnacle West has received grand jury subpoenas issued in connection with an investigation by the office of the United States Attorney for the District of Arizona. The subpoenas seek information principally pertaining to the 2014 statewide election races in Arizona for Secretary of State and for positions on the ACC. The subpoenas request records involving certain Pinnacle West officers and employees, including the Company’s Chief Executive Officer, as well as communications between Pinnacle West personnel and a former ACC Commissioner. Pinnacle West is cooperating fully with the United States Attorney’s office in this matter.

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Other Information

Pinnacle West, APS and El Dorado are all incorporated in the State of Arizona.  BCE and 4CA are incorporated in Delaware. Additional information for each of these companies is provided below:

	Principal Executive Office Address	Year of Incorporation	Approximate Number of Employees at December 31, 2017
Pinnacle West	400 North Fifth Street Phoenix, AZ 85004	1985	90
APS	400 North Fifth Street P.O. Box 53999 Phoenix, AZ 85072-3999	1920	6,196
BCE	400 East Van Buren Phoenix, AZ 85004	2014	6
El Dorado	400 East Van Buren Phoenix, AZ 85004	1983	—
4CA	400 North Fifth Street Phoenix, AZ 85004	2016	—
Total			6,292

The APS number includes employees at jointly-owned generating facilities (approximately 2,565 employees) for which APS serves as the generating facility manager.  Approximately 1,369 APS employees are union employees, represented by the International Brotherhood of Electrical Workers ("IBEW"). In January 2018, the Company concluded negotiations with IBEW and approved a two-year extension of the existing collective bargaining agreement, which was set to expire on April 1, 2018.  The new agreement is in place until April 1, 2020. Approximately 200 APS employees at Palo Verde were union employees, represented by the United Security Professionals of America ("USPA").  The USPA collective bargaining agreement expired on May 31, 2017, but APS and the USPA did not reach an agreement over the terms of a new collective bargaining agreement.  Certain members of the USPA bargaining unit filed a petition with the National Labor Relations Board ("NLRB") seeking to decertify the USPA as the representative of the bargaining unit, and the employees elected to decertify the union. The NLRB certified the results of the election on September 11, 2017.

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).

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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 and 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, including in some cases how court challenges to these regulatory decisions are resolved. Arizona, like certain other states, has a statute that allows the ACC to reopen prior decisions and modify otherwise final orders under certain circumstances.

The ACC must also approve APS’s issuance of securities and any significant transfer or encumbrance 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.

APS’s ability to conduct its business operations and avoid fines and penalties depends upon compliance with federal, state and 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 (approximately $1.2 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

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operators or impacting the industry generally may lead the NRC to impose additional requirements and regulations on all nuclear generation facilities, including Palo Verde.  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.

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 of conventional pollutants and greenhouse gases, 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.

Coal Ash. In December 2014, EPA issued final regulations governing the handling and disposal of CCR, which are generated as a result of burning coal and consist of, among other things, fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste. APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners and in a dry landfill storage area at the Navajo Plant. To the extent the rule requires the closure or modification of these CCR units or the construction of new CCR units beyond what we currently anticipate, APS would incur significant additional costs for CCR disposal.

Ozone National Ambient Air Quality Standards. In 2015, EPA finalized revisions to the national ambient air quality standards for nitrogen oxides, which set new, more stringent standards intended to protect human health and human welfare. Depending on the final attainment designations for the new standards and the state implementation requirements, APS may be required to invest in new pollution control technologies and to generate emission offsets for new projects or facility expansions located in ozone nonattainment areas.

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

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legislation coupled with trends in natural gas and coal prices, 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 potential financial risks resulting from climate change litigation and legislative and regulatory efforts to limit GHG emissions, as well as physical and operational risks related to climate effects.

Concern over climate change 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.

Potential Financial Risks - Greenhouse Gas Regulation, the Clean Power Plan and Potential Litigation. In 2015, EPA finalized a rule to limit carbon dioxide emissions from existing power plants. The implementation of this rule within the jurisdictions where APS operates could result in a shift in in-state generation from coal to natural gas and renewable generation. Such a substantial change in APS’s generation portfolio could require additional capital investments and increased operating costs, and thus have a significant financial impact on the Company. EPA took action in October 2017 to potentially repeal these regulations and is currently taking public comments on whether or how EPA could take action to replace the Clean Power Plan with a new set of regulations.

Depending on the final outcome of a pending judicial review of the Clean Power Plan, along with related regulatory activity to repeal or replace these regulations, the utility industry may face alternative efforts from private parties seeking to establish alternative GHG emission limitations from power plants. Alternative GHG emission limitations may arise from litigation under either federal or state common laws or citizen suit provisions of federal environmental statutes that attempt to force federal agency rulemaking or imposing direct facility emission limitations. Such lawsuits may also seek damages from harm alleged to have resulted from power plant GHG emissions.

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.

Co-owners of our jointly owned generation facilities may have unaligned goals and positions due to the effects of legislation, regulations, economic conditions or changes in our industry, which could have a significant impact on our ability to continue operations of such facilities.

APS owns certain of our power plants jointly with other owners with varying ownership interests in such facilities. Changes in the nature of our industry and the economic viability of certain plants, including impacts resulting from types and availability of other resources, fuel costs, legislation and regulation, together with timing considerations related to expiration of leases or other agreements for such facilities, could result in unaligned positions among co-owners. Such differences in the co-owners’ willingness or ability to continue their participation could ultimately lead to disagreements among the parties as to how and whether to continue operation of such plants, which could lead to eventual shut down of units or facilities and uncertainty related to the resulting cost recovery of such assets. See Note 3 for a discussion of the co-owners' plans to cease operations of the Navajo Plant and the related risks associated with APS's continued recovery of its remaining investment in the plant.

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

In 1999, the ACC approved rules for the introduction of retail electric competition in Arizona.  Retail competition could have a significant adverse financial impact on APS due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital.  Although some very limited retail competition existed in APS’s service area in 1999 and 2000, there are currently no active retail competitors offering unbundled energy or other utility services to APS’s customers.  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 would be a continuation or expansion of APS’s existing AG (Alternative Generation)-X program, which essentially allows up to 200 MW of cumulative load to be served via a buy-through arrangement with competitive suppliers of generation.  The AG-X program was approved by the ACC as part of the 2017 Settlement Agreement.

Proposals to enable or support retail electric competition may be made from time to time through ballot initiatives, legislative action or other forums in Arizona. We cannot predict future regulatory or legislative action that might result in increased competition.

OPERATIONAL RISKS

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

Weather Conditions.  Weather conditions directly influence the demand for electricity and affect the price of energy commodities.  Electric power demand is generally a seasonal business.  In Arizona, demand for power peaks during the hot summer months, with market prices also peaking at that time.  As a result, APS’s overall operating results fluctuate substantially on a seasonal basis.  In addition, APS has historically sold less power, and consequently earned less income, when weather conditions are milder.  As a result, unusually mild weather could diminish APS’s financial condition, results of operations or 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 Resources.  The ACC has enacted rules regarding energy efficiency that mandate a 22% cumulative 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

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the recovery of net lost income/revenue that would result from lower sales due to increased energy efficiency requirements.  To that end, the LFCR is designed 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 of their own energy needs. 

In addition to these rules and requirements, energy efficiency technologies and distributed energy resources continue to evolve, which may have similar impacts on demand for electricity. Reduced demand due to these energy efficiency requirements, distributed energy requirements and other emerging technologies, unless substantially offset through ratemaking mechanisms, could have a material adverse impact on APS’s financial condition, results of operations and cash flows.

Actual and Projected Customer and Sales Growth.  Retail customers in APS's service territory increased 1.8% for the year ended December 31, 2017 compared with the prior year. For the three years 2015 through 2017, APS’s retail customer growth averaged 1.5% per year.  We currently project annual customer growth to be 1.5-2.5% for 2018 and to average in the range of 2-3% for 2018 through 2020 based on our assessment of modestly improving economic conditions in Arizona. 

Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, decreased 0.3% for the year ended December 31, 2017 compared with the prior year. Improving economic conditions and customer growth were more than offset by energy savings driven by customer conservation, energy efficiency, distributed renewable generation initiatives and one fewer day of sales due to the leap year in 2016. For the three years 2015 through 2017, APS experienced annual increases in retail electricity sales averaging 0.1%, adjusted to exclude the effects of weather variations.  We currently project that annual retail electricity sales in kWh will increase in the range of 0.5-1.5% for 2018 and increase on average in the range of 0.5-1.5% during 2018 through 2020, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations.  A slower recovery of the Arizona economy or acceleration of the expected effects of customer conservation, energy efficiency or distributed renewable generation initiatives could further impact these estimates.

Actual customer and sales growth 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 renewable generation, and responses to retail price changes. 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 we experience acceleration of expected effects of customer conservation, energy efficiency or distributed renewable generation initiatives, we may be unable to reach our estimated 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.  Concerns over physical security of these assets could include damage to certain of our facilities due to vandalism or other deliberate acts that could lead to outages or other adverse effects. 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. 

The inability to successfully develop or acquire generation resources to meet reliability requirements and other 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 various 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 challenges as to the appropriate generation portfolio and fuel diversification mix.  In addition, APS is required by the ACC to meet certain energy resource portfolio requirements, including those related to renewables development and energy efficiency measures.  The development of any generation facility is subject to many risks, including those related to financing, siting, permitting, new and evolving technology, the construction of sufficient transmission capacity to support these facilities and stresses to generation and transmission resources from the 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.

In expressing concerns about the environmental and climate-related impacts from continued extraction, transportation, delivery and combustion of fossil fuels, environmental advocacy groups and other third parties have in recent years undertaken greater efforts to oppose the permitting and construction of fossil fuel infrastructure projects. These efforts may increase in scope and frequency depending on a number of variables, including the future course of Federal environmental regulation and the increasing financial resources devoted to these opposition activities. APS cannot predict the effect that any such opposition may have on our ability to develop and construct fossil fuel infrastructure projects in the future.

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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We are subject to cybersecurity risksand risks of unauthorized access to our systems.

We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. In the regular course of our business, we handle a range of sensitive security, customer and business systems information. There appears to be an increasing level of activity, sophistication and maturity of threat actors, in particular nation state actors, that seek to exploit potential vulnerabilities in the electric utility industry and wish to disrupt the U.S. bulk power, transmission and distribution system. Our information technology systems, generation (including our Palo Verde nuclear facility), transmission and distribution facilities, and other infrastructure facilities and systems and physical assets could be targets of unauthorized access and are critical areas of cyber protection for us.

Despite implementation of security measures, our technology systems are vulnerable to disability, failures or unauthorized access. If a significant cybersecurity event or breach were to occur, we may not be able to fulfill critical business functions and we could (i) experience property damage, disruptions to our business, theft of or unauthorized access to customer, employee, financial or system operation information or other information; (ii) experience loss of revenue or incur significant costs for repair, remediation and breach notification, and increased capital and operating costs to implement increased security measures; and (iii) be subject to increased regulation, litigation and reputational damage. These types of events could also require significant management attention and resources, and could have a material adverse impact on our financial condition, results of operations or cash flows.

We are subject to laws and rules issued by multiple government agencies concerning safeguarding and maintaining the confidentiality of our security, customer and business information. One of these agencies, NERC, has issued comprehensive regulations and standards surrounding the security of bulk power systems, and is continually in the process of developing updated and additional requirements with which the utility industry must comply. The NRC also has issued regulations and standards related to the protection of critical digital assets at commercial nuclear power plants. The increasing promulgation of NERC and NRC rules and standards will increase our compliance costs and our exposure to the potential risk of violations of the standards. Experiencing a cybersecurity incident could cause us to be non-compliant with applicable laws and regulations, such as those promulgated by NERC and the NRC, or contracts that require us to securely maintain confidential data, causing us to incur costs related to legal claims or proceedings and regulatory fines or penalties.

The risk of these system-related events and security breaches occurring continues to intensify. We have experienced, and expect to continue to experience, threats and attempted intrusions to our information technology systems and we could experience such threats and attempted intrusions to our operational control systems. To date we have not experienced a material breach or disruption to our network or information systems or our service operations. However, as such attacks continue to increase in sophistication and frequency, we may be unable to prevent all such attacks from being successful in the future.

We have 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 is subject to a number of exclusions and may not cover the total loss or damage caused by a breach. The market for cybersecurity insurance is relatively new and coverage available for cybersecurity events may evolve as the industry matures. In the future, adequate insurance may not be available at rates that we believe are reasonable, and the costs of responding to and recovering from a cyber incident may not be covered by insurance or recoverable in rates.

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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 and portions of certain APS transmission lines are located on Indian lands pursuant to leases, easements or other rights-of-way that are effective for specified periods.  APS is unable to predict the final outcomes of pending and future approvals by the applicable sovereign 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 $16.6 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 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 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.

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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.

Alternative energy technologies that produce power or reduce power consumption or emissions are being developed and commercialized, including renewable technologies such as photovoltaic (solar) cells, customer-sited generation, energy storage (batteries), and efficiency technologies.  Advances in technology and equipment/appliance efficiency could reduce the demand for supply from conventional generation and increase the complexity of managing APS's information technology and power system operations, which could adversely affect APS’s business.

APS continues to pursue and implement advanced grid technologies, including transmission and distribution system technologies and 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 established or mature as APS’s existing technologies and equipment.  The implementation of new and additional technologies adds complexity to our information technology and operational technology systems, which could require additional infrastructure and resources. Widespread installation and acceptance of new technologies could also 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 traditional business model.

Deployment of renewable energy technologies is expected to continue across the western states and result in a larger portion of the overall energy production coming from these sources. These trends, which have benefited from historical and continuing government support for certain technologies, have the potential to put downward pressure on wholesale power prices throughout the western states which could make APS's existing generating facilities less economical and impact their operational patterns and long-term viability.

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

Like many companies in the electric utility industry, our workforce is maturing, with approximately 30% of employees eligible to retire by the end of 2020.  Although we have undertaken efforts to recruit, train and develop 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.

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FINANCIAL RISKS

Financial market disruptions or new 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 cause our cost of borrowing to increase 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 or continued beyond current commitment periods for a variety of reasons, including new rules and regulations, periods of financial distress or liquidity issues affecting our lenders or financial markets, which could materially adversely affect the adequacy of our liquidity sources and the cost of maintaining these sources.

Changes in economic conditions, monetary policy, financial regulation 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, whether as a result of these factors or otherwise, 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 investment in our business or other purposes.

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

Our current ratings are set forth in “Liquidity and Capital Resources — Credit Ratings” in Item 7.  We cannot be sure that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant.  Any downgrade or withdrawal could adversely affect the market price of Pinnacle West’s and APS’s securities, limit our access to capital and increase our borrowing costs, which would diminish our financial results.  We would be required to pay a higher interest rate for future financings, and our potential pool of investors and funding sources could decrease.  In addition, borrowing costs under our existing credit facilities depend on our credit ratings.  A downgrade could 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.

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Investment performance, changing interest rates and other economic, social and political factors could decrease the value of our benefit plan assets and nuclear decommissioning trust funds or increase the valuation of our related obligations, resulting in significant additional funding requirements.  We are also subject to risks related to the provision of employee healthcare benefits and 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 our pension trust and 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 number of retirements or changes in life expectancy and changes in other actuarial assumptions, may also result in similar impacts.  The minimum contributions required under these plans are impacted by federal legislation and related regulations.  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.  While most of the Patient Protection and Affordable Care Act provisions have been implemented, changes to that Act or other potential legislation could increase costs of providing medical insurance for our employees. Any potential changes and resulting cost impacts cannot be determined with certainty at this time.

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.

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

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

The market price of our common stock may be volatile.

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

• variations in our quarterly operating results;

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

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

• developments generally affecting industries in which we operate;

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

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

• favorable or adverse regulatory or legislative developments;

• our dividend policy;

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

• general domestic and international economic conditions.

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

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

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

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

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

• 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

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• 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.

Our financial results could be adversely affected if 4CA is unable to reach resolution with NTEC regarding the future ownership of 4CA’s 7% interest in Four Corners and NTEC is unwilling or unable to satisfy its contractual obligations.

On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners.  NTEC had the option to purchase the 7% interest within a certain timeframe pursuant to an option granted to NTEC.  On December 29, 2015, NTEC provided notice of its intent to exercise the option.  The purchase did not occur during the originally contemplated timeframe.  The parties are currently in discussions as to the future of the option transaction. 

The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% interest in the event NTEC does not purchase the interest.  At this time, since NTEC has not yet purchased the 7% interest, the alternate pricing provisions are applicable to 4CA as the holder of the 7% interest.  These terms include a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales.  Such payments are due to 4CA at the end of each calendar year.  A $10 million payment was due to 4CA at December 31, 2017, which NTEC satisfied by directing to 4CA a prepayment from APS of a portion of a future mine reclamation obligation.  The balance of the amount under this formula at December 31, 2017 is approximately $20 million, which is due to 4CA at December 31, 2018.  In future years there may be similar payments due from NTEC to 4CA under this formula. 4CA believes NTEC should continue to satisfy its contractual obligations related to these payments; however, if NTEC fails to meet its contractual obligations when due, 4CA will consider appropriate measures.

If NTEC is unwilling or unable to ultimately assume ownership of the 7% interest of Four Corners on terms acceptable to 4CA, and if NTEC is unwilling or unable to satisfy its contractual obligations related to payments owed to 4CA under the 2016 Coal Supply Agreement, 4CA will consider potential impacts to the Company’s financial statements, which may negatively impact our financial condition, results of operations or cash flows. 4CA and NTEC are in active discussions regarding these matters and cannot predict the outcome of those discussions.

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 2017 fiscal year and that remain unresolved.

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ITEM 2.  PROPERTIES

Generation Facilities

APS

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 1,3 (d)	2			Coal	Base Load	387
Navajo (e)	3	14	%	Coal	Base Load	315
Ocotillo	2			Gas	Peaking	220
Total Steam						1,892
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	3			Gas	Peaking	189
Fairview	1			Oil	Peaking	16
Sundance	10			Gas	Peaking	420
West Phoenix	2			Gas	Peaking	110
Yucca 1, 2, 3	3			Gas	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 I	1			Solar	As Available	16
Paloma	1			Solar	As Available	17
Chino Valley	1			Solar	As Available	19
Gila Bend	1			Solar	As Available	32
Hyder II	1			Solar	As Available	14
Foothills	1			Solar	As Available	35
Luke AFB	1			Solar	As Available	10
Desert Star	1			Solar	As Available	10
Red Rock	1			Solar	As Available	40
APS Owned Distributed Energy				Solar	As Available	25
Multiple facilities				Solar	As Available	4
Total Solar						239
Total Capacity						6,236

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(a) 100% unless otherwise noted.

(b) See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Generation Facilities — Nuclear” in Item 1 for details regarding leased interests in Palo Verde.  The other participants are Salt River Project (17.49%), SCE (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 4CA(7%).  The plant is operated by APS. 

(d) Cholla Unit 2's last day of service was on October 1, 2015.

(e) The other participants are Salt River Project (42.9%), Nevada Power Company (11.3%), the United States Government (24.3%) and Tucson Electric Power Company (7.5%).  The plant is operated by Salt River Project. In July 2016, Salt River Project purchased Los Angeles Department of Water & Power's share in this plant (21.2%).

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.

4CA

4CA, a wholly-owned subsidiary of Pinnacle West, purchased El Paso's 7% interest in Units 4 and 5 of Four Corners on July 6, 2016. See "Areas of Business Focus - Operational Performance, Reliability and Recent Developments - Four Corners - Asset Purchase Agreement and Coal Supply Matters" in Item 7 for additional information about 4CA's interest in Four Corners.

Transmission and Distribution Facilities

Current Facilities.  APS’s transmission facilities consist of approximately 6,137 pole miles of overhead lines and approximately 49 miles of underground lines, 5,914 miles of which are located in Arizona.  APS’s distribution facilities consist of approximately 11,167 miles of overhead lines and approximately 21,524 miles of underground primary cable, all of which are located in Arizona. APS distribution facilities reflect an actual net gain of 419 miles in 2017.  APS shares ownership of some of its transmission facilities with other companies. 

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The following table shows APS’s jointly-owned interests in those transmission facilities recorded on the Consolidated Balance Sheets at December 31, 2017:

	Percent Owned (Weighted-Average)
Morgan — Pinnacle Peak System	64.6	%
Palo Verde — Rudd 500kV System	50.0	%
Round Valley System	50.0	%
ANPP 500kV System	34.0	%
Navajo Southern System	27.5	%
Four Corners Switchyards	63.2	%
Palo Verde — Yuma 500kV System	18.1	%
Phoenix — Mead System	17.1	%
Palo Verde — Morgan System	90.9	%
Hassayampa — North Gila System	80.0	%
Cholla 500kV Switchyard	85.7	%
Saguaro 500kV Switchyard	60.0	%
Kyrene - Knox System	50.0	%

Expansion.  Each year APS prepares and files with the ACC a ten-year transmission plan.  In APS’s 2018 plan, APS projects it will develop 52 miles of new transmission 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 Palo Verde to Morgan System includes Palo Verde-Delaney-Sun Valley-Morgan-Pinnacle Peak. The project consists of four phases. The first three phases, Morgan to Pinnacle Peak 500kV, Palo Verde to Delaney 500kV, and Delaney to Sun Valley 500kV are currently in-service. The fourth phase, Morgan to Sun Valley 500kV, has started construction and is expected to be energized by May 2018. 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 have been completed and were included in previous APS transmission plans, are the Delaney to Palo Verde line and the North Gila to Hassayampa line, both of which support the transmission of renewable energy to Phoenix and California. The North Gila to Hassayampa line went into service in May 2015 and the Delaney to Palo Verde line went into service in May 2016.

Physical Security Standards. On July 14, 2015, FERC approved version 2 of the proposed Physical Security Reliability Standard CIP-014. It became effective on October 2, 2015 and requires transmission owners and operators to protect those critical transmission stations and substations and their associated primary control centers that, if rendered inoperable or damaged as a result of a physical attack, could result in widespread instability, uncontrolled separation or cascading within an interconnection.  As required by the Physical Security Reliability Standard, APS determined its critical transmission stations and substations and associated primary control centers that were required to comply with the standard timely, which triggered additional requirements and obligations within the Physical Security Reliability Standard.  These remaining obligations, which consist of a risk evaluation and development and verification of a physical security plan, were largely completed in 2016 with remaining activities projected to be complete in the first quarter of 2018.  At this time, significant financial or operational impacts on APS are not anticipated.

NERC Critical Infrastructure Protection Reliability Standards.  In 2014, APS initiated a comprehensive project to ensure compliance with Version 5 of NERC's Critical Infrastructure Protection

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Reliability Standards ("CIP V.5"), which will become effective pursuant to various implementation dates through 2018.  APS completed a significant portion of its compliance implementation activities to meet an initial compliance date of July 1, 2016; however, APS will be incurring incremental capital expenditures through 2018 to meet further upcoming compliance deadlines associated with CIP V.5.  Total expenditures are estimated to be approximately $52 million, the majority of which has been incurred by the Company as of December 31, 2017.

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 co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant will remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that will allow for decommissioning activities to begin after the plant ceases operations in December 2019. APS, on behalf of the Four Corners participants, negotiated amendments to the Four Corners facility lease with the Navajo Nation, which extends the Four Corners leasehold interest from 2016 to 2041.  See "Areas of Business Focus - Operational Performance, Reliability and Recent Developments - Four Corners - Lease Extension" in Item 7 for additional information about the Four Corners right-of-way and lease matters.

Certain portions of our transmission lines 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 certain 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 10 for information regarding environmental matters and Superfund–related matters. 

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 23, 2018, current positions and principal occupations for the past five years are as follows:

Name	Age	Position	Period
Donald E. Brandt	63	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
Robert S. Bement	62	Executive Vice President and Chief Nuclear Officer, PVGS, of APS	2016-Present
		Senior Vice President, Site Operations, PVGS, of APS	2011-2016
Denise R. Danner	62	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
Donna M. Easterly	53	Vice President, Human Resources and Ethics of APS	2017-Present
		Vice President, Chief Procurement Officer of APS	2014-2017
		Director, Transmission and Distribution Construction of APS	2013-2014
		Director, Statewide Energy Delivery of APS	2010-2013

David P. Falck (a)	64	Executive Vice President, Law of Pinnacle West	2017-Present
		Executive Vice President and General Counsel of Pinnacle West and APS	2009-2017
Daniel T. Froetscher	56	Executive Vice President, Operations of APS	2018-Present
		Senior Vice President, Transmission, Distribution & Customers of APS	2014-2018
		Vice President, Energy Delivery of APS	2008-2014
Jeffrey B. Guldner	52	Executive Vice President, Public Policy and General Counsel of Pinnacle West and APS	2017-Present
		Senior Vice President, Public Policy of APS	2014-2017
		Senior Vice President, Customers and Regulation of APS	2012-2014
James R. Hatfield	60	Executive Vice President of Pinnacle West and APS	2012-Present
		Chief Financial Officer of Pinnacle West and APS	2008-Present
John S. Hatfield	52	Vice President, Communications of APS	2010-Present
Barbara D. Lockwood	51	Vice President, Regulation of APS	2015-Present
		General Manager, Regulatory Policy and Compliance of APS	2014-2015
		General Manager, Innovation of APS	2012-2014
Lee R. Nickloy	51	Vice President and Treasurer of Pinnacle West and APS	2010-Present
Mark A. Schiavoni (b)	62	Executive Vice President of APS	2018-Present
		Executive Vice President and Chief Operating Officer of APS	2014-2018
		Executive Vice President, Operations of APS	2012-2014

(a) David P. Falck is retiring from PNW on April 2, 2018.

(b) Mark A. Schiavoni is retiring from APS on August 20, 2018.

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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 16, 2018, Pinnacle West’s common stock was held of record by approximately 18,684 shareholders.

QUARTERLY STOCK PRICES AND DIVIDENDS PAID PER SHARE

STOCK SYMBOL: PNW

							Dividends
2017	High		Low		Close		Per Share
1st Quarter	$	84.72	$	75.79	$	83.38	$	0.655
2nd Quarter	89.56		82.62		85.16		0.655
3rd Quarter	90.92		83.95		84.56		0.655
4th Quarter	92.48		84.14		85.18		0.695

							Dividends
2016	High		Low		Close		Per Share
1st Quarter	$	75.15	$	62.51	$	75.07	$	0.625
2nd Quarter	81.08		70.11		81.06		0.625
3rd Quarter	82.78		73.94		75.99		0.625
4th Quarter	78.97		70.86		78.03		0.655

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 2017 and 2016.

Common Stock Dividends

(Dollars in Thousands)

Quarter	2017		2016
1st Quarter	$	72,900	$	69,400
2nd Quarter	73,100		69,500
3rd Quarter	73,100		69,500
4th Quarter	77,700		72,900

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, 2017, APS did not have any outstanding preferred stock.

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ITEM 6.  SELECTED FINANCIAL DATA

PINNACLE WEST CAPITAL CORPORATION – CONSOLIDATED

The selected data presented below as of and for the years ended December 31, 2017, 2016, 2015, 2014 and 2013 are derived from the Consolidated Financial Statements. The data should be read in connection with the Consolidated Financial Statements including the related notes included in Item 8 of this Form 10-K.

	2017		2016		2015		2014		2013
	(dollars in thousands, except per share amounts)
OPERATING RESULTS
Operating revenues	$	3,565,296	$	3,498,682	$	3,495,443	$	3,491,632	$	3,454,628
Net income	507,949		461,527		456,190		423,696		439,966
Less: Net income attributable to noncontrolling interests	19,493		19,493		18,933		26,101		33,892
Net income attributable to common shareholders	$	488,456	$	442,034	$	437,257	$	397,595	$	406,074
COMMON STOCK DATA
Book value per share – year-end	$	44.80	$	43.14	$	41.30	$	39.50	$	38.07
Earnings per weighted-average common share outstanding:
Net income attributable to common shareholders – basic	$	4.37	$	3.97	$	3.94	$	3.59	$	3.69
Net income attributable to common shareholders – diluted	$	4.35	$	3.95	$	3.92	$	3.58	$	3.66
Dividends declared per share	$	2.70	$	2.56	$	2.44	$	2.33	$	2.23
Weighted-average common shares outstanding – basic	111,838,922		111,408,729		111,025,944		110,626,101		109,984,160
Weighted-average common shares outstanding – diluted	112,366,675		112,046,043		111,552,130		111,178,141		110,805,943
BALANCE SHEET DATA
Total assets	$	17,019,082	$	16,004,253	$	15,028,258	$	14,288,890	$	13,486,826
Liabilities and equity:
Current liabilities	$	1,197,852	$	1,292,946	$	1,442,317	$	1,559,143	$	1,618,644
Long-term debt less current maturities	4,789,713		4,021,785		3,462,391		3,006,573		2,774,605
Deferred credits and other	5,895,787		5,753,610		5,404,093		5,204,072		4,753,117
Total liabilities	11,883,352		11,068,341		10,308,801		9,769,788		9,146,366
Total equity	5,135,730		4,935,912		4,719,457		4,519,102		4,340,460
Total liabilities and equity	$	17,019,082	$	16,004,253	$	15,028,258	$	14,288,890	$	13,486,826

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SELECTED FINANCIAL DATA

ARIZONA PUBLIC SERVICE COMPANY – CONSOLIDATED

	2017		2016		2015		2014		2013
	(dollars in thousands)
OPERATING RESULTS
Electric operating revenues	$	3,554,139	$	3,489,754	$	3,492,357	$	3,488,946	$	3,451,251
Fuel and purchased power costs	992,744		1,082,625		1,101,298		1,179,829		1,095,709
Other operating expenses	1,881,826		1,789,149		1,779,075		1,716,325		1,733,677
Operating income	679,569		617,980		611,984		592,792		621,865
Other income	36,284		46,744		33,332		36,358		20,797
Interest expense — net of allowance for borrowed funds	192,051		183,090		176,109		181,830		183,801
Net income	523,802		481,634		469,207		447,320		458,861
Less: Net income attributable to noncontrolling interests	19,493		19,493		18,933		26,101		33,892
Net income attributable to common shareholder	$	504,309	$	462,141	$	450,274	$	421,219	$	424,969
BALANCE SHEET DATA
Total assets	$	16,893,751	$	15,931,175	$	14,982,182	$	14,190,362	$	13,359,517
Liabilities and equity:
Total equity	$	5,385,869	$	5,037,970	$	4,814,794	$	4,629,852	$	4,454,874
Long-term debt less current maturities	4,491,292		4,021,785		3,337,391		2,881,573		2,649,604
Total capitalization	9,877,161		9,059,755		8,152,185		7,511,425		7,104,478
Current liabilities	1,098,274		1,094,037		1,424,708		1,532,464		1,580,847
Deferred credits and other	5,918,316		5,777,383		5,405,289		5,146,473		4,674,192
Total liabilities and equity	$	16,893,751	$	15,931,175	$	14,982,182	$	14,190,362	$	13,359,517

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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 currently accounts for essentially all of our revenues and earnings.

Areas of Business Focus

Operational Performance, Reliability and Recent Developments.

Nuclear. APS operates and is a joint owner of Palo Verde.  Palo Verde experienced strong performance throughout 2017.  The April and October scheduled refueling outages were each completed in 30 days.  During the peak summer demand season, its capacity factor was 98.9%, and the total year capacity factor was 93.8%. For additional information, see “Business of Arizona Public Service Company - Energy Sources and Resource Planning - Generation Facilities - Nuclear.”

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.  On August 3, 2015, EPA finalized a rule to limit carbon dioxide emissions from existing power plants (the "Clean Power Plan").  On October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan. On December 18, 2017, EPA issued an Advanced Notice of Proposed Rulemaking through which EPA is soliciting comments as to potential replacements for the Clean Power Plan that would be consistent with EPA's current legal interpretation of the Clean Air Act. APS will monitor these proceedings to assess whether or how any future proposed regulations of carbon emissions from existing EGUs would affect APS. See "Business - Environmental Matters - Climate Change - Regulatory Initiatives" for additional information on the current status of EPA's carbon pollution standards for EGUs. APS continually analyzes its long-range capital management plans to assess the potential effects of these changes, 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 continue participation in such plants.

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Cholla

On September 11, 2014, APS announced that it would close its 260 MW Unit 2 at Cholla and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit, which was later addressed in the 2017 Settlement Agreement. (See Note 3 for details related to the resulting cost recovery.) APS believes that the environmental benefits of this proposal are greater in the long-term than the benefits that would have resulted from adding emissions control equipment. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017. For additional information, see "Business of Arizona Public Service Company - Energy Sources and Resource Planning - Coal-Fueled Generating Facilities - Cholla."

Four Corners

Asset Purchase Agreement and Coal Supply Matters.  On December 30, 2013, APS purchased SCE’s 48% interest in each of Units 4 and 5 of Four Corners. The final purchase price for the interest was approximately $182 million. In connection with APS’s prior general 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 23, 2014, the ACC approved rate adjustments related to APS’s acquisition of SCE’s interest in Four Corners resulting in a revenue increase of $57.1 million on an annual basis. This decision was appealed and, on September 26, 2017, the Court of Appeals affirmed the ACC's decision on the Four Corners rate adjustment.

Concurrently with the closing of the SCE transaction described above, BHP Billiton, the parent company of BNCC, the coal supplier and operator of the mine that served 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. Also occurring concurrently with the closing, the Four Corners’ co-owners executed the 2016 Coal Supply Agreement for the supply of coal to Four Corners from July 2016 through 2031. 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 agreed to assume the 7% shortfall obligation. (See Note 10 for a discussion of a pending arbitration related to the 2016 Coal Supply Agreement.) On February 17, 2015, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in each of Units 4 and 5 of Four Corners. 4CA purchased the El Paso interest on July 6, 2016. The purchase price was immaterial in amount, and 4CA assumed El Paso's reclamation and decommissioning obligations associated with the 7% interest.

NTEC had the option to purchase the 7% interest within a certain timeframe pursuant to an option granted to NTEC. On December 29, 2015, NTEC provided notice of its intent to exercise the option. The purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction.

The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% shortfall obligations in the event NTEC does not purchase the interest. At this time, since NTEC has not yet purchased the 7% interest, the alternate pricing provisions are applicable to 4CA as the holder of the 7% interest. These terms include a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales. Such payments are due to 4CA at the end of each calendar year. A $10 million payment was due to 4CA at December 31, 2017, which NTEC satisfied by directing to 4CA a prepayment from APS of a portion of a future mine reclamation obligation. The balance of the amount under this formula at December 31, 2017 is

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approximately $20 million, which is due to 4CA at December 31, 2018. In future years there may be similar payments due from NTEC to 4CA under this formula. 4CA believes NTEC should continue to satisfy its contractual obligations related to these payments; however, if NTEC fails to meet its contractual obligations when due, 4CA will consider appropriate measures and potential impacts to the Company's financial statements.

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 required the approval of the DOI, as did a related federal rights-of-way grant.  A federal environmental review was undertaken as part of the DOI review process, and culminated in the issuance by DOI of a record of decision on July 17, 2015 justifying the agency action extending the life of the plant and the adjacent mine.  

On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine.  The lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016.  APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016.

On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. We cannot predict whether this appeal will be successful and, if it is successful, the outcome of further district court proceedings.

For additional information, see "Business of Arizona Public Service Company - Energy Sources and Resource Planning - Generation Facilities - Coal-Fueled Generating Facilities - Four Corners." 

Navajo Plant

The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant will remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that will allow for decommissioning activities to begin after the plant ceases operations in December 2019. Various stakeholders including regulators, tribal representatives, the plant's coal supplier and DOI have been meeting to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. Although we cannot predict whether any alternate plans will be found that would be acceptable to all of the stakeholders and feasible to implement, we believe it is probable that the Navajo Plant will cease operations in December 2019.

APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant (see Note 3 for details related to the resulting regulatory asset) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material.

On February 14, 2017, the ACC opened a docket titled "ACC Investigation Concerning the Future of the Navajo Generating Station" with the stated goal of engaging stakeholders and negotiating a sustainable

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pathway for the Navajo Plant to continue operating in some form after December 2019. APS cannot predict the outcome of this proceeding.

For additional information, see "Business of Arizona Public Service Company - Energy Sources and Resource Planning - Generation Facilities - Coal-Fueled Generating Facilities - Navajo Plant."

Natural Gas.  APS has six natural gas power plants located throughout Arizona, including Ocotillo. Ocotillo is a 330 MW 4-unit gas plant located in the metropolitan Phoenix area.  In early 2014, APS announced a project to modernize the plant, which involves retiring two older 110 MW steam units, adding five 102 MW combustion turbines and maintaining two existing 55 MW combustion turbines.  In total, this increases the capacity of the site by 290 MW, to 620 MW, with completion targeted by summer 2019.  (See Note 3 for details of the rate recovery in our 2017 Rate Case Decision.) For additional information, see "Business of Arizona Public Service Company - Energy Sources and Resource Planning - Generation Facilities - Coal-Fueled Generating Facilities - Natural Gas and Oil-Fueled Generating Facilities."

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 below includes new APS transmission projects, along with other transmission costs for upgrades and replacements.  APS is also working to establish and expand advanced 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 manage their energy usage, minimize system outage durations and frequency, enable customer choice for new customer sited technologies, and facilitate greater cost savings to APS through improved reliability and the automation of certain distribution functions.

Energy Imbalance Market. In 2015, APS and the CAISO, the operator for the majority of California's transmission grid, signed an agreement for APS to begin participation in EIM. APS's participation in the EIM began on October 1, 2016.  The EIM allows for rebalancing supply and demand in 15-minute blocks with dispatching every five minutes before the energy is needed, instead of the traditional one hour blocks.  APS expects that its participation in EIM will lower its fuel costs, improve visibility and situational awareness for system operations in the Western Interconnection power grid, and improve integration of APS’s renewable resources.

Regulatory Matters

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.  See Note 3 for information on APS’s FERC rates.

On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates of $165.9 million. This amount excluded amounts that were then collected on customer bills through adjustor mechanisms. The application requested that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have had an incremental effect on average customer bills. The average annual customer bill impact of APS’s request was an increase of 5.74% (the average annual bill impact for a typical APS residential customer was 7.96%). See Note 3 for details regarding the principal provisions of APS's application.

On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar

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organizations signed the 2017 Settlement Agreement and filed it with the ACC. The average annual customer bill impact under the 2017 Settlement Agreement is an increase of 3.28% (the average annual bill impact for a typical APS residential customer is 4.54%). (See Note 3 for details of the 2017 Settlement Agreement.)

On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications.  On August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the "2017 Rate Case Decision"), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017. On August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the ACC's order approving the 2017 Settlement Agreement so that alleged issues of disqualification and bias on the part of the other Commissioners can be fully investigated.   APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition.

On October 17, 2017, Warren Woodward (an intervener in APS's general retail rate case) filed a Notice of Appeal in the Arizona Court of Appeals, Division One. The notice raises a single issue related to the application of certain rate schedules to new APS residential customers after May 1, 2018. Mr. Woodward filed a second notice of appeal on November 13, 2017 challenging APS’s $5 per month automated metering infrastructure opt-out program. Mr. Woodward’s two appeals have been consolidated and APS has filed a motion to intervene. APS cannot predict the outcome of this consolidated appeal but does not believe it will have a material impact.

On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”) and not a request for rehearing. Arizona Revised Statute §40-246 requires the ACC to hold a hearing regarding any complaint alleging that a public service corporation is in violation of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least twenty-five customers of the public service corporation. The Complaint alleged that APS is “in violation of commission order” [sic]. On February 13, 2018, the complainant filed an amended Complaint alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable.  The complainant is requesting that the ACC hold a hearing on her amended Complaint to determine if the average bill impact on residential customers of the rates and charges approved in the 2017 Rate Case Decision is greater than 4.54% (the average annual bill impact for a typical APS residential customer estimated by APS), and if so, what effect the alleged greater bill impact has on APS's revenues and the overall reasonableness and justness of APS's rates and charges, in order to determine if there is sufficient evidence to warrant a full-scale rate hearing.  APS cannot predict the outcome of this matter.

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 below and in Note 3.

SCR Cost Recovery. On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Rate Rider to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5.  APS intends to file the SCR Rate Rider in April 2018. Consistent with the 2017 Rate Case Decision, the rate rider filing will be narrow in scope and will address only costs associated with this specific environmental compliance equipment. Also, as provided for in the 2017 Rate Case Decision, APS will request that the rate rider become effective no later than January 1, 2019.

Renewable Energy.  The ACC approved the RES in 2006.  The renewable energy requirement is 8% of retail electric sales in 2018 and increases annually until it reaches 15% in 2025.  In APS’s 2009 general retail rate case settlement agreement, APS agreed to exceed the RES standards, committing to use APS’s best efforts

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to have 1,700 GWh of new renewable resources in service by year-end 2015, in addition to its RES renewable resource commitments.  APS met its settlement commitment and overall RES target for 2017. A component of the RES targets development of distributed energy systems. For additional information, see “Business of Arizona Public Service Company-Energy Sources and Resource Planning - Current and Future Resources-Renewable Energy Standard.”

On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million. APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules. On April 7, 2017, APS filed an amended 2017 RES Implementation Plan and updated budget request which included the revenue neutral transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement.  On August 15, 2017, the ACC approved the 2017 RES Implementation Plan.

On June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million.  APS’s budget request supports existing approved projects and commitments and includes the anticipated transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. APS's 2018 RES budget request is lower than the 2017 RES budget due in part to a certain portion of the RES being collected by APS in base rates rather than through the RES adjustor.

On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a three-year program requiring APS to spend $10-15 million in capital costs each year to install utility-owned distributed generation ("DG") systems for low to moderate income residential homes, buildings of non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES. The ACC has not yet ruled on APS's 2018 RES Implementation Plan.

In September 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES.  The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically.  The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent EPA regulations.  The proceeding will also examine the feasibility of increasing the standard to 30% of retail sales by 2030, in contrast to the current standard of 15% of retail sales by 2025.  On January 30, 2018, ACC Commissioner Tobin proposed a new standard in this proceeding which would broaden the RES to include a series of energy reform policies tied to clean energy sources. The proposal would rename the RES to the Clean Resource Energy Standard and Tariff ("CREST").  APS cannot predict the outcome of this proceeding. See Note 3 for more information on the RES and the CREST.

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 Electric Energy Efficiency Standard of 22% cumulative annual energy savings by 2020.  The 22% figure represents the cumulative reduction in future energy usage through 2020 attributable to energy efficiency initiatives.  This standard became effective on January 1, 2011.

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On June 1, 2016, APS filed its 2017 DSM Implementation Plan, in which APS proposed programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand.  The requested budget in the 2017 DSM Implementation Plan is $62.6 million.  On January 27, 2017, APS filed an updated and modified 2017 DSM Implementation Plan that incorporated the proposed $4 million Residential Demand Response, Energy Storage and Load Management Program that was filed with the ACC on December 5, 2016 and requested that the budget for the 2017 DSM Implementation Plan be increased to $66.6 million. On August 15, 2017, the ACC approved the amended 2017 DSM Implementation Plan.

On September 1, 2017, APS filed its 2018 DSM Implementation Plan, which proposes modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Implementation Plan seeks a reduced requested budget of $52.6 million and requests a waiver of the Electric Energy Efficiency Standard for 2018. On November 14, 2017, APS filed an amended 2018 DSM Implementation Plan, which revised the allocations between budget items to address customer participation levels, but kept the overall budget at $52.6 million. See Note 3 for more information on demand side management.    

Tax Expense Adjustor Mechanism and FERC Tax Filing. As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. On December 22, 2017 the Tax Cuts and Jobs Act (“Tax Act”) was enacted.  This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018.

On January 8, 2018, APS filed an application with the ACC requesting that the TEAM be implemented in two steps. The first addresses the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and, if approved, would reduce rates by $119.1 million annually through an equal cents per kWh credit. APS asked that this decrease become effective February 1, 2018. On February 22, 2018, the ACC approved the reduction of rates by $119.1 million annually through an equal cents per kWh credit applied to all but a small subset of customers who are taking service under specially-approved tariffs. The rate reduction will be effective March 1, 2018.

The second step will address the amortization of excess deferred taxes previously collected from customers. APS is analyzing the final impact of the Tax Act provisions related to deferred taxes and intends to make a second TEAM filing later in 2018.

The TEAM expressly applies to APS's retail rates with the exception noted above. The Company expects to make a filing with FERC in the first quarter of 2018 seeking authorization to provide for the cost reductions resulting from the income tax changes in its wholesale transmission rates.

See Note 3 for additional details.

Net Metering.      In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of DG to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases.  A hearing was held in April 2016. On October 7, 2016, an Administrative Law Judge issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended opinion and order by the Administrative Law Judge. After making several amendments, the ACC approved the recommended opinion and order by a 4-1 vote. As a result of the ACC’s action, effective as of APS’s 2017 Rate Case Decision, the current net metering tariff that governs payments for energy exported to the grid from rooftop

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solar systems was replaced by a more formula-driven approach that utilizes inputs from historical wholesale solar power costs and eventually an avoided cost methodology.

As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a resource comparison proxy methodology, a method that is based on the price that APS pays for utility-scale solar projects on a five year rolling average, while a forecasted avoided cost methodology is being developed.  The price established by this resource comparison proxy method will be updated annually (between general retail rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent general retail rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy.

In addition, the ACC made the following determinations:

• Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to August 19, 2017, the date new rates were effective based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility;

• Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and

• Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years.

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh is included in the 2017 Settlement Agreement and became effective on August 19, 2017.

On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC filed a Notice of Appeal in the Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.

Subpoena from Arizona Corporation Commissioner Robert Burns. On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer.

On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay APS's obligations to comply with the subpoenas and decline to decide APS's motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a

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declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed.

On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC staff.  As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns' suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel. On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the complaint. On February 15, 2018, the Superior Court dismissed Commissioner Burns’ complaint. The matter is subject to appeal. APS and Pinnacle West cannot predict the outcome of this matter.

In addition to the Superior Court proceedings discussed above, on August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the 2017 Rate Case Decision so that alleged issues of disqualification and bias on the part of the other Commissioners could be fully investigated. APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition.

Renewable Energy Ballot Initiative. On February 20, 2018, a coalition of renewable energy advocates filed with the Arizona Secretary of State a ballot initiative for an Arizona constitutional amendment requiring Arizona public service corporations to procure 50% of their energy supply from renewable sources by 2030. For purposes of the proposed amendment, eligible renewable sources would not include nuclear generating facilities. The stated goal of the Clean Energy for a Healthy Arizona coalition is to complete the necessary steps to allow the initiative to be placed on the November 2018 Arizona elections ballot. The coalition must present over 225,000 verifiable signatures to the Secretary of State by July 5, 2018 to meet that goal. APS intends to oppose this effort. We believe the initiative is irresponsible and would result in negative impacts to Arizona utility customers, the Arizona economy and our company. We cannot predict the outcome of this matter.

Clean Resource Energy Standard and Tariff. On January 30, 2018, ACC Commissioner Tobin proposed the CREST, which consists of a series of energy reform policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the Integrated Resource Plan process. The ACC has not yet initiated any formal proceedings with respect to Commissioner Tobin’s proposal; however, on February 22, 2018, the ACC Staff filed a Notice of Inquiry to further examine the matter. APS cannot predict the outcome of this matter.

FERC Matter. As part of APS’s acquisition of SCE’s interest in Four Corners Units 4 and 5, 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.  On December 22, 2015, APS and SCE agreed to terminate the

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Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement.  APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates.  APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter of 2016.  On July 29, 2016, APS filed for a rehearing with FERC. In its order denying recovery, FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. On October 5, 2017, FERC issued an order denying APS's request for rehearing. FERC also upheld its prior determination that the agreement relating to the settlement was a jurisdictional contract and should have been filed with FERC. APS cannot predict whether or if the enforcement division will take any action. APS filed an appeal of FERC's July 1, 2016 and October 5, 2017 orders with the United States Court of Appeals for the Ninth Circuit on December 4, 2017. That proceeding is pending and APS cannot predict the outcome of the proceeding.

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

Other Subsidiaries.

Bright Canyon Energy.On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE.  BCE's focus is on new growth opportunities that leverage the Company’s core expertise in the electric energy industry.  BCE’s first initiative is a 50/50 joint venture with BHE U.S. Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company.  The joint venture, named TransCanyon, is pursuing independent transmission opportunities within the eleven states that comprise the Western Electricity Coordinating Council, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the venture partners’ utility affiliates.  TransCanyon continues to pursue transmission development opportunities in the western United States consistent with its strategy.

On March 29, 2016, TransCanyon entered into a strategic alliance agreement with PG&E to jointly pursue competitive transmission opportunities solicited by the CAISO, the operator for the majority of California's transmission grid. TransCanyon and PG&E intend to jointly engage in the development of future transmission infrastructure and compete to develop, build, own and operate transmission projects approved by the CAISO.

El Dorado. The operations of El Dorado are not expected to have any material impact on our financial results, or to require any material amounts of capital, over the next three years.

4CA. See "Four Corners - Asset Purchase Agreement and Coal Supply Matters" above for information regarding 4CA.

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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 2015 through 2017, retail electric revenues comprised approximately 95% of our total electric operating revenues.  Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms.  These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.

Actual and Projected Customer and Sales Growth.  Retail customers in APS’s service territory increased 1.8% for the year ended December 31, 2017 compared with the prior year.  For the three years 2015 through 2017, APS’s customer growth averaged 1.5% per year. We currently project annual customer growth to be 1.5 - 2.5% for 2018 and to average in the range of 2 - 3% for 2018 through 2020 based on our assessment of modestly improving economic conditions in Arizona.

Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, decreased 0.3% for the year ended December 31, 2017 compared with the prior year. Improving economic conditions and customer growth were more than offset by energy savings driven by customer conservation, energy efficiency, distributed renewable generation initiatives and one fewer day of sales due to the leap year in 2016.  For the three years 2015 through 2017, APS experienced annual increases in retail electricity sales averaging 0.1%, adjusted to exclude the effects of weather variations.  We currently project that annual retail electricity sales in kWh will increase in the range of 0.5 - 1.5% for 2018 and increase on average in the range of 0.5 - 1.5% during 2018 through 2020, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations.  A slower recovery of the Arizona economy or acceleration of the expected effects of customer conservation, energy efficiency or distributed renewable generation initiatives 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 DG, and responses to retail price changes.  Based on past experience, a reasonable range of variation in our kWh sales projections attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of up to approximately $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

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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, unplanned outages, planned outages (typically scheduled in the spring and fall), renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors. See Note 2 for discussion on new accounting guidance related to the presentation of net periodic pension and postretirement benefit cost.

Depreciation and Amortization Expenses.  Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates.  See "Liquidity and Capital Resources" below for information regarding the planned additions to our facilities and income tax impacts related to bonus depreciation. 

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 11.2% of the assessed value for 2017, 11.2% for 2016 and 11.0% for 2015.  We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units and transmission and distribution facilities. 

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. On December 22, 2017, the Tax Cuts and Jobs Act was enacted and is generally effective on January 1, 2018. Changes which will impact the Company include a reduction in the corporate tax rate to 21%, revisions to the rules related to tax bonus depreciation, limitations on interest deductibility and an associated exception for certain public utilities, and requirements that certain excess deferred tax amounts of regulated utilities be normalized. (See Note 4 for details of the impacts on the Company as of December 31, 2017.) In APS's recent general retail rate case, the ACC approved a Tax Expense Adjustor Mechanism which will be used to pass through the income tax effects to retail customers of the Tax Cuts and Jobs Act. (See Note 3 for details of the TEAM.)

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.  AFUDC 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 – 2017 compared with 2016.

Our consolidated net income attributable to common shareholders for the year ended December 31, 2017 was $488 million, compared with $442 million for the prior year.  The results reflect an increase of

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approximately $48 million for the regulated electricity segment primarily due to higher revenue resulting from the retail regulatory settlement effective August 19, 2017, higher transmission revenues, higher retail revenues due to customer growth and higher average effective prices due to customer usage patterns and changes relating to customer program eligibility, partially offset by higher depreciation and amortization primarily due to increased plant in service and higher depreciation and amortization rates.

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

	Year Ended December 31,
	2017			2016			Net change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	2,561		$	2,407		$	154
Operations and maintenance	(911		)	(906		)	(5		)
Depreciation and amortization	(532		)	(485		)	(47		)
Taxes other than income taxes	(183		)	(166		)	(17		)
All other income and expenses, net	29			35			(6		)
Interest charges, net of allowance for borrowed funds used during construction	(198		)	(186		)	(12		)
Income taxes (Note 4)	(256		)	(237		)	(19		)
Less income related to noncontrolling interests (Note 18)	(19		)	(19		)	—
Regulated electricity segment income	491			443			48
All other	(3		)	(1		)	(2		)
Net Income Attributable to Common Shareholders	$	488		$	442		$	46

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Operating revenues less fuel and purchased power expenses.  Regulated electricity segment operating revenues less fuel and purchased power expenses were $154 million higher for the year ended December 31, 2017 compared with the prior year.  The following table summarizes the major components of this change:

	Increase (Decrease)
	Operating revenues			Fuel and purchased power expenses			Net change
	(dollars in millions)
Impacts of retail regulatory settlement effective August 19, 2017 (Note 3)	$	55		$	—		$	55
Transmission revenues (Note 3):
Higher transmission revenues	30			—			30
Absence of 2016 FERC disallowance	12			—			12
Higher retail revenue due to customer growth and higher average effective prices due to customer usage patterns and changes relating to customer program participation (a)	21			(3		)	24
Lost fixed cost recovery	14			—			14
Effects of weather	9			3			6
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals	(83		)	(92		)	9
Higher demand side management regulatory surcharges and renewable energy regulatory surcharges and purchased power, partially offset in operations and maintenance costs	9			2			7
Miscellaneous items, net	(3		)	—			(3		)
Total	$	64		$	(90	)	$	154

(a) Partially offset by the impacts of efficiency programs and distributed generation.

Operations and maintenance.  Operations and maintenance expenses increased $5 million for the year ended December 31, 2017 compared with the prior year primarily because of:

• An increase of $10 million for employee benefit costs;

• An increase of $9 million for costs primarily related to information technology and other corporate support;

• An increase of $8 million related to costs for demand-side management, renewable energy and similar regulatory programs, which is partially offset in operating revenues and purchased power;

• An increase of $5 million related to the Navajo Plant capital projects canceled due to the expected plant retirement, which were deferred for regulatory recovery in depreciation;

• A decrease of $12 million for lower Palo Verde operating costs;

• A decrease of $11 million in fossil generation costs primarily due to less planned outage activity in the current year and lower Navajo Generating Plant costs;

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• A decrease of $5 million primarily due to the absence of 2016 costs to support the Company's positions on a solar net metering ballot initiative in Arizona; and

• An increase of $1 million related to miscellaneous other factors.

Depreciation and amortization.  Depreciation and amortization expenses were $47 million higher for the year ended December 31, 2017 compared with the prior year primarily related to increased plant in service of $32 million and increased depreciation and amortization rates of $19 million, partially offset by the regulatory deferral of the canceled capital projects associated with the expected Navajo Plant retirement of $5 million.

Taxes other than income taxes.  Taxes other than income taxes were $17 million higher for the year ended December 31, 2017 compared with the prior year primarily due to higher property values and the amortization of our property tax deferral regulatory asset.

All other income and expenses, net.  All other income and expenses, net, were $6 million lower for the year ended December 31, 2017 compared with the prior year primarily due to the absence of a gain on sale of a transmission line, which occurred in 2016.

Interest charges, net of allowance for borrowed funds used during construction.  Interest charges, net of allowance for borrowed funds used during construction, increased $12 million for the year ended December 31, 2017 compared with the prior year, primarily because of higher debt balances in the current year.

Income taxes.  Income taxes were $19 million higher for the year ended December 31, 2017 compared with the prior year primarily due to the effects of higher pretax income in the current year and the effects of the federal tax reform, partially offset by a lower effective tax rate primarily due to stock compensation. The stock compensation guidance requires all excess income tax benefits and deficiencies arising from share-based payments to be recognized in earnings in the period they occur, which causes effective tax rate fluctuations when stock compensation payouts occur.

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Operating Results – 2016 compared with 2015.

Our consolidated net income attributable to common shareholders for the year ended December 31, 2016 was $442 million, compared with $437 million for the prior year.  The results reflect an increase of approximately $4 million for the regulated electricity segment primarily due to higher transmission revenues, higher retail revenues due to customer growth and changes in customer usage patterns and related pricing, partially offset by higher operations and maintenance expense primarily related to transmission, distribution and customer service costs.

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

	Year Ended December 31,
	2016			2015			Net change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	2,407		$	2,391		$	16
Operations and maintenance	(906		)	(868		)	(38		)
Depreciation and amortization	(485		)	(494		)	9
Taxes other than income taxes	(166		)	(172		)	6
All other income and expenses, net	35			19			16
Interest charges, net of allowance for borrowed funds used during construction	(186		)	(179		)	(7		)
Income taxes	(237		)	(239		)	2
Less income related to noncontrolling interests (Note 18)	(19		)	(19		)	—
Regulated electricity segment income	443			439			4
All other	(1		)	(2		)	1
Net Income Attributable to Common Shareholders	$	442		$	437		$	5

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Operating revenues less fuel and purchased power expenses.  Regulated electricity segment operating revenues less fuel and purchased power expenses were $16 million higher for the year ended December 31, 2016 compared with the prior year.  The following table summarizes the major components of this change:

	Increase (Decrease)
	Operating revenues			Fuel and purchased power expenses			Net change
	(dollars in millions)
Lost fixed cost recovery	$	17		$	—		$	17
Effects of weather	6			2			4
Transmission revenues (Note 3):
Higher transmission revenues	27			—			27
FERC disallowance	(12		)	—			(12		)
Higher retail revenues due to changes in customer usage patterns and related pricing	10			—			10
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals	(15		)	(17		)	2
Palo Verde system benefits charge (offset in depreciation and amortization, see Note 3)	(14		)	—			(14		)
Lower demand side management regulatory surcharges and renewable energy regulatory surcharges and purchased power partially offset in operations and maintenance costs	(16		)	(1		)	(15		)
Miscellaneous items, net	(6		)	(3		)	(3		)
Total	$	(3	)	$	(19	)	$	16

Operations and maintenance.  Operations and maintenance expenses increased $38 million for the year ended December 31, 2016 compared with the prior year primarily because of:

• An increase of $16 million for transmission, distribution, and customer service costs primarily related to increased maintenance costs and implementation of new systems;

• An increase of $9 million primarily for costs to support the company's positions on a solar net metering ballot initiative in Arizona and increased political participation costs;

• An increase of $8 million in fossil generation costs primarily related to $33 million in higher planned outage costs, partially offset by $25 million of lower other fossil operating costs;

• An increase of $7 million for costs related to legal, regulatory, information systems and other corporate support;

• An increase of $5 million for employee benefit costs primarily related to increased pension, medical claims and other benefit costs;

• An increase of $5 million related to higher nuclear generation costs;

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• An offsetting decrease of $13 million related to costs for demand-side management, renewable energy and similar regulatory programs, which is partially offset in operating revenues and purchased power; and

• An increase of $1 million related to miscellaneous other factors.

Additionally, stock compensation costs were flat compared to the prior year as a $12 million increase in costs was offset by a one-time $12 million reduction for the adoption of new stock compensation guidance (See Note 15);

Depreciation and amortization.  Depreciation and amortization expenses were $9 million lower for the year ended December 31, 2016 compared with the prior year primarily related to:

• A decrease of $20 million related to the regulatory treatment of the Palo Verde sale leaseback lease extension;

• A decrease of $14 million due to lower Palo Verde decommissioning expense recovered through the system benefits charge (offset in operating revenues); and

• An increase of $25 million due to increased plant in service.

Taxes other than income taxes.  Taxes other than income taxes were $6 million lower for the year ended December 31, 2016 compared with the prior year primarily due to lower assessed values resulting from a lower Arizona statutory rate, partially offset by higher property tax rates.

All other income and expenses, net.  All other income and expenses, net, were $16 million higher for the year ended December 31, 2016 compared with the prior year primarily due to higher allowance for equity funds used during construction and the gain on sale of a transmission line.

Interest charges, net of allowance for borrowed funds used during construction.  Interest charges, net of allowance for borrowed funds used during construction, increased $7 million for the year ended December 31, 2016 compared with the prior year, primarily because of higher debt balances in the current year.

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 related ACC order, the common equity ratio is defined as 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, 2017, APS’s common equity ratio, as defined, was 53%.  Its total shareholder equity was approximately $5.3 billion, and total capitalization was approximately $10.0 billion.  Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $4.0 billion,

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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.

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 was enacted.  As a result of this legislation, bonus depreciation is no longer available for regulated public utility company property acquired, or that commenced construction, after September 27, 2017. The final legislative language contains a transition rule for property which was acquired, or under construction, prior to September 28, 2017 which would allow at least some part of APS’s capital projects under construction at that time to continue to qualify for bonus depreciation under pre-Act rules. However, because of current ambiguities regarding the scope of this transition rule, it is unclear how much of APS’s capital projects which were under construction prior to September 28, 2017, will qualify. The Company currently believes the continued availability of bonus depreciation for property under construction prior to September 28, 2017 will generate at least $60-$75 million of cash tax benefits over the next two years. These benefits may be higher if the current ambiguities in the legislative language are clarified in a manner which allows additional expenditures incurred after September 27, 2017, related to ongoing capital projects under construction as of that date, to qualify for bonus depreciation.  The cash generated by bonus depreciation is an acceleration of the tax benefits that APS would have otherwise received over 20 years and reduces rate base for ratemaking purposes. At Pinnacle West Consolidated, when coupled with a lower 21 percent corporate tax rate, the continued availability of bonus depreciation to this transition period property is expected to delay until 2019 full cash realization of approximately $85 million of currently unrealized Investment Tax Credits and other tax credits, which are recorded as a deferred tax asset on the Condensed Consolidated Balance Sheet as of December 31, 2017.

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, 2017, 2016 and 2015 (dollars in millions):

Pinnacle West Consolidated

	2017			2016			2015
Net cash flow provided by operating activities	$	1,118		$	1,023		$	1,094
Net cash flow used for investing activities	(1,429		)	(1,252		)	(1,066		)
Net cash flow provided by financing activities	316			198			4
Net increase (decrease) in cash and cash equivalents	$	5		$	(31	)	$	32

Arizona Public Service Company

	2017			2016			2015
Net cash flow provided by operating activities	$	1,162		$	1,010		$	1,100
Net cash flow used for investing activities	(1,401		)	(1,219		)	(1,060		)
Net cash flow provided by (used for) financing activities	244			196			(22		)
Net increase (decrease) in cash and cash equivalents	$	5		$	(13	)	$	18

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Operating Cash Flows

2017 Compared with 2016. Pinnacle West’s consolidated net cash provided by operating activities was $1,118 million in 2017 compared to $1,023 million in 2016. The increase of $95 million in net cash provided is primarily due to lower payments of operations and maintenance, fuel and purchased power costs and higher cash receipts, partially offset by no collateral posted in 2017 compared to $17 million returned in 2016. The difference between APS and Pinnacle West's net cash provided by operating activities primarily relates to Pinnacle West's cash payments for 4CA's operating costs and differences in other operating cash payments.

2016 Compared with 2015. Pinnacle West’s consolidated net cash provided by operating activities was $1,023 million in 2016 compared to $1,094 million in 2015. The decrease of $71 million in net cash provided is primarily due to higher operations and maintenance costs.

Retirement plans and other postretirement benefits. 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 116% funded as of January 1, 2018 and 115% as of January 1, 2017.  Under accounting principles generally accepted in the United States of America ("GAAP"), the qualified pension plan was 95% funded as of January 1, 2018 and 88% funded as of January 1, 2017. See Note 7 for additional details. 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 $100 million in 2017, $100 million in 2016, and $100 million in 2015.  The minimum required contributions for the pension plan are zero for the next three years.  We expect to make voluntary contributions up to a total of $250 million during the 2018-2020 period.  With regard to contributions to our other postretirement benefit plans, we made a contribution of approximately $1 million in each of 2017, 2016 and 2015.  We do not expect to make any contributions over the next three years to our other postretirement benefit plans. APS funds its share of the contributions.  APS’s share of the pension plan contribution was approximately $100 million in 2017, $100 million in 2016 and $100 million in 2015.  APS’s share of the contributions to the other postretirement benefit plan was approximately $1 million in 2017, 2016 and 2015.

Due to plan changes in September 2014, the Company is currently in the process of seeking Internal Revenue Service ("IRS") approval to move approximately $186 million of other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. In December 2016, FERC approved a methodology for determining the amount of other postretirement benefit trust assets to transfer into a new trust account to pay for active union employee medical costs. On January 2, 2018, these funds were moved to the new trust account.  The Company negotiated a draft Closing Agreement granting tentative approval from the IRS prior to the transfer. Subsequent to the transfer, the Company submitted proof of the transfer to the IRS and expects to execute a final Closing Agreement early in 2018. Per the terms of an order from FERC, the Company must also make an informational filing with FERC. The Company made this FERC filing during February 2018. It is the Company’s understanding that completion of these regulatory requirements will then permit access to the approximately $186 million for the sole purpose of paying active union employee medical benefits.

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Investing Cash Flows

2017 Compared with 2016. Pinnacle West’s consolidated net cash used for investing activities was $(1,429) million in 2017, compared to $(1,252) million in 2016. The increase of $177 million in net cash used primarily related to increased capital expenditures.

2016 Compared with 2015. Pinnacle West’s consolidated net cash used for investing activities was $(1,252) million in 2016, compared to $(1,066) million in 2015. The increase of $186 million in net cash used primarily related to increased capital expenditures.

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,
	2018		2019		2020
APS
Generation:
Nuclear Fuel	$	72	$	64	$	64
Renewables	16		24		17
Environmental	91		22		46
New Gas Generation	120		9		—
Other Generation	210		177		134
Distribution	444		541		617
Transmission	148		215		180
Other (a)	80		101		153
Total APS	$	1,181	$	1,153	$	1,211

 (a)Primarily information systems and facilities projects.

Generation capital expenditures are comprised of various improvements to APS’s existing fossil, renewable 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.  We are monitoring the status of environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.

On February 17, 2015, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in each of Units 4 and 5 of Four Corners. 4CA purchased the El Paso interest on July 6, 2016. NTEC had the option to purchase the 7% interest within a certain timeframe pursuant to an option granted to NTEC. On December 29, 2015, NTEC provided notice of its intent to exercise the option. The purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction. The table above does not include capital expenditures related to 4CA's interest in Four Corners Units 4 and 5 of approximately $15 million in 2018, $7 million in 2019 and $6 million in 2020, which will be assumed by the ultimate owner of the 7% interest.

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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

2017 Compared with 2016. Pinnacle West’s consolidated net cash provided by financing activities was $316 million in 2017, compared to $198 million in 2016, an increase of $118 million in net cash provided.  The net cash provided by financing activities includes $245 million in lower long-term debt repayments and $155 million higher issuances of long-term debt through December 31, 2017, partially offset by a $259 million net decrease in short-term borrowings and $16 million of higher dividend payments.

APS’s consolidated net cash provided by financing activities was $244 million in 2017, compared to $196 million in 2016, an increase of $48 million in net cash provided.  The net cash provided by financing activities includes $370 million in lower long-term debt repayments and $108 million in higher equity infusions from Pinnacle West, partially offset by $143 million lower issuances of long-term debt through December 31, 2017, $271 million net decrease in short-term borrowings and $16 million of higher dividend payments.

2016 Compared with 2015. Pinnacle West’s consolidated net cash provided by financing activities was $198 million in 2016, compared to $4 million in 2015, an increase of $194 million in net cash provided.  The increase in net cash provided by financing activities is primarily due to a $325 million net increase in short-term borrowings and $45 million in lower long-term debt repayments partially offset by $149 million lower issuances of long-term debt through December 31, 2016.

Significant Financing Activities.  On December 20, 2017, the Pinnacle West Board of Directors declared a dividend of $0.695 per share of common stock, payable on March 1, 2018 to shareholders of record on February 1, 2018. During 2017, Pinnacle West increased its indicated annual dividend from $2.62 per share to $2.78 per share. For the year ended December 31, 2017, Pinnacle West's total dividends paid per share of common stock were $2.66 per share, which resulted in dividend payments of $290 million.

On November 30, 2017, Pinnacle West issued $300 million of 2.25% unsecured senior notes that mature on November 30, 2020.  The net proceeds from the sale were used to repay our $125 million term loan and for general corporate purposes.

On March 21, 2017, APS issued an additional $250 million par amount of its outstanding 4.35% senior unsecured notes that mature on November 15, 2045.  The net proceeds from the sale were used to refinance commercial paper borrowings and to replenish cash temporarily used to fund capital expenditures.

On September 11, 2017, APS issued $300 million of 2.95% senior unsecured notes that mature on September 15, 2027. The net proceeds from the sale were used to refinance commercial paper and other indebtedness and to replenish cash used to fund capital expenditures.

On November 30, 2017, PNW contributed $150 million to APS in the form of an equity infusion.  APS used this contribution to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes.

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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, 2017, Pinnacle West had a $200 million facility that matures in May 2021. 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, 2017, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $29.4 million of commercial paper borrowings.

On July 31, 2017, Pinnacle West amended its 364-day unsecured revolving credit facility to increase its capacity from $75 million to $125 million, and to extend the termination date of the facility from August 30, 2017 to July 30, 2018.  Borrowings under the facility bear interest at LIBOR plus 0.80% per annum. At December 31, 2017, Pinnacle West had $66 million outstanding under the facility.

On June 29, 2017, APS replaced its $500 million revolving credit facility that would have matured in September 2020, with a new $500 million facility that matures in June 2022.

At December 31, 2017, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in May 2021 and the above-mentioned $500 million facility. APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2017, APS had no commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities.

 See "Financial Assurances" in Note 10 for a discussion of APS’s separate outstanding letters of credit.

Other Financing Matters.  See Note 16 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, 2017, the ratio was approximately 50% for Pinnacle West and 47% 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.

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See Note 6 for further discussions of liquidity matters.

Credit Ratings

The ratings of securities of Pinnacle West and APS as of February 16, 2018 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	A3	A-	A-
Senior unsecured	A3	BBB+	A-
Commercial paper	P-2	A-2	F2
Outlook	Stable	Positive	Stable
APS
Corporate credit rating	A2	A-	A-
Senior unsecured	A2	A-	A
Commercial paper	P-1	A-2	F2
Outlook	Stable	Positive	Stable

Off-Balance Sheet Arrangements

See Note 18 for a discussion of the impacts on our financial statements of consolidating certain VIEs.

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Contractual Obligations

The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2017 (dollars in millions):

	2018		2019- 2020		2021- 2022		Thereafter		Total
Long-term debt payments, including interest: (a)
APS	$	290	$	1,192	$	310	$	5,959	$	7,751
Pinnacle West	7		314		—		—		321
Total long-term debt payments, including interest	297		1,506		310		5,959		8,072
Short-term debt payments, including interest (b)	95		—		—		—		95
Fuel and purchased power commitments (c)	539		1,099		1,084		6,271		8,993
Renewable energy credits (d)	40		80		80		370		570
Purchase obligations (e)	176		27		18		204		425
Coal reclamation	32		56		46		207		341
Nuclear decommissioning funding requirements	2		4		4		55		65
Noncontrolling interests (f)	23		46		46		182		297
Operating lease payments	13		21		12		56		102
Total contractual commitments	$	1,217	$	2,839	$	1,600	$	13,304	$	18,960

(a) The long-term debt matures at various dates through 2046 and bears interest principally at fixed rates.  Interest on variable-rate long-term debt is determined by using average rates at December 31, 2017 (see Note 6).

(b) See Note 5 - Lines of credit and short-term borrowings for further details.

(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 10).

(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 18).

This table excludes $42 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain.  Estimated minimum required pension contributions are zero for 2018, 2019 and 2020 (see Note 7).

CRITICAL ACCOUNTING POLICIES

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

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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 amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to 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 $1,450 million of regulatory assets and $2,553 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2017.

Included in the balance of regulatory assets at December 31, 2017 is a regulatory asset of $576 million for pension benefits.  This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings.  If all or a portion of these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future earnings.

See Notes 1 and 3 for more information.

Pensions and Other Postretirement Benefit Accounting

Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit liability and expense can have a significant impact on our earnings and financial position.  The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, the mortality assumptions, 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, 2017 reported pension liability on the Consolidated Balance Sheets and our 2017 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%	$	(372	)	$	(11	)
Decrease 1%	455			14
Expected long-term rate of return on plan assets:
Increase 1%	—			(13		)
Decrease 1%	—			13

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

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The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2017 other postretirement benefit obligation and our 2017 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%	$	(100	)	$	(3	)
Decrease 1%	129			6
Healthcare cost trend rate (b):
Increase 1%	128			8
Decrease 1%	(98		)	(6		)
Expected long-term rate of return on plan assets – pretax:
Increase 1%	—			(4		)
Decrease 1%	—			4

(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 Notes 2 and 7 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, investments held in our coal reclamation escrow account, 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. We utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  The significance of a particular input determines how the instrument is classified in a fair value hierarchy.  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 of accounting policies and Note 13 for fair value measurement disclosures.

Asset Retirement Obligations

We recognize an ARO for the future decommissioning or retirement of our tangible long-lived assets for which a legal obligation exists. The ARO liability represents an estimate of the fair value of the current obligation related to decommissioning and the retirement of those assets. ARO measurements inherently involve uncertainty in the amount and timing of settlement of the liability. We use an expected cash flow approach to measure the amount we recognize as an ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the power plant’s current license or lease term and expected

75

decommissioning dates. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related assets. In addition, we accrete the ARO liability to reflect the passage of time. Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets. In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.

AROs as of December 31, 2017 are described further in “Note 11, Asset Retirement Obligations”.

Income Taxes

Our income tax expense, deferred tax assets and liabilities, and liabilities for unrecognized tax benefits reflect management’s best estimate of current and future taxes to be paid.

On December 22, 2017, the Tax Cuts and Jobs Act was enacted, and is generally effective January 1, 2018. This legislation made significant changes to the federal income tax laws. Changes which will impact the Company include, but are not limited to, a reduction in the corporate tax rate to 21%, revisions to the rules related to tax bonus depreciation, limitations on interest deductibility and an associated exception for certain public utility property, and requirements that certain excess deferred tax amounts of regulated utilities be normalized. Several sections of the final legislation contain technical ambiguities. Accordingly, it is necessary for management to interpret this legislation and make judgements until further guidance becomes available. As a result, changes in these judgments could materially affect amounts the Company recognized in its financial statements.

Deferred tax assets or liabilities are recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period the change is enacted. Given the regulatory nature of the Company’s business, the effect on deferred tax assets and liabilities for the reduction in the federal corporate tax rate to 21%, which management believes it is probable that a regulatory agency will seek to recover for ratepayers, has been recorded as a regulatory liability as of December 31, 2017.

The calculation of our tax liabilities involves dealing with the application of complex laws and regulations which are voluminous and often ambiguous. Interpretations and guidance surrounding income tax laws and regulations change over time. Tax positions taken by Pinnacle West on its income tax returns that are recognized in the financial statements must satisfy a more likely than not recognition threshold, assuming that the position will be sustained upon examination by taxing authorities with full knowledge of all relevant information, including resolutions of any related appeals or litigation processes, on the basis of the technical merits.

We record unrecognized tax benefits for tax positions that may not satisfy this more likely than not recognition threshold as liabilities in accordance with generally accepted accounting principles. These liabilities are adjusted when management judgement changes as a result of the evaluation of new information not previously available. These changes will be reflected as an increase or decrease to income tax expense in the period in which new information is available.

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OTHER ACCOUNTING MATTERS

We adopted the following new accounting standards on January 1, 2018:

• ASU 2014-09: Revenue from Contracts with Customers, and related amendments

• ASU 2016-01: Financial Instruments, Recognition and Measurement

• ASU 2016-15: Statement of Cash Flows, Classification of Certain Cash Receipts and Cash Payments

• ASU 2016-18: Statement of Cash Flows, Restricted Cash

• ASU 2017-07: Compensation-Retirement Benefits, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

• ASU 2017-01: Business Combinations, Clarifying the Definition of a Business

• ASU 2017-05: Other Income, Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets

We are currently evaluating the impacts of the pending adoption of the following new accounting standards:

• ASU 2016-02: Leases, and related amendments, effective for us on January 1, 2019

• ASU 2017-12: Derivatives and Hedging, Targeted Improvements to Accounting for Hedging Activities, effective for us on January 1, 2019

• ASU 2018-02: Income Statement-Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

• ASU 2016-13: Financial Instruments, Measurement of Credit Losses, effective for us on January 1, 2020

See Note 2 for additional information related to new accounting standards.

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 13 and Note 19) 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.

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The tables below present contractual balances of our consolidated long-term and short-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2017 and 2016.  The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2017 and 2016 (dollars in millions):

Pinnacle West – Consolidated

	Short-Term Debt				Variable-Rate Long-Term Debt				Fixed-Rate Long-Term Debt
	Interest				Interest				Interest
2017	Rates		Amount		Rates		Amount		Rates		Amount
2018	2.14	%	$	95	2.17	%	$	50	1.75	%	$	32
2019	—		—		2.27	%	100		8.75	%	500
2020	—		—		—		—		2.23	%	550
2021	—		—		—		—		—		—
2022	—		—		—		—		—		—
Years thereafter	—		—		1.77	%	36		4.25	%	3,640
Total			$	95			$	186			$	4,722
Fair value			$	95			$	186			$	5,119

	Short-Term Debt				Variable-Rate Long-Term Debt				Fixed-Rate Long-Term Debt
	Interest				Interest				Interest
2016	Rates		Amount		Rates		Amount		Rates		Amount
2017	1.01	%	$	177	1.52	%	$	125	—	%	$	—
2018	—		—		1.37	%	50		1.75	%	32
2019	—		—		1.46	%	100		8.75	%	500
2020	—		—		—		—		2.20	%	250
2021	—		—		—		—		—		—
Years thereafter	—		—		0.81	%	36		4.37	%	3,090
Total			$	177			$	311			$	3,872
Fair value			$	177			$	311			$	4,115

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The tables below present contractual balances of APS’s long-term and short-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2017 and 2016.  The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2017 and 2016 (dollars in millions):

APS — Consolidated

	Variable-Rate Long-Term Debt				Fixed-Rate Long-Term Debt
	Interest				Interest
2017	Rates		Amount		Rates		Amount
2018	2.17	%	$	50	1.75	%	$	32
2019	2.27	%	100		8.75	%	500
2020	—		—		2.20	%	250
2021	—		—		—		—
2022	—		—		—		—
Years thereafter	1.77	%	36		4.25	%	3,640
Total			$	186			$	4,422
Fair value			$	186			$	4,820

	Short-Term Debt				Variable-Rate Long-Term Debt				Fixed-Rate Long-Term Debt
	Interest				Interest				Interest
2016	Rates		Amount		Rates		Amount		Rates		Amount
2017	0.88	%	$	135	—	%	$	—	—	%	$	—
2018	—		—		1.37	%	50		1.75	%	32
2019	—		—		1.46	%	100		8.75	%	500
2020	—		—		—		—		2.20	%	250
2021	—		—		—		—		—		—
Years thereafter	—		—		0.81	%	36		4.37	%	3,090
Total			$	135			$	186			$	3,872
Fair value			$	135			$	186			$	4,115

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.

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The following table shows the net pretax changes in mark-to-market of our derivative positions in 2017 and 2016 (dollars in millions):

	2017			2016
Mark-to-market of net positions at beginning of year	$	(49	)	$	(154	)
Decrease (Increase) in regulatory asset	(46		)	101
Recognized in OCI:
Mark-to-market losses realized during the period	4			4
Change in valuation techniques	—			—
Mark-to-market of net positions at end of year	$	(91	)	$	(49	)

The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at December 31, 2017 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	2018			2019			2020			2021			Total  fair  value
Observable prices provided by other external sources	$	(49	)	$	(23	)	$	(1	)	$	(1	)	$	(74	)
Prices based on unobservable inputs	(5		)	(8		)	(4		)	—			(17		)
Total by maturity	$	(54	)	$	(31	)	$	(5	)	$	(1	)	$	(91	)

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, 2017 and 2016 (dollars in millions):

	December 31, 2017 Gain (Loss)					December 31, 2016 Gain (Loss)
	Price Up  10%		Price Down 10%			Price Up  10%		Price Down 10%
Mark-to-market changes reported in:
Regulatory asset (liability) or OCI (a)
Electricity	$	1	$	(1	)	$	2	$	(2	)
Natural gas	45		(45		)	46		(46		)
Total	$	46	$	(46	)	$	48	$	(48	)

(a) 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.

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Credit Risk

We are exposed to losses in the event of non-performance or non-payment by counterparties.  See Note 16 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 risks.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS AND

FINANCIAL STATEMENT SCHEDULES

	Page
Management’s Report on Internal Control over Financial Reporting (Pinnacle West Capital Corporation)	83
Report of Independent Registered Public Accounting Firm	84
Pinnacle West Consolidated Statements of Income for 2017, 2016 and 2015	86
Pinnacle West Consolidated Statements of Comprehensive Income for 2017, 2016, and 2015	87
Pinnacle West Consolidated Balance Sheets as of December 31, 2017 and 2016	88
Pinnacle West Consolidated Statements of Cash Flows for 2017, 2016 and 2015	90
Pinnacle West Consolidated Statements of Changes in Equity for 2017, 2016 and 2015	91
Management’s Report on Internal Control over Financial Reporting (Arizona Public Service Company)	92
Report of Independent Registered Public Accounting Firm	93
APS Consolidated Statements of Income for 2017, 2016 and 2015	95
APS Consolidated Statements of Comprehensive Income for 2017, 2016 and 2015	96
APS Consolidated Balance Sheets as of December 31, 2017 and 2016	97
APS Consolidated Statements of Cash Flows for 2017, 2016 and 2015	99
APS Consolidated Statements of Changes in Equity for 2017, 2016 and 2015	100
Combined Notes to Consolidated Financial Statements	101
Note 1. Summary of Significant Accounting Policies	101
Note 2. New Accounting Standards	108
Note 3. Regulatory Matters	112
Note 4. Income Taxes	124
Note 5. Lines of Credit and Short-Term Borrowings	128
Note 6. Long-Term Debt and Liquidity Matters	130
Note 7. Retirement Plans and Other Postretirement Benefits	133
Note 8. Leases	141
Note 9. Jointly-Owned Facilities	143
Note 10. Commitments and Contingencies	144
Note 11. Asset Retirement Obligations	152
Note 12. Selected Quarterly Financial Data (Unaudited)	153
Note 13. Fair Value Measurements	154
Note 14. Earnings Per Share	161
Note 15. Stock-Based Compensation	161
Note 16. Derivative Accounting	164
Note 17. Other Income and Other Expense	169
Note 18. Palo Verde Sale Leaseback Variable Interest Entities	169
Note 19. Investments	171
Note 20. Changes in Accumulated Other Comprehensive Loss	172

See Note 12 for the selected quarterly financial data (unaudited) required to be presented in this Item.

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MANAGEMENT’S REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

(PINNACLE WEST CAPITAL CORPORATION)

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Pinnacle West.  Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2017.  The effectiveness of our internal control over financial reporting as of December 31, 2017 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 23, 2018

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of

Pinnacle West Capital Corporation

Phoenix, Arizona

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the "Company") as of December 31, 2017 and 2016, 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, 2017, the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

Basis for Opinions

The Company’s management is responsible for these financial statements, 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 an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. 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, and 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.

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Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed 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.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte & Touche LLP

Phoenix, Arizona

February 23, 2018

We have served as the Company's auditor since 1932.

85

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

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

	Year Ended December 31,
	2017			2016			2015
OPERATING REVENUES	$	3,565,296		$	3,498,682		$	3,495,443
OPERATING EXPENSES
Fuel and purchased power	981,301			1,075,510			1,101,298
Operations and maintenance	924,443			911,319			868,377
Depreciation and amortization	534,118			485,829			494,422
Taxes other than income taxes	184,347			166,499			171,812
Other expenses	6,660			3,541			4,932
Total	2,630,869			2,642,698			2,640,841
OPERATING INCOME	934,427			855,984			854,602
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction (Note 1)	47,011			42,140			35,215
Other income (Note 17)	4,006			901			621
Other expense (Note 17)	(21,539		)	(15,337		)	(17,823		)
Total	29,478			27,704			18,013
INTEREST EXPENSE
Interest charges	219,796			205,720			194,964
Allowance for borrowed funds used during construction (Note 1)	(22,112		)	(19,970		)	(16,259		)
Total	197,684			185,750			178,705
INCOME BEFORE INCOME TAXES	766,221			697,938			693,910
INCOME TAXES (Note 4)	258,272			236,411			237,720
NET INCOME	507,949			461,527			456,190
Less: Net income attributable to noncontrolling interests (Note 18)	19,493			19,493			18,933
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	488,456		$	442,034		$	437,257
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	111,839			111,409			111,026
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	112,367			112,046			111,552
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic	$	4.37		$	3.97		$	3.94
Net income attributable to common shareholders — diluted	$	4.35		$	3.95		$	3.92

The accompanying notes are an integral part of the financial statements.

86

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)

	Year Ended December 31,
	2017			2016			2015
NET INCOME	$	507,949		$	461,527		$	456,190
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit (expense) of $24, $(585), and $(342) (Note 16)	(35		)	(538		)	(957		)
Reclassification of net realized loss, net of tax benefit of $1,294, $985, and $1,801 (Note 16)	2,225			2,941			4,187
Pension and other postretirement benefits activity, net of tax benefit (expense) of $693, $633, and $(13,302) (Note 7)	(3,370		)	(1,477		)	20,163
Total other comprehensive income (loss)	(1,180		)	926			23,393
COMPREHENSIVE INCOME	506,769			462,453			479,583
Less: Comprehensive income attributable to noncontrolling interests	19,493			19,493			18,933
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	487,276		$	442,960		$	460,650

The accompanying notes are an integral part of the financial statements.

87

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	December 31,
	2017			2016
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	13,892		$	8,881
Customer and other receivables	305,147			250,491
Accrued unbilled revenues	112,434			107,949
Allowance for doubtful accounts	(2,513		)	(3,037		)
Materials and supplies (at average cost)	264,012			253,979
Fossil fuel (at average cost)	25,258			28,608
Income tax receivable (Note 4)	—			3,751
Assets from risk management activities (Note 16)	1,931			19,694
Deferred fuel and purchased power regulatory asset (Note 3)	75,637			12,465
Other regulatory assets (Note 3)	172,451			94,410
Other current assets	48,039			45,028
Total current assets	1,016,288			822,219
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 16)	51			1
Nuclear decommissioning trust (Notes 13 and 19)	871,000			779,586
Other assets	84,531			69,063
Total investments and other assets	955,582			848,650
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Plant in service and held for future use	17,798,061			17,341,888
Accumulated depreciation and amortization	(6,128,535		)	(5,970,100		)
Net	11,669,526			11,371,788
Construction work in progress	1,291,498			1,019,947
Palo Verde sale leaseback, net of accumulated depreciation of $241,405 and $237,535 (Note 18)	109,645			113,515
Intangible assets, net of accumulated amortization of $582,272 and $603,637	257,189			90,022
Nuclear fuel, net of accumulated amortization of $144,070 and $147,202	117,408			119,004
Total property, plant and equipment	13,445,266			12,714,276
DEFERRED DEBITS
Regulatory assets (Notes 1, 3 and 4)	1,202,302			1,313,428
Assets for other postretirement benefits (Note 7)	268,978			166,206
Other	130,666			139,474
Total deferred debits	1,601,946			1,619,108
TOTAL ASSETS	$	17,019,082		$	16,004,253

The accompanying notes are an integral part of the financial statements.

88

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	December 31,
	2017			2016
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	256,442		$	264,631
Accrued taxes (Note 4)	148,946			138,964
Accrued interest	56,397			52,835
Common dividends payable	77,667			72,926
Short-term borrowings (Note 5)	95,400			177,200
Current maturities of long-term debt (Note 6)	82,000			125,000
Customer deposits	70,388			82,520
Liabilities from risk management activities (Note 16)	59,252			25,836
Liabilities for asset retirements (Note 11)	4,745			9,135
Regulatory liabilities (Note 3)	100,086			99,899
Other current liabilities	246,529			244,000
Total current liabilities	1,197,852			1,292,946
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)	4,789,713			4,021,785
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)	1,690,805			2,945,232
Regulatory liabilities (Notes 1, 3, 4 and 7)	2,452,536			948,916
Liabilities for asset retirements (Note 11)	674,784			615,340
Liabilities for pension benefits (Note 7)	327,300			509,310
Liabilities from risk management activities (Note 16)	37,170			47,238
Customer advances	113,996			88,672
Coal mine reclamation	231,597			221,910
Deferred investment tax credit	205,575			210,162
Unrecognized tax benefits (Note 4)	13,115			10,046
Other	148,909			156,784
Total deferred credits and other	5,895,787			5,753,610
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 111,816,170 and 111,392,053 issued at respective dates	2,614,805			2,596,030
Treasury stock at cost; 64,463 shares at end of 2017 and 55,317 shares at end of 2016	(5,624		)	(4,133		)
Total common stock	2,609,181			2,591,897
Retained earnings	2,442,511			2,255,547
Accumulated other comprehensive loss (Note 20)	(45,002		)	(43,822		)
Total shareholders’ equity	5,006,690			4,803,622
Noncontrolling interests (Note 18)	129,040			132,290
Total equity	5,135,730			4,935,912
TOTAL LIABILITIES AND EQUITY	$	17,019,082		$	16,004,253

The accompanying notes are an integral part of the financial statements.

89

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

	Year Ended December 31,
	2017			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	507,949		$	461,527		$	456,190
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	610,629			565,011			571,664
Deferred fuel and purchased power	(48,405		)	(60,303		)	14,997
Deferred fuel and purchased power amortization	(14,767		)	38,152			1,617
Allowance for equity funds used during construction	(47,011		)	(42,140		)	(35,215		)
Deferred income taxes	248,164			206,870			236,819
Deferred investment tax credit	(4,587		)	23,082			8,473
Change in derivative instruments fair value	(373		)	(403		)	(381		)
Stock compensation	20,502			18,883			18,756
Changes in current assets and liabilities:
Customer and other receivables	(93,797		)	(2,489		)	(22,219		)
Accrued unbilled revenues	(4,485		)	(11,709		)	4,293
Materials, supplies and fossil fuel	(6,683		)	(1,491		)	(23,945		)
Income tax receivable	3,751			(3,162		)	2,509
Other current assets	(10,580		)	(23,324		)	3,145
Accounts payable	(23,769		)	(66,917		)	(34,266		)
Accrued taxes	9,982			447			(2,013		)
Other current liabilities	19,154			29,594			603
Change in margin and collateral accounts — assets	(300		)	673			(324		)
Change in margin and collateral accounts — liabilities	(533		)	17,735			22,776
Change in unrecognized tax benefits	5,891			1,628			(10,328		)
Change in long-term regulatory liabilities	45,764			14,682			(20,535		)
Change in other long-term assets	(68,480		)	(60,163		)	2,426
Change in other long-term liabilities	(29,980		)	(82,793		)	(100,715		)
Net cash flow provided by operating activities	1,118,036			1,023,390			1,094,327
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,408,774		)	(1,275,472		)	(1,076,087		)
Contributions in aid of construction	23,708			64,296			46,546
Allowance for borrowed funds used during construction	(22,112		)	(19,970		)	(16,259		)
Proceeds from nuclear decommissioning trust sales	542,246			633,410			478,813
Investment in nuclear decommissioning trust	(544,527		)	(635,691		)	(496,062		)
Other	(19,078		)	(18,651		)	(3,184		)
Net cash flow used for investing activities	(1,428,537		)	(1,252,078		)	(1,066,233		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	848,239			693,151			842,415
Repayment of long-term debt	(125,000		)	(370,430		)	(415,570		)
Short-term borrowings and (repayments) — net	(107,800		)	137,200			(147,400		)
Short-term debt borrowings under revolving credit facility	58,000			40,000			—
Short-term debt repayments under revolving credit facility	(32,000		)	—			—
Dividends paid on common stock	(289,793		)	(274,229		)	(260,027		)
Common stock equity issuance and purchases - net	(13,390		)	(4,867		)	19,373
Distributions to noncontrolling interests	(22,744		)	(22,744		)	(35,002		)
Other	—			—			1
Net cash flow provided by financing activities	315,512			198,081			3,790
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	5,011			(30,607		)	31,884
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	8,881			39,488			7,604
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	13,892		$	8,881		$	39,488

 The accompanying notes are an integral part of the financial statements.

90

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(dollars in thousands, except per share amounts)

	Common Stock			Treasury Stock					Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Shares	Amount		Shares		Amount
Balance, December 31, 2014	110,649,762	$	2,512,970	(78,400	)	$	(3,401	)	$	1,926,065		$	(68,141	)	$	151,609		$	4,519,102
Net income		—				—			437,257			—			18,933			456,190
Other comprehensive income		—				—			—			23,393			—			23,393
Dividends on common stock ($2.44 per share)		—				—			(270,519		)	—			—			(270,519		)
Issuance of common stock	445,640	28,698				—			—			—			—			28,698
Purchase of treasury stock (a)		—		(154,751	)	(10,136		)	—			—			—			(10,136		)
Reissuance of treasury stock for stock-based compensation and other		—		118,121		7,731			—			—			—			7,731
Net capital activities by noncontrolling interests		—				—			—			—			(35,002		)	(35,002		)
Balance, December 31, 2015	111,095,402	2,541,668		(115,030	)	(5,806		)	2,092,803			(44,748		)	135,540			4,719,457
Net income		—				—			442,034			—			19,493			461,527
Other comprehensive income		—				—			—			926			—			926
Dividends on common stock ($2.56 per share)		—				—			(284,765		)	—			—			(284,765		)
Issuance of common stock	296,651	13,982				—			—			—			—			13,982
Purchase of treasury stock (a)		—		(128,105	)	(9,087		)	—			—			—			(9,087		)
Reissuance of treasury stock for stock-based compensation and other		—		187,818		10,760			—			—			—			10,760
Stock compensation cumulative effect adjustments (See Note 15)		40,380				—			5,475			—			—			45,855
Net capital activities by noncontrolling interests		—				—			—			—			(22,743		)	(22,743		)
Balance, December 31, 2016	111,392,053	2,596,030		(55,317	)	(4,133		)	2,255,547			(43,822		)	132,290			4,935,912
Net income		—				—			488,456			—			19,493			507,949
Other comprehensive loss		—				—			—			(1,180		)	—			(1,180		)
Dividends on common stock ($2.70 per share)		—				—			(301,492		)	—			—			(301,492		)
Issuance of common stock	424,117	18,775				—			—			—			—			18,775
Purchase of treasury stock (a)		—		(216,911	)	(17,755		)	—			—			—			(17,755		)
Reissuance of treasury stock for stock-based compensation and other		—		207,765		16,264			—			—			—			16,264
Net capital activities by noncontrolling interests		—				—			—			—			(22,743		)	(22,743		)
Balance, December 31, 2017	111,816,170	$	2,614,805	(64,463	)	$	(5,624	)	$	2,442,511		$	(45,002	)	$	129,040		$	5,135,730

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

The accompanying notes are an integral part of the financial statements.

91

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 (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2017.  The effectiveness of our internal control over financial reporting as of December 31, 2017 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 23, 2018

92

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of

Arizona Public Service Company

Phoenix, Arizona

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Arizona Public Service Company and subsidiary (the "Company") as of December 31, 2017 and 2016, 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, 2017, the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

Basis for Opinions

The Company’s management is responsible for these financial statements, 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 an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. 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, and 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.

93

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed 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.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte & Touche LLP

Phoenix, Arizona

February 23, 2018

We have served as the Company's auditor since 1932.

94

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(dollars in thousands)

	Year Ended December 31,
	2017			2016			2015
ELECTRIC OPERATING REVENUES	$	3,554,139		$	3,489,754		$	3,492,357
OPERATING EXPENSES
Fuel and purchased power	992,744			1,082,625			1,101,298
Operations and maintenance	891,129			879,108			853,135
Depreciation and amortization	532,423			484,909			494,298
Income taxes (Note 4)	275,295			259,353			260,143
Taxes other than income taxes	182,979			165,779			171,499
Total	2,874,570			2,871,774			2,880,373
OPERATING INCOME	679,569			617,980			611,984
OTHER INCOME (DEDUCTIONS)
Income taxes (Note 4)	6,127			13,511			14,302
Allowance for equity funds used during construction (Note 1)	47,011			42,140			35,215
Other income (Note 17)	6,526			8,607			2,834
Other expense (Note 17)	(23,380		)	(17,514		)	(19,019		)
Total	36,284			46,744			33,332
INTEREST EXPENSE
Interest on long-term debt	200,211			189,828			180,123
Interest on short-term borrowings	9,119			7,983			7,376
Debt discount, premium and expense	4,833			4,760			4,793
Allowance for borrowed funds used during construction (Note 1)	(22,112		)	(19,481		)	(16,183		)
Total	192,051			183,090			176,109
NET INCOME	523,802			481,634			469,207
Less: Net income attributable to noncontrolling interests (Note 18)	19,493			19,493			18,933
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	504,309		$	462,141		$	450,274

The accompanying notes are an integral part of the financial statements.

95

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)

	Year Ended December 31,
	2017			2016			2015
NET INCOME	$	523,802		$	481,634		$	469,207
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit (expense) of $24, $(585), and $(342) (Note 16)	(35		)	(538		)	(957		)
Reclassification of net realized loss, net of tax benefit of $1,294, $985, and $1,801 (Note 16)	2,225			2,941			4,187
Pension and other postretirement benefits activity, net of tax benefit (expense) of $977, $293, and $(11,776) (Note 7)	(3,750		)	(729		)	18,006
Total other comprehensive income (loss)	(1,560		)	1,674			21,236
COMPREHENSIVE INCOME	522,242			483,308			490,443
Less: Comprehensive income attributable to noncontrolling interests	19,493			19,493			18,933
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	502,749		$	463,815		$	471,510

The accompanying notes are an integral part of the financial statements.

96

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	December 31,
	2017			2016
ASSETS
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Plant in service and held for future use	$	17,654,078		$	17,228,787
Accumulated depreciation and amortization	(6,041,965		)	(5,881,941		)
Net	11,612,113			11,346,846
Construction work in progress	1,266,636			989,497
Palo Verde sale leaseback, net of accumulated depreciation of $241,405 and $237,535 (Note 18)	109,645			113,515
Intangible assets, net of accumulated amortization of $581,135 and $603,637	257,028			89,868
Nuclear fuel, net of accumulated amortization of $144,070 and $147,202	117,408			119,004
Total property, plant and equipment	13,362,830			12,658,730
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 13 and 19)	871,000			779,586
Assets from risk management activities (Note 16)	51			1
Other assets	67,103			48,320
Total investments and other assets	938,154			827,907
CURRENT ASSETS
Cash and cash equivalents	13,851			8,840
Customer and other receivables	292,791			262,611
Accrued unbilled revenues	112,434			107,949
Allowance for doubtful accounts	(2,513		)	(3,037		)
Materials and supplies (at average cost)	262,630			252,777
Fossil fuel (at average cost)	25,258			28,608
Income tax receivable	—			11,174
Assets from risk management activities (Note 16)	1,931			19,694
Deferred fuel and purchased power regulatory asset (Note 3)	75,637			12,465
Other regulatory assets (Note 3)	172,451			94,410
Other current assets	41,055			41,849
Total current assets	995,525			837,340
DEFERRED DEBITS
Regulatory assets (Notes 1, 3, and 4)	1,202,302			1,313,428
Assets for other postretirement benefits (Note 7)	265,139			162,911
Other	129,801			130,859
Total deferred debits	1,597,242			1,607,198
TOTAL ASSETS	$	16,893,751		$	15,931,175

The accompanying notes are an integral part of the financial statements.

97

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	December 31,
	2017			2016
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital	2,571,696			2,421,696
Retained earnings	2,533,954			2,331,245
Accumulated other comprehensive loss (Note 20)	(26,983		)	(25,423		)
Total shareholder equity	5,256,829			4,905,680
Noncontrolling interests (Note 18)	129,040			132,290
Total equity	5,385,869			5,037,970
Long-term debt less current maturities (Note 6)	4,491,292			4,021,785
Total capitalization	9,877,161			9,059,755
CURRENT LIABILITIES
Short-term borrowings (Note 5)	—			135,500
Current maturities of long-term debt (Note 6)	82,000			—
Accounts payable	247,852			259,161
Accrued taxes (Note 4)	157,349			130,576
Accrued interest	55,533			52,525
Common dividends payable	77,700			72,900
Customer deposits	70,388			82,520
Liabilities from risk management activities (Note 16)	59,252			25,836
Liabilities for asset retirements (Note 11)	4,192			8,703
Regulatory liabilities (Note 3)	100,086			99,899
Other current liabilities	243,922			226,417
Total current liabilities	1,098,274			1,094,037
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)	1,742,485			2,999,295
Regulatory liabilities (Notes 1, 3, and 4)	2,452,536			948,916
Liabilities for asset retirements (Note 11)	666,527			607,234
Liabilities for pension benefits (Note 7)	306,542			488,253
Liabilities from risk management activities (Note 16)	37,170			47,238
Customer advances	113,996			88,672
Coal mine reclamation	215,830			206,645
Deferred investment tax credit	205,575			210,162
Unrecognized tax benefits (Note 4)	43,876			37,408
Other	133,779			143,560
Total deferred credits and other	5,918,316			5,777,383
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	16,893,751		$	15,931,175

The accompanying notes are an integral part of the financial statements.

98

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

	Year Ended December 31,
	2017			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	523,802		$	481,634		$	469,207
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	608,935			564,091			571,540
Deferred fuel and purchased power	(48,405		)	(60,303		)	14,997
Deferred fuel and purchased power amortization	(14,767		)	38,152			1,617
Allowance for equity funds used during construction	(47,011		)	(42,140		)	(35,215		)
Deferred income taxes	249,465			221,167			223,069
Deferred investment tax credit	(4,587		)	23,082			8,473
Change in derivative instruments fair value	(373		)	(403		)	(381		)
Changes in current assets and liabilities:
Customer and other receivables	(68,040		)	(1,601		)	(21,040		)
Accrued unbilled revenues	(4,485		)	(11,709		)	4,293
Materials, supplies and fossil fuel	(6,503		)	(1,454		)	(23,945		)
Income tax receivable	11,174			(14,567		)	—
Other current assets	(6,775		)	(21,640		)	4,498
Accounts payable	(26,561		)	(67,543		)	(34,891		)
Accrued taxes	26,773			(13,912		)	13,378
Other current liabilities	27,912			5,097			(3,718		)
Change in margin and collateral accounts — assets	(300		)	673			(324		)
Change in margin and collateral accounts — liabilities	(533		)	17,735			22,776
Change in long-term regulatory liabilities	45,764			14,682			(20,535		)
Change in unrecognized tax benefits	5,891			1,628			(10,328		)
Change in other long-term assets	(78,540		)	(45,866		)	(813		)
Change in other long-term liabilities	(31,106		)	(76,855		)	(82,628		)
Net cash flow provided by operating activities	1,161,730			1,009,948			1,100,030
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,381,930		)	(1,248,010		)	(1,072,053		)
Contributions in aid of construction	23,708			64,296			46,546
Allowance for borrowed funds used during construction	(22,112		)	(19,481		)	(16,183		)
Proceeds from nuclear decommissioning trust sales	542,246			633,410			478,813
Investment in nuclear decommissioning trust	(544,527		)	(635,691		)	(496,062		)
Other	(18,538		)	(13,865		)	(1,093		)
Net cash flow used for investing activities	(1,401,153		)	(1,219,341		)	(1,060,032		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	549,478			693,151			842,415
Repayment of long-term debt	—			(370,430		)	(415,570		)
Short-term borrowings and (repayments) — net	(135,500		)	135,500			(147,400		)
Dividends paid on common stock	(296,800		)	(281,300		)	(266,900		)
Equity infusion from Pinnacle West	150,000			42,000			—
Noncontrolling interests	(22,744		)	(22,744		)	(35,002		)
Net cash flow provided by (used for) financing activities	244,434			196,177			(22,457		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	5,011			(13,216		)	17,541
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	8,840			22,056			4,515
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	13,851		$	8,840		$	22,056
Supplemental disclosure of cash flow information:
Cash paid (received) during the year for:
Income taxes, net of refunds	$	(14,098	)	$	26,864		$	14,831
Interest, net of amounts capitalized	184,210			181,809			167,670
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	130,057		$	114,874		$	83,798
Dividends declared but not paid	77,700			72,900			69,400

The accompanying notes are an integral part of the financial statements.

99

ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(dollars in thousands)

	Common Stock			Additional Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Shares	Amount
Balance, December 31, 2014	71,264,947	$	178,162	$	2,379,696	$	1,968,718		$	(48,333	)	$	151,609		$	4,629,852
Net income		—		—		450,274			—			18,933			469,207
Other comprehensive income		—		—		—			21,236			—			21,236
Dividends on common stock		—		—		(270,500		)	—			—			(270,500		)
Other		—		—		1			—			—			1
Net capital activities by noncontrolling interests		—		—		—			—			(35,002		)	(35,002		)
Balance, December 31, 2015	71,264,947	178,162		2,379,696		2,148,493			(27,097		)	135,540			4,814,794
Equity infusion from Pinnacle West		—		42,000		—			—			—			42,000
Net income		—		—		462,141			—			19,493			481,634
Other comprehensive income		—		—		—			1,674			—			1,674
Dividends on common stock		—		—		(284,800		)	—			—			(284,800		)
Other		—		—		—			—			—			—
Stock compensation cumulative effect adjustments (See Note 15)		—		—		5,411			—			—			5,411
Net capital activities by noncontrolling interests		—		—		—			—			(22,743		)	(22,743		)
Balance, December 31, 2016	71,264,947	178,162		2,421,696		2,331,245			(25,423		)	132,290			5,037,970
Equity infusion from Pinnacle West		—		150,000		—			—			—			150,000
Net income		—		—		504,309			—			19,493			523,802
Other comprehensive loss		—		—		—			(1,560		)	—			(1,560		)
Dividends on common stock		—		—		(301,600		)	—			—			(301,600		)
Net capital activities by noncontrolling interests		—		—		—			—			(22,743		)	(22,743		)
Balance, December 31, 2017	71,264,947	$	178,162	$	2,571,696	$	2,533,954		$	(26,983	)	$	129,040		$	5,385,869

The accompanying notes are an integral part of the financial statements.

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1.    Summary of Significant Accounting Policies

Description of Business and Basis of Presentation

Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado, BCE and 4CA. 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.  El Dorado is an investment firm. BCE is a subsidiary that was formed in 2014 that focuses on growth opportunities that leverage the Company's core expertise in the electric energy industry. BCE is currently pursuing transmission opportunities through a joint venture arrangement. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners.

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries:  APS, El Dorado, BCE and 4CA. 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 18).

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 a more condensed form on the Consolidated Balance Sheets than in the prior year. The prior year amounts were reclassified to conform to the current year presentation. These reclassifications have no impact on accumulated other comprehensive loss. The following tables show the impacts of the reclassifications of the prior year (previously reported) amounts (dollars in thousands):

Pinnacle West Capital Corporation Consolidated Balance Sheets- December 31, 2016	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Accumulated other comprehensive loss:
Pension and other postretirement benefits	$	(39,070	)	$	39,070		$	—
Derivative instruments	(4,752		)	4,752			—
Total accumulated other comprehensive loss	(43,822		)	43,822			—
Accumulated other comprehensive loss	—			(43,822		)	(43,822		)

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Arizona Public Service Company Consolidated Balance Sheets - December 31, 2016	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Accumulated other comprehensive loss:
Pension and other postretirement benefits	$	(20,671	)	$	20,671		$	—
Derivative instruments	(4,752		)	4,752			—
Total accumulated other comprehensive loss	(25,423		)	25,423			—
Accumulated other comprehensive loss	—			(25,423		)	(25,423		)

Accounting Records and Use of Estimates

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

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 amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to 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

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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.

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.

Pinnacle West’s property, plant and equipment included in the December 31, 2017 and 2016 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:	2017			2016
Generation	$	7,963,998		$	7,874,898
Transmission	2,836,578			2,746,508
Distribution	6,025,856			5,738,801
General plant	971,629			981,681
Plant in service and held for future use	17,798,061			17,341,888
Accumulated depreciation and amortization	(6,128,535		)	(5,970,100		)
Net	11,669,526			11,371,788
Construction work in progress	1,291,498			1,019,947
Palo Verde sale leaseback, net of accumulated depreciation	109,645			113,515
Intangible assets, net of accumulated amortization	257,189			90,022
Nuclear fuel, net of accumulated amortization	117,408			119,004
Total property, plant and equipment	$	13,445,266		$	12,714,276

Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 11.

APS records a regulatory liability 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 and amortization 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, 2017 were as follows:

•Fossil plant — 21 years;

•Nuclear plant — 26 years;

•Other generation — 25 years;

•Transmission — 38 years;

•Distribution — 33 years; and

•General plant — 6 years.

Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $453 million in 2017, $422 million in 2016, and $430 million in 2015. For the years 2015 through 2017, the depreciation rates ranged from a low of 0.18% to a high of 16.44%.  The weighted-average depreciation rate was 2.80% in 2017, 2.66% in 2016, and 2.74% in 2015.

Asset Retirement Obligations

APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation 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.  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 and coal ash pond closures. 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 transmission and distribution assets. Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites.

See Note 11 for further information on Asset Retirement Obligations.

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 Statements of Income.  Plant

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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 6.68% for 2017, 7.17% for 2016, and 8.02% for 2015.  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, coal reclamation escrow accounts, 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 13 for additional information about fair value measurements.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Derivative Accounting

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal 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 16 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 Postretirement 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 its 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 7 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 charged APS $0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero.  In accordance with a settlement agreement with the DOE in August 2014, we will now accrue a receivable for incurred claims and an offsetting regulatory liability through the settlement period ending December of 2019. See Note 10 for information on spent nuclear fuel disposal costs.

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Income Taxes

Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes and are based on currently enacted tax rates.  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):

	Year ended December 31,
	2017		2016		2015
Cash paid during the period for:
Income taxes, net of refunds	$	2,186	$	9,956	$	6,550
Interest, net of amounts capitalized	189,288		184,462		170,209
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	130,404	$	114,855	$	83,798
Dividends declared but not paid	77,667		72,926		69,363

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 $72 million in 2017, $58 million in 2016, and $58 million in 2015.  Estimated amortization expense on existing intangible assets over the next five years is $53 million in 2018, $38 million in 2019, $28 million in 2020, $22 million in 2021, and $17 million in 2022.  At December 31, 2017, the weighted-average remaining amortization period for intangible assets was 6 years.

Investments

El Dorado holds investments in both debt and equity securities.  Investments in debt securities are generally accounted for as held-to-maturity and investments in equity securities are accounted for using either the equity method (if significant influence) or the cost method (if less than 20% ownership and no significant influence).

Our investments in the nuclear decommissioning trust fund, and coal reclamation escrow, are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities. See Note 13 and Note 19 for more information on these investments.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

See Note 2 for new accounting guidance relating to financial instruments including investments in equity securities, effective for us in 2018.  

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.

Preferred Stock

At December 31, 2017, 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.

2.    New Accounting Standards

ASU 2014-09, Revenue from Contracts with Customers

In May 2014, a new revenue recognition accounting standard was issued. This standard provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, became effective for us on January 1, 2018. The standard may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application.

We adopted this standard on January 1, 2018 using the modified retrospective transition approach. The adoption of this standard will not have significant impact on our financial statement results. Our revenues are derived primarily from sales of electricity to our regulated retail customers, and based on our assessment the adoption of this guidance does not generally impact the timing of our revenue recognition relating to these customers. The adoption of the new standard will result in expanded revenue related disclosures.

ASU 2016-01, Financial Instruments: Recognition and Measurement

In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new standard became effective for us on January 1, 2018. Certain aspects of the standard require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We adopted this standard on a prospective basis on January 1, 2018. The adoption of this standard will not have a significant impact on our financial statement results, as we did not have significant equity investments impacted by this standard.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ASU 2016-02, Leases

In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. In January 2018, additional lease guidance was issued specifically relating to land easements and how entities may elect to account for these arrangements at transition. The new standard, and related amendments, will be effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition.

We plan on adopting this standard, and related amendments, on January 1, 2019, and are evaluating the transition practical expedients we may elect. Our evaluation of this new accounting standard and the impacts it will have on our financial statements is on-going. We expect the adoption of the new guidance will impact our Consolidated Balance Sheets as we will be required to reflect lease assets and lease liabilities relating to certain operating lease arrangements. We are currently evaluating the significance of the expected balance sheet impacts, and the impacts, if any, the lease guidance will have on our other financial statements. Our evaluation includes assessing leasing activities, implementing new processes and procedures, and preparing the expanded lease disclosures.

ASU 2016-13, Financial Instruments: Measurement of Credit Losses

In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard will require entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments

In August 2016, a new accounting standard was issued that clarifies how entities should present certain specific cash flow activities on the statement of cash flows. The guidance is intended to eliminate diversity in practice in how entities classify these specific activities between cash flows from operating activities, investing activities and financing activities. The specific activities addressed include debt prepayments and extinguishment costs, proceeds from the settlement of insurance claims, proceeds from corporate owned life insurance policies, and other activities. The standard also addresses how entities should apply the predominance principle when a transaction includes separately identifiable cash flows. The new standard is effective for us, and will be adopted, during the first quarter of 2018 using a retrospective transition method. The adoption of this guidance will not have a significant impact on our financial statements, as either our statement of cash flow presentation is consistent with the new prescribed guidance or we do not have significant activities relating to the specific transactions that are addressed by the new standard.

ASU 2016-18, Statement of Cash Flows: Restricted Cash

In November 2016, a new accounting standard was issued that clarifies how restricted cash and restricted cash equivalents should be presented on the statement of cash flows. The new guidance requires entities to include restricted cash and restricted cash equivalents as a component of the beginning and ending cash and cash equivalent balances on the statement of cash flows. The new standard is effective for us, and will be adopted, during the first quarter of 2018 using a retrospective transition method. We do not expect the adoption of this guidance will impact our financial statements, as our holdings and activities designated as restricted cash and restricted cash equivalents are generally insignificant.

ASU 2017-01, Business Combinations: Clarifying the Definition of a Business

In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business.  The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The new standard became effective for us on January 1, 2018 using a prospective approach. We adopted this new standard on January 1, 2018, using a prospective approach with no impacts on our financial statements on the date of adoption.

ASU 2017-05, Other Income: Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets

In February 2017, a new accounting standard was issued that intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard became effective for us on January 1, 2018. The guidance may be applied using either a retrospective or modified retrospective transition approach. We adopted this standard on January 1, 2018 using a modified retrospective transition approach. The adoption of this guidance did not have a significant impact on our financial statement results.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs). The presentation changes will require net benefit costs to be disaggregated on the income statement by the various components that comprise these costs. Specifically, only the service cost component will be eligible for presentation as an operating income item, and all other cost components will be presented as non-operating items. This presentation change must be applied retrospectively. Furthermore, the new standard only allows the service cost component to be eligible for capitalization. The change in capitalization requirements must be applied prospectively. The new guidance became effective for us on January 1, 2018.

We adopted this new accounting standard on January 1, 2018. Beginning in the first quarter of 2018, we will present the non-service cost components of net benefit costs in other income instead of operating income. Prior year non-service cost components will also be reclassified from operating income to other income. Upon adoption, we will no longer capitalize a portion of the non-service cost components of net benefit costs. In 2018, because the non-service cost components are a reduction to total benefit costs, we estimate this change will result in the capitalization of an additional $15 million of net benefit costs, with a corresponding increase to pretax income. See note 7 for additional information related to our pension plans and other postretirement benefits.

ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities

In August 2017, a new accounting standard was issued that modifies hedge accounting guidance with the intent of simplifying the application of hedge accounting. The new standard is effective for us on January 1, 2019, with early application permitted. At transition, the guidance requires the changes to be applied to hedging relationships existing on the date of adoption, with the effect of adoption reflected as of the beginning of the fiscal year of adoption using a cumulative effect adjustment approach. The presentation and disclosure changes may be applied prospectively. We are evaluating the new guidance, but at this time we do not expect the adoption of this guidance will have a significant impact on our financial statement results as we are currently not applying hedge accounting.

ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

In February 2018, new accounting guidance was issued that allows entities an optional election to reclassify the income tax effects of the 2017 Tax Cuts and Jobs Act legislation on items within accumulated other comprehensive income to retained earnings. Amounts eligible for reclassification must relate to the effects from the Tax Cuts and Jobs Act remaining in accumulated other comprehensive income. The new guidance also requires expanded disclosures. This guidance is effective for us on January 1, 2019 with early application permitted. The guidance should be applied either in the period of adoption or retrospectively to each period in which the effect of the Tax Cuts and Jobs Act was recognized. We are currently evaluating this new guidance to determine whether we will elect this reclassification adjustment. The adoption of this guidance will not impact our income from continuing operations. See Note 4 for additional discussion of the Tax Cuts and Jobs Act.

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3.    Regulatory Matters

Retail Rate Case Filing with the Arizona Corporation Commission

On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates of $165.9 million. This amount excluded amounts that were then collected on customer bills through adjustor mechanisms. The application requested that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have had an incremental effect on average customer bills. The average annual customer bill impact of APS’s request was an increase of 5.74% (the average annual bill impact for a typical APS residential customer was 7.96%).

On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed a settlement agreement (the "2017 Settlement Agreement") and filed it with the ACC. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules. The average annual customer bill impact under the 2017 Settlement Agreement is an increase of 3.28% (the average annual bill impact for a typical APS residential customer is 4.54%).

Other key provisions of the agreement include the following:

• an agreement by APS not to file another general retail rate case application before June 1, 2019;

• an authorized return on common equity of 10.0%;

• a capital structure comprised of 44.2% debt and 55.8% common equity;

• a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project;

• a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing selective catalytic reduction ("SCR") equipment at Four Corners;

• a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate;

• an expansion of the PSA to include certain environmental chemical costs and third-party battery storage costs;

• a new AZ Sun II program (now known as APS Solar Communities) for utility-owned solar distributed generation ("DG") with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the RES, to be no less than $10 million per year, and not more than $15 million per year;

• an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account;

• rate design changes, including:

▪ a change in the on-peak time of use period from noon - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays;

▪ non-grandfathered DG customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component;

▪ a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and

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• an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027 for combined-cycle generating units), unless expressly authorized by the ACC.

Through a separate agreement, APS, industry representatives, and solar advocates committed to stand by the 2017 Settlement Agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC.

On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications.  On August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the "2017 Rate Case Decision"), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017. On August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the ACC's order approving the 2017 Settlement Agreement so that alleged issues of disqualification and bias on the part of the other Commissioners can be fully investigated.   APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition.

On October 17, 2017, Warren Woodward (an intervener in APS's general retail rate case) filed a Notice of Appeal in the Arizona Court of Appeals, Division One. The notice raises a single issue related to the application of certain rate schedules to new APS residential customers after May 1, 2018. Mr. Woodward filed a second notice of appeal on November 13, 2017 challenging APS’s $5 per month automated metering infrastructure opt-out program. Mr. Woodward’s two appeals have been consolidated and APS has filed a motion to intervene. APS cannot predict the outcome of this consolidated appeal but does not believe it will have a material impact.

On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”) and not a request for rehearing. Arizona Revised Statute §40-246 requires the ACC to hold a hearing regarding any complaint alleging that a public service corporation is in violation of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least twenty-five customers of the public service corporation. The Complaint alleged that APS is “in violation of commission order” [sic]. On February 13, 2018, the complainant filed an amended Complaint alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable.  The complainant is requesting that the ACC hold a hearing on her amended Complaint to determine if the average bill impact on residential customers of the rates and charges approved in the 2017 Rate Case Decision is greater than 4.54% (the average annual bill impact for a typical APS residential customer estimated by APS), and if so, what effect the alleged greater bill impact has on APS's revenues and the overall reasonableness and justness of APS's rates and charges, in order to determine if there is sufficient evidence to warrant a full-scale rate hearing.  APS cannot predict the outcome of this matter.

Prior 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.  On January 6, 2012, APS and other parties to the general retail rate case entered into the 2012 Settlement Agreement (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.

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Cost Recovery Mechanisms

APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case 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 5-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.

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 to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014.  The revised rules went into effect on April 21, 2015.    

In December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid.  The first stage of the program, called the "Solar Partner Program," placed 8 MW of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016.  The costs for this program have been included in APS's rate base as part of the 2017 Rate Case Decision.

On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million. APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules. On April 7, 2017, APS filed an amended 2017 RES Implementation Plan and updated budget request which included the revenue neutral transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement.  On August 15, 2017, the ACC approved the 2017 RES Implementation Plan.

On June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million.  APS’s budget request supports existing approved projects and commitments and includes the anticipated transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. APS's 2018 RES budget request is lower than the 2017 RES budget due in part to a certain portion of the RES being collected by APS in base rates rather than through the RES adjustor.

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On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a 3-year program requiring APS to spend $10-$15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, buildings of non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES. The ACC has not yet ruled on APS's 2018 RES Implementation Plan.

In September 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES.  The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically.  The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent regulations of EPA.  The proceeding will also examine the feasibility of increasing the standard to 30% of retail sales by 2030, in contrast to the current standard of 15% of retail sales by 2025. On January 30, 2018, ACC Commissioner Tobin proposed a new standard in this proceeding which would broaden the RES to include a series of energy reform policies tied to clean energy sources. The proposal would rename the RES to the Clean Resource Energy Standard and Tariff ("CREST").  APS cannot predict the outcome of this proceeding.

Demand Side Management Adjustor Charge. The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan ("DSM Plan") annually for review by and approval of the ACC. On March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also ruled that verified energy savings from APS's resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standards; however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from conservation voltage reduction in the calculation of its LFCR mechanism.

On June 1, 2016, APS filed its 2017 DSM Plan, in which APS proposed programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand.  The requested budget in the 2017 DSM Plan is $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and requested that the budget be increased to $66.6 million. On August 15, 2017, the ACC approved the amended 2017 DSM Plan.

On September 1, 2017, APS filed its 2018 DSM Plan, which proposes modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Plan seeks a reduced requested budget of $52.6 million and requests a waiver of the Electric Energy Efficiency Standard for 2018.   On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels, but kept the overall budget at $52.6 million.

Electric Energy Efficiency. On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards should be modified.  The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy

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efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. On July 12, 2016, the ACC Commissioners ordered that ACC staff convene a workshop within 120 days to discuss a number of issues related to the Electric Energy Efficiency Standards, including the process of determining the cost effectiveness of DSM programs and the treatment of peak demand and capacity reductions, among others. ACC staff convened the workshop on November 29, 2016 and sought public comment on potential revisions to the Electric Energy Efficiency Standards. APS cannot predict the outcome of this proceeding.

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

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

• An adjustment to the PSA rate is made annually each February 1 (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 or refunded through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and

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

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2017 and 2016 (dollars in thousands):

	Twelve Months Ended December 31,
	2017		2016
Beginning balance	$	12,465	$	(9,688	)
Deferred fuel and purchased power costs — current period	48,405		60,303
Amounts refunded/(charged) to customers	14,767		(38,150		)
Ending balance	$	75,637	$	12,465

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The PSA rate for the PSA year beginning February 1, 2017 was $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year.  This rate was comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh. On August 19, 2017, the PSA rate was revised to $0.000555 per kWh as part of the 2017 Rate Case Decision. This new rate was comprised of a forward component of $0.000876 per kWh and a historical component of $(0.000321) per kWh. On November 30, 2017, APS submitted its calculation for the 2018 PSA year beginning February 1, 2018. The current PSA rate is $.004555 per kWh consisting of a forward component of $.002009 per kWh and a historical component of $.002546 per kWh.

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.  In July 2008, the 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, 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 Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.

Effective June 1, 2016, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $24.9 million for the twelve-month period beginning June 1, 2016 in accordance with the FERC-approved formula.  An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2016.    

Effective June 1, 2017, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $35.1 million for the twelve-month period beginning June 1, 2017 in accordance with the FERC-approved formula.  An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2017.

On January 31, 2017, APS made a filing to reduce the Post-Employment Benefits Other than Pension expense reflected in its FERC transmission formula rate calculation to recognize certain savings resulting from plan design changes to the other postretirement benefit plans.  A transmission customer intervened and protested certain aspects of APS’s filing.  FERC initiated a proceeding under Section 206 of the Federal Power Act to evaluate the justness and reasonableness of the revised formula rate filing APS proposed.  APS entered into a settlement agreement with the intervening transmission customer, which was filed with FERC for approval on September 26, 2017. FERC approved the settlement agreement without modification or condition on December 21, 2017.

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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 DG such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were first 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.  These amounts were revised in the 2017 Settlement Agreement to 2.5 cents for both lost residential and non-residential kWh. The LFCR adjustment has a year-over-year cap of 1% of retail revenues.  Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year.  The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs.  DG sales losses are determined from the metered output from the DG units.

APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase). The ACC approved the 2016 annual LFCR effective beginning in May 2016. APS filed its 2017 LFCR adjustment on January 13, 2017 requesting an LFCR adjustment of $63.7 million (a $17.3 million per year increase over 2016 levels). On April 5, 2017, the ACC approved the 2017 annual LFCR adjustment as filed, effective with the first billing cycle of April 2017. On February 15, 2018, APS filed its LFCR Adjustment, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 million (a $3 million per year decrease over 2017 levels). Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, a one or two month delay in implementation does not have an adverse effect on APS.

Tax Expense Adjustor Mechanism and FERC Tax Filing.  As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. On December 22, 2017 the Tax Cuts and Jobs Act (“Tax Act”) was enacted.  This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018.

On January 8, 2018, APS filed an application with the ACC requesting that the TEAM be implemented in two steps.  The first addresses the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and, if approved, would reduce rates by $119.1 million annually through an equal cents per kWh credit.  APS asked that this decrease become effective February 1, 2018. On February 22, 2018, the ACC approved the reduction of rates by $119.1 million annually through an equal cents per kWh credit applied to all but a small subset of customers who are taking service under specially-approved tariffs. The rate reduction will be effective March 1, 2018.

The second step will address the amortization of excess deferred taxes previously collected from customers. APS is analyzing the final impact of the Tax Act provisions related to deferred taxes and intends to make a second TEAM filing later in 2018.

The TEAM expressly applies to APS's retail rates with the exception noted above. The Company expects to make a filing with FERC in the first quarter of 2018 seeking authorization to provide for the cost reductions resulting from the income tax changes in its wholesale transmission rates.

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Net Metering

In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of DG to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases.  A hearing was held in April 2016. On October 7, 2016, the Administrative Law Judge issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended opinion and order by the Administrative Law Judge. After making several amendments, the ACC approved the recommended opinion and order by a 4-1 vote. As a result of the ACC’s action, effective as of APS’s 2017 Rate Case Decision, the current net metering tariff that governs payments for energy exported to the grid from rooftop solar systems was replaced by a more formula-driven approach that utilizes inputs from historical wholesale solar power costs and eventually an avoided cost methodology.

As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a RCP methodology, a method that is based on the price that APS pays for utility-scale solar projects on a five year rolling average, while a forecasted avoided cost methodology is being developed.  The price established by this RCP method will be updated annually (between general retail rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent general retail rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy.

In addition, the ACC made the following determinations:

• Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to August 19, 2017, the date new rates were effective based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility;

• Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and

• Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years.

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh is included in the 2017 Settlement Agreement and became effective on August 19, 2017.

On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC filed a Notice of Appeal in the Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.

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System Benefits Charge

The 2012 Settlement Agreement provided that once APS achieved full funding of its decommissioning obligation under the sale leaseback agreements covering Unit 2 of Palo Verde, APS was required to implement a reduced System Benefits charge effective January 1, 2016.  Beginning on January 1, 2016, APS began implementing a reduced System Benefits charge.  The impact on APS retail revenues from the new System Benefits charge is an overall reduction of approximately $14.6 million per year with a corresponding reduction in depreciation and amortization expense. This adjustment is subsumed within the 2017 Settlement Agreement and its associated revenue requirement.

Subpoena from Arizona Corporation Commissioner Robert Burns

On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer.

On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay APS's obligations to comply with the subpoenas and decline to decide APS's motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed.

On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC staff.  As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns' suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel. On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the complaint. On February 15, 2018, the Superior Court dismissed Commissioner Burns’ complaint. The matter is subject to appeal. APS and Pinnacle West cannot predict the outcome of this matter.

In addition to the Superior Court proceedings discussed above, on August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the 2017 Rate Case Decision so that alleged issues of disqualification and bias on the part of the other Commissioners could be fully investigated. APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition.

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Renewable Energy Ballot Initiative

On February 20, 2018, a coalition of renewable energy advocates filed with the Arizona Secretary of State a ballot initiative for an Arizona constitutional amendment requiring Arizona public service corporations to procure 50% of their energy supply from renewable sources by 2030. For purposes of the proposed amendment, eligible renewable sources would not include nuclear generating facilities. The stated goal of the Clean Energy for a Healthy Arizona coalition is to complete the necessary steps to allow the initiative to be placed on the November 2018 Arizona elections ballot. The coalition must present over 225,000 verifiable signatures to the Secretary of State by July 5, 2018 to meet that goal. APS intends to oppose this effort. We believe the initiative is irresponsible and would result in negative impacts to Arizona utility customers, the Arizona economy and our company. We cannot predict the outcome of this matter.

Clean Resource Energy Standard and Tariff

On January 30, 2018, ACC Commissioner Tobin proposed the CREST, which consists of a series of energy reform policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the Integrated Resource Plan process. The ACC has not yet initiated any formal proceedings with respect to Commissioner Tobin’s proposal; however, on February 22, 2018, the ACC Staff filed a Notice of Inquiry to further examine the matter. APS cannot predict the outcome of this matter.

Four Corners

SCE-Related Matters. On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners.  The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general retail rate case related to APS’s acquisition of the 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. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis.  This included the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates.  The 2012 Settlement Agreement also provided for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $56 million as of December 31, 2017 and is being amortized in rates over a total of 10 years. The ACC's rate adjustment decision was appealed and on September 26, 2017, the Court of Appeals affirmed the ACC's decision on the Four Corners rate adjustment.

As part of APS’s acquisition of SCE’s interest in Units 4 and 5, 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. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates.  APS and SCE completed the termination of the Transmission Agreement on July 6,

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2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter of 2016.  On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery, FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. On October 5, 2017, FERC issued an order denying APS's request for rehearing. FERC also upheld its prior determination that the agreement relating to the settlement was a jurisdictional contract and should have been filed with FERC. APS cannot predict whether or if the enforcement division will take any action. APS filed an appeal of FERC's July 1, 2016 and October 5, 2017 orders with the United States Court of Appeals for the Ninth Circuit on December 4, 2017. That proceeding is pending and APS cannot predict the outcome of the proceeding.

SCR Cost Recovery. On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Rate Rider to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5.  APS intends to file the SCR Rate Rider in April 2018. Consistent with the 2017 Rate Case Decision, the rate rider filing will be narrow in scope and will address only costs associated with this specific environmental compliance equipment. Also, as provided for in the 2017 Rate Case Decision, APS will request that the rate rider become effective no later than January 1, 2019. 

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of Cholla and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect on April 26, 2017.

Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS has been recovering a return on and of the net book value of the unit in base rates. Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs ($105 million as of December 31, 2017), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2026.

Navajo Plant

The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant will remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that will allow for decommissioning activities to begin after the plant ceases operations in December 2019. Various stakeholders including regulators, tribal representatives, the plant's coal supplier and the U.S. Department of the Interior have been meeting to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. Although we cannot predict whether any alternate plans will be found that would be acceptable to all of the stakeholders and feasible to implement, we believe it is probable that the Navajo Plant will cease operations in December 2019.

On February 14, 2017, the ACC opened a docket titled "ACC Investigation Concerning the Future of the Navajo Generating Station" with the stated goal of engaging stakeholders and negotiating a sustainable

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pathway for the Navajo Plant to continue operating in some form after December 2019. APS cannot predict the outcome of this proceeding.

APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($99 million as of December 31, 2017) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and APS's net income, cash flows, and financial position will be negatively impacted.

Regulatory Assets and Liabilities

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

S		December 31, 2017				December 31, 2016
	Amortization Through	Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	576,188	$	—	$	711,059
Retired power plant costs	2033	27,402		188,843		9,913		117,591
Income taxes - AFUDC equity	2047	3,828		142,852		6,305		152,118
Deferred fuel and purchased power — mark-to-market (Note 16)	2020	52,100		34,845		—		42,963
Four Corners cost deferral	2024	8,077		48,305		6,689		56,894
Income taxes — investment tax credit basis adjustment	2046	1,066		26,218		2,120		54,356
Lost fixed cost recovery (b)	2018	59,844		—		61,307		—
Palo Verde VIEs (Note 18)	2046	—		19,395		—		18,775
Deferred compensation	2036	—		36,413		—		35,595
Deferred property taxes	2027	8,569		74,926		—		73,200
Loss on reacquired debt	2038	1,637		15,305		1,637		16,942
AG-1 deferral	2022	2,654		8,472		—		5,868
Demand side management (b)	2017	—		—		3,744		—
Tax expense of Medicare subsidy	2024	1,236		7,415		1,513		10,589
Mead-Phoenix transmission line CIAC	2050	332		10,376		332		10,708
Deferred fuel and purchased power (b) (c)	2018	75,637		—		12,465		—
Coal reclamation	2026	1,068		12,396		418		5,182
Other	Various	4,638		353		432		1,588
Total regulatory assets (d)		$	248,088	$	1,202,302	$	106,875	$	1,313,428

(a) This asset represents the future recovery of pension 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 7 for further discussion.

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

(c) Subject to a carrying charge.

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(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, Transmission Cost Adjustor and Other Transmission Matters.”

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

		December 31, 2017				December 31, 2016
	Amortization Through	Current		Non-Current		Current		Non-Current
Excess deferred income taxes - Tax Cuts and Jobs Act	(a)	$	—	$	1,520,274	$	—	$	—
Asset retirement obligations	2057	—		332,171		—		279,976
Removal costs	(b)	18,238		209,191		29,899		223,145
Other post retirement benefits	(d)	37,642		151,985		32,662		123,913
Income taxes - deferred investment tax credit	2046	2,164		52,497		4,368		108,827
Income taxes - change in rates	2046	2,573		70,537		1,771		70,898
Spent nuclear fuel	2027	6,924		62,132		—		71,726
Renewable energy standard (c)	2018	23,155		—		26,809		—
Demand side management (c)	2019	3,066		4,921		—		20,472
Sundance maintenance	2030	—		16,897		—		15,287
Deferred gains on utility property	2022	4,423		10,988		2,063		8,895
Four Corners coal reclamation	2038	1,858		18,921		—		18,248
Other	Various	43		2,022		2,327		7,529
Total regulatory liabilities		$	100,086	$	2,452,536	$	99,899	$	948,916

(a) See Note 4. While the majority of the excess deferred tax balance shown is subject to special amortization rules under federal income tax laws, which require amortization of the balance over the remaining regulatory life of the related property, treatment of a portion of the liability, and the month in which pass-through of the excess deferred tax balance will begin is subject to regulatory approval. This approval will be sought through the Company's TEAM adjustor mechanism and FERC filings in 2018. As a result, the Company cannot estimate the amount of this regulatory liability which is expected to reverse within the next 12 months.

(b) 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 11).

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

(d) See Note 7.

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, investment tax credit (“ITC”) basis adjustment and tax expense of Medicare subsidy.  The regulatory liabilities primarily relate to the change in income tax rates and deferred taxes resulting from ITCs.

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On December 22, 2017, the Tax Cuts and Jobs Act ("Tax Act") was enacted. This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate to 21% effective January 1, 2018. In accordance with generally accepted accounting principles, the effects of this corporate tax rate reduction were recognized for the year ending December 31, 2017. As a result of this rate reduction, the Company has recognized a $1.14 billion reduction in its net deferred income tax liabilities as of December 31, 2017.

In accordance with accounting for regulated companies, the effect of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2017, to reflect the $1.14 billion reduction in its net deferred income tax liabilities caused by the rate reduction, APS has recorded a regulatory liability of $1.52 billion and a new $377 million deferred tax asset. The company intends to amortize the regulatory liability in accordance with applicable federal income tax laws, which require the amortization of a majority of the balance over the remaining regulatory life of the related property, and in a manner to be approved by its federal and state regulatory agencies. See Note 3 for more details.

Additionally, as a result of the corporate tax rate reduction, the Company recorded income tax expense of $9.3 million, for the year ended December 31, 2017, to recognize the effect of certain reductions in deferred tax assets, for which the Company did not believe recovery was probable through its revenue requirement.

Several sections of the Tax Cuts and Jobs Act contain technical ambiguities. These ambiguities include certain transition rules regarding the applicability of bonus depreciation to property acquired, or under construction, prior to September 28, 2017 and the continued deductibility of certain executive compensation arrangements in place prior to November 3, 2017. Management has recognized tax positions which it believes are more likely than not to be sustained upon examination based upon its interpretation of this legislation. Clarifying guidance may be issued through additional legislation, Treasury regulations, or other technical guidance, within the next 12 months which may impact the income tax effects of the Tax Act as recorded by the Company. As of December 31, 2017, the Company does not have a reasonable estimate of what the income tax effects of such clarifying guidance may be, if any.

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.

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 18).  As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS 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):

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	Pinnacle West Consolidated									APS Consolidated
	2017			2016			2015			2017			2016			2015
Total unrecognized tax benefits, January 1	$	36,075		$	34,447		$	44,775		$	36,075		$	34,447		$	44,775
Additions for tax positions of the current year	2,937			2,695			2,175			2,937			2,695			2,175
Additions for tax positions of prior years	4,783			886			—			4,783			886			—
Reductions for tax positions of prior years for:
Changes in judgment	(1,829		)	(1,953		)	(10,244		)	(1,829		)	(1,953		)	(10,244		)
Settlements with taxing authorities	—			—			—			—			—			—
Lapses of applicable statute of limitations	—			—			(2,259		)	—			—			(2,259		)
Total unrecognized tax benefits, December 31	$	41,966		$	36,075		$	34,447		$	41,966		$	36,075		$	34,447

Included in the balances of unrecognized tax benefits are the following tax positions that, if recognized, would decrease our effective tax rate (dollars in thousands):

	Pinnacle West Consolidated						APS Consolidated
	2017		2016		2015		2017		2016		2015
Tax positions, that if recognized, would decrease our effective tax rate	$	16,373	$	11,313	$	9,523	$	16,373	$	11,313	$	9,523

As of the balance sheet date, the tax year ended December 31, 2014 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 2013.

We reflect interest and penalties, if any, on unrecognized tax benefits in the Pinnacle West Consolidated and APS Consolidated Statements of Income as income tax expense.  The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands): 

	Pinnacle West Consolidated							APS Consolidated
	2017		2016		2015			2017		2016		2015
Unrecognized tax benefit interest expense/(benefit) recognized	$	577	$	529	$	(161	)	$	577	$	529	$	(161	)

Following are the total amount of accrued liabilities for interest recognized related to unrecognized benefits that could reverse and decrease our effective tax rate to the extent matters are settled favorably (dollars in thousands):

	Pinnacle West Consolidated						APS Consolidated
	2017		2016		2015		2017		2016		2015
Unrecognized tax benefit interest accrued	$	1,910	$	1,333	$	804	$	1,910	$	1,333	$	804

Additionally, as of December 31, 2017, we have recognized less than $1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

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

	Pinnacle West Consolidated							APS Consolidated
	Year Ended December 31,							Year Ended December 31,
	2017		2016		2015			2017		2016		2015
Current:
Federal	$	11,624	$	8,630	$	(12,335	)	$	21,512	$	711	$	6,485
State	3,052		1,259		4,763			2,778		4,276		7,813
Total current	14,676		9,889		(7,572		)	24,290		4,987		14,298
Deferred:
Federal	223,729		201,743		221,505			221,078		215,178		208,326
State	19,867		24,779		23,787			23,800		25,677		23,217
Total deferred	243,596		226,522		245,292			244,878		240,855		231,543
Income tax expense	$	258,272	$	236,411	$	237,720		$	269,168	$	245,842	$	245,841

On the APS Consolidated Statements of Income, federal and state income taxes are allocated between operating income and other income.

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

	Pinnacle West Consolidated									APS Consolidated
	Year Ended December 31,									Year Ended December 31,
	2017			2016			2015			2017			2016			2015
Federal income tax expense at 35% statutory rate	$	268,177		$	244,278		$	242,869		$	277,540		$	254,617		$	250,267
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	14,897			16,311			18,265			17,276			18,750			20,433
Credits and favorable adjustments related to prior years resolved in current year	—			—			(2,169		)	—			—			(1,892		)
Medicare Subsidy Part-D	853			844			837			853			844			837
Stock compensation	(6,659		)	(2,951		)	—			(3,489		)	(1,937		)	—
Excess Deferred Income Taxes - Tax Cuts and Jobs Act	9,348			—			—			9,431			—			—
Allowance for equity funds used during construction (see Note 1)	(12,937		)	(11,724		)	(9,711		)	(12,937		)	(11,724		)	(9,711		)
Palo Verde VIE noncontrolling interest (see Note 18)	(6,823		)	(6,823		)	(6,626		)	(6,823		)	(6,823		)	(6,626		)
Investment tax credit amortization	(6,715		)	(5,887		)	(5,527		)	(6,715		)	(5,887		)	(5,527		)
Other	(1,869		)	2,363			(218		)	(5,968		)	(1,998		)	(1,940		)
Income tax expense	$	258,272		$	236,411		$	237,720		$	269,168		$	245,842		$	245,841

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

	Pinnacle West Consolidated						APS Consolidated
	December 31,						December 31,
	2017			2016			2017			2016
DEFERRED TAX ASSETS
Risk management activities	$	25,103		$	26,614		$	25,103		$	26,614
Regulatory liabilities:
Excess Deferred Income Taxes - Tax Cuts and Jobs Act	376,906			—			376,906			—
Asset retirement obligation and removal costs	135,847			200,140			135,847			200,140
Unamortized investment tax credits	54,661			113,195			54,661			113,195
Other postretirement benefits	47,021			60,375			47,021			60,375
Other	37,489			63,311			37,489			63,311
Pension liabilities	83,126			204,436			77,280			194,981
Renewable energy incentives	33,546			56,379			33,546			56,379
Credit and loss carryforwards	53,946			75,944			1,920			1,645
Other	102,432			158,421			108,223			187,453
Total deferred tax assets	950,077			958,815			897,996			904,093
DEFERRED TAX LIABILITIES
Plant-related	(2,220,886		)	(3,297,989		)	(2,220,886		)	(3,297,989		)
Risk management activities	(491		)	(7,594		)	(491		)	(7,594		)
Other postretirement assets	(66,134		)	(63,477		)	(65,733		)	(62,819		)
Regulatory assets:
Allowance for equity funds used during construction	(36,365		)	(61,088		)	(36,365		)	(61,088		)
Deferred fuel and purchased power — mark-to-market	(40,778		)	(21,396		)	(40,778		)	(21,396		)
Pension benefits	(142,848		)	(274,184		)	(142,848		)	(274,184		)
Retired power plant costs (see Note 3)	(53,611		)	(49,166		)	(53,611		)	(49,166		)
Other	(74,423		)	(123,987		)	(74,423		)	(123,987		)
Other	(5,346		)	(5,166		)	(5,346		)	(5,165		)
Total deferred tax liabilities	(2,640,882		)	(3,904,047		)	(2,640,481		)	(3,903,388		)
Deferred income taxes — net	$	(1,690,805	)	$	(2,945,232	)	$	(1,742,485	)	$	(2,999,295	)

As of December 31, 2017, the deferred tax assets for credit and loss carryforwards relate primarily to federal general business credits of approximately $79 million, which first begin to expire in 2034, and other federal and state credit carryforwards of $6 million, which first begin to expire in 2031. The credit and loss carryforwards amount above has been reduced by $31 million of unrecognized tax benefits.

5.Lines of Credit and Short-Term Borrowings

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2017 and 2016 (dollars in thousands):

	December 31, 2017								December 31, 2016
	Pinnacle West			APS		Total			Pinnacle West			APS			Total
Commitments under Credit Facilities	$	325,000		$	1,000,000	$	1,325,000		$	275,000		$	1,000,000		$	1,275,000
Outstanding Commercial Paper and Revolving Credit Facility Borrowings	(95,400		)	—		(95,400		)	(41,700		)	(135,500		)	(177,200		)
Amount of Credit Facilities Available	$	229,600		$	1,000,000	$	1,229,600		$	233,300		$	864,500		$	1,097,800
Weighted-Average Commitment Fees	0.125%			0.100%					0.125%			0.100%

Pinnacle West

At December 31, 2017, Pinnacle West had a $200 million facility that matures in May 2021. 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, 2017, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $29.4 million of commercial paper borrowings.

On July 31, 2017, Pinnacle West amended its 364-day unsecured revolving credit facility to increase its capacity from $75 million to $125 million, and to extend the termination date of the facility from August 30, 2017 to July 30, 2018.  Borrowings under the facility bear interest at LIBOR plus 0.80% per annum. At December 31, 2017, Pinnacle West had $66 million outstanding under the facility.

APS

On June 29, 2017, APS replaced its $500 million revolving credit facility that would have matured in September 2020, with a new $500 million facility that matures in June 2022.

At December 31, 2017, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in May 2021 and the above-mentioned $500 million facility. APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2017, APS had no commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities. See "Financial Assurances" in Note 10 for a discussion of APS's other outstanding letters of credit.

Debt Provisions

On February 6, 2013, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to a sum of 7% of APS’s capitalization, and $500 million (which is required to be used for costs relating to purchases of natural gas and power). This financing order was set to expire on December 31, 2017; however, on December 15, 2016, APS filed a financing application with the ACC requesting continuation of its authorization of (i) Continuing Long-Term Debt of $5.1 billion and (ii) Continuing Short-Term Debt. The financing application is currently pending with

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the ACC. The authorizations approved in the 2013 order continue until further order of the ACC with respect to the pending application. See Note 6 for additional long-term debt provisions.

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, 2017 and 2016 (dollars in thousands):

	Maturity	Interest	December 31,
	Dates (a)	Rates	2017			2016
APS
Pollution control bonds:
Variable	2029	(b)	$	35,975		$	35,975
Fixed	2024-2029	1.75%-4.70%	147,150			147,150
Total pollution control bonds			183,125			183,125
Senior unsecured notes	2019-2046	2.20%-8.75%	4,275,000			3,725,000
Term loans	2018-2019	(c)	150,000			150,000
Unamortized discount			(11,288		)	(11,816		)
Unamortized premium			8,049			4,506
Unamortized debt issuance cost			(31,594		)	(29,030		)
Total APS long-term debt			4,573,292			4,021,785
Less current maturities			82,000			—
Total APS long-term debt less current maturities			4,491,292			4,021,785
Pinnacle West
Term loan	2017	(d)	—			125,000
Senior unsecured notes	2020	2.25%	300,000			—
Unamortized discount			(184		)	—
Unamortized debt issuance cost			(1,395		)	—
Total PNW long-term debt			298,421			125,000
Less current maturities			—			125,000
Total PNW long-term debt less current maturities			298,421			—
TOTAL LONG-TERM DEBTLESS CURRENT MATURITIES			$	4,789,713		$	4,021,785

(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 1.77% at December 31, 2017 and 0.81% at December 31, 2016.

(c) The weighted-average interest rate was 2.236% at December 31, 2017, and 1.427% at December 31, 2016.

(d) The interest rate was 1.520% at December 31, 2016.

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

Year	Consolidated Pinnacle West		Consolidated APS
2018	$	82,000	$	82,000
2019	600,000		600,000
2020	550,000		250,000
2021	—		—
2022	—		—
Thereafter	3,676,125		3,676,125
Total	$	4,908,125	$	4,608,125

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 thousands):

	As of December 31, 2017				As of December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	298,421	$	298,608	$	125,000	$	125,000
APS	4,573,292		5,006,348		4,021,785		4,300,789
Total	$	4,871,713	$	5,304,956	$	4,146,785	$	4,425,789

Credit Facilities and Debt Issuances

Pinnacle West

On November 30, 2017, Pinnacle West issued $300 million of 2.25% unsecured senior notes that mature on November 30, 2020.  The net proceeds from the sale were used to repay our $125 million term loan and for general corporate purposes.

APS

On March 21, 2017, APS issued an additional $250 million par amount of its outstanding 4.35% senior unsecured notes that mature on November 15, 2045.  The net proceeds from the sale were used to refinance commercial paper borrowings and to replenish cash temporarily used to fund capital expenditures.

On September 11, 2017, APS issued $300 million of 2.95% senior unsecured notes that mature on September 15, 2027. The net proceeds from the sale were used to refinance commercial paper and other indebtedness and to replenish cash used to fund capital expenditures.

On November 30, 2017, PNW contributed $150 million into APS in the form of an equity infusion.  APS used this contribution to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes.

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See “Lines of Credit and Short-Term Borrowings” in Note 5 and “Financial Assurances” in Note 10 for discussion of APS’s separate outstanding 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, 2017, the ratio was approximately 50% for Pinnacle West and 47% 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. Its total shareholder equity was approximately $5.3 billion, and total capitalization was approximately $10.0 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $4.0 billion, assuming APS’s total capitalization remains the same. APS was in compliance with this common equity ratio requirement as of December 31, 2017.

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 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 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 was set to expire on December 31, 2017; however, on December 15, 2016, APS filed a financing application with the ACC requesting continuation of its authorization of (i) Continuing Long-Term Debt of $5.1 billion and (ii) Continuing Short-Term Debt.  The financing application is currently pending with the ACC. The authorizations approved in the 2013 order continue until further order of the ACC with respect to the pending application.  See Note 5 for additional short-term debt provisions.

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7.    Retirement Plans and Other Postretirement 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.  We calculate the benefits based on age, years of service and pay.

Pinnacle West also sponsors other postretirement benefit plans (Pinnacle West Capital Corporation Group Life and Medical Plan and Pinnacle West Capital Corporation Post-65 Retiree Health Reimbursement Arrangement) for the employees of Pinnacle West and its subsidiaries.  These plans provide 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.

On September 30, 2014, Pinnacle West announced plan design changes to the postretirement benefit plan, which required an interim remeasurement of the benefit obligation for the plan. Effective January 1, 2015, those eligible retirees and dependents over age 65 and on Medicare can choose to be enrolled in a Health Reimbursement Arrangement ("HRA"). The Company is providing a subsidy allowing post-65 retirees to purchase a Medicare supplement plan on a private exchange network. The remeasurement of the benefit obligation included updating the assumptions. The 2014 remeasurement also resulted in a decrease in Pinnacle West’s other postretirement benefit obligation of $316 million, which was offset by the related regulatory asset and accumulated other comprehensive income.

Because of plan changes in September 2014, the Company is currently in the process of seeking IRS approval to move approximately $186 million of other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. In December 2016, FERC approved a methodology for determining the amount of other postretirement benefit trust assets to transfer into a new trust account to pay for active union employee medical costs. On January 2, 2018, these funds were moved to the new trust account.  The Company negotiated a draft Closing Agreement granting tentative approval from the IRS prior to the transfer. Subsequent to the transfer, the Company submitted proof of the transfer to the IRS and expects to execute a final Closing Agreement early in 2018. Per the terms of an order from FERC, the Company must also make an informational filing with FERC. The Company made this FERC filing during February 2018. It is the Company’s understanding that completion of these regulatory requirements will then permit access to the approximately $186 million for the sole purpose of paying active union employee medical 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 13 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 or regulatory liability.  In its 2009 retail rate case settlement, APS received approval to defer a

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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 three years beginning in July 2012.  We amortized approximately $5 million in 2015, $8 million in 2014, $8 million in 2013 and $4 million in 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 or liability) (dollars in thousands):

	Pension									Other Benefits
	2017			2016			2015			2017			2016			2015
Service cost-benefits earned during the period	$	54,858		$	53,792		$	59,627		$	17,119		$	14,993		$	16,827
Interest cost on benefit obligation	129,756			131,647			123,983			29,959			29,721			28,102
Expected return on plan assets	(174,271		)	(173,906		)	(179,231		)	(53,401		)	(36,495		)	(36,855		)
Amortization of:
Prior service cost (credit)	81			527			594			(37,842		)	(37,883		)	(37,968		)
Net actuarial loss	47,900			40,717			31,056			5,118			4,589			4,881
Net periodic benefit cost	$	58,324		$	52,777		$	36,029		$	(39,047	)	$	(25,075	)	$	(25,013	)
Portion of cost charged to expense	$	27,295		$	26,172		$	20,036		$	(18,274	)	$	(12,435	)	$	(10,391	)

See Note 2 for additional information regarding accounting changes relating to ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.

The following table shows the plans’ changes in the benefit obligations and funded status for the years 2017 and 2016 (dollars in thousands):

	Pension						Other Benefits
	2017			2016			2017			2016
Change in Benefit Obligation
Benefit obligation at January 1	$	3,204,462		$	3,033,803		$	716,445		$	647,020
Service cost	54,858			53,792			17,119			14,993
Interest cost	129,756			131,647			29,959			29,721
Benefit payments	(166,342		)	(142,247		)	(30,144		)	(26,231		)
Actuarial loss	171,452			127,467			20,014			50,942
Benefit obligation at December 31	3,394,186			3,204,462			753,393			716,445
Change in Plan Assets
Fair value of plan assets at January 1	2,675,357			2,542,774			882,651			833,017
Actual return on plan assets	428,374			166,408			139,367			63,463
Employer contributions	100,000			100,000			353			819
Benefit payments	(146,704		)	(133,825		)	—			(14,648		)
Fair value of plan assets at December 31	3,057,027			2,675,357			1,022,371			882,651
Funded Status at December 31	$	(337,159	)	$	(529,105	)	$	268,978		$	166,206

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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, 2017 and 2016 (dollars in thousands):

	2017		2016
Projected benefit obligation	$	3,394,186	$	3,204,462
Accumulated benefit obligation	3,227,233		3,049,406
Fair value of plan assets	3,057,027		2,675,357

The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2017 and 2016 (dollars in thousands):

	Pension						Other Benefits
	2017			2016			2017		2016
Noncurrent asset	$	—		$	—		$	268,978	$	166,206
Current liability	(9,859		)	(19,795		)	—		—
Noncurrent liability	(327,300		)	(509,310		)	—		—
Net amount recognized	$	(337,159	)	$	(529,105	)	$	268,978	$	166,206

The following table shows the details related to accumulated other comprehensive loss as of December 31, 2017 and 2016 (dollars in thousands): 

	Pension						Other Benefits
	2017			2016			2017			2016
Net actuarial loss	$	643,199		$	773,750		$	75,439		$	146,509
Prior service cost (credit)	—			81			(265,575		)	(303,417		)
APS’s portion recorded as a regulatory (asset) liability	(576,188		)	(711,059		)	189,627			156,575
Income tax expense (benefit)	(24,915		)	(24,202		)	853			833
Accumulated other comprehensive loss	$	42,096		$	38,570		$	344		$	500

The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets and liabilities into net periodic benefit cost in 2018 (dollars in thousands):

	Pension		Other Benefits
Net actuarial loss	$	28,334	$	—
Prior service credit	—		(37,842		)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2018	$	28,334	$	(37,842	)

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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,
	2017		2016		2017		2016		2015
Discount rate – pension	3.65	%	4.08	%	4.08	%	4.37	%	4.02	%
Discount rate – other benefits	3.71	%	4.17	%	4.17	%	4.52	%	4.14	%
Rate of compensation increase	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%
Expected long-term return on plan assets - pension	N/A		N/A		6.55	%	6.90	%	6.90	%
Expected long-term return on plan assets - other benefits	N/A		N/A		6.05	%	4.45	%	4.45	%
Initial healthcare cost trend rate (pre-65 participants)	7.00	%	7.00	%	7.00	%	7.00	%	7.00	%
Initial healthcare cost trend rate (post-65 participants)	4.75	%	5.00	%	5.00	%	5.00	%	5.00	%
Ultimate healthcare cost trend rate	4.75	%	5.00	%	5.00	%	5.00	%	5.00	%
Number of years to ultimate trend rate (pre-65 participants)	8		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 2018, we are assuming a 6.05% long-term rate of return for pension assets and 5.55% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

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 on our December 31, 2017 amounts (dollars in thousands): 

	1% Increase		1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	$	8,424	$	(5,616	)
Effect on service and interest cost components of net periodic other postretirement benefit costs	9,145		(7,037		)
Effect on the accumulated other postretirement benefit obligation	128,203		(98,143		)

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.

Changes in the value of long-term fixed income assets, also known as liability-hedging assets, are intended 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 and other government

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agencies, U.S. Treasury Futures Contracts, and fixed income debt securities issued by corporations.  Long-term fixed income assets may also include interest rate swaps, 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 also hold investments in return-generating assets by holding securities in partnerships, common and collective trusts and mutual funds.

Based on the IPS, and given the pension plan's funded status at year-end 2017, the target and actual allocation for the pension plan at December 31, 2017 are as follows:

	Pension
	Target Allocation		Actual Allocation
Long-term fixed income assets	62	%	58	%
Return-generating assets	38	%	42	%
Total	100	%	100	%

The permissible range is within +/- 3% of the target allocation shown in the above table, and also considers the Plan's funded status.

The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-generating assets:

Asset Class	Target Allocation
Equities in US and other developed markets	18	%
Equities in emerging markets	6	%
Alternative investments	14	%
Total	38	%

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, 2017, the asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for different asset allocation target mixes depending on the characteristics of the liability.  Some of these asset allocation target mixes vary with the plan’s funded status. The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2017:

	Other Benefits
	Actual Allocation
Long-term fixed income assets	67	%
Return-generating assets	33	%
Total	100	%

See Note 13 for a discussion on the fair value hierarchy and how fair value methodologies are applied.  The plans invest directly in fixed income, U.S. Treasury Futures Contracts, and equity securities, in addition to

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investing indirectly in fixed income securities, equity securities and real estate through the use of mutual funds, partnerships and 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.  U.S. Treasury Future Contracts are valued using the quoted active market prices from the exchange on which they trade, 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.

Mutual funds, partnerships, and common and collective trusts are valued utilizing a net asset value (NAV) concept or its equivalent. Mutual funds, which includes exchange traded funds (ETFs), are classified as Level 1 and valued using a NAV that is observable and based on the active market in which the fund trades.

Common and collective trusts are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 Index).  The trust's shares are offered to a limited group of investors, and are not traded in an active market. Investments in common and collective trusts are valued using NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for trusts investing in exchange traded equities, and fixed income securities is derived from the market prices of the underlying securities held by the trusts. The NAV for trusts investing in real estate is derived from the appraised values of the trust's underlying real estate assets.  As of December 31, 2017, the plans were able to transact in the common and collective trusts at NAV.

Investments in partnerships are also valued using the concept of NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for these investments is derived from the value of the partnerships' underlying assets. The plan's partnerships holdings relate to investments in high-yield fixed income instruments and assets of privately held portfolio companies. Certain partnerships also include funding commitments that may require the plan to contribute up to $75 million to these partnerships; as of December 31, 2017, approximately $58 million of these commitments have been funded.

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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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2017, by asset category, are as follows (dollars in thousands):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Other (a)		Balance at December 31, 2017
Pension Plan:
Cash and cash equivalents	$	3,830	$	—	$	—	$	3,830
Fixed income securities:
Corporate	—		1,365,194		—		1,365,194
U.S. Treasury	221,291		—		—		221,291
Other (b)	—		100,599		—		100,599
Common stock equities (c)	228,088		—		—		228,088
Mutual funds (d)	233,732		—		—		233,732
Common and collective trusts:
Equities	—		—		408,763		408,763
Real estate	—		—		171,569		171,569
Fixed Income	—		—		90,869		90,869
Partnerships	—		—		133,379		133,379
Short-term investments and other (e)	—		1,208		98,505		99,713
Total	$	686,941	$	1,467,001	$	903,085	$	3,057,027
Other Benefits:
Cash and cash equivalents	$	143	$	—	$	—	$	143
Fixed income securities:
Corporate	—		306,008		—		306,008
U.S. Treasury	336,963		—		—		336,963
Other (b)	—		32,508		—		32,508
Common stock equities (c)	196,153		—		—		196,153
Mutual funds (d)	39,269		—		—		39,269
Common and collective trusts:
Equities	—		—		75,310		75,310
Real estate	—		—		15,422		15,422
Short-term investments and other (e)	11,268		149		9,178		20,595
Total	$	583,796	$	338,665	$	99,910	$	1,022,371

(a) These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy.

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

(c) This category primarily consists of U.S. common stock equities.

(d) These funds invest in U.S. and international common stock equities.

(e) This category includes plan receivables and payables.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2016, by asset category, are as follows (dollars in thousands):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Other (a)		Balance at December 31, 2016
Pension Plan:
Cash and cash equivalents	$	13,995	$	—	$	—	$	13,995
Fixed income securities:
Corporate	—		1,210,453		—		1,210,453
U.S. Treasury	112,583		—		—		112,583
Other (b)	—		102,170		—		102,170
Common stock equities (c)	235,109		—		—		235,109
Mutual funds (d)	251,506		—		—		251,506
Common and collective trusts:
Equities	—		—		266,840		266,840
Real estate	—		—		161,449		161,449
Partnerships	—		—		208,915		208,915
Short-term investments and other (e)	—		—		112,337		112,337
Total	$	613,193	$	1,312,623	$	749,541	$	2,675,357
Other Benefits:
Cash and cash equivalents	$	304	$	—	$	—	$	304
Fixed income securities:
Corporate	—		268,193		—		268,193
U.S. Treasury	145,255		—		—		145,255
Other (b)	—		34,506		—		34,506
Common stock equities (c)	243,741		—		—		243,741
Mutual funds (d)	67,418		—		—		67,418
Common and collective trusts:
Equities	—		—		95,814		95,814
Real estate	—		—		14,509		14,509
Partnerships	—		—		3,060		3,060
Short-term investments and other (e)	—		—		9,851		9,851
Total	$	456,718	$	302,699	$	123,234	$	882,651

(a) These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy.

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

(c) This category primarily consists of U.S. common stock equities.

(d) These funds invest in U.S. and international common stock equities.

(e) This category includes plan receivables and payables.

Contributions

Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  We made contributions to our pension plan totaling $100 million in 2017, $100 million in 2016, and $100 million in 2015.  The minimum required contributions for the pension plan are zero for the next three years.  We expect to make voluntary contributions up to a total of $250 million during the 2018-2020 period. 

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

With regard to contributions to our other postretirement benefit plans, we made a contribution of approximately $1 million in each of 2017, 2016 and 2015.  We do not expect to make any contributions over the next three years to our other postretirement benefit plans. APS funds its share of the contributions.  APS’s share of the pension plan contribution was approximately $100 million in 2017, $100 million in 2016 and $100 million in 2015.  APS’s share of the contributions to the other postretirement benefit plan was approximately $1 million in 2017, 2016 and 2015.

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
2018	$	175,383	$	31,891
2019	181,902		34,000
2020	191,586		35,658
2021	196,583		37,090
2022	201,463		37,860
Years 2023-2027	1,068,568		191,207

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 2017, 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 $10 million for 2017, $10 million for 2016, and $9 million for 2015.

8.    Leases

We lease certain vehicles, land, buildings, equipment and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates. See Note 2 for a discussion of the new lease accounting standard.

Total lease expense recognized in the Consolidated Statements of Income was $18 million in 2017, $16 million in 2016, and $17 million in 2015.  APS’s lease expense was $17 million in 2017, $15 million in 2016, and $14 million in 2015.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Year	Pinnacle West Consolidated		APS
2018	$	13,412	$	13,110
2019	11,054		10,802
2020	9,641		9,392
2021	7,105		6,858
2022	4,609		4,510
Thereafter	55,940		53,605
Total future lease commitments	$	101,761	$	98,277

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 impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation.  See Note 18 for a discussion of VIEs.

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9.    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 which are included in the corresponding operating expenses on our Consolidated Statements of Income. We are also responsible 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, 2017 (dollars in thousands):

	Percent Owned			Plant in Service		Accumulated Depreciation		Construction Work in Progress
Generating facilities:
Palo Verde Units 1 and 3	29.1	%		$	1,872,104	$	1,092,049	$	24,257
Palo Verde Unit 2 (a)	16.8	%		619,263		364,516		14,672
Palo Verde Common	28.0	%	(b)	726,223		262,065		46,577
Palo Verde Sale Leaseback			(a)	351,050		241,405		—
Four Corners Generating Station	63.0	%		1,196,683		568,304		240,514
Cholla common facilities (c)	50.5	%		180,907		69,633		1,091
Transmission facilities:
ANPP 500kV System	34.0	%	(b)	130,767		46,400		684
Navajo Southern System	27.5	%	(b)	85,299		28,915		180
Palo Verde — Yuma 500kV System	18.1	%	(b)	14,765		6,614		486
Four Corners Switchyards	63.2	%	(b)	66,386		12,605		327
Phoenix — Mead System	17.1	%	(b)	39,383		17,600		41
Palo Verde — Rudd 500kV System	50.0	%		97,600		23,884		245
Morgan — Pinnacle Peak System	64.6	%	(b)	117,721		14,569		1
Round Valley System	50.0	%		515		141		—
Palo Verde — Morgan System	90.9	%	(b)	137,887		3,948		94,350
Hassayampa — North Gila System	80.0	%		142,541		6,953		—
Cholla 500kV Switchyard	85.7	%		5,243		1,312		190
Saguaro 500kV Switchyard	60.0	%		20,473		12,574		—
Kyrene — Knox System	50.0	%		578		297		—

(a) See Note 18.

(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.

APS also has a 14% ownership in the Navajo Plant.  In the second quarter of 2017, APS’s remaining net book value of its interest was reclassified from property, plant and equipment to a regulatory asset.  See “Navajo Plant” in Note 3 for more details.

4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners. At December 31, 2017, 4CA had plant in service of $141 million, accumulated depreciation of $83 million and construction work in progress of $25 million.

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10.    Commitments and Contingencies

Palo Verde 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 second breach of contract lawsuit against the DOE in the United States Court of Federal Claims ("Court of Federal Claims").  The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde's spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.  On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on the amount of reported net income. In addition, the settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019.

APS has submitted three claims pursuant to the terms of the August 18, 2014 settlement agreement, for three separate time periods during July 1, 2011 through June 30, 2016. The DOE has approved and paid $65.2 million for these claims (APS’s share is $19 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 retail rate case settlement, this regulatory liability is being refunded to customers (see Note 3). APS's next claim pursuant to the terms of the August 18, 2014 settlement agreement was submitted to the DOE in the fourth quarter of 2017 in the amount of $9 million (APS's share is $2.6 million). In February 2018, the DOE approved this claim.

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-wide 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 approximately $13.4 billion per occurrence.  Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers ("ANI").  The remaining balance of approximately $13.0 billion of liability coverage is provided through a mandatory industry-wide retrospective premium program.  If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums.  The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $127.3 million, subject to a maximum annual premium of $19 million per incident.  Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $111.1 million, with a maximum annual retrospective premium of approximately $16.6 million.

The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion.  APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units. The property damage,

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decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited ("NEIL").  APS is subject to retrospective premium adjustments 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 $24 million for each retrospective premium 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 $64.8 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 various fuel and purchased power contracts and purchase obligations with terms expiring between 2018 and 2043 that include required purchase provisions.  APS estimates the contract requirements to be approximately $715 million in 2018; $578 million in 2019; $548 million in 2020; $548 million in 2021; $554 million in 2022; and $6.5 billion thereafter.  However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.

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

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

	Years Ended December 31,
	2018		2019		2020		2021		2022		Thereafter
Coal take-or-pay commitments (a)	$	159,997	$	185,365	$	186,632	$	190,607	$	194,678	$	1,750,739

(a) Total take-or-pay commitments are approximately $2.7 billion.  The total net present value of these commitments is approximately $1.9 billion.

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

	Year Ended December 31,
	2017		2016		2015
Total purchases	$	165,220	$	160,066	$	211,327

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 $40 million in 2018; $40 million in 2019; $40 million in 2020; $40 million in 2021; $40 million in 2022; and $370 million thereafter.  These amounts do not include purchases of renewable energy credits that are bundled with energy.

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Coal Mine Reclamation Obligations

APS and 4CA 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 an obligation for the coal mine final reclamation of approximately $216 million at December 31, 2017 and $207 million at December 31, 2016. 4CA recorded an obligation for the coal mine final reclamation of approximately $16 million at December 31, 2017 and $15 million at December 31, 2016. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows:  $31 million in 2018; $32 million in 2019; $21 million in 2020; $20 million in 2021; $22 million in 2022; and $191 million thereafter.  4CA expects to make payments for the final mine reclamation as follows: $1 million in 2018; $1 million in 2019; $2 million in 2020; $2 million in 2021; $2 million in 2022; and $16 million thereafter. Any amendments to current coal supply agreements may change the timing of the contribution. Portions of these funds will be held in an escrow account and distributed to certain coal providers under the terms of the applicable coal supply agreements.

Superfund-Related Matters

Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.  Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs.  PRPs may be strictly, and often are jointly and severally, liable for clean-up.  On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52^nd Street Superfund Site, 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 RI/FS.  Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS, APS anticipates finalizing the RI/FS in the summer or fall of 2018. 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.  As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, ADEQ sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area.  APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID contractors filed ancillary lawsuits for recovery of costs against APS and the other defendants. Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS’s exposure or risk related to these matters. In addition, on March 15, 2017, the Arizona District Court granted partial summary judgment to RID for one element of RID's lawsuit against APS and the other defendants. On May 12, 2017, the court denied a motion for reconsideration as to this order. We are unable to

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predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, 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 pollution control requirements on Four Corners and the Navajo Plant. EPA will require these plants to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plants. EPA approved a proposed rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the Cholla BART approval.

Four Corners. Based on EPA’s final standards, APS's 63% share of the cost of required controls for Four Corners Units 4 and 5 is approximately $400 million.  In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. NTEC had the option to purchase the interest within a certain timeframe pursuant to an option granted to NTEC. In December 2015, NTEC notified APS of its intent to exercise the option. The purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction. The cost of the pollution controls related to the 7% interest is approximately $45 million, which will be assumed by the ultimate owner of the 7% interest.

Navajo Plant. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s FIP, could be up to approximately $200 million; however, given the future plans for the Navajo Plant, we do not expect to incur these costs.  See "Navajo Plant" in Note 3 for information regarding future plans for the Navajo Plant.

Cholla. APS believed that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls, was unsupported and that EPA had no basis for disapproving Arizona’s SIP and promulgating a FIP that was inconsistent with the state’s considered BART determinations under the regional haze program.  In September 2014, APS met with EPA to propose a compromise BART strategy. APS would permanently close Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP.

On October 16, 2015, ADEQ issued a revised operating permit for Cholla, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to EPA, which would incorporate the new permit terms.  On June 30, 2016, EPA issued a proposed rule approving a revision to the Arizona SIP that

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incorporates APS’s compromise approach for compliance with the Regional Haze program.  In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017.

Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of RCRA and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity.

While EPA has chosen to regulate the disposal of CCR in landfills and surface impoundments as non-hazardous waste under the final rule, the agency makes clear that it will continue to evaluate any risks associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future.

On December 16, 2016, President Obama signed the WIIN Act into law, which contains a number of provisions requiring EPA to modify the self-implementing provisions of the Agency's current CCR rules under Subtitle D. Such modifications include new EPA authority to directly enforce the CCR rules through the use of administrative orders and providing states, like Arizona, where the Cholla facility is located, the option of developing CCR disposal unit permitting programs, subject to EPA approval. For facilities in states that do not develop state-specific permitting programs, EPA is required to develop a federal permit program, pending the availability of congressional appropriations. By contrast, for facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation, where the Navajo Plant and Four Corners facilities are located, EPA is required to develop a federal permit program regardless of appropriated funds.

ADEQ has initiated a process to evaluate how to develop a state CCR permitting program that would cover EGUs, including Cholla. While APS has been working with ADEQ on the development of this program, we are unable to predict when Arizona will be able to finalize and secure EPA approval for a state-specific CCR permitting program. With respect to the Navajo Nation, APS recently filed a comment letter with EPA seeking clarification as to when and how EPA would be initiating permit proceedings for facilities on the reservation, including Four Corners. We are unable to predict at this time when EPA will be issuing CCR management permits for the facilities on the Navajo Nation. At this time, it remains unclear how the CCR provisions of the WIIN Act will affect APS and its management of CCR.

Based upon utility industry petitions for EPA to reconsider the RCRA Subtitle D regulations for CCR, which were premised in part on the CCR provisions of the 2016 WIIN Act, on September 13, 2017 EPA agreed to evaluate whether to revise these federal CCR regulations. At this time, it is not clear whether EPA will initiate further notice-and-comment rulemaking to revise the federal CCR rules, nor is it clear what aspects of the federal CCR rules might be changed as a result of this process. With respect to ongoing litigation initiated by industry and environmental groups challenging the legality of these federal CCR regulations, on September 27, 2017 the United States Court of Appeals for the D.C. Circuit, the court overseeing these judicial challenges, ordered EPA to file by November 15, 2017 a list of federal regulatory provisions addressing CCR that are or likely will be revised through EPA’s reconsideration proceedings. While this filing identified certain provisions of the federal CCR regulations that EPA intends to revise, including allowances for risk-based

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groundwater protection standards for regulated CCR constituents for which no federal maximum contaminant level has been set, it is not clear at this time which specific provisions of the federal CCR rules will be modified, how they will be modified, or when such modification will occur.

Pursuant to a June 24, 2016 order by the D.C. Circuit Court of Appeals in the litigation by industry- and environmental-groups challenging EPA’s CCR regulations, within the next 2 years EPA is required to complete a rulemaking proceeding concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules.  EPA is not required to take final action approving the inclusion of boron, but EPA must propose and consider its inclusion.  Should EPA take final action adding boron to the list of groundwater constituents that might trigger corrective action, any resulting corrective action measures may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities.  At this time APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings.

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $22 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $20 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. By October 17, 2017, electric utility companies that own or operate CCR disposal units, such as APS, must have collected sufficient groundwater sampling data to initiate a detection monitoring program.  To the extent that certain threshold constituents are identified through this initial detection monitoring at levels above the CCR rule’s standards, the rule requires the initiation of an assessment monitoring program by April 15, 2018.  If this assessment monitoring program reveals concentrations of certain constituents above the CCR rule standards that trigger remedial obligations, a corrective measures evaluation must be completed by January 2019. Depending upon the results of such groundwater monitoring and data evaluations at each of Cholla, Four Corners and the Navajo Plant, we may be required to take corrective actions, the costs of which we are unable to reasonably estimate at this time.

Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for EGUs. Shortly thereafter, a coalition of states, industry groups and electric utilities challenged the legality of these standards, including EPA's Clean Power Plan for existing EGUs, in the U.S. Court of Appeals for the D.C. Circuit. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations under the Clean Power Plan. On March 28, 2017, President Trump issued an Executive Order that, among other things, instructs EPA to reevaluate Agency regulations concerning carbon emissions from EGUs and take appropriate action to suspend, revise or rescind the August 2015 carbon pollution standards for EGUs, including the Clean Power Plan. Also on March 28, 2017, the U.S. Department of Justice, on behalf of EPA, filed a motion with the U.S. Court of Appeals for the D.C. Circuit Court to hold the ongoing litigation over the Clean Power Plan in abeyance pending EPA action in accordance with the Executive Order. At this time, the D.C. Circuit Court proceedings evaluating the legality of the Clean Power Plan remain on hold.

Based upon EPA's reevaluation of the August 2015 carbon pollution standards and the legal basis for these regulations, on October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan. That proposal relies on EPA's current view as to the Agency's legal authority under Clean Air Act Section 111(d), which (in contrast to the Clean Power Plan) would limit the scope of any future Section 111(d) regulations to measures undertaken exclusively at a power plant's source of GHG emissions. On December 18, 2017, EPA issued an Advanced Notice of Proposed Rulemaking through which EPA is soliciting comments as to potential

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replacements for the Clean Power Plan that would be consistent with EPA's current legal interpretation of the Clean Air Act.

We cannot predict the outcome of EPA's regulatory actions related to the August 2015 carbon pollution standards for EGU's, including any actions related to EPA's repeal proposal for the Clean Power Plan or additional rulemaking actions to develop regulations replacing the Clean Power Plan. In addition, we cannot predict whether the D.C. Circuit Court will continue to hold the litigation challenging the original Clean Power Plan in abeyance in light of EPA's repeal proposal.

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants.  The financial impact of complying with current and 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.

Federal Agency Environmental Lawsuit Related to Four Corners

On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine.  The lawsuit alleges that these federal agencies violated both ESA and NEPA in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016.  APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016.

On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. We cannot predict whether this appeal will be successful and, if it is successful, the outcome of further district court proceedings.

Four Corners Coal Supply Agreement

Arbitration

On June 13, 2017, APS received a Demand for Arbitration from NTEC in connection with the 2016 Coal Supply Agreement, dated December 30, 2013, under which NTEC supplies coal to APS and the other Four Corners owners (collectively, the “Buyer”) for use at the Four Corners Power Plant. NTEC was originally seeking a declaratory judgment to support its interpretation of a provision regarding uncontrollable forces in the agreement that relates to annual minimum quantities of coal to be purchased by the Buyer. NTEC also alleged a shortfall in the Buyer’s purchases for the initial contract year of approximately $30 million. APS’s share of this amount is approximately $17 million. On September 20, 2017, NTEC amended its Demand for Arbitration removing its request for a declaratory judgment and at this time is only seeking relief for the alleged shortfall in the Buyer's purchases for the initial contract year. We cannot predict the timing or

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outcome of this arbitration; however we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

4CA Matter

On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC had the option to purchase the 7% interest within a certain timeframe pursuant to an option granted to NTEC. On December 29, 2015, NTEC provided notice of its intent to exercise the option. The purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction.

The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% interest in the event NTEC does not purchase the interest. At this time, since NTEC has not yet purchased the 7% interest, the alternate pricing provisions are applicable to 4CA as the holder of the 7% interest. These terms include a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales. Such payments are due to 4CA at the end of each calendar year. A $10 million payment was due to 4CA at December 31, 2017, which NTEC satisfied by directing to 4CA a prepayment from APS of a portion of a future mine reclamation obligation. The balance of the amount under this formula at December 31, 2017 is approximately $20 million, which is due to 4CA at December 31, 2018. In future years there may be similar payments due from NTEC to 4CA under this formula. 4CA believes NTEC should continue to satisfy its contractual obligations related to these payments; however, if NTEC fails to meet its contractual obligations when due, 4CA will consider appropriate measures and potential impacts to the Company's financial statements.

Financial Assurances

In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support certain commodity contract collateral obligations and other transactions. As of December 31, 2017, standby letters of credit totaled $5 million and will expire in 2018. As of December 31, 2017, surety bonds expiring through 2019 totaled $62 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.

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 has provided indemnification under certain surety bonds for APS which were not material at December 31, 2017. Since July 6, 2016, Pinnacle West has issued four parental guarantees for 4CArelating to payment obligations arising from 4CA’s acquisition of El Paso’s 7% interest in Four Corners, and pursuant to the Four Corners participation agreement payment obligations arising from 4CA’s ownership interest in Four Corners.

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11.     Asset Retirement Obligations

In 2017, APS received a new decommissioning study for the Navajo Plant. This resulted in an increase to the ARO in the amount of $22 million, an increase in regulatory asset of $2 million and a reduction of the regulatory liability of $20 million.

In 2016, APS recognized an ARO for the Ocotillo steam units as a condition of the air permit (issued in 2016) to allow the construction and operation of five new turbine units. This resulted in an increase to the ARO in the amount of $10 million. In addition, 4CA acquired El Paso's share of Four Corners Units 4 and 5 and the associated ARO. This resulted in an increase to the ARO in the amount of $9 million. In addition, Four Corners spent $16 million in actual decommissioning costs. Finally, in 2016, APS received a new decommissioning study for the Palo Verde Generating Station. This resulted in an increase to the ARO in the amount of $151 million, an increase in plant in service of $131 million, and a reduction of the regulatory liability of $20 million.

The following table shows the change in our asset retirement obligations for 2017 and 2016 (dollars in thousands):

	2017		2016
Asset retirement obligations at the beginning of year	$	624,475	$	443,576
Changes attributable to:
Accretion expense	33,104		26,656
Settlements	—		(15,732		)
Estimated cash flow revisions	21,950		151,046
Newly incurred or acquired obligations	—		18,929
Asset retirement obligations at the end of year	$	679,529	$	624,475

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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12.    Selected Quarterly Financial Data (Unaudited)

Consolidated quarterly financial information for 2017 and 2016 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.

	2017 Quarter Ended								2017
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	677,728	$	944,587	$	1,183,322	$	759,659	$	3,565,296
Operations and maintenance	219,976		214,013		224,305		266,149		924,443
Operating income	73,506		304,229		466,082		90,610		934,427
Income taxes	4,211		88,967		144,319		20,775		258,272
Net income	28,185		172,317		280,945		26,502		507,949
Net income attributable to common shareholders	23,312		167,443		276,072		21,629		488,456
Earnings Per Share:
Net income attributable to common shareholders — Basic	$	0.21	$	1.50	$	2.47	$	0.19	$	4.37
Net income attributable to common shareholders — Diluted	0.21		1.49		2.46		0.19		4.35

	2016 Quarter Ended								2016
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	677,167	$	915,394	$	1,166,922	$	739,199	$	3,498,682
Operations and maintenance	243,195		242,279		217,568		208,277		911,319
Operating income	50,162		231,748		451,258		122,816		855,984
Income taxes	1,914		65,742		141,446		27,309		236,411
Net income	9,326		126,182		267,900		58,119		461,527
Net income attributable to common shareholders	4,453		121,308		263,027		53,246		442,034
Earnings Per Share:
Net income attributable to common shareholders — Basic	$	0.04	$	1.09	$	2.36	$	0.48	$	3.97
Net income attributable to common shareholders — Diluted	0.04		1.08		2.35		0.47		3.95

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Selected Quarterly Financial Data (Unaudited) - APS

APS's quarterly financial information for 2017 and 2016 is as follows (dollars in thousands):

	2017 Quarter Ended,								2017
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	676,869	$	942,615	$	1,178,106	$	756,549	$	3,554,139
Operations and maintenance	212,218		208,286		215,264		255,361		891,129
Operating income	65,468		212,790		322,053		79,258		679,569
Net income attributable to common shareholder	23,162		169,108		284,256		27,783		504,309

	2016 Quarter Ended,								2016
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	676,632	$	909,757	$	1,166,359	$	737,006	$	3,489,754
Operations and maintenance	238,711		233,712		209,366		197,319		879,108
Operating income	48,930		165,684		307,601		95,765		617,980
Net income attributable to common shareholder	7,253		127,188		269,220		58,480		462,141

13.    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.

Level 2 — Other significant observable inputs, including 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). 

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

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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.

Certain instruments have been valued using the concept of NAV, as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV, as a practical expedient are included in our fair value disclosures however, in accordance with GAAP are not classified within the fair value hierarchy levels.

Recurring Fair Value Measurements

We apply recurring fair value measurements to certain cash equivalents, derivative instruments, and investments held in our coal reclamation escrow accounts and nuclear decommissioning trust. On an annual basis we apply fair value measurements to plan assets held in our retirement and other benefit plans.  See Note 7 for 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, characteristics of the product, 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.

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.

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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 Nuclear Decommissioning Trust and Coal Reclamation Escrow

The nuclear decommissioning trust invests in fixed income securities, equity securities, and may hold cash and cash equivalents. The coal reclamation escrow account invests in fixed income instruments and may also hold cash and cash equivalents. See Note 19 for additional discussion about our investment accounts.

The nuclear decommissioning trust's equity security investments are held indirectly through commingled funds.  The commingled funds are valued using the funds' NAV as a practical expedient. The funds' NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds. We may transact in these commingled funds on a semi-monthly basis at the NAV.  The commingled 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 funds' shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy.

Fixed income securities issued by the U.S. Treasury are valued using quoted active market prices and are typically 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 fixed income 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.

Cash equivalents reported within Level 1 represent investments held in short-term investment exchange-traded mutual funds. These short-term investment accounts invest in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, commercial paper, and other short term instruments.

We price investment securities using information provided by our trustees for our nuclear decommissioning trust assets, and provided by our escrow agent for coal reclamation escrow assets. Our trustee and escrow agent use pricing services that utilize the valuation methodologies described above 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 and escrow agent's internal operating controls and valuation processes. 

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Fair Value Tables

The following table presents the fair value at December 31, 2017 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

	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, 2017
Assets
Cash equivalents	$	10,630	$	—		$	—		$	—			$	10,630
Risk management activities — derivative instruments:
Commodity contracts	—		5,683			1,036			(4,737		)	(b)	1,982
Coal reclamation escrow account (c):	455		31,562			—			525				32,542
Nuclear decommissioning trust:
Cash and cash equivalents	7,224		—			—			109			(d)	7,333
U.S. commingled equity funds	—		—			—			417,390			(e)	417,390
Fixed income securities:
U.S. Treasury	127,662		—			—			—				127,662
Corporate debt	—		114,007			—			—				114,007
Mortgage-backed securities	—		111,874			—			—				111,874
Municipal bonds	—		79,049			—			—				79,049
Other	—		13,685			—			—				13,685
Subtotal nuclear decommissioning trust	134,886		318,615			—			417,499				871,000
Total Assets	$	145,971	$	355,860		$	1,036		$	413,287			$	916,154
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(78,646	)	$	(19,292	)	$	1,516		(b)	$	(96,422	)

(a) Primarily consists of long-dated electricity contracts.

(b) Represents counterparty netting, margin, and collateral. See Note 16.

(c) Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Consolidated Balance Sheets. Primarily consists of fixed income municipal bonds.

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

(e) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

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The following table presents the fair value at December 31, 2016 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

	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, 2016
Assets
Coal reclamation trust (b):	$	14,521	$	—		$	—		$	—			$	14,521
Risk management activities — derivative instruments:
Commodity contracts	—		43,722			11,076			(35,103		)	(c)	19,695
Nuclear decommissioning trust:
U.S. commingled equity funds	—		—			—			353,261			(d)	353,261
Fixed income securities:
Cash and cash equivalent funds	—		—			—			795			(e)	795
U.S. Treasury	95,441		—			—			—				95,441
Corporate debt	—		111,623			—			—				111,623
Mortgage-backed securities	—		115,337			—			—				115,337
Municipal bonds	—		80,997			—			—				80,997
Other	—		22,132			—			—				22,132
Subtotal nuclear decommissioning trust	95,441		330,089			—			354,056				779,586
Total	$	109,962	$	373,811		$	11,076		$	318,953			$	813,802
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(45,641	)	$	(58,482	)	$	31,049		(c)	$	(73,074	)

(a) Primarily consists of long-dated electricity contracts.

(b) Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Consolidated Balance Sheets. Primarily consists of cash equivalents. Presented as Coal reclamation escrow in 2017.

(c) Represents counterparty netting, margin and collateral. See Note 16.

(d) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

(e) 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.  Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements.  Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 3).

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Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts.  Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.

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, 2017 and December 31, 2016:

	December 31, 2017 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Commodity Contracts	Assets		Liabilities
Electricity:
Forward Contracts (a)	$	21	$	15,485	Discounted cash flows	Electricity forward price (per MWh)	$18.51 - $38.75	$	27.89
Natural Gas:
Forward Contracts (a)	1,015		3,807		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.33 - $3.11	$	2.71
Total	$	1,036	$	19,292

(a) Includes swaps and physical and financial contracts.

	December 31, 2016 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Commodity Contracts	Assets		Liabilities
Electricity:
Forward Contracts (a)	$	10,648	$	32,042	Discounted cash flows	Electricity forward price (per MWh)	$16.43 - $41.07	$	29.86
Natural Gas:
Forward Contracts (a)	428		26,440		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.32 - $3.60	$	2.81
Total	$	11,076	$	58,482

(a) Includes swaps and physical and financial contracts.

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The following table shows the changes in fair value for our risk management activities' assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the years ended December 31, 2017 and 2016 (dollars in thousands):

	Year Ended December 31,
Commodity Contracts	2017			2016
Net derivative balance at beginning of period	$	(47,406	)	$	(32,979	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			—
Included in OCI	3			88
Deferred as a regulatory asset or liability	(13,643		)	(37,543		)
Settlements	5,834			15,146
Transfers into Level 3 from Level 2	(10,026		)	1,900
Transfers from Level 3 into Level 2	46,982			5,982
Net derivative balance at end of period	$	(18,256	)	$	(47,406	)
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 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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14.    Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for continuing operations attributable to common shareholders for the years ended December 31, 2017, 2016 and 2015 (in thousands, except per share amounts):

	2017		2016		2015
Net income attributable to common shareholders	$	488,456	$	442,034	$	437,257
Weighted average common shares outstanding — basic	111,839		111,409		111,026
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	528		637		526
Weighted average common shares outstanding — diluted	112,367		112,046		111,552
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders - basic	$	4.37	$	3.97	$	3.94
Net Income attributable to common shareholders - diluted	$	4.35	$	3.95	$	3.92

15.    Stock-Based Compensation

Pinnacle West has incentive compensation plans under which stock-based compensation is granted to officers, key-employees, and non-officer members of the Board of Directors. Awards granted under the 2012 Long-Term Incentive Plan (“2012 Plan”) may be in the form of stock grants, restricted stock units, stock units, performance shares, restricted stock, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights.  The 2012 Plan authorizes up to 4.6 million common shares to be available for grant.  As of December 31, 2017, 2.2 million common shares were available for issuance under the 2012 Plan. During 2017, 2016, and 2015, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. Awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”), and no new awards may be granted under the 2007 Plan.

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Stock-Based Compensation Expense and Activity

During the fourth quarter of 2016, we adopted new stock-based compensation accounting guidance prescribed by ASU 2016-09. Prior to the adoption of this guidance we had certain awards that were accounted for as liability awards due to the ability of the employee to withhold taxes beyond the minimum statutory tax withholding rate. Under the new standard, the tax withholding terms of our awards no longer trigger liability treatment. Accordingly, effective January 1, 2016 certain awards that were previously classified as liability awards are now accounted for as equity awards. The impacts of this accounting change relating to prior years have been applied using a modified retrospective approach, resulting in a $6 million cumulative-effect adjustment, net of income tax expense of $3 million, to increase Retained Earnings as of January 1, 2016. The impacts of this accounting change relating to 2016 resulted in a pre-tax $12 million adjustment to decrease operations and maintenance expense that was recognized during the fourth quarter of 2016. The following amounts related to years ended 2017 and 2016 expense and activity include the effects of adopting this new accounting standard; however, expense and activities relating to 2015 reflect the historical accounting treatment. The new standard also requires excess income tax benefits and deficiencies arising from stock based compensation to now be recognized in the period incurred, simplifies accounting for forfeitures, and clarifies certain cash flow presentation matters. These other provisions of the standard did not have a material impact on our consolidated financial statements.

Compensation cost included in net income for stock-based compensation plans was $21 million in 2017, $19 million in 2016, and $19 million in 2015.  The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $15 million in 2017, $10 million in 2016, and $7 million in 2015.

As of December 31, 2017, there were approximately $12 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. We expect to recognize these costs over a weighted-average period of 2 years. 

The total fair value of shares vested was $22 million in 2017, $22 million in 2016 and $21 million in 2015.

The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2017, 2016 and 2015.

	Restricted Stock Units, Stock Grants, and Stock Units (a)						Performance Shares (b)
	2017		2016		2015		2017		2016		2015
Units granted	161,963		141,811		152,651		147,706		166,666		151,430
Weighted-average grant date fair value	$	72.60	$	67.34	$	64.12	$	78.99	$	66.60	$	64.97

(a) Units granted includes awards that will be cash settled of 67,599 in 2017, 43,952 in 2016, and 45,104 in 2015.

(b) Reflects the target payout level.

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The following table is a summary of the status of non-vested awards as of December 31, 2017 and changes during the year.

	Restricted Stock Units, Stock Grants, and Stock Units					Performance Shares
	Shares			Weighted-Average Grant Date Fair Value		Shares (b)		Weighted-Average Grant Date Fair Value
Nonvested at January 1, 2017	335,259			$	62.04	312,724		$	65.32
Granted	161,963			72.60		147,706		78.99
Change in performance factor	—			—		18,266		64.97
Vested	(202,327	)		59.19		(164,396	)	63.87
Forfeited (c)	(3,607	)		69.58		(4,798	)	69.77
Nonvested at December 31, 2017	291,288		(a)	69.78		309,502		72.46
Vested Awards Outstanding at December 31, 2017	89,928					164,396

(a) Includes 133,373 of awards that will be cash settled.

(b) The nonvested performance shares are reflected at target payout level.  The performance metric component 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.

(c) We account for forfeitures as they occur.

Share-based liabilities paid relating to restricted stock units were $4 million, $3 million and $10 million in 2017, 2016 and 2015, respectively. This includes cash used to settle restricted stock units of $4 million, $3 million and $3 million in 2017, 2016 and 2015, respectively. Restricted stock units that are cash settled are classified as liability awards. Share-based liabilities paid relating to performance shares were $16 million in 2015. In 2017 and 2016, performance shares were classified as equity awards.

Restricted Stock Units, Stock Grants, and Stock Units

Restricted stock units are granted to officers and key employees.  Restricted stock units typically vest and settle in equal annual installments over a 4-year period after the grant date.  Vesting is typically dependent upon continuous service during the vesting period; however, awards granted to retirement-eligible employees will vest upon the employee's retirement. Awardees elect to receive payment in either 100% stock, 100% cash, or 50% in cash and 50% in stock. Restricted stock unit awards typically include a dividend equivalent feature. This feature allows each award to accrue dividend rights equal to the dividends they would have received had they directly owned the stock. Interest on dividend rights compounds quarterly. If the award is forfeited the employee is not entitled to the dividends on those shares.

In December 2012, the Company granted a retention award of 50,617 performance-linked restricted stock units to the Chairman of the Board and Chief Executive Officer of Pinnacle West.  This award vested on December 31, 2016, because he remained employed with the Company through that date.  The Board did increase the number of awards that vested by 33,745 restricted stock units, payable in stock because certain performance requirements were met. In February 2017, 84,362 restricted stock units were released.

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Compensation cost for restricted stock unit awards is based on the fair value of the award, with the fair value being the market price of our stock on the measurement date. Restricted stock unit awards that will be settled in cash 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. Restricted stock unit awards that will be settled in shares are accounted for as equity awards, with compensation cost calculated using the Company's closing stock price on the date of grant. Compensation cost is recognized over the requisite service period based on the fair value of the award.

Stock grants are issued to non-officer members of the Board of Directors. They may elect to receive the stock grant, or to defer receipt until a later date and receive 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 100% stock, or 50% in cash and 50% in stock.  Each stock unit is convertible to one share of stock. The 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 or 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.

Performance Share Awards

Performance share awards are granted to officers and key employees.  The awards contain two separate performance criteria that affect the number of shares that may be received if after the end of a 3-year performance period the performance criteria are met. For the first criteria, the number of shares that will vest is based on non-financial performance metrics (i.e., the metric component). The other criteria is based upon Pinnacle West's total shareholder return ('TSR') in relation to the TSR of other companies in a specified utility index (i.e., the TSR component). 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 recipients 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. If the award is forfeited or if the performance criteria are not achieved, the employee is not entitled to the dividends on those shares.

Performance share awards are accounted for as equity awards, with compensation cost based on the fair value of the award on the grant date. Compensation cost relating to the metric component of the award is based on the Company’s closing stock price on the date of grant, with compensation cost recognized over the requisite service period based on the number of shares expected to vest. Management evaluates the probability of meeting the metric component at each balance sheet date. If the metric component criteria are not ultimately achieved, no compensation cost is recognized relating to the metric component, and any previously recognized compensation cost is reversed. Compensation cost relating to the TSR component of the award is determined using a Monte Carlo simulation valuation model, with compensation cost recognized ratably over the requisite service period, regardless of the number of shares that actually vest.

16.    Derivative Accounting

Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and interest rates.  Risks associated with market volatility are managed 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

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flow variability on forecasted transactions.  The changes in market value of such instruments have a high correlation to price changes in the hedged transactions.  Derivative instruments are also entered into for economic hedging purposes.  While economic hedges may 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.

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 13 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.

For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses 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, 2017, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

		Quantity
Commodity	Unit of Measure	December 31, 2017	December 31, 2016
Power	GWh	583	1,314
Gas	Billion cubic feet	240	194

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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, 2017, 2016 and 2015 (dollars in thousands):

	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2017			2016			2015
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	OCI — derivative instruments	$	(59	)	$	47		$	(615	)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	(3,519		)	(3,926		)	(5,988		)

(a) During the years ended December 31, 2017, 2016, and 2015, we had no 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 $2 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, most 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, 2017, 2016 and 2015 (dollars in thousands):

	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2017			2016		2015
Net Gain (Loss) Recognized in Income	Operating revenues	$	(1,192	)	$	771	$	574
Net Gain (Loss) Recognized in Income	Fuel and purchased power (a)	(87,991		)	25,711		(108,973		)
Total		$	(89,183	)	$	26,482	$	(108,399	)

(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

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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.

As of December 31, 2017, we no longer have derivative instruments that are designated as cash flow hedging instruments. As of December 31, 2016, the Consolidated Balance Sheets included $2 million of gross liabilities related to derivative instruments designated as cash flow 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, 2017 and 2016.  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, 2017: (dollars in thousands)	Gross  Recognized  Derivatives (a)			Amounts  Offset (b)			Net Recognized Derivatives			Other (c)			Amount  Reported on  Balance Sheet
Current assets	$	5,427		$	(3,796	)	$	1,631		$	300		$	1,931
Investments and other assets	1,292			(1,241		)	51			—			51
Total assets	6,719			(5,037		)	1,682			300			1,982
Current liabilities	(59,527		)	3,796			(55,731		)	(3,521		)	(59,252		)
Deferred credits and other	(38,411		)	1,241			(37,170		)	—			(37,170		)
Total liabilities	(97,938		)	5,037			(92,901		)	(3,521		)	(96,422		)
Total	$	(91,219	)	$	—		$	(91,219	)	$	(3,221	)	$	(94,440	)

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

(b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c) Represents cash collateral and cash 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 $3,521 and cash margin provided to counterparties of $300.

As of December 31, 2016: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset  (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	48,094		$	(28,400	)	$	19,694		$	—		$	19,694
Investments and other assets	6,704			(6,703		)	1			—			1
Total assets	54,798			(35,103		)	19,695			—			19,695
Current liabilities	(50,182		)	28,400			(21,782		)	(4,054		)	(25,836		)
Deferred credits and other	(53,941		)	6,703			(47,238		)	—			(47,238		)
Total liabilities	(104,123		)	35,103			(69,020		)	(4,054		)	(73,074		)
Total	$	(49,325	)	$	—		$	(49,325	)	$	(4,054	)	$	(53,379	)

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

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(b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c) Represents cash collateral and cash 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 $4,054.

Credit Risk and Credit Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of December 31, 2017, Pinnacle West has no counterparties with positive exposures of greater than 10% of risk management assets. 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 counterparties 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, 2017 (dollars in thousands):

	December 31, 2017
Aggregate fair value of derivative instruments in a net liability position	$	97,938
Cash collateral posted	—
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)	91,071

(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 $110 million if our debt credit ratings were to fall below investment grade.

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17.    Other Income and Other Expense

The following table provides detail of Pinnacle West's Consolidated other income and other expense for 2017, 2016 and 2015 (dollars in thousands):

	2017			2016			2015
Other income:
Interest income	$	3,497		$	884		$	493
Miscellaneous	509			17			128
Total other income	$	4,006		$	901		$	621
Other expense:
Non-operating costs	$	(11,749	)	$	(9,235	)	$	(11,292	)
Investment losses — net	(4,113		)	(1,747		)	(2,080		)
Miscellaneous	(5,677		)	(4,355		)	(4,451		)
Total other expense	$	(21,539	)	$	(15,337	)	$	(17,823	)

Other Income and Other Expense - APS

The following table provides detail of APS’s other income and other expense for 2017, 2016 and 2015 (dollars in thousands):

	2017			2016			2015
Other income:
Interest income	$	2,858		$	261		$	163
Gain on disposition of property	2,048			5,745			716
Miscellaneous	1,620			2,601			1,955
Total other income	$	6,526		$	8,607		$	2,834
Other expense:
Non-operating costs (a)	$	(12,395	)	$	(11,034	)	$	(11,648	)
Loss on disposition of property	(5,424		)	(1,246		)	(2,219		)
Miscellaneous	(5,561		)	(5,234		)	(5,152		)
Total other expense	$	(23,380	)	$	(17,514	)	$	(19,019	)

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

18.    Palo Verde Sale Leaseback Variable Interest Entities

In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities.  APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually for the period 2018 through 2023, and about $16 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

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The leases' terms give APS the ability to utilize the assets for a significant portion of the assets' economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs' economic performance. Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income of $19 million for 2017, 2016 and 2015. The increase in net income is entirely attributable to the noncontrolling interests.  Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Consolidated Balance Sheets at December 31, 2017 and December 31, 2016 include the following amounts relating to the VIEs (dollars in thousands):

	December 31, 2017		December 31, 2016
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation	$	109,645	$	113,515
Equity-Noncontrolling interests	129,040		132,290

Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders.  These assets are reported on our consolidated financial statements.

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 and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $293 million beginning in 2018, and up to $456 million over the lease extension term.

For regulatory ratemaking purposes, the agreements 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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19.    Investments

We have investments in debt and equity securities held in Nuclear Decommissioning Trusts and Coal Reclamation Escrow Accounts. These investments are classified as available for sale securities, and as a result we record the investments at their fair value on our Consolidated Balance Sheets. See Note 13 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning and coal reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities. The costs of securities sold are determined on the basis of specific identification.

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.  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, 2017 and December 31, 2016 (dollars in thousands):

	December 31, 2017							December 31, 2016
	Fair Value		Total  Unrealized  Gains		Total  Unrealized  Losses			Fair Value		Total  Unrealized  Gains		Total  Unrealized  Losses
Equity securities	$	417,390	$	248,623	$	—		$	353,261	$	188,091	$	—
Fixed income securities	446,277		11,537		(2,996		)	425,530		9,820		(4,962		)
Cash and cash equivalents	7,224		—		—			—		—		—
Net receivables (a)	109		—		—			795		—		—
Total	$	871,000	$	260,160	$	(2,996	)	$	779,586	$	197,911	$	(4,962	)

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

The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in thousands):

	Nuclear Decommissioning
	Year Ended December 31,
	2017			2016			2015
Realized gains	$	21,813		$	11,213		$	5,189
Realized losses	(13,146		)	(10,106		)	(6,225		)
Proceeds from the sale of securities (a)	542,246			633,410			478,813

(a) Proceeds are reinvested in the trust/account.

Coal Reclamation Escrow Accounts

APS has investments restricted for coal mine reclamation funding related to Four Corners. As of December 31, 2017, APS’s coal reclamation escrow accounts are invested in fixed income securities with a fair value of $30 million. The realized and unrealized gains and losses relating to these fixed income securities was

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immaterial for the twelve months ended December 31, 2017 and December 31, 2016. The proceeds from the sale of securities for the twelve months endedDecember 31, 2017 was $4 million. There were no proceeds from the sale of securities for the twelve months endedDecember 31, 2016. The proceeds are reinvested in the escrow accounts. 

4CA also has investments restricted for coal mine reclamation funding relating to Four Corners invested in fixed income securities. The 4CA fixed income investments have a fair value of $2 million as of December 31, 2017. The realized and unrealized gains and losses relating to these fixed income securities was immaterial for the twelve months endedDecember 31, 2017 and 2016.

Fixed Income Securities Contractual Maturities

The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2017 is as follows (dollars in thousands):

	Nuclear Decommissioning Trusts		Escrow Accounts		Total
Less than one year	$	24,668	$	455	$	25,123
1 year – 5 years	100,289		2,494		102,783
5 years – 10 years	129,239		8,615		137,854
Greater than 10 years	192,081		20,453		212,534
Total	$	446,277	$	32,017	$	478,294

20.    Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2017 and 2016 (dollars in thousands): 

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2015	$	(37,593	)		$	(7,155	)		$	(44,748	)
OCI (loss) before reclassifications	(4,509		)		(538		)		(5,047		)
Amounts reclassified from accumulated other comprehensive loss	3,032			(a)	2,941			(b)	5,973
Balance December 31, 2016	(39,070		)		(4,752		)		(43,822		)
OCI (loss) before reclassifications	(6,438		)		(35		)		(6,473		)
Amounts reclassified from accumulated other comprehensive loss	3,068			(a)	2,225			(b)	5,293
Balance December 31, 2017	$	(42,440	)		$	(2,562	)		$	(45,002	)

(a) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.

(b) 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 16.

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Changes in Accumulated Other Comprehensive Loss - APS

The following table shows the changes in APS's accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2017 and 2016 (dollars in thousands): 

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2015	$	(19,942	)		$	(7,155	)		$	(27,097	)
OCI (loss) before reclassifications	(3,821		)		(538		)		(4,359		)
Amounts reclassified from accumulated other comprehensive loss	3,092			(a)	2,941			(b)	6,033
Balance December 31, 2016	(20,671		)		(4,752		)		(25,423		)
OCI (loss) before reclassifications	(6,884		)		(35		)		(6,919		)
Amounts reclassified from accumulated other comprehensive loss	3,134			(a)	2,225			(b)	5,359
Balance December 31, 2017	$	(24,421	)		$	(2,562	)		$	(26,983	)

(a) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.

(b) 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 16.

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CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)

	Year Ended December 31,
	2017			2016			2015
Operating revenues	$	119		$	370		$	550
Operating expenses	24,298			26,424			12,733
Operating loss	(24,179		)	(26,054		)	(12,183		)
Other
Equity in earnings of subsidiaries	507,495			462,027			446,508
Other expense	(2,715		)	(1,771		)	(3,302		)
Total	504,780			460,256			443,206
Interest expense	5,633			3,151			2,672
Income before income taxes	474,968			431,051			428,351
Income tax benefit	(13,488		)	(10,983		)	(8,906		)
Net income attributable to common shareholders	488,456			442,034			437,257
Other comprehensive income (loss) — attributable to common shareholders	(1,180		)	926			23,393
Total comprehensive income — attributable to common shareholders	$	487,276		$	442,960		$	460,650

See Combined Notes to Consolidated Financial Statements.

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CONDENSED BALANCE SHEETS

(dollars in thousands)

	December 31,
	2017			2016
ASSETS
Current assets
Cash and cash equivalents	$	41		$	41
Accounts receivable	93,554			81,751
Income tax receivable	19,124			—
Other current assets	267			340
Total current assets	112,986			82,132
Investments and other assets
Investments in subsidiaries	5,465,137			5,084,035
Deferred income taxes	54,352			53,805
Other assets	44,613			38,500
Total investments and other assets	5,564,102			5,176,340
Total Assets	$	5,677,088		$	5,258,472
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	7,638		$	5,421
Accrued taxes	8,927			12,050
Common dividends payable	77,667			72,926
Short-term borrowings	95,400			41,700
Current maturities of long-term debt	—			125,000
Other current liabilities	17,417			31,182
Total current liabilities	207,049			288,279
Long-term debt less current maturities	298,421			—
Pension liabilities	20,758			21,057
Other	15,130			13,224
Total deferred credits and other	35,888			34,281
Common stock equity
Common stock	2,609,181			2,591,897
Accumulated other comprehensive loss	(45,002		)	(43,822		)
Retained earnings	2,442,511			2,255,547
Total Pinnacle West Shareholders’ equity	5,006,690			4,803,622
Noncontrolling interests	129,040			132,290
Total Equity	5,135,730			4,935,912
Total Liabilities and Equity	$	5,677,088		$	5,258,472

See Combined Notes to Consolidated Financial Statements.

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CONDENSED STATEMENTS OF CASH FLOWS

(dollars in thousands)

	Year Ended December 31,
	2017			2016			2015
Cash flows from operating activities
Net income	$	488,456		$	442,034		$	437,257
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries — net	(507,495		)	(462,027		)	(446,508		)
Depreciation and amortization	76			85			92
Deferred income taxes	(264		)	(12,402		)	12,967
Accounts receivable	(2,106		)	15,823			11,336
Accounts payable	(11,162		)	10,402			637
Accrued taxes and income tax receivables — net	(22,247		)	20,041			(12,882		)
Dividends received from subsidiaries	296,800			239,300			266,900
Other	15,092			5,514			(6,995		)
Net cash flow provided by operating activities	257,150			258,770			262,804
Cash flows from investing activities
Construction work in progress	—			(18,457		)	(3,462		)
Investments in subsidiaries	(178,027		)	(19,242		)	(3,491		)
Repayments of loans from subsidiaries	2,987			1,026			157
Advances of loans to subsidiaries	(6,388		)	(2,092		)	(1,010		)
Net cash flow used for investing activities	(181,428		)	(38,765		)	(7,806		)
Cash flows from financing activities
Issuance of long-term debt	298,761			—			—
Short-term debt borrowings under revolving credit facility	58,000			40,000			—
Short-term debt repayments under revolving credit facility	(32,000		)	—			—
Commercial paper - net	27,700			1,700			—
Dividends paid on common stock	(289,793		)	(274,229		)	(260,027		)
Repayment of long-term debt	(125,000		)	—			—
Common stock equity issuance - net of purchases	(13,390		)	(4,867		)	19,373
Net cash flow used for financing activities	(75,722		)	(237,396		)	(240,654		)
Net increase (decrease) in cash and cash equivalents	—			(17,391		)	14,344
Cash and cash equivalents at beginning of year	41			17,432			3,088
Cash and cash equivalents at end of year	$	41		$	41		$	17,432

     See Combined Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

NOTES TO FINANCIAL STATEMENTS OF HOLDING COMPANY

The Combined Notes to Consolidated Financial Statements in Part II, Item 8 should be read in conjunction with the Pinnacle West Capital Corporation Holding Company Financial Statements.

The Pinnacle West Capital Corporation Holding Company Financial Statements have been prepared to present the financial position, results of operations and cash flows of Pinnacle West Capital Corporation on a stand-alone basis as a holding company. Investments in subsidiaries are accounted for using the equity method.

176

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:
2017	$	3,037	$	6,836	$	—	$	7,360	$	2,513
2016	3,125		4,025		—		4,113		3,037
2015	3,094		4,073		—		4,042		3,125

177

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:
2017	$	3,037	$	6,836	$	—	$	7,360	$	2,513
2016	3,125		4,025		—		4,113		3,037
2015	3,094		4,073		—		4,042		3,125

178

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, 2017.  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, 2017.  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)” in Item 8 of this report and “Management’s Report on Internal Control over Financial Reporting (Arizona Public Service Company)” in Item 8 of this report.

(c)Attestation Reports of the Registered Public Accounting Firm

Reference is made to “Report of Independent Registered Public Accounting Firm” in Item 8 of this report and “Report of Independent Registered Public Accounting Firm” in Item 8 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, 2017 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’s internal control over financial reporting.

179

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 16, 2018 (the “2018 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 2018 Proxy Statement.

180

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 2018 Proxy Statement.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table sets forth information as of December 31, 2017 with respect to the 2012 Plan and the 2007 Plan, under which our equity securities are outstanding or currently authorized for issuance.

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	1,364,170	—	2,172,786
Equity compensation plans not approved by security holders		—
Total	1,364,170	—	2,172,786

(a) This amount includes 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 the 2007 Plan.  However, if an award under the 2012 Plan is forfeited, terminated or canceled 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.

181

Equity Compensation Plans Approved By Security Holders

Amounts in column (a) in the table above include shares subject to awards outstanding under two equity compensation plans that were previously approved by our shareholders:  (a) 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 (b) the 2012 Plan, as amended, which was approved by our shareholders at our 2012 annual meeting of shareholders and the first amendment to the 2012 Plan was approved by our shareholders at our 2017 annual meeting of shareholders.  See Note 15 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 2018 Proxy Statement.

182

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 2018 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	2017		2016
Audit Fees (1)	$	2,212,137	$	2,137,925
Audit-Related Fees (2)	292,467		283,070

(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 and related services that are reasonably related to the performance of the audit or review of the financial statements and are not included in Audit Fees reported above, which primarily consist of fees for employee benefit plan audits performed in 2017 and 2016.

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 2017 were pre-approved by the Audit Committee or the Chair consistent with the pre-approval policy.

183

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	8/7/2008
3.2	Pinnacle West	Pinnacle West Capital Corporation Bylaws, amended as of February 22, 2017	3.1 to Pinnacle West/APS February 28, 2017 Form 8-K Report, File Nos. 1-8962 and 1-4473	2/28/2017
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	9/29/1993
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	5/22/2012
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	2/20/2009
4.1	Pinnacle West	Specimen Certificate of Pinnacle West Capital Corporation Common Stock, no par value	4.1 to Pinnacle West June 20, 2017 Form 8-K Report, File No. 1-8962	6/20/2017
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	1/11/1995
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	1/11/1995
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	11/22/1996

184

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed
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	11/22/1996
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	4/9/1997
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	5/15/2003
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	12/21/2000
4.4a	Pinnacle West	Third Supplemental Indenture dated as of November 30, 2017	4.1 to Pinnacle West November 30, 2017 Form 8-K Report, File No. 1-8962	11/30/2017
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	12/21/2000
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	1/16/1998
4.6a	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	5/9/2003
4.6b	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	6/28/2004
4.6c	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	8/22/2005
4.6d	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	8/3/2006
4.6e	Pinnacle West APS	Eleventh Supplemental Indenture dated as of February 26, 2009	4.6e to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473	2/20/2015
4.6f	Pinnacle West APS	Twelfth Supplemental Indenture dated as of August 25, 2011	4.6f to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473	2/20/2015
4.6g	Pinnacle West APS	Thirteenth Supplemental Indenture dated as of January 13, 2012	4.6g to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473	2/20/2015

185

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed
4.6h	Pinnacle West APS	Fourteenth Supplemental Indenture dated as of January 10, 2014	4.6h to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473	2/20/2015
4.6i	Pinnacle West APS	Fifteenth Supplemental Indenture dated as of June 18, 2014	4.6i to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473	2/20/2015
4.6j	Pinnacle West APS	Sixteenth Supplemental Indenture dated as of January 12, 2015	4.6j to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473	2/20/2015
4.6k	Pinnacle West APS	Seventeenth Supplemental Indenture dated as of May 19, 2015	4.1 to Pinnacle West/APS May 14, 2015 Form 8-K Report, File Nos. 1-8962 and 1-4473	5/19/2015
4.6l	Pinnacle West APS	Eighteenth Supplemental Indenture dated as of November 6, 2015	4.1 to Pinnacle West/APS November 3, 2015 Form 8-K Report, File Nos. 1-8962 and 1-4473	11/6/2015
4.6m	Pinnacle West APS	Nineteenth Supplemental Indenture dated as of May 6, 2016	4.1 to Pinnacle West/APS May 3, 2016 Form 8-K Report, File Nos. 1-8962 and 1-4473	5/6/2016
4.6n	Pinnacle West APS	Twentieth Supplemental Indenture dated as of September 20, 2016	4.1 to Pinnacle West/APS September 15, 2016 Form 8-K Report, File Nos. 1-8962 and 1-4473	9/20/2016
4.6o	Pinnacle West APS	Twenty-First Supplemental Indenture dated as of September 11, 2017	4.1 to Pinnacle West/APS September 11, 2017 Form 8-K Report, File Nos. 1-8962 and 1-4473	9/11/2017
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	8/9/2004
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	11/25/2008
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	3/30/1988
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	3/30/1994
10.1.1	Pinnacle West APS	Two separate Decommissioning Trust Agreements (relating to PVGS 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	11/14/1991
10.1.1a	Pinnacle West APS	Amendment No. 1 to Decommissioning Trust Agreement (PVGS Unit 1), dated as of December 1, 1994	10.1 to APS’s 1994 Form 10-K Report, File No. 1-4473	3/30/1995

186

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 (PVGS Unit 3), dated as of December 1, 1994	10.2 to APS’s 1994 Form 10-K Report, File No. 1-4473	3/30/1995
10.1.1c	Pinnacle West APS	Amendment No. 2 to APS Decommissioning Trust Agreement (PVGS Unit 1) dated as of July 1, 1991	10.4 to APS’s 1996 Form 10-K Report , File No. 1-4473	3/28/1997
10.1.1d	Pinnacle West APS	Amendment No. 2 to APS Decommissioning Trust Agreement (PVGS Unit 3) dated as of July 1, 1991	10.6 to APS’s 1996 Form 10-K Report, File No. 1-4473	3/28/1997
10.1.1e	Pinnacle West APS	Amendment No. 3 to the Decommissioning Trust Agreement (PVGS 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	5/15/2002
10.1.1f	Pinnacle West APS	Amendment No. 3 to the Decommissioning Trust Agreement (PVGS Unit 3), dated as of March 18, 2002	10.4 to Pinnacle West’s March 2002 Form 10-Q Report, File No. 1-8962	5/15/2002
10.1.1g	Pinnacle West APS	Amendment No. 4 to the Decommissioning Trust Agreement (PVGS Unit 1), dated as of December 19, 2003	10.3 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	3/15/2004
10.1.1h	Pinnacle West APS	Amendment No. 4 to the Decommissioning Trust Agreement (PVGS Unit 3), dated as of December 19, 2003	10.5 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	3/15/2004
10.1.1i	Pinnacle West APS	Amendment No. 5 to the Decommissioning Trust Agreement (PVGS 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	5/9/2007
10.1.1j	Pinnacle West APS	Amendment No. 5 to the Decommissioning Trust Agreement (PVGS 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	5/9/2007
10.1.2	Pinnacle West APS	Amended and Restated Decommissioning Trust Agreement (PVGS 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 PVGS Unit 2	10.1 to Pinnacle West’s 1991 Form 10-K Report, File No. 1-8962	3/26/1992
10.1.2a	Pinnacle West APS	First Amendment to Amended and Restated Decommissioning Trust Agreement (PVGS Unit 2), dated as of November 1, 1992	10.2 to APS’s 1992 Form 10-K Report, File No. 1-4473	3/30/1993

187

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 (PVGS Unit 2), dated as of November 1, 1994	10.3 to APS’s 1994 Form 10-K Report, File No. 1-4473	3/30/1995
10.1.2c	Pinnacle West APS	Amendment No. 3 to Amended and Restated Decommissioning Trust Agreement (PVGS Unit 2), dated as of June 20, 1996	10.1 to APS’s June 30, 1996 Form 10-Q Report, File No. 1-4473	8/9/1996
10.1.2d	Pinnacle West APS	Amendment No. 4 to Amended and Restated Decommissioning Trust Agreement (PVGS Unit 2) dated as of December 16, 1996	APS 10.5 to APS’s 1996 Form 10-K Report, File No. 1-4473	3/28/1997
10.1.2e	Pinnacle West APS	Amendment No. 5 to the Amended and Restated Decommissioning Trust Agreement (PVGS 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	5/15/2002
10.1.2f	Pinnacle West APS	Amendment No. 6 to the Amended and Restated Decommissioning Trust Agreement (PVGS 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	5/15/2002
10.1.2g	Pinnacle West APS	Amendment No. 7 to the Amended and Restated Decommissioning Trust Agreement (PVGS Unit 2), dated as of December 19, 2003	10.4 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	3/15/2004
10.1.2h	Pinnacle West APS	Amendment No. 8 to the Amended and Restated Decommissioning Trust Agreement (PVGS Unit 2), dated as of April 1, 2007	10.1.2h to Pinnacle West’s 2007 Form 10-K Report, File No. 1-8962	2/27/2008
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	3/8/1989
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	3/30/1994
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	11/10/1994
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	3/28/1997
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	3/14/2001
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	8/13/1986

188

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed
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	3/30/1994
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	11/10/1994
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	3/30/2000
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	3/30/2000
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	3/30/2000
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	3/29/1996
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	3/30/2000
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	3/30/2000
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	5/15/2003
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	10.64b to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3/13/2006

189

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed
10.2.5b	Pinnacle West APS	Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates (as amended and restated effective January 1, 2016)	10.2.5 to Pinnacle West/APS 2015 Form 10-K Report, File Nos. 1-8962 and 1-4473	2/19/2016
10.3.1b	Pinnacle West APS	Pinnacle West Capital Corporation Supplemental 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	3/15/2004
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	3/13/2006
10.3.2b	Pinnacle West APS	Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan of 2005 (as amended and restated effective January 1, 2016)	10.3.2 to Pinnacle West/APS 2015 Form 10-K Report, File Nos. 1-8962 and 1-4473	2/19/2016
10.3.2ab	Pinnacle West APS	First Amendment to the Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan of 2005 (as amended and restated effective January 1, 2016)	10.3.2a to Pinnacle West/APS 2016 Form 10-K Report, File Nos. 1-8962 and 1-4473	2/24/2017
10.3.2bb	Pinnacle West APS	Second Amendment to the Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan of 2005 (as amended and restated effective January 1, 2016)
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	2/28/2007
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	8/7/2008
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	8/7/2008
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	2/20/2009
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	2/19/2010
10.4.6b	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	5/6/2010
10.4.7b	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	8/2/2012
10.4.8b	APS	Description of 2016 Palo Verde Specific Compensation Opportunity for Randall K. Edington	Pinnacle West/APS December 15, 2015 Form 8-K Report, File No. 1-4473	12/21/2015

190

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed
10.4.9b	APS	Supplemental Agreement dated December 14, 2014 between APS and Randall K. Edington	10.4.9 to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473	2/20/2015
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	10.77bd to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3/13/2006
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	11/6/2007
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	11/6/2007
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	2/19/2010
10.5.4bd	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	2/22/2013
10.6.1b	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	4/20/2007
10.6.1ab	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	4/20/2007
10.6.1bbd	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	5/5/2009
10.6.1cbd	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	8/3/2010
10.6.1dbd	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	8/3/2010
10.6.1ebd	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	4/29/2011
10.6.1fbd	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	4/29/2011

191

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed
10.6.1gbd	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	4/29/2011
10.6.2b	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	11/6/2007
10.6.3b	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	8/7/2008
10.6.4bd	Pinnacle West APS	Summary of 2018 CEO Variable Incentive Plan and Officer Variable Incentive Plan
10.6.5	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	12/26/2012
10.6.6b	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	3/29/2012
10.6.6abd	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	5/3/2012
10.6.6bbd	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	5/3/2012
10.6.6cbd	Pinnacle West	Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan	10.6.8c to Pinnacle West/APS 2013 Form 10-K Report, File Nos. 1-8962 and 1-4473	2/21/2014
10.6.6dbd	Pinnacle West	Form of Restricted Stock Unit Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan	10.6.8d to Pinnacle West/APS 2013 Form 10-K Report, File Nos. 1-8962 and 1-4473	2/21/2014
10.6.6ebd	Pinnacle West	Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan	10.6.6e to Pinnacle West/APS 2015 Form 10-K Report, File Nos. 1-8962 and 1-4473	2/19/2016
10.6.6fbd	Pinnacle West	Form of Restricted Stock Unit Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan	10.6.6f to Pinnacle West/APS 2016 Form 10-K Report, File Nos. 1-8962 and 1-4473	2/24/2017
10.6.6gbd	Pinnacle West	Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan	10.6.6g to Pinnacle West/APS 2016 Form 10-K Report, File Nos. 1-8962 and 1-4473	2/24/2017
10.6.6hbd	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	5/3/2012

192

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed
10.6.6ibd	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	5/3/2012
10.6.6jbd	Pinnacle West	Performance Cash Award Agreement, dated May 10, 2017, between Pinnacle West and Donald E. Brandt	10.1 to Pinnacle West/APS June 30, 2017 Form 10-Q Report, File Nos. 1-8962 and 1-4473	5/2/2017
10.6.6kbd	Pinnacle West	First Amendment to the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan	Appendix A to the Proxy Statement for Pinnacle West’s 2017 Annual Meeting of Shareholders, File No. 1-8962	3/31/2017
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	9/1/1977
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	9/1/1977
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. 1-89	7/25/1985
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	4/29/2011
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	4/29/2011
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	9/1/1977
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	7/25/1985
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	9/1/1977
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	7/25/1985
10.7.4a	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	3/14/2001
10.7.4b	Pinnacle West APS	Four Corners Project Co-Tenancy Agreement Amendment No. 7, dated December 30, 2013, among APS, El Paso Electric Company, Public Service Company of New Mexico, SRP, SCE, and Tucson Electric Power Company	10.3 to Pinnacle West/APS March 31, 2014 Form 10-Q Report, File Nos. 1-8962 and 1-4473	5/2/2014

193

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed
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	3/23/1970
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	3/23/1970
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	3/16/1971
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	3/13/2006
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	3/13/2006
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	3/8/1989
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	5/15/1991
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	8/14/2000

194

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	2/18/2011
10.9.1d	Pinnacle West APS	Amendment No. 16, dated April 28, 2014, 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	10.2 to Pinnacle West/APS March 31, 2014 Form 10-Q Report, File Nos. 1-8962 and 1-4473	5/2/2014
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	8/8/1991
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	8/8/1991
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	3/29/1996
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	3/29/1996
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	3/29/1996
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	3/29/1996
10.11.1	Pinnacle West	Term Loan Agreement dated as of December 31, 2014 among Pinnacle West, as Borrower,  JPMorgan Chase Bank, N.A., as Agent, U.S. Bank Association, as Syndication Agent, TD Bank, N.A., The Bank of Nova Scotia and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Co-Documentation Agents, and such institutions compromising the lenders party thereto	10.11.2 to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473	2/20/2015

195

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed
10.11.2	Pinnacle West	Five-Year Credit Agreement dated as of May 13, 2016, among Pinnacle West, as Borrower, Barclays Bank PLC, as Agent and Issuing Bank, and the lenders and other parties thereto	10.1 to Pinnacle West/APS June 30, 2016 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8/2/2016
10.11.2a	Pinnacle West	Amendment No. 1 to Five-Year Credit Agreement dated as of May 13, 2016, among Pinnacle West, as Borrower, Barclays Bank PLC, as Agent and Issuing Bank, and the lenders and other parties thereto	10.11.2a to Pinnacle West/APS June 30, 2017 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8/3/2017
10.11.3	Pinnacle West	364-day Credit Agreement dated as of August 31, 2016, among Pinnacle West, as Borrower, The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Agent and Issuing Bank, and the lenders and other parties thereto	10.1 to Pinnacle West/APS September 30, 2016 Form 10-Q Report, File Nos. 1-8962 and 1-4473	11/3/2016
10.11.3a	Pinnacle West	Amendment No. 1 to 364-day Credit Agreement dated as of August 31, 2016, among Pinnacle West, as Borrower, The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Agent and Issuing Bank, and the lenders and other parties thereto	10.11.3a to Pinnacle West/APS June 30, 2017 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8/3/2017
10.11.4	Pinnacle West APS	Five-Year Credit Agreement dated as of June 29, 2017 among APS, as Borrower, Barclays Bank PLC, as Agent and Issuing Bank, and the lenders and other parties thereto	10.2 to Pinnacle West/APS June 30, 2017 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8/3/2017
10.11.5	Pinnacle West APS	Term Loan Agreement dated as of June 26, 2015 among APS, as Borrower, Toronto Dominion (Texas) LLC, as Agent, Citibank, N.A., as Syndication Agent, and such institutions compromising the lenders party thereto	10.1 to Pinnacle West/APS June 30, 2015 Form 10-Q Report, File Nos. 1-8962 and 1-4473	7/30/2015
10.11.6	Pinnacle West APS	Term Loan Agreement dated as of April 22, 2016 among APS, as Borrower, Toronto Dominion (Texas) LLC, as Agent and such institutions compromising the lenders party thereto	10.1 to Pinnacle West/APS March 31, 2016 Form 10-Q Report, File Nos. 1-8962 and 1-4473	4/29/2016
10.11.7	Pinnacle West APS	Five-Year Credit Agreement dated as of May 13, 2016, among APS, as Borrower, Barclays Bank PLC, as Agent and Issuing Bank, and the lenders and other parties thereto	10.2 to Pinnacle West/APS June 30, 2016 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8/2/2016
10.11.7a	Pinnacle West APS	Amendment No. 1 to Five-Year Credit Agreement dated as of May 13, 2016, among APS, as Borrower, Barclays Bank PLC, as Agent and Issuing Bank, and the lenders and other parties thereto	10.11.7a to Pinnacle West/APS June 30, 2017 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8/3/2017

196

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	10/24/1986
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	12/4/1986
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	3/8/1989
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	3/30/1993
10.12.1dc	Pinnacle West APS	Amendment No. 4, dated as of September 30, 2015, 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 Owner Trustee under a Trust Agreement with Emerson Finance LLC, as Lessor, and APS, as Lessee	10.2 to Pinnacle West/APS September 30, 2015 Form 10-Q Report, File Nos. 1-8962 and 1-4473	10/30/2015
10.12.1ec	Pinnacle West APS	Amendment No. 3, dated as of September 30, 2015, 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 Owner Trustee under a Trust Agreement with Security Pacific Capital Leasing Corporation, as Lessor, and APS, as Lessee	10.3 to Pinnacle West/APS September 30, 2015 Form 10-Q Report, File Nos. 1-8962 and 1-4473	10/30/2015

197

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed
10.12.2	Pinnacle West APS	Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee	10.1 to APS’s November 18, 1986 Form 8-K Report, File No. 1-4473	1/20/1987
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	8/24/1987
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	3/30/1993
10.12.2c	Pinnacle West APS	Amendment No. 3, dated July 10, 2014, 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	10.2 to Pinnacle West/APS June 30, 2014 Form 10-Q Report, File Nos. 1-8962 and 1-4473	7/31/2014
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	3/16/2005
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	3/16/2005
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	3/16/2005
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	3/16/2005

198

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed
10.13.5	Pinnacle West APS	Municipal Effluent Purchase and Sale Agreement dated April 29, 2010, by and between City of Phoenix, City of Mesa, City of Tempe, City of Scottsdale, City of Glendale, APS and SRP	10.1 to Pinnacle West/APS March 31, 2010 Form 10-Q Report, File Nos. 1-8962 and 1-4473	5/6/2010
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	3/13/1985
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	5/15/1998
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	5/15/1998
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	5/15/1998
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	6/26/1998
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	11/8/2010
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	2/24/2012
10.18	Pinnacle West APS	Proposed Settlement Agreement dated March 27, 2017 by and among APS and certain parties to its retail rate case (approved by ACC Order No. 76295)	10.1 to Pinnacle West/APS March 31, 2017 Form 10-Q Report, File Nos. 1-8962 and 1-4473	5/2/2017
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
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

199

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed
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
99.1	Pinnacle West APS	Collateral Trust Indenture among PVGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee	4.2 to APS’s 1992 Form 10-K Report, File No. 1-4473	3/30/1993
99.1a	Pinnacle West APS	Supplemental Indenture to Collateral Trust Indenture among PVGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee	4.3 to APS’s 1992 Form 10-K Report, File No. 1-4473	3/30/1993
99.2c	Pinnacle West APS	Participation Agreement, dated as of August 1, 1986, among PVGS 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	11/9/1992
99.2ac	Pinnacle West APS	Amendment No. 1 dated as of November 1, 1986, to Participation Agreement, dated as of August 1, 1986, among PVGS 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	12/4/1986

200

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Date Filed
99.2bc	Pinnacle West APS	Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of August 1, 1986, among PVGS Funding Corp., Inc., PVGS 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	3/30/1993
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	10/24/1986
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	12/4/1986
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	3/30/1993
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	10/24/1986
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	12/4/1986

201

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	3/30/1993
99.5	Pinnacle West APS	Participation Agreement, dated as of December 15, 1986, among PVGS 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	11/9/1992
99.5a	Pinnacle West APS	Amendment No. 1, dated as of August 1, 1987, to Participation Agreement, dated as of December 15, 1986, among PVGS 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	8/10/1987
99.5b	Pinnacle West APS	Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of December 15, 1986, among PVGS Funding Corp., Inc., PVGS 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	3/30/1993
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	1/20/1987
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	8/24/1987

202

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	3/30/1993
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	1/20/1987
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	3/30/1993
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	3/30/1993
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	8/10/1987
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	11/15/1999
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	8/9/2005
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
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.

203

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.

204

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 23, 2018	/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 Jeffrey B. Guldner, 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 23, 2018
(Donald E. Brandt, Chairman	and Director
of the Board of Directors, President
and Chief Executive Officer)
/s/ James R. Hatfield	Principal Financial Officer	February 23, 2018
(James R. Hatfield,
Executive Vice President and
Chief Financial Officer)
/s/ Denise R. Danner	Principal Accounting Officer	February 23, 2018
(Denise R. Danner,
Vice President, Controller and
Chief Accounting Officer)

205

/s/ Denis A. Cortese	Director	February 23, 2018
(Denis A. Cortese, M.D.)
/s/ Richard P. Fox	Director	February 23, 2018
(Richard P. Fox)
/s/ Michael L. Gallagher	Director	February 23, 2018
(Michael L. Gallagher)
/s/ Roy A. Herberger, Jr., Ph.D.	Director	February 23, 2018
(Roy A. Herberger, Jr., Ph.D.)
/s/ Dale E. Klein, Ph.D.	Director	February 23, 2018
(Dale E. Klein, Ph.D.)
/s/ Humberto S. Lopez	Director	February 23, 2018
(Humberto S. Lopez)
/s/ Kathryn L. Munro	Director	February 23, 2018
(Kathryn L. Munro)
/s/ Bruce J. Nordstrom	Director	February 23, 2018
(Bruce J. Nordstrom)
/s/ Paula J. Sims	Director	February 23, 2018
(Paula J. Sims)
/s/ David P. Wagener	Director	February 23, 2018
(David P. Wagener)

206

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 23, 2018	/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 Jeffrey B. Guldner, 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 23, 2018
(Donald E. Brandt, Chairman	and Director
of the Board of Directors, President and
Chief Executive Officer)
/s/ James R. Hatfield	Principal Financial Officer	February 23, 2018
(James R. Hatfield,
Executive Vice President and
Chief Financial Officer)
/s/ Denise R. Danner	Principal Accounting Officer	February 23, 2018
(Denise R. Danner,
Vice President, Controller and
Chief Accounting Officer)

207

/s/ Denis A. Cortese	Director	February 23, 2018
(Denis A. Cortese, M.D.)
/s/ Richard P. Fox	Director	February 23, 2018
(Richard P. Fox)
/s/ Michael L. Gallagher	Director	February 23, 2018
(Michael L. Gallagher)
/s/ Roy A. Herberger, Jr., Ph.D.	Director	February 23, 2018
(Roy A. Herberger, Jr., Ph.D.)
/s/ Dale E. Klein, Ph.D.	Director	February 23, 2018
(Dale E. Klein, Ph.D.)
/s/ Humberto S. Lopez	Director	February 23, 2018
(Humberto S. Lopez)
/s/ Kathryn L. Munro	Director	February 23, 2018
(Kathryn L. Munro)
/s/ Bruce J. Nordstrom	Director	February 23, 2018
(Bruce J. Nordstrom)
/s/ Paula J. Sims	Director	February 23, 2018
(Paula J. Sims)
/s/ David P. Wagener	Director	February 23, 2018
(David P. Wagener)

208

EX-10.3.2B

Exhibit 10.3.2b

SECOND AMENDMENT TO THE

PINNACLE WEST CAPITAL CORPORATION

SUPPLEMENTAL EXCESS BENEFIT RETIREMENT PLAN OF 2005

Effective as of January 1, 2005, Pinnacle West Capital Corporation (the “Company”) adopted the Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan of 2005 (the “Plan”). Effective as of January 1, 2016, the Company amended and restated the Plan. The amended and restated Plan has been amended on one prior occasion. By this instrument, the Company amends the Plan to (1) clarify the definitions of “compensation” and “spouse,” and (2) adjust the forms of benefit available to certain participants.

1.    Unless otherwise provided, this Second Amendment shall be effective as of the date set forth below.

2.    This Second Amendment shall amend only those sections set forth herein and those sections not amended hereby shall remain in full force and effect. Notwithstanding the foregoing, this Second Amendment shall supersede the provisions of the Plan to the extent those provisions are inconsistent with the provisions and the intent of this Second Amendment.

3.    Section 4(a)(4) of the Plan is hereby amended and restated in its entirety to read as follows:

(4)    Compensation. For purposes of this Section 4(a), Compensation and Monthly Compensation shall be determined without regard to the limitation set forth in Section 401(a)(17) of the Code. Compensation and Monthly Compensation shall be increased by any amounts deferred by the participant under any deferred compensation plan for employees maintained by the Company or by an Affiliate and by any cash payments made to the participant pursuant to “year-end” bonus or incentive plans maintained by the Company or by an Affiliate, even if such cash payments are made to the participant after the participant has terminated his or her employment with the Company or an Affiliate and after the participant has commenced receiving benefits under this Plan. Bonus or incentive payments made in a form other than cash, bonus or

1

Exhibit 10.3.2b

incentive payments which are not “year-end” bonus or incentive payments, bonus or incentive payments under individual agreements between the Company or an Affiliate and a participant, and large asset bonus plan payments shall not be taken into account as Compensation and Monthly Compensation for purposes of this Plan unless the Company’s President or Chief Executive Officer determines, in his or her discretion, that such bonus or incentive payment shall be taken into account as Compensation and Monthly Compensation under this Plan. Subject to the foregoing, (a) eligible bonuses and incentive payments (including eligible bonuses and incentive payments paid after termination) shall be taken into account as Compensation and Monthly Compensation in the year in which such amounts are paid rather than in the year in which they are earned, provided that the Company’s President or Chief Executive Officer shall have the authority to determine, in his or her discretion, that such bonus or incentive payment shall be taken into account in the year in which such amounts are earned rather than in the year in which they are paid, (b) Retention Unit Awards granted in a calendar month which become vested shall be counted as Compensation paid and earned in such calendar month; provided, however, that if Retention Unit Awards are taken into account in determining a participant’s Average Monthly Compensation with respect to benefits described in Sections 4(a)(1) or 4(a)(2)(i), no more than two other year-end bonus or incentive payments will be taken into account in determining such Average Monthly Compensation. The Company’s President or Chief Executive Officer shall have the sole and absolute discretion to determine whether a bonus or incentive payment made to a participant constitutes Compensation or Monthly Compensation for purposes of this Section 4(a) and may differentiate among individuals in establishing the bonus or incentive payments that may be taken into account under the Plan. For purposes of this Section 4(a)(4), an “Affiliate” means a participating employer under the Retirement Plan.

4.    Article 4 of the Plan is hereby amended to add the following new Section 4(f) to follow the end of Section 4(e):

(f)    Spouse. For purposes of this Plan, references to a participant’s “spouse” shall have the same meaning as under the Retirement Plan, without regard to whether such references are capitalized. As under the Retirement Plan, an individual must be legally married to a participant for at least 365 consecutive days to be considered a “spouse” under the terms of this Plan.

2

Exhibit 10.3.2b

5.    Section 5(b) of the Plan is hereby amended and restated in its entirety to read as follows:

(b)    Spouse’s Benefit with Respect to Officer Traditional Benefits Described in Sections 4(a)(1) and 4(a)(2)(i).

(1)    General Rule. If a participant entitled to benefits under Section 4(a)(1) or Section 4(a)(2)(i) dies while still employed by the Company or an Affiliate and without electing the five-year installment option pursuant to Section 5(a)(2) or dies prior to January 1, 2019 after having elected the five-year installment option prior to January 1, 2018, the participant’s spouse shall be entitled to a one hundred percent (100%) survivor annuity. The one hundred percent (100%) survivor annuity shall provide a benefit to the participant’s surviving spouse, for the spouse’s life, equal to one hundred percent (100%) of the monthly benefit for life that the participant would have received under Section 4(a)(1) or Section 4(a)(2)(i) had he or she (i) terminated employment on the day before he or she died, (ii) survived to the day on which he or she would first be eligible to commence benefits under Section 5(a)(1), (iii) elected to retire and commence benefits under the Plan and the Retirement Plan in the form of a joint and one hundred percent (100%) survivor annuity and (iv) then died. The benefit payable to the surviving spouse pursuant to this paragraph shall commence on the first day of the month following the participant’s date of death.

If a participant entitled to benefits under Section 4(a)(1) or Section 4(a)(2)(i) dies after terminating employment with the Company and all Affiliates but before commencing benefits under the Plan and without electing the five-year installment option pursuant to Section 5(a)(2) or dies prior to January 1, 2019 after having elected the five-year installment option prior to January 1, 2018, the participant’s spouse shall be entitled to a one hundred percent (100%) survivor annuity. The one hundred percent (100%) survivor annuity payable to the surviving spouse of a participant shall provide a benefit to the participant’s surviving spouse, for the spouse’s life, equal to one hundred percent (100%) of the monthly benefit for life that the participant would have received under Section 4(a)(1) or Section 4(a)(2)(i) had he or she survived to the day on which he or she would first be eligible to commence benefits under Section 5(a)(1) and elected to retire and commence benefits under the Plan and the Retirement Plan in the form of a joint and one hundred percent (100%) survivor annuity commencing on the day determined in accordance with the next sentence. The benefit payable to the surviving spouse pursuant to this paragraph shall commence as

3

Exhibit 10.3.2b

follows: (i) upon death if at the time of such death the participant has either attained age sixty-five (65) or has both attained age fifty-five (55) and completed ten (10) Years of Service or (ii) age sixty-five (65) if at the time of such death the participant has neither attained age sixty-five (65) nor both attained age fifty-five (55) and completed ten (10) Years of Service.

(2)    Special Rule for Participants Who Elected the Five-Year Installment Option Prior to January 1, 2018. Effective as of January 1, 2019, the one hundred percent (100%) survivor annuity described by Section 5(b)(1) will no longer be available to participants entitled to benefits under Section 4(a)(1) or Section 4(a)(2)(i) who elected the five-year installment option described in Section 5(a)(2) before January 1, 2018. Instead, five installment payments shall be paid to the participant’s spouse or beneficiary, as applicable, if the participant dies while still employed by the Company or any Affiliate or dies after terminating employment with the Company and all Affiliates but before commencing benefits under the Plan. Such installment payments shall commence on the first day of the month following the participant’s date of death and the second and subsequent payments shall be made on each anniversary thereof. A participant described by this Section who wishes to retain the one hundred percent (100%) survivor annuity described by Section 5(b)(1) may file such a request with the Committee no later than December 31, 2018.

(3)    Special Rule for Participants Who Elect the Five-Year Installment Option on or after January 1, 2018. If a participant entitled to benefits under Section 4(a)(1) or Section 4(a)(2)(i) elects the five-year installment option pursuant to Section 5(a)(2) on or after January 1, 2018 and either dies while still employed by the Company or any Affiliate or dies after terminating employment with the Company and all Affiliates but before commencing benefits under the Plan, the participant’s spouse will not receive the one hundred percent (100%) survivor benefit described in Section 5(b)(1). Instead, all five installment payments shall be paid to the participant’s spouse or beneficiary, as applicable. Such installment payments shall commence on the first day of the month following the participant’s death and the second and subsequent payments shall be made on each anniversary thereof.

6.    Section 5(d)(5) of the Plan is hereby amended and restated in its entirety to read as follows:

(5)    Time and Form of Benefits Payable Upon Death.

4

Exhibit 10.3.2b

(i)    General Rule – Traditional Benefits. In the event a participant dies before the Traditional Benefits described in Section 4(b) commence, benefits shall be paid to the surviving spouse for his or her life commencing as follows: (i) upon death if at the time of such death the participant has neither attained age sixty-five (65) or has both attained age fifty-five (55) and completed ten (10) Years of Service; or (ii) age sixty-five (65) if at the time of such death the participant has neither attained age sixty-five (65) nor both attained age fifty-five (55) and completed ten (10) Years of Service.

(ii)    Special Rule for Participants Who Elected the Five-Year Installment Option Prior to January 1, 2018. Effective as of January 1, 2019, the form of benefit described by Section 5(d)(5)(i) will no longer be available to participants entitled to Traditional Benefits under Section 4(b) who elected the five-year installment option under Section 5(d)(1) prior to January 1, 2018. Instead, five installment payments shall be paid to the participant’s spouse or beneficiary, as applicable, if the participant dies while still employed by the Company or any Affiliate or dies after terminating employment with the Company and all Affiliates but before commencing benefits under the Plan. Such installment payments shall commence on the first day of the month following the participant’s date of death and the second and subsequent payments shall be made on each anniversary thereof. A participant described by this Section who wishes to retain the form of benefits described by Section 5(d)(5)(i) may file such a request with the Committee no later than December 31, 2018.

(iii)    Special Rule for Participants Who Elect the Five-Year Installment Option on or after January 1, 2018. If a participant entitled to Traditional Benefits under Section 4(b) elects the five-year installment option under Section 5(d)(1) on or after January 1, 2018 and either dies while still employed by the Company or any Affiliate or dies after terminating employment with the Company and all Affiliates but before commencing benefits under the Plan, the participant’s spouse will not receive the benefit described by Section 5(d)(5)(i). Instead, all five installment payments shall be paid to the participant’s spouse or beneficiary, as applicable. Such installment payments shall commence on the first day of the month following the participant’s date of death and the second and subsequent payments shall be made on each anniversary thereof.

(iv)    Retirement Account Balance Benefits. In the event that the participant dies before the Retirement Account

5

Exhibit 10.3.2b

Balance Benefits described in Section 4(b) commence to a participant, then such benefits shall be paid to the participant’s spouse or beneficiary, as applicable, in a lump sum upon the participant’s death.

IN WITNESS WHEREOF, Pinnacle West Capital Corporation has caused this Second Amendment to be executed on this 20th day of December, 2017.

PINNACLE WEST CAPITAL CORPORATION

By /s/ Donald E. Brandt                

Its Chairman of the Board of Directors, President

and Chief Executive Officer            

6

EX-10.6.4

Exhibit 10.6.4

Summary of 2018 Incentive Plans

On December 19, 2017, the Human Resources Committee (the “Committee”) of the Pinnacle West Capital Corporation (“Pinnacle West” or the “Company”) Board of Directors (the “Board”) approved the Pinnacle West 2018 CEO 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 20, 2017, the Board, acting on the recommendation of the Committee, approved the APS 2018 Annual Incentive Award Plan (the “APS Plan”), which includes an incentive award opportunity for Mark A. Schiavoni, Executive Vice President and Chief Operating Officer of APS, James R. Hatfield, Executive Vice President and Chief Financial Officer of Pinnacle West and APS and David P. Falck, Executive Vice President, Law of Pinnacle West.

No incentive payments will be awarded under the PNW Plan or the APS Plan unless Pinnacle West, with respect to Mr. Brandt, or APS, with respect to Messrs. Schiavoni, Hatfield and Falck, each achieves a specified threshold earnings level.  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 PNW Plan and may make adjustments to reflect such impacts. Earnings impacts of actions of the Arizona Corporation Commission ("ACC") in the PNW Plan year are excluded.

Mr. Brandt’s incentive award opportunity is based 62.5% on Pinnacle West’s 2018 earnings, and 37.5% on the achievement of performance goals established for all business units of APS. Mr. Brandt has an award opportunity of 50% of his base salary if the threshold earnings level is met. If Pinnacle West’s 2018 earnings exceed the threshold level, Mr. Brandt’s award opportunity increases proportionately by up to an additional 75% of his base salary. To the extent certain business unit performance goals are met, Mr. Brandt has a further award opportunity of up to 75% of base salary. The business unit performance indicators for Mr. Brandt are in the functional areas of customer service, transmission and distribution, fossil generation, corporate resources and performance of the Palo Verde Nuclear Generating Station. In no event may Mr. Brandt’s award exceed 200% of his base salary.

The award opportunities for Messrs. Schiavoni, Hatfield and Falck under the APS Plan are based on the achievement of specified 2018 APS earnings levels and specified business unit performance goals.  Messrs. Schiavoni and Hatfield each have a target award opportunity of up to 75% of their base salary, and Mr. Falck has a target award opportunity of up to 70% of his base salary.  Messrs. Schiavoni, Hatfield and Falck may earn less or more than the target amount, up to a maximum award opportunity of 150% of base salary for Messrs. Schiavoni and Hatfield and 140% for Mr. Falck, depending on the achievement of the earnings and business unit performance goals separately or in combination, and before adjustment for individual performance.  The business unit performance indicators that will be considered for Messrs. Schiavoni, Hatfield and Falck are derived from the APS critical areas of focus, as provided in its “Core” strategic framework, in the functional areas of employees, operational excellence, customer and communities, environment, and shareholder value.  The Committee may adjust targets under the APS Plan to reflect unanticipated events or unusual or nonrecurring adjustments to earnings that arise in the APS Plan year, including ACC rate-related impacts on earnings.

Any awards for Messrs. Brandt, Schiavoni, Hatfield and Falck will be subject to potential forfeiture or recovery to the extent called for by the Company’s clawback policy.

EX-12.1

Exhibit 12.1

PINNACLE WEST CAPITAL CORPORATION

RATIO OF EARNINGS TO FIXED CHARGES

(dollars in thousands)

	2017		2016		2015		2014		2013
Earnings:
Net income attributable to common shareholders	$	488,456	$	442,034	$	437,257	$	397,595	$	406,074
Income taxes	258,272		236,411		237,720		220,705		230,591
Fixed charges	228,377		213,973		202,465		208,226		206,089
Total earnings	$	975,105	$	892,418	$	877,442	$	826,526	$	842,754
Fixed Charges:
Interest expense	$	219,796	$	205,720	$	194,964	$	200,950	201,888
Estimated interest portion of annual rents	8,581		8,253		7,501		7,276		4,201
Total fixed charges	$	228,377	$	213,973	$	202,465	$	208,226	$	206,089
Ratio of Earnings to Fixed Charges (rounded down)	4.26		4.17		4.33		3.96		4.08

EX-12.2

Exhibit 12.2

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

	2017		2016		2015		2014		2013
Earnings:
Net income attributable to common shareholder	$	504,309	$	462,141	$	450,274	$	421,219	$	424,969
Income taxes	269,168		245,842		245,841		237,360		245,095
Fixed charges	222,667		210,776		199,458		204,198		202,457
Total earnings	$	996,144	$	918,759	$	895,573	$	862,777	$	872,521
Fixed Charges:
Interest charges	$	209,330	$	197,811	$	187,499	$	193,119	$	194,616
Amortization of debt discount	4,833		4,760		4,793		4,168		4,046
Estimated interest portion of annual rents	8,504		8,205		7,166		6,911		3,795
Total fixed charges	$	222,667	$	210,776	$	199,458	$	204,198	$	202,457
Ratio of Earnings to Fixed Charges (rounded down)
Earnings:	4.47		4.35		4.49		4.22		4.30

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)

	2017		2016		2015		2014		2013
Earnings:
Net income attributable to common shareholders	$	488,456	$	442,034	$	437,257	$	397,595	$	406,074
Income taxes	258,272		236,411		237,720		220,705		230,591
Fixed charges	228,377		213,973		202,465		208,226		206,089
Total earnings	$	975,105	$	892,418	$	877,442	$	826,526	$	842,754
Fixed Charges:
Interest expense	$	219,796	$	205,720	$	194,964	$	200,950	$	201,888
Estimated interest portion of annual rents	8,581		8,253		7,501		7,276		4,201
Total fixed charges	$	228,377	$	213,973	$	202,465	$	208,226	$	206,089
Preferred Stock Dividend Requirements:
Income before income taxes attributable to common shareholders	$	746,728	$	678,445	$	674,977	$	618,300	$	636,665
Net income from continuing operations attributable to common shareholders	488,456		442,034		437,257		397,595		406,074
Ratio of income before income taxes to net income	1.53		1.53		1.54		1.56		1.57
Preferred stock dividends	—		—		—		—		—
Preferred stock dividend requirements — ratio (above) times preferred stock dividends	$	—	$	—	$	—	$	—	$	—
Fixed Charges and Preferred Stock Dividend Requirements:
Fixed charges	$	228,377	$	213,973	$	202,465	$	208,226	$	206,089
Preferred stock dividend requirements	—		—		—		—		—
Total	$	228,377	$	213,973	$	202,465	$	208,226	$	206,089
Ratio of Earnings to Fixed Charges (rounded down)	4.26		4.17		4.33		3.96		4.08

EX-21.1

Exhibit 21.1

SUBSIDIARIES LIST

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. 333-203578 and 333-218886 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 23, 2018, relating to the consolidated financial statements and financial statement schedules of Pinnacle West Capital Corporation and subsidiaries, and the effectiveness of Pinnacle West Capital Corporation and subsidiaries' 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, 2017.

/s/ Deloitte & Touche LLP

Phoenix, Arizona

February 23, 2018

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-203578-01 on Form S-3 and in Registration Statement Nos. 333-46161 and 333-158774 on Form S-8 of our report dated February 23, 2018, relating to the consolidated financial statements and financial statement schedule of Arizona Public Service Company and subsidiaries, and the effectiveness of Arizona Public Service Company and subsidiaries' 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, 2017.

/s/ Deloitte & Touche LLP

Phoenix, Arizona

February 23, 2018

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

1

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 23, 2018

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and Chief Executive Officer

2

EX-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

1

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 23, 2018

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and Chief Financial Officer

2

EX-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

2

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 23, 2018

/s/ Donald E. Brandt

Donald E. Brandt

Chairman, President and Chief Executive Officer

2

EX-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

2

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 23, 2018

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and Chief Financial Officer

2

EX-32.1

CERTIFICATIONOFCHIEF EXECUTIVE OFFICERANDCHIEF FINANCIAL OFFICERPURSUANT TO 18 U.S.C. 1350,AS ADOPTED PURSUANT TOSECTION 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, 2017 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 23, 2018

/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, 2017 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 23, 2018

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and Chief Financial Officer

EX-32.2

CERTIFICATIONOFCHIEF EXECUTIVE OFFICERANDCHIEF FINANCIAL OFFICERPURSUANT TO 18 U.S.C. 1350,AS ADOPTED PURSUANT TOSECTION 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, 2017 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 23, 2018

/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, 2017 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 23, 2018

/s/ James R. Hatfield

James R. Hatfield

Executive Vice President and Chief Financial Officer

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Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 16, 2018	Jun. 30, 2017
Entity Information [Line Items]
Entity Registrant Name	PINNACLE WEST CAPITAL CORP
Entity Central Index Key	0000764622
Document Type	10-K
Document Period End Date	Dec. 31, 2017
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			$ 9,461,736,502
Entity Common Stock, Shares Outstanding		111,799,789
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
ARIZONA PUBLIC SERVICE COMPANY
Entity Information [Line Items]
Entity Registrant Name	ARIZONA PUBLIC SERVICE COMPANY
Entity Central Index Key	0000007286
Document Type	10-K
Document Period End Date	Dec. 31, 2017
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	Non-accelerated Filer
Entity Public Float			$ 0
Entity Common Stock, Shares Outstanding		71,264,947
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY

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CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
OPERATING REVENUES	$ 3,565,296	$ 3,498,682	$ 3,495,443
OPERATING EXPENSES
Fuel and purchased power	981,301	1,075,510	1,101,298
Operations and maintenance	924,443	911,319	868,377
Depreciation and amortization	534,118	485,829	494,422
Taxes other than income taxes	184,347	166,499	171,812
Other expenses	6,660	3,541	4,932
Total	2,630,869	2,642,698	2,640,841
OPERATING INCOME	934,427	855,984	854,602
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction (Note 1)	47,011	42,140	35,215
Other income (Note 17)	4,006	901	621
Other expense (Note 17)	(21,539)	(15,337)	(17,823)
Total	29,478	27,704	18,013
INTEREST EXPENSE
Interest charges	219,796	205,720	194,964
Allowance for borrowed funds used during construction (Note 1)	(22,112)	(19,970)	(16,259)
Total	197,684	185,750	178,705
INCOME BEFORE INCOME TAXES	766,221	697,938	693,910
INCOME TAXES (Note 4)	258,272	236,411	237,720
NET INCOME	507,949	461,527	456,190
Less: Net income attributable to noncontrolling interests (Note 18)	19,493	19,493	18,933
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 488,456	$ 442,034	$ 437,257
Weighted Average common shares outstanding — basic (in shares)	111,839	111,409	111,026
Weighted Average common shares outstanding — diluted (in shares)	112,367	112,046	111,552
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders - basic (in dollars per share)	$ 4.37	$ 3.97	$ 3.94
Net income attributable to common shareholders — diluted (in dollars per share)	$ 4.35	$ 3.95	$ 3.92
ARIZONA PUBLIC SERVICE COMPANY
ELECTRIC OPERATING REVENUES	$ 3,554,139	$ 3,489,754	$ 3,492,357
OPERATING EXPENSES
Fuel and purchased power	992,744	1,082,625	1,101,298
Operations and maintenance	891,129	879,108	853,135
Depreciation and amortization	532,423	484,909	494,298
Taxes other than income taxes	182,979	165,779	171,499
Income taxes (Note 4)	275,295	259,353	260,143
Total	2,874,570	2,871,774	2,880,373
OPERATING INCOME	679,569	617,980	611,984
OTHER INCOME (DEDUCTIONS)
Income taxes (Note 4)	6,127	13,511	14,302
Allowance for equity funds used during construction (Note 1)	47,011	42,140	35,215
Other income (Note 17)	6,526	8,607	2,834
Other expense (Note 17)	(23,380)	(17,514)	(19,019)
Total	36,284	46,744	33,332
INTEREST EXPENSE
Interest on long-term debt	200,211	189,828	180,123
Interest on short-term borrowings	9,119	7,983	7,376
Debt discount, premium and expense	4,833	4,760	4,793
Allowance for borrowed funds used during construction (Note 1)	(22,112)	(19,481)	(16,183)
Total	192,051	183,090	176,109
INCOME TAXES (Note 4)	269,168	245,842	245,841
NET INCOME	523,802	481,634	469,207
Less: Net income attributable to noncontrolling interests (Note 18)	19,493	19,493	18,933
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 504,309	$ 462,141	$ 450,274

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
NET INCOME	$ 507,949	$ 461,527	$ 456,190
Derivative instruments:
Net unrealized loss, net of tax benefit (expense)	(35)	(538)	(957)
Reclassification of net realized loss, net of tax benefit	2,225	2,941	4,187
Pension and other postretirement benefits activity, net of tax (expense) benefit	(3,370)	(1,477)	20,163
Total other comprehensive income (loss)	(1,180)	926	23,393
COMPREHENSIVE INCOME	506,769	462,453	479,583
Less: Comprehensive income attributable to noncontrolling interests	19,493	19,493	18,933
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	487,276	442,960	460,650
ARIZONA PUBLIC SERVICE COMPANY
NET INCOME	523,802	481,634	469,207
Derivative instruments:
Net unrealized loss, net of tax benefit (expense)	(35)	(538)	(957)
Reclassification of net realized loss, net of tax benefit	2,225	2,941	4,187
Pension and other postretirement benefits activity, net of tax (expense) benefit	(3,750)	(729)	18,006
Total other comprehensive income (loss)	(1,560)	1,674	21,236
COMPREHENSIVE INCOME	522,242	483,308	490,443
Less: Comprehensive income attributable to noncontrolling interests	19,493	19,493	18,933
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 502,749	$ 463,815	$ 471,510

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net unrealized loss, tax (expense)	$ 24	$ (585)	$ (342)
Reclassification of net realized loss, tax benefit	1,294	985	1,801
Pension and other postretirement benefits activity, tax benefit (expense)	693	633	(13,302)
ARIZONA PUBLIC SERVICE COMPANY
Net unrealized loss, tax (expense)	24	(585)	(342)
Reclassification of net realized loss, tax benefit	1,294	985	1,801
Pension and other postretirement benefits activity, tax benefit (expense)	$ 977	$ 293	$ (11,776)

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CONSOLIDATED BALANCE SHEETS - USD ($)	Dec. 31, 2017	Dec. 31, 2016
CURRENT ASSETS
Cash and cash equivalents	$ 13,892,000	$ 8,881,000
Customer and other receivables	305,147,000	250,491,000
Accrued unbilled revenues	112,434,000	107,949,000
Allowance for doubtful accounts	(2,513,000)	(3,037,000)
Materials and supplies (at average cost)	264,012,000	253,979,000
Fossil fuel (at average cost)	25,258,000	28,608,000
Income tax receivable (Note 4)	0	3,751,000
Assets from risk management activities (Note 16)	1,931,000	19,694,000
Deferred fuel and purchased power regulatory asset (Note 3)	75,637,000	12,465,000
Other regulatory assets (Note 3)	172,451,000	94,410,000
Other current assets	48,039,000	45,028,000
Total current assets	1,016,288,000	822,219,000
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 16)	51,000	1,000
Nuclear decommissioning trust (Notes 13 and 19)	871,000,000	779,586,000
Other assets	84,531,000	69,063,000
Total investments and other assets	955,582,000	848,650,000
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Plant in service and held for future use	17,798,061,000	17,341,888,000
Accumulated depreciation and amortization	(6,128,535,000)	(5,970,100,000)
Net	11,669,526,000	11,371,788,000
Construction work in progress	1,291,498,000	1,019,947,000
Palo Verde sale leaseback, net of accumulated depreciation of $241,405 and $237,535 (Note 18)	109,645,000	113,515,000
Intangible assets, net of accumulated amortization of $582,272 and $603,637	257,189,000	90,022,000
Nuclear fuel, net of accumulated amortization of $144,070 and $147,202	117,408,000	119,004,000
Total property, plant and equipment	13,445,266,000	12,714,276,000
DEFERRED DEBITS
Regulatory assets (Notes 1, 3 and 4)	1,202,302,000	1,313,428,000
Assets for other postretirement benefits (Note 7)	268,978,000	166,206,000
Other	130,666,000	139,474,000
Total deferred debits	1,601,946,000	1,619,108,000
Total Assets	17,019,082,000	16,004,253,000
CURRENT LIABILITIES
Accounts payable	256,442,000	264,631,000
Accrued taxes (Note 4)	148,946,000	138,964,000
Accrued interest	56,397,000	52,835,000
Common dividends payable	77,667,000	72,926,000
Short-term borrowings (Note 5)	95,400,000	177,200,000
Current maturities of long-term debt (Note 6)	82,000,000	125,000,000
Customer deposits	70,388,000	82,520,000
Liabilities from risk management activities (Note 16)	59,252,000	25,836,000
Liabilities for asset retirements (Note 11)	4,745,000	9,135,000
Regulatory liabilities (Note 3)	100,086,000	99,899,000
Other current liabilities	246,529,000	244,000,000
Total current liabilities	1,197,852,000	1,292,946,000
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)	4,789,713,000	4,021,785,000
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)	1,690,805,000	2,945,232,000
Regulatory liabilities (Notes 1, 3, 4 and 7)	2,452,536,000	948,916,000
Liabilities for asset retirements (Note 11)	674,784,000	615,340,000
Liabilities for pension benefits (Note 7)	327,300,000	509,310,000
Liabilities from risk management activities (Note 16)	37,170,000	47,238,000
Customer advances	113,996,000	88,672,000
Coal mine reclamation	231,597,000	221,910,000
Deferred investment tax credit	205,575,000	210,162,000
Unrecognized tax benefits (Note 4)	13,115,000	10,046,000
Other	148,909,000	156,784,000
Total deferred credits and other	5,895,787,000	5,753,610,000
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 111,816,170 and 111,392,053 issued at respective dates	2,614,805,000	2,596,030,000
Treasury stock at cost; 64,463 shares at end of 2017 and 55,317 shares at end of 2016	(5,624,000)	(4,133,000)
Total common stock	2,609,181,000	2,591,897,000
Retained earnings	2,442,511,000	2,255,547,000
Accumulated other comprehensive loss	(45,002,000)	(43,822,000)
Total shareholders’ equity	5,006,690,000	4,803,622,000
Noncontrolling interests (Note 18)	129,040,000	132,290,000
Total equity	5,135,730,000	4,935,912,000
Total Liabilities and Equity	17,019,082,000	16,004,253,000
ARIZONA PUBLIC SERVICE COMPANY
CURRENT ASSETS
Cash and cash equivalents	13,851,000	8,840,000
Customer and other receivables	292,791,000	262,611,000
Accrued unbilled revenues	112,434,000	107,949,000
Allowance for doubtful accounts	(2,513,000)	(3,037,000)
Materials and supplies (at average cost)	262,630,000	252,777,000
Fossil fuel (at average cost)	25,258,000	28,608,000
Income tax receivable (Note 4)	0	11,174,000
Assets from risk management activities (Note 16)	1,931,000	19,694,000
Deferred fuel and purchased power regulatory asset (Note 3)	75,637,000	12,465,000
Other regulatory assets (Note 3)	172,451,000	94,410,000
Other current assets	41,055,000	41,849,000
Total current assets	995,525,000	837,340,000
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 16)	51,000	1,000
Nuclear decommissioning trust (Notes 13 and 19)	871,000,000	779,586,000
Other assets	67,103,000	48,320,000
Total investments and other assets	938,154,000	827,907,000
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Plant in service and held for future use	17,654,078,000	17,228,787,000
Accumulated depreciation and amortization	(6,041,965,000)	(5,881,941,000)
Net	11,612,113,000	11,346,846,000
Construction work in progress	1,266,636,000	989,497,000
Palo Verde sale leaseback, net of accumulated depreciation of $241,405 and $237,535 (Note 18)	109,645,000	113,515,000
Intangible assets, net of accumulated amortization of $582,272 and $603,637	257,028,000	89,868,000
Nuclear fuel, net of accumulated amortization of $144,070 and $147,202	117,408,000	119,004,000
Total property, plant and equipment	13,362,830,000	12,658,730,000
DEFERRED DEBITS
Regulatory assets (Notes 1, 3 and 4)	1,202,302,000	1,313,428,000
Assets for other postretirement benefits (Note 7)	265,139,000	162,911,000
Other	129,801,000	130,859,000
Total deferred debits	1,597,242,000	1,607,198,000
Total Assets	16,893,751,000	15,931,175,000
CURRENT LIABILITIES
Accounts payable	247,852,000	259,161,000
Accrued taxes (Note 4)	157,349,000	130,576,000
Accrued interest	55,533,000	52,525,000
Common dividends payable	77,700,000	72,900,000
Short-term borrowings (Note 5)	0	135,500,000
Current maturities of long-term debt (Note 6)	82,000,000	0
Customer deposits	70,388,000	82,520,000
Liabilities from risk management activities (Note 16)	59,252,000	25,836,000
Liabilities for asset retirements (Note 11)	4,192,000	8,703,000
Regulatory liabilities (Note 3)	100,086,000	99,899,000
Other current liabilities	243,922,000	226,417,000
Total current liabilities	1,098,274,000	1,094,037,000
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)	1,742,485,000	2,999,295,000
Regulatory liabilities (Notes 1, 3, 4 and 7)	2,452,536,000	948,916,000
Liabilities for asset retirements (Note 11)	666,527,000	607,234,000
Liabilities for pension benefits (Note 7)	306,542,000	488,253,000
Liabilities from risk management activities (Note 16)	37,170,000	47,238,000
Customer advances	113,996,000	88,672,000
Coal mine reclamation	215,830,000	206,645,000
Deferred investment tax credit	205,575,000	210,162,000
Unrecognized tax benefits (Note 4)	43,876,000	37,408,000
Other	133,779,000	143,560,000
Total deferred credits and other	5,918,316,000	5,777,383,000
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY
Total common stock	178,162,000	178,162,000
Additional paid-in capital	2,571,696,000	2,421,696,000
Retained earnings	2,533,954,000	2,331,245,000
Accumulated other comprehensive loss	(26,983,000)	(25,423,000)
Total shareholders’ equity	5,256,829,000	4,905,680,000
Noncontrolling interests (Note 18)	129,040,000	132,290,000
Total equity	5,385,869,000	5,037,970,000
Long-term debt less current maturities (Note 6)	4,491,292,000	4,021,785,000
Total capitalization	9,877,161,000	9,059,755,000
Total Liabilities and Equity	$ 16,893,751,000	$ 15,931,175,000

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Accumulated depreciation of Palo Verde sale leaseback	$ 241,405	$ 237,535
Accumulated amortization on intangible assets	582,272	603,637
Accumulated amortization on nuclear fuel	$ 144,070	$ 147,202
EQUITY
Common stock, par value	$ 0	$ 0
Common stock, authorized shares	150,000,000	150,000,000
Common stock, issued shares	111,816,170	111,392,053
Treasury stock at cost, shares	64,463	55,317
ARIZONA PUBLIC SERVICE COMPANY
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)
Accumulated depreciation of Palo Verde sale leaseback	$ 241,405	$ 237,535
Accumulated amortization on intangible assets	581,135	603,637
Accumulated amortization on nuclear fuel	$ 144,070	$ 147,202

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CONSOLIDATED STATEMENTS OF CASH FLOWS $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 507,949	$ 461,527	$ 456,190
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	610,629	565,011	571,664
Deferred fuel and purchased power	(48,405)	(60,303)	14,997
Deferred fuel and purchased power amortization	(14,767)	38,152	1,617
Allowance for equity funds used during construction	(47,011)	(42,140)	(35,215)
Deferred income taxes	248,164	206,870	236,819
Deferred investment tax credit	(4,587)	23,082	8,473
Change in derivative instruments fair value	(373)	(403)	(381)
Stock compensation	20,502	18,883	18,756
Change in derivative instruments fair value
Customer and other receivables	(93,797)	(2,489)	(22,219)
Accrued unbilled revenues	(4,485)	(11,709)	4,293
Materials, supplies and fossil fuel	(6,683)	(1,491)	(23,945)
Income tax receivable	3,751	(3,162)	2,509
Other current assets	(10,580)	(23,324)	3,145
Accounts payable	(23,769)	(66,917)	(34,266)
Accrued taxes	9,982	447	(2,013)
Other current liabilities	19,154	29,594	603
Change in margin and collateral accounts — assets	(300)	673	(324)
Change in margin and collateral accounts — liabilities	(533)	17,735	22,776
Change in unrecognized tax benefits	5,891	1,628	(10,328)
Change in long-term regulatory liabilities	45,764	14,682	(20,535)
Change in other long-term assets	(68,480)	(60,163)	2,426
Change in other long-term liabilities	(29,980)	(82,793)	(100,715)
Net cash flow provided by operating activities	1,118,036	1,023,390	1,094,327
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,408,774)	(1,275,472)	(1,076,087)
Contributions in aid of construction	23,708	64,296	46,546
Allowance for borrowed funds used during construction	(22,112)	(19,970)	(16,259)
Proceeds from nuclear decommissioning trust sales	542,246	633,410	478,813
Investment in nuclear decommissioning trust	(544,527)	(635,691)	(496,062)
Other	(19,078)	(18,651)	(3,184)
Net cash flow used for investing activities	(1,428,537)	(1,252,078)	(1,066,233)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	848,239	693,151	842,415
Repayment of long-term debt	(125,000)	(370,430)	(415,570)
Short-term borrowings and (repayments) — net	(107,800)	137,200	(147,400)
Short-term debt borrowings under revolving credit facility	58,000	40,000	0
Short-term debt repayments under revolving credit facility	(32,000)	0	0
Dividends paid on common stock	(289,793)	(274,229)	(260,027)
Common stock equity issuance and purchases - net	(13,390)	(4,867)	19,373
Distributions to noncontrolling interests	(22,744)	(22,744)	(35,002)
Other	0	0	1
Net cash flow provided by financing activities	315,512	198,081	3,790
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	5,011	(30,607)	31,884
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	8,881	39,488	7,604
CASH AND CASH EQUIVALENTS AT END OF YEAR	13,892	8,881	39,488
Supplemental disclosure of cash flow information:
Income taxes, net of refunds	2,186	9,956	6,550
Interest, net of amounts capitalized	189,288	184,462	170,209
Significant non-cash investing and financing activities:
Accrued capital expenditures	130,404	114,855	83,798
Dividends declared but not paid	77,667	72,926	69,363
ARIZONA PUBLIC SERVICE COMPANY
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	523,802	481,634	469,207
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	608,935	564,091	571,540
Deferred fuel and purchased power	(48,405)	(60,303)	14,997
Deferred fuel and purchased power amortization	(14,767)	38,152	1,617
Allowance for equity funds used during construction	(47,011)	(42,140)	(35,215)
Deferred income taxes	249,465	221,167	223,069
Deferred investment tax credit	(4,587)	23,082	8,473
Change in derivative instruments fair value	(373)	(403)	(381)
Change in derivative instruments fair value
Customer and other receivables	(68,040)	(1,601)	(21,040)
Accrued unbilled revenues	(4,485)	(11,709)	4,293
Materials, supplies and fossil fuel	(6,503)	(1,454)	(23,945)
Income tax receivable	11,174	(14,567)	0
Other current assets	(6,775)	(21,640)	4,498
Accounts payable	(26,561)	(67,543)	(34,891)
Accrued taxes	26,773	(13,912)	13,378
Other current liabilities	27,912	5,097	(3,718)
Change in margin and collateral accounts — assets	(300)	673	(324)
Change in margin and collateral accounts — liabilities	(533)	17,735	22,776
Change in unrecognized tax benefits	5,891	1,628	(10,328)
Change in long-term regulatory liabilities	45,764	14,682	(20,535)
Change in other long-term assets	(78,540)	(45,866)	(813)
Change in other long-term liabilities	(31,106)	(76,855)	(82,628)
Net cash flow provided by operating activities	1,161,730	1,009,948	1,100,030
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,381,930)	(1,248,010)	(1,072,053)
Contributions in aid of construction	23,708	64,296	46,546
Allowance for borrowed funds used during construction	(22,112)	(19,481)	(16,183)
Proceeds from nuclear decommissioning trust sales	542,246	633,410	478,813
Investment in nuclear decommissioning trust	(544,527)	(635,691)	(496,062)
Other	(18,538)	(13,865)	(1,093)
Net cash flow used for investing activities	(1,401,153)	(1,219,341)	(1,060,032)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	549,478	693,151	842,415
Repayment of long-term debt	0	(370,430)	(415,570)
Short-term borrowings and (repayments) — net	(135,500)	135,500	(147,400)
Dividends paid on common stock	(296,800)	(281,300)	(266,900)
Equity infusion from Pinnacle West	150,000	42,000	0
Distributions to noncontrolling interests	(22,744)	(22,744)	(35,002)
Net cash flow provided by financing activities	244,434	196,177	(22,457)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	5,011	(13,216)	17,541
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	8,840	22,056	4,515
CASH AND CASH EQUIVALENTS AT END OF YEAR	13,851	8,840	22,056
Supplemental disclosure of cash flow information:
Income taxes, net of refunds	(14,098)	26,864	14,831
Interest, net of amounts capitalized	184,210	181,809	167,670
Significant non-cash investing and financing activities:
Accrued capital expenditures	130,057	114,874	83,798
Dividends declared but not paid	$ 77,700	$ 72,900	$ 69,400

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CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Thousands		Total	Common Stock	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests	ARIZONA PUBLIC SERVICE COMPANY	ARIZONA PUBLIC SERVICE COMPANY Common Stock	ARIZONA PUBLIC SERVICE COMPANY Additional Paid-In Capital	ARIZONA PUBLIC SERVICE COMPANY Retained Earnings	ARIZONA PUBLIC SERVICE COMPANY Accumulated Other Comprehensive Income (Loss)	ARIZONA PUBLIC SERVICE COMPANY Noncontrolling Interests
Beginning balance at Dec. 31, 2014		$ 4,519,102	$ 2,512,970	$ (3,401)	$ 1,926,065	$ (68,141)	$ 151,609	$ 4,629,852	$ 178,162	$ 2,379,696	$ 1,968,718	$ (48,333)	$ 151,609
Beginning Balance (in shares) at Dec. 31, 2014			110,649,762	78,400					71,264,947
Increase (Decrease) in Shareholders' Equity
Net income		456,190			437,257		18,933	469,207			450,274		18,933
Other comprehensive income		23,393				23,393		21,236				21,236
Dividends on common stock		(270,519)			(270,519)			(270,500)			(270,500)
Other								1			1
Issuance of common stock		28,698	$ 28,698
Issuance of common stock (in shares)			445,640
Purchase of treasury stock	[1]	(10,136)		$ (10,136)
Purchase of treasury stock (in shares)	[1]			(154,751)
Reissuance of treasury stock for stock-based compensation and other		7,731		$ 7,731
Reissuance of treasury stock for stock-based compensation and other (in shares)				118,121
Net capital activities by noncontrolling interests		(35,002)					(35,002)	(35,002)					(35,002)
Ending balance at Dec. 31, 2015		4,719,457	$ 2,541,668	$ (5,806)	2,092,803	(44,748)	135,540	4,814,794	$ 178,162	2,379,696	2,148,493	(27,097)	135,540
Ending Balance (in shares) at Dec. 31, 2015			111,095,402	115,030					71,264,947
Increase (Decrease) in Shareholders' Equity
Net income		461,527			442,034		19,493	481,634			462,141		19,493
Other comprehensive income		926				926		1,674				1,674
Dividends on common stock		(284,765)			(284,765)			(284,800)			(284,800)
Other								0			0
Issuance of common stock		13,982	$ 13,982
Issuance of common stock (in shares)			296,651
Purchase of treasury stock	[1]	(9,087)		$ (9,087)
Purchase of treasury stock (in shares)	[1]			(128,105)
Reissuance of treasury stock for stock-based compensation and other		10,760		$ 10,760
Reissuance of treasury stock for stock-based compensation and other (in shares)				187,818
Equity infusion from Pinnacle West								42,000		42,000
Net capital activities by noncontrolling interests		(22,743)					(22,743)	(22,743)					(22,743)
Ending balance at Dec. 31, 2016		$ 4,935,912	$ 2,596,030	$ (4,133)	2,255,547	(43,822)	132,290	5,037,970	$ 178,162	2,421,696	2,331,245	(25,423)	132,290
Ending Balance (in shares) at Dec. 31, 2016		111,392,053	111,392,053	55,317					71,264,947
Increase (Decrease) in Shareholders' Equity
Stock compensation cumulative effect adjustments		$ 45,855	$ 40,380		5,475			5,411			5,411
Net income		507,949			488,456		19,493	523,802			504,309		19,493
Other comprehensive income		(1,180)				(1,180)		(1,560)				(1,560)
Dividends on common stock		(301,492)			(301,492)			(301,600)			(301,600)
Issuance of common stock		18,775	$ 18,775
Issuance of common stock (in shares)			424,117
Purchase of treasury stock	[1]	(17,755)		$ (17,755)
Purchase of treasury stock (in shares)	[1]			(216,911)
Reissuance of treasury stock for stock-based compensation and other		16,264		$ 16,264
Reissuance of treasury stock for stock-based compensation and other (in shares)				207,765
Equity infusion from Pinnacle West								150,000		150,000
Net capital activities by noncontrolling interests		(22,743)					(22,743)	(22,743)					(22,743)
Ending balance at Dec. 31, 2017		$ 5,135,730	$ 2,614,805	$ (5,624)	$ 2,442,511	$ (45,002)	$ 129,040	$ 5,385,869	$ 178,162	$ 2,571,696	$ 2,533,954	$ (26,983)	$ 129,040
Ending Balance (in shares) at Dec. 31, 2017		111,816,170	111,816,170	64,463					71,264,947

[1] Primarily represents shares of common stock withheld from certain stock awards for tax purposes.

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CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Stockholders' Equity [Abstract]
Common stock dividends declared (in dollars per share)	$ 2.70	$ 2.56	$ 2.44

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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, El Dorado, BCE and 4CA. 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.  El Dorado is an investment firm. BCE is a subsidiary that was formed in 2014 that focuses on growth opportunities that leverage the Company's core expertise in the electric energy industry. BCE is currently pursuing transmission opportunities through a joint venture arrangement. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners.

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries:  APS, El Dorado, BCE and 4CA. 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 18).

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 a more condensed form on the Consolidated Balance Sheets than in the prior year. The prior year amounts were reclassified to conform to the current year presentation. These reclassifications have no impact on accumulated other comprehensive loss. The following tables show the impacts of the reclassifications of the prior year (previously reported) amounts (dollars in thousands):

Pinnacle West Capital Corporation Consolidated Balance Sheets- December 31, 2016	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Accumulated other comprehensive loss:
Pension and other postretirement benefits	$	(39,070	)	$	39,070		$	—
Derivative instruments	(4,752		)	4,752			—
Total accumulated other comprehensive loss	(43,822		)	43,822			—
Accumulated other comprehensive loss	—			(43,822		)	(43,822		)

Arizona Public Service Company Consolidated Balance Sheets - December 31, 2016	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Accumulated other comprehensive loss:
Pension and other postretirement benefits	$	(20,671	)	$	20,671		$	—
Derivative instruments	(4,752		)	4,752			—
Total accumulated other comprehensive loss	(25,423		)	25,423			—
Accumulated other comprehensive loss	—			(25,423		)	(25,423		)

Accounting Records and Use of Estimates

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

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 amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to 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.

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.

Pinnacle West’s property, plant and equipment included in the December 31, 2017 and 2016 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:	2017			2016
Generation	$	7,963,998		$	7,874,898
Transmission	2,836,578			2,746,508
Distribution	6,025,856			5,738,801
General plant	971,629			981,681
Plant in service and held for future use	17,798,061			17,341,888
Accumulated depreciation and amortization	(6,128,535		)	(5,970,100		)
Net	11,669,526			11,371,788
Construction work in progress	1,291,498			1,019,947
Palo Verde sale leaseback, net of accumulated depreciation	109,645			113,515
Intangible assets, net of accumulated amortization	257,189			90,022
Nuclear fuel, net of accumulated amortization	117,408			119,004
Total property, plant and equipment	$	13,445,266		$	12,714,276

Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West.

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 11.

APS records a regulatory liability 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 and amortization 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, 2017 were as follows:

•Fossil plant — 21 years;

•Nuclear plant — 26 years;

•Other generation — 25 years;

•Transmission — 38 years;

•Distribution — 33 years; and

•General plant — 6 years.

Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $453 million in 2017, $422 million in 2016, and $430 million in 2015. For the years 2015 through 2017, the depreciation rates ranged from a low of 0.18% to a high of 16.44%.  The weighted-average depreciation rate was 2.80% in 2017, 2.66% in 2016, and 2.74% in 2015.

Asset Retirement Obligations

APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation 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.  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 and coal ash pond closures. 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 transmission and distribution assets. Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites.

See Note 11 for further information on Asset Retirement Obligations.

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 Statements 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 6.68% for 2017, 7.17% for 2016, and 8.02% for 2015.  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, coal reclamation escrow accounts, 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 13 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 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 16 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 Postretirement 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 its 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 7 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 charged APS $0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero.  In accordance with a settlement agreement with the DOE in August 2014, we will now accrue a receivable for incurred claims and an offsetting regulatory liability through the settlement period ending December of 2019. See Note 10 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 and are based on currently enacted tax rates.  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):

	Year ended December 31,
	2017		2016		2015
Cash paid during the period for:
Income taxes, net of refunds	$	2,186	$	9,956	$	6,550
Interest, net of amounts capitalized	189,288		184,462		170,209
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	130,404	$	114,855	$	83,798
Dividends declared but not paid	77,667		72,926		69,363

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 $72 million in 2017, $58 million in 2016, and $58 million in 2015.  Estimated amortization expense on existing intangible assets over the next five years is $53 million in 2018, $38 million in 2019, $28 million in 2020, $22 million in 2021, and $17 million in 2022.  At December 31, 2017, the weighted-average remaining amortization period for intangible assets was 6 years.

Investments

El Dorado holds investments in both debt and equity securities.  Investments in debt securities are generally accounted for as held-to-maturity and investments in equity securities are accounted for using either the equity method (if significant influence) or the cost method (if less than 20% ownership and no significant influence).

Our investments in the nuclear decommissioning trust fund, and coal reclamation escrow, are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities. See Note 13 and Note 19 for more information on these investments.

See Note 2 for new accounting guidance relating to financial instruments including investments in equity securities, effective for us in 2018.  

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.

Preferred Stock

At December 31, 2017, 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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New Accounting Standards

12 Months Ended

Dec. 31, 2017

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Standards

New Accounting Standards

ASU 2014-09, Revenue from Contracts with Customers

In May 2014, a new revenue recognition accounting standard was issued. This standard provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, became effective for us on January 1, 2018. The standard may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application.

We adopted this standard on January 1, 2018 using the modified retrospective transition approach. The adoption of this standard will not have significant impact on our financial statement results. Our revenues are derived primarily from sales of electricity to our regulated retail customers, and based on our assessment the adoption of this guidance does not generally impact the timing of our revenue recognition relating to these customers. The adoption of the new standard will result in expanded revenue related disclosures.

ASU 2016-01, Financial Instruments: Recognition and Measurement

In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new standard became effective for us on January 1, 2018. Certain aspects of the standard require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We adopted this standard on a prospective basis on January 1, 2018. The adoption of this standard will not have a significant impact on our financial statement results, as we did not have significant equity investments impacted by this standard.

ASU 2016-02, Leases

In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. In January 2018, additional lease guidance was issued specifically relating to land easements and how entities may elect to account for these arrangements at transition. The new standard, and related amendments, will be effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition.

We plan on adopting this standard, and related amendments, on January 1, 2019, and are evaluating the transition practical expedients we may elect. Our evaluation of this new accounting standard and the impacts it will have on our financial statements is on-going. We expect the adoption of the new guidance will impact our Consolidated Balance Sheets as we will be required to reflect lease assets and lease liabilities relating to certain operating lease arrangements. We are currently evaluating the significance of the expected balance sheet impacts, and the impacts, if any, the lease guidance will have on our other financial statements. Our evaluation includes assessing leasing activities, implementing new processes and procedures, and preparing the expanded lease disclosures.

ASU 2016-13, Financial Instruments: Measurement of Credit Losses

In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard will require entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments

In August 2016, a new accounting standard was issued that clarifies how entities should present certain specific cash flow activities on the statement of cash flows. The guidance is intended to eliminate diversity in practice in how entities classify these specific activities between cash flows from operating activities, investing activities and financing activities. The specific activities addressed include debt prepayments and extinguishment costs, proceeds from the settlement of insurance claims, proceeds from corporate owned life insurance policies, and other activities. The standard also addresses how entities should apply the predominance principle when a transaction includes separately identifiable cash flows. The new standard is effective for us, and will be adopted, during the first quarter of 2018 using a retrospective transition method. The adoption of this guidance will not have a significant impact on our financial statements, as either our statement of cash flow presentation is consistent with the new prescribed guidance or we do not have significant activities relating to the specific transactions that are addressed by the new standard.

ASU 2016-18, Statement of Cash Flows: Restricted Cash

In November 2016, a new accounting standard was issued that clarifies how restricted cash and restricted cash equivalents should be presented on the statement of cash flows. The new guidance requires entities to include restricted cash and restricted cash equivalents as a component of the beginning and ending cash and cash equivalent balances on the statement of cash flows. The new standard is effective for us, and will be adopted, during the first quarter of 2018 using a retrospective transition method. We do not expect the adoption of this guidance will impact our financial statements, as our holdings and activities designated as restricted cash and restricted cash equivalents are generally insignificant.

ASU 2017-01, Business Combinations: Clarifying the Definition of a Business

In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business.  The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The new standard became effective for us on January 1, 2018 using a prospective approach. We adopted this new standard on January 1, 2018, using a prospective approach with no impacts on our financial statements on the date of adoption.

ASU 2017-05, Other Income: Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets

In February 2017, a new accounting standard was issued that intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard became effective for us on January 1, 2018. The guidance may be applied using either a retrospective or modified retrospective transition approach. We adopted this standard on January 1, 2018 using a modified retrospective transition approach. The adoption of this guidance did not have a significant impact on our financial statement results.

ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs). The presentation changes will require net benefit costs to be disaggregated on the income statement by the various components that comprise these costs. Specifically, only the service cost component will be eligible for presentation as an operating income item, and all other cost components will be presented as non-operating items. This presentation change must be applied retrospectively. Furthermore, the new standard only allows the service cost component to be eligible for capitalization. The change in capitalization requirements must be applied prospectively. The new guidance became effective for us on January 1, 2018.

We adopted this new accounting standard on January 1, 2018. Beginning in the first quarter of 2018, we will present the non-service cost components of net benefit costs in other income instead of operating income. Prior year non-service cost components will also be reclassified from operating income to other income. Upon adoption, we will no longer capitalize a portion of the non-service cost components of net benefit costs. In 2018, because the non-service cost components are a reduction to total benefit costs, we estimate this change will result in the capitalization of an additional $15 million of net benefit costs, with a corresponding increase to pretax income. See note 7 for additional information related to our pension plans and other postretirement benefits.

ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities

In August 2017, a new accounting standard was issued that modifies hedge accounting guidance with the intent of simplifying the application of hedge accounting. The new standard is effective for us on January 1, 2019, with early application permitted. At transition, the guidance requires the changes to be applied to hedging relationships existing on the date of adoption, with the effect of adoption reflected as of the beginning of the fiscal year of adoption using a cumulative effect adjustment approach. The presentation and disclosure changes may be applied prospectively. We are evaluating the new guidance, but at this time we do not expect the adoption of this guidance will have a significant impact on our financial statement results as we are currently not applying hedge accounting.

ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

In February 2018, new accounting guidance was issued that allows entities an optional election to reclassify the income tax effects of the 2017 Tax Cuts and Jobs Act legislation on items within accumulated other comprehensive income to retained earnings. Amounts eligible for reclassification must relate to the effects from the Tax Cuts and Jobs Act remaining in accumulated other comprehensive income. The new guidance also requires expanded disclosures. This guidance is effective for us on January 1, 2019 with early application permitted. The guidance should be applied either in the period of adoption or retrospectively to each period in which the effect of the Tax Cuts and Jobs Act was recognized. We are currently evaluating this new guidance to determine whether we will elect this reclassification adjustment. The adoption of this guidance will not impact our income from continuing operations. See Note 4 for additional discussion of the Tax Cuts and Jobs Act.

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Regulatory Matters

12 Months Ended

Dec. 31, 2017

Regulated Operations [Abstract]

Regulatory Matters

Regulatory Matters

Retail Rate Case Filing with the Arizona Corporation Commission

On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates of $165.9 million. This amount excluded amounts that were then collected on customer bills through adjustor mechanisms. The application requested that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have had an incremental effect on average customer bills. The average annual customer bill impact of APS’s request was an increase of 5.74% (the average annual bill impact for a typical APS residential customer was 7.96%).

On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed a settlement agreement (the "2017 Settlement Agreement") and filed it with the ACC. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules. The average annual customer bill impact under the 2017 Settlement Agreement is an increase of 3.28% (the average annual bill impact for a typical APS residential customer is 4.54%).

Other key provisions of the agreement include the following:

• an agreement by APS not to file another general retail rate case application before June 1, 2019;

• an authorized return on common equity of 10.0%;

• a capital structure comprised of 44.2% debt and 55.8% common equity;

• a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project;

• a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing selective catalytic reduction ("SCR") equipment at Four Corners;

• a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate;

• an expansion of the PSA to include certain environmental chemical costs and third-party battery storage costs;

• a new AZ Sun II program (now known as APS Solar Communities) for utility-owned solar distributed generation ("DG") with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the RES, to be no less than $10 million per year, and not more than $15 million per year;

• an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account;

• rate design changes, including:

▪ a change in the on-peak time of use period from noon - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays;

▪ non-grandfathered DG customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component;

▪ a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and

• an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027 for combined-cycle generating units), unless expressly authorized by the ACC.

Through a separate agreement, APS, industry representatives, and solar advocates committed to stand by the 2017 Settlement Agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC.

On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications.  On August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the "2017 Rate Case Decision"), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017. On August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the ACC's order approving the 2017 Settlement Agreement so that alleged issues of disqualification and bias on the part of the other Commissioners can be fully investigated.   APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition.

On October 17, 2017, Warren Woodward (an intervener in APS's general retail rate case) filed a Notice of Appeal in the Arizona Court of Appeals, Division One. The notice raises a single issue related to the application of certain rate schedules to new APS residential customers after May 1, 2018. Mr. Woodward filed a second notice of appeal on November 13, 2017 challenging APS’s $5 per month automated metering infrastructure opt-out program. Mr. Woodward’s two appeals have been consolidated and APS has filed a motion to intervene. APS cannot predict the outcome of this consolidated appeal but does not believe it will have a material impact.

On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”) and not a request for rehearing. Arizona Revised Statute §40-246 requires the ACC to hold a hearing regarding any complaint alleging that a public service corporation is in violation of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least twenty-five customers of the public service corporation. The Complaint alleged that APS is “in violation of commission order” [sic]. On February 13, 2018, the complainant filed an amended Complaint alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable.  The complainant is requesting that the ACC hold a hearing on her amended Complaint to determine if the average bill impact on residential customers of the rates and charges approved in the 2017 Rate Case Decision is greater than 4.54% (the average annual bill impact for a typical APS residential customer estimated by APS), and if so, what effect the alleged greater bill impact has on APS's revenues and the overall reasonableness and justness of APS's rates and charges, in order to determine if there is sufficient evidence to warrant a full-scale rate hearing.  APS cannot predict the outcome of this matter.

Prior 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.  On January 6, 2012, APS and other parties to the general retail rate case entered into the 2012 Settlement Agreement (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.

Cost Recovery Mechanisms

APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case 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 5-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.

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 to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014.  The revised rules went into effect on April 21, 2015.    

In December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid.  The first stage of the program, called the "Solar Partner Program," placed 8 MW of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016.  The costs for this program have been included in APS's rate base as part of the 2017 Rate Case Decision.

On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million. APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules. On April 7, 2017, APS filed an amended 2017 RES Implementation Plan and updated budget request which included the revenue neutral transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement.  On August 15, 2017, the ACC approved the 2017 RES Implementation Plan.

On June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million.  APS’s budget request supports existing approved projects and commitments and includes the anticipated transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. APS's 2018 RES budget request is lower than the 2017 RES budget due in part to a certain portion of the RES being collected by APS in base rates rather than through the RES adjustor.

On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a 3-year program requiring APS to spend $10-$15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, buildings of non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES. The ACC has not yet ruled on APS's 2018 RES Implementation Plan.

In September 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES.  The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically.  The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent regulations of EPA.  The proceeding will also examine the feasibility of increasing the standard to 30% of retail sales by 2030, in contrast to the current standard of 15% of retail sales by 2025. On January 30, 2018, ACC Commissioner Tobin proposed a new standard in this proceeding which would broaden the RES to include a series of energy reform policies tied to clean energy sources. The proposal would rename the RES to the Clean Resource Energy Standard and Tariff ("CREST").  APS cannot predict the outcome of this proceeding.

Demand Side Management Adjustor Charge. The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan ("DSM Plan") annually for review by and approval of the ACC. On March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also ruled that verified energy savings from APS's resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standards; however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from conservation voltage reduction in the calculation of its LFCR mechanism.

On June 1, 2016, APS filed its 2017 DSM Plan, in which APS proposed programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand.  The requested budget in the 2017 DSM Plan is $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and requested that the budget be increased to $66.6 million. On August 15, 2017, the ACC approved the amended 2017 DSM Plan.

On September 1, 2017, APS filed its 2018 DSM Plan, which proposes modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Plan seeks a reduced requested budget of $52.6 million and requests a waiver of the Electric Energy Efficiency Standard for 2018.   On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels, but kept the overall budget at $52.6 million.

Electric Energy Efficiency. On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards should be modified.  The ACC held a series of three workshops in March and April 2014 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.

On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. On July 12, 2016, the ACC Commissioners ordered that ACC staff convene a workshop within 120 days to discuss a number of issues related to the Electric Energy Efficiency Standards, including the process of determining the cost effectiveness of DSM programs and the treatment of peak demand and capacity reductions, among others. ACC staff convened the workshop on November 29, 2016 and sought public comment on potential revisions to the Electric Energy Efficiency Standards. APS cannot predict the outcome of this proceeding.

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

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

• An adjustment to the PSA rate is made annually each February 1 (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 or refunded through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and

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

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2017 and 2016 (dollars in thousands):

	Twelve Months Ended December 31,
	2017		2016
Beginning balance	$	12,465	$	(9,688	)
Deferred fuel and purchased power costs — current period	48,405		60,303
Amounts refunded/(charged) to customers	14,767		(38,150		)
Ending balance	$	75,637	$	12,465

The PSA rate for the PSA year beginning February 1, 2017 was $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year.  This rate was comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh. On August 19, 2017, the PSA rate was revised to $0.000555 per kWh as part of the 2017 Rate Case Decision. This new rate was comprised of a forward component of $0.000876 per kWh and a historical component of $(0.000321) per kWh. On November 30, 2017, APS submitted its calculation for the 2018 PSA year beginning February 1, 2018. The current PSA rate is $.004555 per kWh consisting of a forward component of $.002009 per kWh and a historical component of $.002546 per kWh.

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.  In July 2008, the 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, 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 Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.

Effective June 1, 2016, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $24.9 million for the twelve-month period beginning June 1, 2016 in accordance with the FERC-approved formula.  An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2016.    

Effective June 1, 2017, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $35.1 million for the twelve-month period beginning June 1, 2017 in accordance with the FERC-approved formula.  An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2017.

On January 31, 2017, APS made a filing to reduce the Post-Employment Benefits Other than Pension expense reflected in its FERC transmission formula rate calculation to recognize certain savings resulting from plan design changes to the other postretirement benefit plans.  A transmission customer intervened and protested certain aspects of APS’s filing.  FERC initiated a proceeding under Section 206 of the Federal Power Act to evaluate the justness and reasonableness of the revised formula rate filing APS proposed.  APS entered into a settlement agreement with the intervening transmission customer, which was filed with FERC for approval on September 26, 2017. FERC approved the settlement agreement without modification or condition on December 21, 2017.

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 DG such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were first 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.  These amounts were revised in the 2017 Settlement Agreement to 2.5 cents for both lost residential and non-residential kWh. The LFCR adjustment has a year-over-year cap of 1% of retail revenues.  Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year.  The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs.  DG sales losses are determined from the metered output from the DG units.

APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase). The ACC approved the 2016 annual LFCR effective beginning in May 2016. APS filed its 2017 LFCR adjustment on January 13, 2017 requesting an LFCR adjustment of $63.7 million (a $17.3 million per year increase over 2016 levels). On April 5, 2017, the ACC approved the 2017 annual LFCR adjustment as filed, effective with the first billing cycle of April 2017. On February 15, 2018, APS filed its LFCR Adjustment, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 million (a $3 million per year decrease over 2017 levels). Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, a one or two month delay in implementation does not have an adverse effect on APS.

Tax Expense Adjustor Mechanism and FERC Tax Filing.  As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. On December 22, 2017 the Tax Cuts and Jobs Act (“Tax Act”) was enacted.  This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018.

On January 8, 2018, APS filed an application with the ACC requesting that the TEAM be implemented in two steps.  The first addresses the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and, if approved, would reduce rates by $119.1 million annually through an equal cents per kWh credit.  APS asked that this decrease become effective February 1, 2018. On February 22, 2018, the ACC approved the reduction of rates by $119.1 million annually through an equal cents per kWh credit applied to all but a small subset of customers who are taking service under specially-approved tariffs. The rate reduction will be effective March 1, 2018.

The second step will address the amortization of excess deferred taxes previously collected from customers. APS is analyzing the final impact of the Tax Act provisions related to deferred taxes and intends to make a second TEAM filing later in 2018.

The TEAM expressly applies to APS's retail rates with the exception noted above. The Company expects to make a filing with FERC in the first quarter of 2018 seeking authorization to provide for the cost reductions resulting from the income tax changes in its wholesale transmission rates.

Net Metering

In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of DG to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases.  A hearing was held in April 2016. On October 7, 2016, the Administrative Law Judge issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended opinion and order by the Administrative Law Judge. After making several amendments, the ACC approved the recommended opinion and order by a 4-1 vote. As a result of the ACC’s action, effective as of APS’s 2017 Rate Case Decision, the current net metering tariff that governs payments for energy exported to the grid from rooftop solar systems was replaced by a more formula-driven approach that utilizes inputs from historical wholesale solar power costs and eventually an avoided cost methodology.

As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a RCP methodology, a method that is based on the price that APS pays for utility-scale solar projects on a five year rolling average, while a forecasted avoided cost methodology is being developed.  The price established by this RCP method will be updated annually (between general retail rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent general retail rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy.

In addition, the ACC made the following determinations:

• Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to August 19, 2017, the date new rates were effective based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility;

• Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and

• Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years.

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh is included in the 2017 Settlement Agreement and became effective on August 19, 2017.

On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC filed a Notice of Appeal in the Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.

System Benefits Charge

The 2012 Settlement Agreement provided that once APS achieved full funding of its decommissioning obligation under the sale leaseback agreements covering Unit 2 of Palo Verde, APS was required to implement a reduced System Benefits charge effective January 1, 2016.  Beginning on January 1, 2016, APS began implementing a reduced System Benefits charge.  The impact on APS retail revenues from the new System Benefits charge is an overall reduction of approximately $14.6 million per year with a corresponding reduction in depreciation and amortization expense. This adjustment is subsumed within the 2017 Settlement Agreement and its associated revenue requirement.

Subpoena from Arizona Corporation Commissioner Robert Burns

On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer.

On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay APS's obligations to comply with the subpoenas and decline to decide APS's motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed.

On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC staff.  As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns' suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel. On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the complaint. On February 15, 2018, the Superior Court dismissed Commissioner Burns’ complaint. The matter is subject to appeal. APS and Pinnacle West cannot predict the outcome of this matter.

In addition to the Superior Court proceedings discussed above, on August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the 2017 Rate Case Decision so that alleged issues of disqualification and bias on the part of the other Commissioners could be fully investigated. APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition.

Renewable Energy Ballot Initiative

On February 20, 2018, a coalition of renewable energy advocates filed with the Arizona Secretary of State a ballot initiative for an Arizona constitutional amendment requiring Arizona public service corporations to procure 50% of their energy supply from renewable sources by 2030. For purposes of the proposed amendment, eligible renewable sources would not include nuclear generating facilities. The stated goal of the Clean Energy for a Healthy Arizona coalition is to complete the necessary steps to allow the initiative to be placed on the November 2018 Arizona elections ballot. The coalition must present over 225,000 verifiable signatures to the Secretary of State by July 5, 2018 to meet that goal. APS intends to oppose this effort. We believe the initiative is irresponsible and would result in negative impacts to Arizona utility customers, the Arizona economy and our company. We cannot predict the outcome of this matter.

Clean Resource Energy Standard and Tariff

On January 30, 2018, ACC Commissioner Tobin proposed the CREST, which consists of a series of energy reform policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the Integrated Resource Plan process. The ACC has not yet initiated any formal proceedings with respect to Commissioner Tobin’s proposal; however, on February 22, 2018, the ACC Staff filed a Notice of Inquiry to further examine the matter. APS cannot predict the outcome of this matter.

Four Corners

SCE-Related Matters. On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners.  The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general retail rate case related to APS’s acquisition of the 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. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis.  This included the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates.  The 2012 Settlement Agreement also provided for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $56 million as of December 31, 2017 and is being amortized in rates over a total of 10 years. The ACC's rate adjustment decision was appealed and on September 26, 2017, the Court of Appeals affirmed the ACC's decision on the Four Corners rate adjustment.

As part of APS’s acquisition of SCE’s interest in Units 4 and 5, 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. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates.  APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter of 2016.  On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery, FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. On October 5, 2017, FERC issued an order denying APS's request for rehearing. FERC also upheld its prior determination that the agreement relating to the settlement was a jurisdictional contract and should have been filed with FERC. APS cannot predict whether or if the enforcement division will take any action. APS filed an appeal of FERC's July 1, 2016 and October 5, 2017 orders with the United States Court of Appeals for the Ninth Circuit on December 4, 2017. That proceeding is pending and APS cannot predict the outcome of the proceeding.

SCR Cost Recovery. On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Rate Rider to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5.  APS intends to file the SCR Rate Rider in April 2018. Consistent with the 2017 Rate Case Decision, the rate rider filing will be narrow in scope and will address only costs associated with this specific environmental compliance equipment. Also, as provided for in the 2017 Rate Case Decision, APS will request that the rate rider become effective no later than January 1, 2019. 

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of Cholla and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect on April 26, 2017.

Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS has been recovering a return on and of the net book value of the unit in base rates. Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs ($105 million as of December 31, 2017), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2026.

Navajo Plant

The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant will remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that will allow for decommissioning activities to begin after the plant ceases operations in December 2019. Various stakeholders including regulators, tribal representatives, the plant's coal supplier and the U.S. Department of the Interior have been meeting to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. Although we cannot predict whether any alternate plans will be found that would be acceptable to all of the stakeholders and feasible to implement, we believe it is probable that the Navajo Plant will cease operations in December 2019.

On February 14, 2017, the ACC opened a docket titled "ACC Investigation Concerning the Future of the Navajo Generating Station" with the stated goal of engaging stakeholders and negotiating a sustainable pathway for the Navajo Plant to continue operating in some form after December 2019. APS cannot predict the outcome of this proceeding.

APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($99 million as of December 31, 2017) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and APS's net income, cash flows, and financial position will be negatively impacted.

Regulatory Assets and Liabilities

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

S		December 31, 2017				December 31, 2016
	Amortization Through	Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	576,188	$	—	$	711,059
Retired power plant costs	2033	27,402		188,843		9,913		117,591
Income taxes - AFUDC equity	2047	3,828		142,852		6,305		152,118
Deferred fuel and purchased power — mark-to-market (Note 16)	2020	52,100		34,845		—		42,963
Four Corners cost deferral	2024	8,077		48,305		6,689		56,894
Income taxes — investment tax credit basis adjustment	2046	1,066		26,218		2,120		54,356
Lost fixed cost recovery (b)	2018	59,844		—		61,307		—
Palo Verde VIEs (Note 18)	2046	—		19,395		—		18,775
Deferred compensation	2036	—		36,413		—		35,595
Deferred property taxes	2027	8,569		74,926		—		73,200
Loss on reacquired debt	2038	1,637		15,305		1,637		16,942
AG-1 deferral	2022	2,654		8,472		—		5,868
Demand side management (b)	2017	—		—		3,744		—
Tax expense of Medicare subsidy	2024	1,236		7,415		1,513		10,589
Mead-Phoenix transmission line CIAC	2050	332		10,376		332		10,708
Deferred fuel and purchased power (b) (c)	2018	75,637		—		12,465		—
Coal reclamation	2026	1,068		12,396		418		5,182
Other	Various	4,638		353		432		1,588
Total regulatory assets (d)		$	248,088	$	1,202,302	$	106,875	$	1,313,428

(a) This asset represents the future recovery of pension 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 7 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, Transmission Cost Adjustor and Other Transmission Matters.”

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

		December 31, 2017				December 31, 2016
	Amortization Through	Current		Non-Current		Current		Non-Current
Excess deferred income taxes - Tax Cuts and Jobs Act	(a)	$	—	$	1,520,274	$	—	$	—
Asset retirement obligations	2057	—		332,171		—		279,976
Removal costs	(b)	18,238		209,191		29,899		223,145
Other post retirement benefits	(d)	37,642		151,985		32,662		123,913
Income taxes - deferred investment tax credit	2046	2,164		52,497		4,368		108,827
Income taxes - change in rates	2046	2,573		70,537		1,771		70,898
Spent nuclear fuel	2027	6,924		62,132		—		71,726
Renewable energy standard (c)	2018	23,155		—		26,809		—
Demand side management (c)	2019	3,066		4,921		—		20,472
Sundance maintenance	2030	—		16,897		—		15,287
Deferred gains on utility property	2022	4,423		10,988		2,063		8,895
Four Corners coal reclamation	2038	1,858		18,921		—		18,248
Other	Various	43		2,022		2,327		7,529
Total regulatory liabilities		$	100,086	$	2,452,536	$	99,899	$	948,916

(a) See Note 4. While the majority of the excess deferred tax balance shown is subject to special amortization rules under federal income tax laws, which require amortization of the balance over the remaining regulatory life of the related property, treatment of a portion of the liability, and the month in which pass-through of the excess deferred tax balance will begin is subject to regulatory approval. This approval will be sought through the Company's TEAM adjustor mechanism and FERC filings in 2018. As a result, the Company cannot estimate the amount of this regulatory liability which is expected to reverse within the next 12 months.

(b) 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 11).

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

(d) See Note 7.

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Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

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, investment tax credit (“ITC”) basis adjustment and tax expense of Medicare subsidy.  The regulatory liabilities primarily relate to the change in income tax rates and deferred taxes resulting from ITCs.

On December 22, 2017, the Tax Cuts and Jobs Act ("Tax Act") was enacted. This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate to 21% effective January 1, 2018. In accordance with generally accepted accounting principles, the effects of this corporate tax rate reduction were recognized for the year ending December 31, 2017. As a result of this rate reduction, the Company has recognized a $1.14 billion reduction in its net deferred income tax liabilities as of December 31, 2017.

In accordance with accounting for regulated companies, the effect of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2017, to reflect the $1.14 billion reduction in its net deferred income tax liabilities caused by the rate reduction, APS has recorded a regulatory liability of $1.52 billion and a new $377 million deferred tax asset. The company intends to amortize the regulatory liability in accordance with applicable federal income tax laws, which require the amortization of a majority of the balance over the remaining regulatory life of the related property, and in a manner to be approved by its federal and state regulatory agencies. See Note 3 for more details.

Additionally, as a result of the corporate tax rate reduction, the Company recorded income tax expense of $9.3 million, for the year ended December 31, 2017, to recognize the effect of certain reductions in deferred tax assets, for which the Company did not believe recovery was probable through its revenue requirement.

Several sections of the Tax Cuts and Jobs Act contain technical ambiguities. These ambiguities include certain transition rules regarding the applicability of bonus depreciation to property acquired, or under construction, prior to September 28, 2017 and the continued deductibility of certain executive compensation arrangements in place prior to November 3, 2017. Management has recognized tax positions which it believes are more likely than not to be sustained upon examination based upon its interpretation of this legislation. Clarifying guidance may be issued through additional legislation, Treasury regulations, or other technical guidance, within the next 12 months which may impact the income tax effects of the Tax Act as recorded by the Company. As of December 31, 2017, the Company does not have a reasonable estimate of what the income tax effects of such clarifying guidance may be, if any.

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.

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 18).  As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS 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):

	Pinnacle West Consolidated									APS Consolidated
	2017			2016			2015			2017			2016			2015
Total unrecognized tax benefits, January 1	$	36,075		$	34,447		$	44,775		$	36,075		$	34,447		$	44,775
Additions for tax positions of the current year	2,937			2,695			2,175			2,937			2,695			2,175
Additions for tax positions of prior years	4,783			886			—			4,783			886			—
Reductions for tax positions of prior years for:
Changes in judgment	(1,829		)	(1,953		)	(10,244		)	(1,829		)	(1,953		)	(10,244		)
Settlements with taxing authorities	—			—			—			—			—			—
Lapses of applicable statute of limitations	—			—			(2,259		)	—			—			(2,259		)
Total unrecognized tax benefits, December 31	$	41,966		$	36,075		$	34,447		$	41,966		$	36,075		$	34,447

Included in the balances of unrecognized tax benefits are the following tax positions that, if recognized, would decrease our effective tax rate (dollars in thousands):

	Pinnacle West Consolidated						APS Consolidated
	2017		2016		2015		2017		2016		2015
Tax positions, that if recognized, would decrease our effective tax rate	$	16,373	$	11,313	$	9,523	$	16,373	$	11,313	$	9,523

As of the balance sheet date, the tax year ended December 31, 2014 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 2013.

We reflect interest and penalties, if any, on unrecognized tax benefits in the Pinnacle West Consolidated and APS Consolidated Statements of Income as income tax expense.  The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands): 

	Pinnacle West Consolidated							APS Consolidated
	2017		2016		2015			2017		2016		2015
Unrecognized tax benefit interest expense/(benefit) recognized	$	577	$	529	$	(161	)	$	577	$	529	$	(161	)

Following are the total amount of accrued liabilities for interest recognized related to unrecognized benefits that could reverse and decrease our effective tax rate to the extent matters are settled favorably (dollars in thousands):

	Pinnacle West Consolidated						APS Consolidated
	2017		2016		2015		2017		2016		2015
Unrecognized tax benefit interest accrued	$	1,910	$	1,333	$	804	$	1,910	$	1,333	$	804

Additionally, as of December 31, 2017, we have recognized less than $1 million of interest expense to be paid on the underpayment 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):

	Pinnacle West Consolidated							APS Consolidated
	Year Ended December 31,							Year Ended December 31,
	2017		2016		2015			2017		2016		2015
Current:
Federal	$	11,624	$	8,630	$	(12,335	)	$	21,512	$	711	$	6,485
State	3,052		1,259		4,763			2,778		4,276		7,813
Total current	14,676		9,889		(7,572		)	24,290		4,987		14,298
Deferred:
Federal	223,729		201,743		221,505			221,078		215,178		208,326
State	19,867		24,779		23,787			23,800		25,677		23,217
Total deferred	243,596		226,522		245,292			244,878		240,855		231,543
Income tax expense	$	258,272	$	236,411	$	237,720		$	269,168	$	245,842	$	245,841

On the APS Consolidated Statements of Income, federal and state income taxes are allocated between operating income and other income.

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

	Pinnacle West Consolidated									APS Consolidated
	Year Ended December 31,									Year Ended December 31,
	2017			2016			2015			2017			2016			2015
Federal income tax expense at 35% statutory rate	$	268,177		$	244,278		$	242,869		$	277,540		$	254,617		$	250,267
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	14,897			16,311			18,265			17,276			18,750			20,433
Credits and favorable adjustments related to prior years resolved in current year	—			—			(2,169		)	—			—			(1,892		)
Medicare Subsidy Part-D	853			844			837			853			844			837
Stock compensation	(6,659		)	(2,951		)	—			(3,489		)	(1,937		)	—
Excess Deferred Income Taxes - Tax Cuts and Jobs Act	9,348			—			—			9,431			—			—
Allowance for equity funds used during construction (see Note 1)	(12,937		)	(11,724		)	(9,711		)	(12,937		)	(11,724		)	(9,711		)
Palo Verde VIE noncontrolling interest (see Note 18)	(6,823		)	(6,823		)	(6,626		)	(6,823		)	(6,823		)	(6,626		)
Investment tax credit amortization	(6,715		)	(5,887		)	(5,527		)	(6,715		)	(5,887		)	(5,527		)
Other	(1,869		)	2,363			(218		)	(5,968		)	(1,998		)	(1,940		)
Income tax expense	$	258,272		$	236,411		$	237,720		$	269,168		$	245,842		$	245,841

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

	Pinnacle West Consolidated						APS Consolidated
	December 31,						December 31,
	2017			2016			2017			2016
DEFERRED TAX ASSETS
Risk management activities	$	25,103		$	26,614		$	25,103		$	26,614
Regulatory liabilities:
Excess Deferred Income Taxes - Tax Cuts and Jobs Act	376,906			—			376,906			—
Asset retirement obligation and removal costs	135,847			200,140			135,847			200,140
Unamortized investment tax credits	54,661			113,195			54,661			113,195
Other postretirement benefits	47,021			60,375			47,021			60,375
Other	37,489			63,311			37,489			63,311
Pension liabilities	83,126			204,436			77,280			194,981
Renewable energy incentives	33,546			56,379			33,546			56,379
Credit and loss carryforwards	53,946			75,944			1,920			1,645
Other	102,432			158,421			108,223			187,453
Total deferred tax assets	950,077			958,815			897,996			904,093
DEFERRED TAX LIABILITIES
Plant-related	(2,220,886		)	(3,297,989		)	(2,220,886		)	(3,297,989		)
Risk management activities	(491		)	(7,594		)	(491		)	(7,594		)
Other postretirement assets	(66,134		)	(63,477		)	(65,733		)	(62,819		)
Regulatory assets:
Allowance for equity funds used during construction	(36,365		)	(61,088		)	(36,365		)	(61,088		)
Deferred fuel and purchased power — mark-to-market	(40,778		)	(21,396		)	(40,778		)	(21,396		)
Pension benefits	(142,848		)	(274,184		)	(142,848		)	(274,184		)
Retired power plant costs (see Note 3)	(53,611		)	(49,166		)	(53,611		)	(49,166		)
Other	(74,423		)	(123,987		)	(74,423		)	(123,987		)
Other	(5,346		)	(5,166		)	(5,346		)	(5,165		)
Total deferred tax liabilities	(2,640,882		)	(3,904,047		)	(2,640,481		)	(3,903,388		)
Deferred income taxes — net	$	(1,690,805	)	$	(2,945,232	)	$	(1,742,485	)	$	(2,999,295	)

As of December 31, 2017, the deferred tax assets for credit and loss carryforwards relate primarily to federal general business credits of approximately $79 million, which first begin to expire in 2034, and other federal and state credit carryforwards of $6 million, which first begin to expire in 2031. The credit and loss carryforwards amount above has been reduced by $31 million of unrecognized tax benefits.

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Lines of Credit and Short-Term Borrowings

12 Months Ended

Dec. 31, 2017

Lines of Credit and Short-Term Borrowings

Lines of Credit and Short-Term Borrowings

Lines of Credit and Short-Term Borrowings

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes.

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2017 and 2016 (dollars in thousands):

	December 31, 2017								December 31, 2016
	Pinnacle West			APS		Total			Pinnacle West			APS			Total
Commitments under Credit Facilities	$	325,000		$	1,000,000	$	1,325,000		$	275,000		$	1,000,000		$	1,275,000
Outstanding Commercial Paper and Revolving Credit Facility Borrowings	(95,400		)	—		(95,400		)	(41,700		)	(135,500		)	(177,200		)
Amount of Credit Facilities Available	$	229,600		$	1,000,000	$	1,229,600		$	233,300		$	864,500		$	1,097,800
Weighted-Average Commitment Fees	0.125%			0.100%					0.125%			0.100%

Pinnacle West

At December 31, 2017, Pinnacle West had a $200 million facility that matures in May 2021. 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, 2017, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $29.4 million of commercial paper borrowings.

On July 31, 2017, Pinnacle West amended its 364-day unsecured revolving credit facility to increase its capacity from $75 million to $125 million, and to extend the termination date of the facility from August 30, 2017 to July 30, 2018.  Borrowings under the facility bear interest at LIBOR plus 0.80% per annum. At December 31, 2017, Pinnacle West had $66 million outstanding under the facility.

APS

On June 29, 2017, APS replaced its $500 million revolving credit facility that would have matured in September 2020, with a new $500 million facility that matures in June 2022.

At December 31, 2017, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in May 2021 and the above-mentioned $500 million facility. APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2017, APS had no commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities. See "Financial Assurances" in Note 10 for a discussion of APS's other outstanding letters of credit.

Debt Provisions

On February 6, 2013, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to a sum of 7% of APS’s capitalization, and $500 million (which is required to be used for costs relating to purchases of natural gas and power). This financing order was set to expire on December 31, 2017; however, on December 15, 2016, APS filed a financing application with the ACC requesting continuation of its authorization of (i) Continuing Long-Term Debt of $5.1 billion and (ii) Continuing Short-Term Debt. The financing application is currently pending with the ACC. The authorizations approved in the 2013 order continue until further order of the ACC with respect to the pending application. See Note 6 for additional long-term debt provisions.

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Long-Term Debt and Liquidity Matters

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Long-Term Debt and Liquidity Matters

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, 2017 and 2016 (dollars in thousands):

	Maturity	Interest	December 31,
	Dates (a)	Rates	2017			2016
APS
Pollution control bonds:
Variable	2029	(b)	$	35,975		$	35,975
Fixed	2024-2029	1.75%-4.70%	147,150			147,150
Total pollution control bonds			183,125			183,125
Senior unsecured notes	2019-2046	2.20%-8.75%	4,275,000			3,725,000
Term loans	2018-2019	(c)	150,000			150,000
Unamortized discount			(11,288		)	(11,816		)
Unamortized premium			8,049			4,506
Unamortized debt issuance cost			(31,594		)	(29,030		)
Total APS long-term debt			4,573,292			4,021,785
Less current maturities			82,000			—
Total APS long-term debt less current maturities			4,491,292			4,021,785
Pinnacle West
Term loan	2017	(d)	—			125,000
Senior unsecured notes	2020	2.25%	300,000			—
Unamortized discount			(184		)	—
Unamortized debt issuance cost			(1,395		)	—
Total PNW long-term debt			298,421			125,000
Less current maturities			—			125,000
Total PNW long-term debt less current maturities			298,421			—
TOTAL LONG-TERM DEBTLESS CURRENT MATURITIES			$	4,789,713		$	4,021,785

(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 1.77% at December 31, 2017 and 0.81% at December 31, 2016.

(c) The weighted-average interest rate was 2.236% at December 31, 2017, and 1.427% at December 31, 2016.

(d) The interest rate was 1.520% at December 31, 2016.

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

Year	Consolidated Pinnacle West		Consolidated APS
2018	$	82,000	$	82,000
2019	600,000		600,000
2020	550,000		250,000
2021	—		—
2022	—		—
Thereafter	3,676,125		3,676,125
Total	$	4,908,125	$	4,608,125

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 thousands):

	As of December 31, 2017				As of December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	298,421	$	298,608	$	125,000	$	125,000
APS	4,573,292		5,006,348		4,021,785		4,300,789
Total	$	4,871,713	$	5,304,956	$	4,146,785	$	4,425,789

Credit Facilities and Debt Issuances

Pinnacle West

On November 30, 2017, Pinnacle West issued $300 million of 2.25% unsecured senior notes that mature on November 30, 2020.  The net proceeds from the sale were used to repay our $125 million term loan and for general corporate purposes.

APS

On March 21, 2017, APS issued an additional $250 million par amount of its outstanding 4.35% senior unsecured notes that mature on November 15, 2045.  The net proceeds from the sale were used to refinance commercial paper borrowings and to replenish cash temporarily used to fund capital expenditures.

On September 11, 2017, APS issued $300 million of 2.95% senior unsecured notes that mature on September 15, 2027. The net proceeds from the sale were used to refinance commercial paper and other indebtedness and to replenish cash used to fund capital expenditures.

On November 30, 2017, PNW contributed $150 million into APS in the form of an equity infusion.  APS used this contribution to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes.

See “Lines of Credit and Short-Term Borrowings” in Note 5 and “Financial Assurances” in Note 10 for discussion of APS’s separate outstanding 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, 2017, the ratio was approximately 50% for Pinnacle West and 47% 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. Its total shareholder equity was approximately $5.3 billion, and total capitalization was approximately $10.0 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $4.0 billion, assuming APS’s total capitalization remains the same. APS was in compliance with this common equity ratio requirement as of December 31, 2017.

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 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 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 was set to expire on December 31, 2017; however, on December 15, 2016, APS filed a financing application with the ACC requesting continuation of its authorization of (i) Continuing Long-Term Debt of $5.1 billion and (ii) Continuing Short-Term Debt.  The financing application is currently pending with the ACC. The authorizations approved in the 2013 order continue until further order of the ACC with respect to the pending application.  See Note 5 for additional short-term debt provisions.

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Retirement Plans and Other Benefits

12 Months Ended

Dec. 31, 2017

Retirement Benefits [Abstract]

Retirement Plans and Other Benefits

Retirement Plans and Other Postretirement 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.  We calculate the benefits based on age, years of service and pay.

Pinnacle West also sponsors other postretirement benefit plans (Pinnacle West Capital Corporation Group Life and Medical Plan and Pinnacle West Capital Corporation Post-65 Retiree Health Reimbursement Arrangement) for the employees of Pinnacle West and its subsidiaries.  These plans provide 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.

On September 30, 2014, Pinnacle West announced plan design changes to the postretirement benefit plan, which required an interim remeasurement of the benefit obligation for the plan. Effective January 1, 2015, those eligible retirees and dependents over age 65 and on Medicare can choose to be enrolled in a Health Reimbursement Arrangement ("HRA"). The Company is providing a subsidy allowing post-65 retirees to purchase a Medicare supplement plan on a private exchange network. The remeasurement of the benefit obligation included updating the assumptions. The 2014 remeasurement also resulted in a decrease in Pinnacle West’s other postretirement benefit obligation of $316 million, which was offset by the related regulatory asset and accumulated other comprehensive income.

Because of plan changes in September 2014, the Company is currently in the process of seeking IRS approval to move approximately $186 million of other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. In December 2016, FERC approved a methodology for determining the amount of other postretirement benefit trust assets to transfer into a new trust account to pay for active union employee medical costs. On January 2, 2018, these funds were moved to the new trust account.  The Company negotiated a draft Closing Agreement granting tentative approval from the IRS prior to the transfer. Subsequent to the transfer, the Company submitted proof of the transfer to the IRS and expects to execute a final Closing Agreement early in 2018. Per the terms of an order from FERC, the Company must also make an informational filing with FERC. The Company made this FERC filing during February 2018. It is the Company’s understanding that completion of these regulatory requirements will then permit access to the approximately $186 million for the sole purpose of paying active union employee medical 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 13 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 or regulatory liability.  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 three years beginning in July 2012.  We amortized approximately $5 million in 2015, $8 million in 2014, $8 million in 2013 and $4 million in 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 or liability) (dollars in thousands):

	Pension									Other Benefits
	2017			2016			2015			2017			2016			2015
Service cost-benefits earned during the period	$	54,858		$	53,792		$	59,627		$	17,119		$	14,993		$	16,827
Interest cost on benefit obligation	129,756			131,647			123,983			29,959			29,721			28,102
Expected return on plan assets	(174,271		)	(173,906		)	(179,231		)	(53,401		)	(36,495		)	(36,855		)
Amortization of:
Prior service cost (credit)	81			527			594			(37,842		)	(37,883		)	(37,968		)
Net actuarial loss	47,900			40,717			31,056			5,118			4,589			4,881
Net periodic benefit cost	$	58,324		$	52,777		$	36,029		$	(39,047	)	$	(25,075	)	$	(25,013	)
Portion of cost charged to expense	$	27,295		$	26,172		$	20,036		$	(18,274	)	$	(12,435	)	$	(10,391	)

See Note 2 for additional information regarding accounting changes relating to ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.

The following table shows the plans’ changes in the benefit obligations and funded status for the years 2017 and 2016 (dollars in thousands):

	Pension						Other Benefits
	2017			2016			2017			2016
Change in Benefit Obligation
Benefit obligation at January 1	$	3,204,462		$	3,033,803		$	716,445		$	647,020
Service cost	54,858			53,792			17,119			14,993
Interest cost	129,756			131,647			29,959			29,721
Benefit payments	(166,342		)	(142,247		)	(30,144		)	(26,231		)
Actuarial loss	171,452			127,467			20,014			50,942
Benefit obligation at December 31	3,394,186			3,204,462			753,393			716,445
Change in Plan Assets
Fair value of plan assets at January 1	2,675,357			2,542,774			882,651			833,017
Actual return on plan assets	428,374			166,408			139,367			63,463
Employer contributions	100,000			100,000			353			819
Benefit payments	(146,704		)	(133,825		)	—			(14,648		)
Fair value of plan assets at December 31	3,057,027			2,675,357			1,022,371			882,651
Funded Status at December 31	$	(337,159	)	$	(529,105	)	$	268,978		$	166,206

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, 2017 and 2016 (dollars in thousands):

	2017		2016
Projected benefit obligation	$	3,394,186	$	3,204,462
Accumulated benefit obligation	3,227,233		3,049,406
Fair value of plan assets	3,057,027		2,675,357

The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2017 and 2016 (dollars in thousands):

	Pension						Other Benefits
	2017			2016			2017		2016
Noncurrent asset	$	—		$	—		$	268,978	$	166,206
Current liability	(9,859		)	(19,795		)	—		—
Noncurrent liability	(327,300		)	(509,310		)	—		—
Net amount recognized	$	(337,159	)	$	(529,105	)	$	268,978	$	166,206

The following table shows the details related to accumulated other comprehensive loss as of December 31, 2017 and 2016 (dollars in thousands): 

	Pension						Other Benefits
	2017			2016			2017			2016
Net actuarial loss	$	643,199		$	773,750		$	75,439		$	146,509
Prior service cost (credit)	—			81			(265,575		)	(303,417		)
APS’s portion recorded as a regulatory (asset) liability	(576,188		)	(711,059		)	189,627			156,575
Income tax expense (benefit)	(24,915		)	(24,202		)	853			833
Accumulated other comprehensive loss	$	42,096		$	38,570		$	344		$	500

The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets and liabilities into net periodic benefit cost in 2018 (dollars in thousands):

	Pension		Other Benefits
Net actuarial loss	$	28,334	$	—
Prior service credit	—		(37,842		)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2018	$	28,334	$	(37,842	)

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,
	2017		2016		2017		2016		2015
Discount rate – pension	3.65	%	4.08	%	4.08	%	4.37	%	4.02	%
Discount rate – other benefits	3.71	%	4.17	%	4.17	%	4.52	%	4.14	%
Rate of compensation increase	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%
Expected long-term return on plan assets - pension	N/A		N/A		6.55	%	6.90	%	6.90	%
Expected long-term return on plan assets - other benefits	N/A		N/A		6.05	%	4.45	%	4.45	%
Initial healthcare cost trend rate (pre-65 participants)	7.00	%	7.00	%	7.00	%	7.00	%	7.00	%
Initial healthcare cost trend rate (post-65 participants)	4.75	%	5.00	%	5.00	%	5.00	%	5.00	%
Ultimate healthcare cost trend rate	4.75	%	5.00	%	5.00	%	5.00	%	5.00	%
Number of years to ultimate trend rate (pre-65 participants)	8		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 2018, we are assuming a 6.05% long-term rate of return for pension assets and 5.55% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

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 on our December 31, 2017 amounts (dollars in thousands): 

	1% Increase		1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	$	8,424	$	(5,616	)
Effect on service and interest cost components of net periodic other postretirement benefit costs	9,145		(7,037		)
Effect on the accumulated other postretirement benefit obligation	128,203		(98,143		)

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.

Changes in the value of long-term fixed income assets, also known as liability-hedging assets, are intended 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 and other government agencies, U.S. Treasury Futures Contracts, and fixed income debt securities issued by corporations.  Long-term fixed income assets may also include interest rate swaps, 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 also hold investments in return-generating assets by holding securities in partnerships, common and collective trusts and mutual funds.

Based on the IPS, and given the pension plan's funded status at year-end 2017, the target and actual allocation for the pension plan at December 31, 2017 are as follows:

	Pension
	Target Allocation		Actual Allocation
Long-term fixed income assets	62	%	58	%
Return-generating assets	38	%	42	%
Total	100	%	100	%

The permissible range is within +/- 3% of the target allocation shown in the above table, and also considers the Plan's funded status.

The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-generating assets:

Asset Class	Target Allocation
Equities in US and other developed markets	18	%
Equities in emerging markets	6	%
Alternative investments	14	%
Total	38	%

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, 2017, the asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for different asset allocation target mixes depending on the characteristics of the liability.  Some of these asset allocation target mixes vary with the plan’s funded status. The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2017:

	Other Benefits
	Actual Allocation
Long-term fixed income assets	67	%
Return-generating assets	33	%
Total	100	%

See Note 13 for a discussion on the fair value hierarchy and how fair value methodologies are applied.  The plans invest directly in fixed income, U.S. Treasury Futures Contracts, and equity securities, in addition to investing indirectly in fixed income securities, equity securities and real estate through the use of mutual funds, partnerships and 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.  U.S. Treasury Future Contracts are valued using the quoted active market prices from the exchange on which they trade, 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.

Mutual funds, partnerships, and common and collective trusts are valued utilizing a net asset value (NAV) concept or its equivalent. Mutual funds, which includes exchange traded funds (ETFs), are classified as Level 1 and valued using a NAV that is observable and based on the active market in which the fund trades.

Common and collective trusts are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 Index).  The trust's shares are offered to a limited group of investors, and are not traded in an active market. Investments in common and collective trusts are valued using NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for trusts investing in exchange traded equities, and fixed income securities is derived from the market prices of the underlying securities held by the trusts. The NAV for trusts investing in real estate is derived from the appraised values of the trust's underlying real estate assets.  As of December 31, 2017, the plans were able to transact in the common and collective trusts at NAV.

Investments in partnerships are also valued using the concept of NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for these investments is derived from the value of the partnerships' underlying assets. The plan's partnerships holdings relate to investments in high-yield fixed income instruments and assets of privately held portfolio companies. Certain partnerships also include funding commitments that may require the plan to contribute up to $75 million to these partnerships; as of December 31, 2017, approximately $58 million of these commitments have been funded.

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, 2017, by asset category, are as follows (dollars in thousands):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Other (a)		Balance at December 31, 2017
Pension Plan:
Cash and cash equivalents	$	3,830	$	—	$	—	$	3,830
Fixed income securities:
Corporate	—		1,365,194		—		1,365,194
U.S. Treasury	221,291		—		—		221,291
Other (b)	—		100,599		—		100,599
Common stock equities (c)	228,088		—		—		228,088
Mutual funds (d)	233,732		—		—		233,732
Common and collective trusts:
Equities	—		—		408,763		408,763
Real estate	—		—		171,569		171,569
Fixed Income	—		—		90,869		90,869
Partnerships	—		—		133,379		133,379
Short-term investments and other (e)	—		1,208		98,505		99,713
Total	$	686,941	$	1,467,001	$	903,085	$	3,057,027
Other Benefits:
Cash and cash equivalents	$	143	$	—	$	—	$	143
Fixed income securities:
Corporate	—		306,008		—		306,008
U.S. Treasury	336,963		—		—		336,963
Other (b)	—		32,508		—		32,508
Common stock equities (c)	196,153		—		—		196,153
Mutual funds (d)	39,269		—		—		39,269
Common and collective trusts:
Equities	—		—		75,310		75,310
Real estate	—		—		15,422		15,422
Short-term investments and other (e)	11,268		149		9,178		20,595
Total	$	583,796	$	338,665	$	99,910	$	1,022,371

(a) These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy.

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

(c) This category primarily consists of U.S. common stock equities.

(d) These funds invest in U.S. and international common stock equities.

(e) This category includes plan receivables and payables.

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2016, by asset category, are as follows (dollars in thousands):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Other (a)		Balance at December 31, 2016
Pension Plan:
Cash and cash equivalents	$	13,995	$	—	$	—	$	13,995
Fixed income securities:
Corporate	—		1,210,453		—		1,210,453
U.S. Treasury	112,583		—		—		112,583
Other (b)	—		102,170		—		102,170
Common stock equities (c)	235,109		—		—		235,109
Mutual funds (d)	251,506		—		—		251,506
Common and collective trusts:
Equities	—		—		266,840		266,840
Real estate	—		—		161,449		161,449
Partnerships	—		—		208,915		208,915
Short-term investments and other (e)	—		—		112,337		112,337
Total	$	613,193	$	1,312,623	$	749,541	$	2,675,357
Other Benefits:
Cash and cash equivalents	$	304	$	—	$	—	$	304
Fixed income securities:
Corporate	—		268,193		—		268,193
U.S. Treasury	145,255		—		—		145,255
Other (b)	—		34,506		—		34,506
Common stock equities (c)	243,741		—		—		243,741
Mutual funds (d)	67,418		—		—		67,418
Common and collective trusts:
Equities	—		—		95,814		95,814
Real estate	—		—		14,509		14,509
Partnerships	—		—		3,060		3,060
Short-term investments and other (e)	—		—		9,851		9,851
Total	$	456,718	$	302,699	$	123,234	$	882,651

(a) These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy.

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

(c) This category primarily consists of U.S. common stock equities.

(d) These funds invest in U.S. and international common stock equities.

(e) This category includes plan receivables and payables.

Contributions

Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  We made contributions to our pension plan totaling $100 million in 2017, $100 million in 2016, and $100 million in 2015.  The minimum required contributions for the pension plan are zero for the next three years.  We expect to make voluntary contributions up to a total of $250 million during the 2018-2020 period.  With regard to contributions to our other postretirement benefit plans, we made a contribution of approximately $1 million in each of 2017, 2016 and 2015.  We do not expect to make any contributions over the next three years to our other postretirement benefit plans. APS funds its share of the contributions.  APS’s share of the pension plan contribution was approximately $100 million in 2017, $100 million in 2016 and $100 million in 2015.  APS’s share of the contributions to the other postretirement benefit plan was approximately $1 million in 2017, 2016 and 2015.

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
2018	$	175,383	$	31,891
2019	181,902		34,000
2020	191,586		35,658
2021	196,583		37,090
2022	201,463		37,860
Years 2023-2027	1,068,568		191,207

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 2017, 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 $10 million for 2017, $10 million for 2016, and $9 million for 2015.

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Leases

12 Months Ended

Dec. 31, 2017

Leases [Abstract]

Leases

Leases

We lease certain vehicles, land, buildings, equipment and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates. See Note 2 for a discussion of the new lease accounting standard.

Total lease expense recognized in the Consolidated Statements of Income was $18 million in 2017, $16 million in 2016, and $17 million in 2015.  APS’s lease expense was $17 million in 2017, $15 million in 2016, and $14 million in 2015.

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

Year	Pinnacle West Consolidated		APS
2018	$	13,412	$	13,110
2019	11,054		10,802
2020	9,641		9,392
2021	7,105		6,858
2022	4,609		4,510
Thereafter	55,940		53,605
Total future lease commitments	$	101,761	$	98,277

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 impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation.  See Note 18 for a discussion of VIEs.

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Jointly-Owned Facilities

12 Months Ended

Dec. 31, 2017

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

Jointly-Owned Facilities

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 which are included in the corresponding operating expenses on our Consolidated Statements of Income. We are also responsible 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, 2017 (dollars in thousands):

	Percent Owned			Plant in Service		Accumulated Depreciation		Construction Work in Progress
Generating facilities:
Palo Verde Units 1 and 3	29.1	%		$	1,872,104	$	1,092,049	$	24,257
Palo Verde Unit 2 (a)	16.8	%		619,263		364,516		14,672
Palo Verde Common	28.0	%	(b)	726,223		262,065		46,577
Palo Verde Sale Leaseback			(a)	351,050		241,405		—
Four Corners Generating Station	63.0	%		1,196,683		568,304		240,514
Cholla common facilities (c)	50.5	%		180,907		69,633		1,091
Transmission facilities:
ANPP 500kV System	34.0	%	(b)	130,767		46,400		684
Navajo Southern System	27.5	%	(b)	85,299		28,915		180
Palo Verde — Yuma 500kV System	18.1	%	(b)	14,765		6,614		486
Four Corners Switchyards	63.2	%	(b)	66,386		12,605		327
Phoenix — Mead System	17.1	%	(b)	39,383		17,600		41
Palo Verde — Rudd 500kV System	50.0	%		97,600		23,884		245
Morgan — Pinnacle Peak System	64.6	%	(b)	117,721		14,569		1
Round Valley System	50.0	%		515		141		—
Palo Verde — Morgan System	90.9	%	(b)	137,887		3,948		94,350
Hassayampa — North Gila System	80.0	%		142,541		6,953		—
Cholla 500kV Switchyard	85.7	%		5,243		1,312		190
Saguaro 500kV Switchyard	60.0	%		20,473		12,574		—
Kyrene — Knox System	50.0	%		578		297		—

(a) See Note 18.

(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.

APS also has a 14% ownership in the Navajo Plant.  In the second quarter of 2017, APS’s remaining net book value of its interest was reclassified from property, plant and equipment to a regulatory asset.  See “Navajo Plant” in Note 3 for more details.

4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners. At December 31, 2017, 4CA had plant in service of $141 million, accumulated depreciation of $83 million and construction work in progress of $25 million.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Palo Verde 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 second breach of contract lawsuit against the DOE in the United States Court of Federal Claims ("Court of Federal Claims").  The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde's spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.  On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on the amount of reported net income. In addition, the settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019.

APS has submitted three claims pursuant to the terms of the August 18, 2014 settlement agreement, for three separate time periods during July 1, 2011 through June 30, 2016. The DOE has approved and paid $65.2 million for these claims (APS’s share is $19 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 retail rate case settlement, this regulatory liability is being refunded to customers (see Note 3). APS's next claim pursuant to the terms of the August 18, 2014 settlement agreement was submitted to the DOE in the fourth quarter of 2017 in the amount of $9 million (APS's share is $2.6 million). In February 2018, the DOE approved this claim.

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-wide 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 approximately $13.4 billion per occurrence.  Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers ("ANI").  The remaining balance of approximately $13.0 billion of liability coverage is provided through a mandatory industry-wide retrospective premium program.  If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums.  The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $127.3 million, subject to a maximum annual premium of $19 million per incident.  Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $111.1 million, with a maximum annual retrospective premium of approximately $16.6 million.

The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion.  APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited ("NEIL").  APS is subject to retrospective premium adjustments 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 $24 million for each retrospective premium 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 $64.8 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 various fuel and purchased power contracts and purchase obligations with terms expiring between 2018 and 2043 that include required purchase provisions.  APS estimates the contract requirements to be approximately $715 million in 2018; $578 million in 2019; $548 million in 2020; $548 million in 2021; $554 million in 2022; and $6.5 billion thereafter.  However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.

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

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

	Years Ended December 31,
	2018		2019		2020		2021		2022		Thereafter
Coal take-or-pay commitments (a)	$	159,997	$	185,365	$	186,632	$	190,607	$	194,678	$	1,750,739

(a) Total take-or-pay commitments are approximately $2.7 billion.  The total net present value of these commitments is approximately $1.9 billion.

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

	Year Ended December 31,
	2017		2016		2015
Total purchases	$	165,220	$	160,066	$	211,327

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 $40 million in 2018; $40 million in 2019; $40 million in 2020; $40 million in 2021; $40 million in 2022; and $370 million thereafter.  These amounts do not include purchases of renewable energy credits that are bundled with energy.

Coal Mine Reclamation Obligations

APS and 4CA 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 an obligation for the coal mine final reclamation of approximately $216 million at December 31, 2017 and $207 million at December 31, 2016. 4CA recorded an obligation for the coal mine final reclamation of approximately $16 million at December 31, 2017 and $15 million at December 31, 2016. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows:  $31 million in 2018; $32 million in 2019; $21 million in 2020; $20 million in 2021; $22 million in 2022; and $191 million thereafter.  4CA expects to make payments for the final mine reclamation as follows: $1 million in 2018; $1 million in 2019; $2 million in 2020; $2 million in 2021; $2 million in 2022; and $16 million thereafter. Any amendments to current coal supply agreements may change the timing of the contribution. Portions of these funds will be held in an escrow account and distributed to certain coal providers under the terms of the applicable coal supply agreements.

Superfund-Related Matters

Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.  Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs.  PRPs may be strictly, and often are jointly and severally, liable for clean-up.  On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52^nd Street Superfund Site, 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 RI/FS.  Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS, APS anticipates finalizing the RI/FS in the summer or fall of 2018. 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.  As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, ADEQ sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area.  APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID contractors filed ancillary lawsuits for recovery of costs against APS and the other defendants. Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS’s exposure or risk related to these matters. In addition, on March 15, 2017, the Arizona District Court granted partial summary judgment to RID for one element of RID's lawsuit against APS and the other defendants. On May 12, 2017, the court denied a motion for reconsideration as to this order. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, 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 pollution control requirements on Four Corners and the Navajo Plant. EPA will require these plants to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plants. EPA approved a proposed rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the Cholla BART approval.

Four Corners. Based on EPA’s final standards, APS's 63% share of the cost of required controls for Four Corners Units 4 and 5 is approximately $400 million.  In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. NTEC had the option to purchase the interest within a certain timeframe pursuant to an option granted to NTEC. In December 2015, NTEC notified APS of its intent to exercise the option. The purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction. The cost of the pollution controls related to the 7% interest is approximately $45 million, which will be assumed by the ultimate owner of the 7% interest.

Navajo Plant. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s FIP, could be up to approximately $200 million; however, given the future plans for the Navajo Plant, we do not expect to incur these costs.  See "Navajo Plant" in Note 3 for information regarding future plans for the Navajo Plant.

Cholla. APS believed that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls, was unsupported and that EPA had no basis for disapproving Arizona’s SIP and promulgating a FIP that was inconsistent with the state’s considered BART determinations under the regional haze program.  In September 2014, APS met with EPA to propose a compromise BART strategy. APS would permanently close Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP.

On October 16, 2015, ADEQ issued a revised operating permit for Cholla, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to EPA, which would incorporate the new permit terms.  On June 30, 2016, EPA issued a proposed rule approving a revision to the Arizona SIP that incorporates APS’s compromise approach for compliance with the Regional Haze program.  In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017.

Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of RCRA and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity.

While EPA has chosen to regulate the disposal of CCR in landfills and surface impoundments as non-hazardous waste under the final rule, the agency makes clear that it will continue to evaluate any risks associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future.

On December 16, 2016, President Obama signed the WIIN Act into law, which contains a number of provisions requiring EPA to modify the self-implementing provisions of the Agency's current CCR rules under Subtitle D. Such modifications include new EPA authority to directly enforce the CCR rules through the use of administrative orders and providing states, like Arizona, where the Cholla facility is located, the option of developing CCR disposal unit permitting programs, subject to EPA approval. For facilities in states that do not develop state-specific permitting programs, EPA is required to develop a federal permit program, pending the availability of congressional appropriations. By contrast, for facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation, where the Navajo Plant and Four Corners facilities are located, EPA is required to develop a federal permit program regardless of appropriated funds.

ADEQ has initiated a process to evaluate how to develop a state CCR permitting program that would cover EGUs, including Cholla. While APS has been working with ADEQ on the development of this program, we are unable to predict when Arizona will be able to finalize and secure EPA approval for a state-specific CCR permitting program. With respect to the Navajo Nation, APS recently filed a comment letter with EPA seeking clarification as to when and how EPA would be initiating permit proceedings for facilities on the reservation, including Four Corners. We are unable to predict at this time when EPA will be issuing CCR management permits for the facilities on the Navajo Nation. At this time, it remains unclear how the CCR provisions of the WIIN Act will affect APS and its management of CCR.

Based upon utility industry petitions for EPA to reconsider the RCRA Subtitle D regulations for CCR, which were premised in part on the CCR provisions of the 2016 WIIN Act, on September 13, 2017 EPA agreed to evaluate whether to revise these federal CCR regulations. At this time, it is not clear whether EPA will initiate further notice-and-comment rulemaking to revise the federal CCR rules, nor is it clear what aspects of the federal CCR rules might be changed as a result of this process. With respect to ongoing litigation initiated by industry and environmental groups challenging the legality of these federal CCR regulations, on September 27, 2017 the United States Court of Appeals for the D.C. Circuit, the court overseeing these judicial challenges, ordered EPA to file by November 15, 2017 a list of federal regulatory provisions addressing CCR that are or likely will be revised through EPA’s reconsideration proceedings. While this filing identified certain provisions of the federal CCR regulations that EPA intends to revise, including allowances for risk-based groundwater protection standards for regulated CCR constituents for which no federal maximum contaminant level has been set, it is not clear at this time which specific provisions of the federal CCR rules will be modified, how they will be modified, or when such modification will occur.

Pursuant to a June 24, 2016 order by the D.C. Circuit Court of Appeals in the litigation by industry- and environmental-groups challenging EPA’s CCR regulations, within the next 2 years EPA is required to complete a rulemaking proceeding concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules.  EPA is not required to take final action approving the inclusion of boron, but EPA must propose and consider its inclusion.  Should EPA take final action adding boron to the list of groundwater constituents that might trigger corrective action, any resulting corrective action measures may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities.  At this time APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings.

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $22 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $20 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. By October 17, 2017, electric utility companies that own or operate CCR disposal units, such as APS, must have collected sufficient groundwater sampling data to initiate a detection monitoring program.  To the extent that certain threshold constituents are identified through this initial detection monitoring at levels above the CCR rule’s standards, the rule requires the initiation of an assessment monitoring program by April 15, 2018.  If this assessment monitoring program reveals concentrations of certain constituents above the CCR rule standards that trigger remedial obligations, a corrective measures evaluation must be completed by January 2019. Depending upon the results of such groundwater monitoring and data evaluations at each of Cholla, Four Corners and the Navajo Plant, we may be required to take corrective actions, the costs of which we are unable to reasonably estimate at this time.

Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for EGUs. Shortly thereafter, a coalition of states, industry groups and electric utilities challenged the legality of these standards, including EPA's Clean Power Plan for existing EGUs, in the U.S. Court of Appeals for the D.C. Circuit. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations under the Clean Power Plan. On March 28, 2017, President Trump issued an Executive Order that, among other things, instructs EPA to reevaluate Agency regulations concerning carbon emissions from EGUs and take appropriate action to suspend, revise or rescind the August 2015 carbon pollution standards for EGUs, including the Clean Power Plan. Also on March 28, 2017, the U.S. Department of Justice, on behalf of EPA, filed a motion with the U.S. Court of Appeals for the D.C. Circuit Court to hold the ongoing litigation over the Clean Power Plan in abeyance pending EPA action in accordance with the Executive Order. At this time, the D.C. Circuit Court proceedings evaluating the legality of the Clean Power Plan remain on hold.

Based upon EPA's reevaluation of the August 2015 carbon pollution standards and the legal basis for these regulations, on October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan. That proposal relies on EPA's current view as to the Agency's legal authority under Clean Air Act Section 111(d), which (in contrast to the Clean Power Plan) would limit the scope of any future Section 111(d) regulations to measures undertaken exclusively at a power plant's source of GHG emissions. On December 18, 2017, EPA issued an Advanced Notice of Proposed Rulemaking through which EPA is soliciting comments as to potential replacements for the Clean Power Plan that would be consistent with EPA's current legal interpretation of the Clean Air Act.

We cannot predict the outcome of EPA's regulatory actions related to the August 2015 carbon pollution standards for EGU's, including any actions related to EPA's repeal proposal for the Clean Power Plan or additional rulemaking actions to develop regulations replacing the Clean Power Plan. In addition, we cannot predict whether the D.C. Circuit Court will continue to hold the litigation challenging the original Clean Power Plan in abeyance in light of EPA's repeal proposal.

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants.  The financial impact of complying with current and 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.

Federal Agency Environmental Lawsuit Related to Four Corners

On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine.  The lawsuit alleges that these federal agencies violated both ESA and NEPA in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016.  APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016.

On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. We cannot predict whether this appeal will be successful and, if it is successful, the outcome of further district court proceedings.

Four Corners Coal Supply Agreement

Arbitration

On June 13, 2017, APS received a Demand for Arbitration from NTEC in connection with the 2016 Coal Supply Agreement, dated December 30, 2013, under which NTEC supplies coal to APS and the other Four Corners owners (collectively, the “Buyer”) for use at the Four Corners Power Plant. NTEC was originally seeking a declaratory judgment to support its interpretation of a provision regarding uncontrollable forces in the agreement that relates to annual minimum quantities of coal to be purchased by the Buyer. NTEC also alleged a shortfall in the Buyer’s purchases for the initial contract year of approximately $30 million. APS’s share of this amount is approximately $17 million. On September 20, 2017, NTEC amended its Demand for Arbitration removing its request for a declaratory judgment and at this time is only seeking relief for the alleged shortfall in the Buyer's purchases for the initial contract year. We cannot predict the timing or outcome of this arbitration; however we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

4CA Matter

On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC had the option to purchase the 7% interest within a certain timeframe pursuant to an option granted to NTEC. On December 29, 2015, NTEC provided notice of its intent to exercise the option. The purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction.

The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% interest in the event NTEC does not purchase the interest. At this time, since NTEC has not yet purchased the 7% interest, the alternate pricing provisions are applicable to 4CA as the holder of the 7% interest. These terms include a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales. Such payments are due to 4CA at the end of each calendar year. A $10 million payment was due to 4CA at December 31, 2017, which NTEC satisfied by directing to 4CA a prepayment from APS of a portion of a future mine reclamation obligation. The balance of the amount under this formula at December 31, 2017 is approximately $20 million, which is due to 4CA at December 31, 2018. In future years there may be similar payments due from NTEC to 4CA under this formula. 4CA believes NTEC should continue to satisfy its contractual obligations related to these payments; however, if NTEC fails to meet its contractual obligations when due, 4CA will consider appropriate measures and potential impacts to the Company's financial statements.

Financial Assurances

In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support certain commodity contract collateral obligations and other transactions. As of December 31, 2017, standby letters of credit totaled $5 million and will expire in 2018. As of December 31, 2017, surety bonds expiring through 2019 totaled $62 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.

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 has provided indemnification under certain surety bonds for APS which were not material at December 31, 2017. Since July 6, 2016, Pinnacle West has issued four parental guarantees for 4CArelating to payment obligations arising from 4CA’s acquisition of El Paso’s 7% interest in Four Corners, and pursuant to the Four Corners participation agreement payment obligations arising from 4CA’s ownership interest in Four Corners.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

In 2017, APS received a new decommissioning study for the Navajo Plant. This resulted in an increase to the ARO in the amount of $22 million, an increase in regulatory asset of $2 million and a reduction of the regulatory liability of $20 million.

In 2016, APS recognized an ARO for the Ocotillo steam units as a condition of the air permit (issued in 2016) to allow the construction and operation of five new turbine units. This resulted in an increase to the ARO in the amount of $10 million. In addition, 4CA acquired El Paso's share of Four Corners Units 4 and 5 and the associated ARO. This resulted in an increase to the ARO in the amount of $9 million. In addition, Four Corners spent $16 million in actual decommissioning costs. Finally, in 2016, APS received a new decommissioning study for the Palo Verde Generating Station. This resulted in an increase to the ARO in the amount of $151 million, an increase in plant in service of $131 million, and a reduction of the regulatory liability of $20 million.

The following table shows the change in our asset retirement obligations for 2017 and 2016 (dollars in thousands):

	2017		2016
Asset retirement obligations at the beginning of year	$	624,475	$	443,576
Changes attributable to:
Accretion expense	33,104		26,656
Settlements	—		(15,732		)
Estimated cash flow revisions	21,950		151,046
Newly incurred or acquired obligations	—		18,929
Asset retirement obligations at the end of year	$	679,529	$	624,475

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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Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2017

Selected Quarterly Financial Information [Line Items]

Selected Quarterly Financial Data (Unaudited)

Selected Quarterly Financial Data (Unaudited)

Consolidated quarterly financial information for 2017 and 2016 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.

	2017 Quarter Ended								2017
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	677,728	$	944,587	$	1,183,322	$	759,659	$	3,565,296
Operations and maintenance	219,976		214,013		224,305		266,149		924,443
Operating income	73,506		304,229		466,082		90,610		934,427
Income taxes	4,211		88,967		144,319		20,775		258,272
Net income	28,185		172,317		280,945		26,502		507,949
Net income attributable to common shareholders	23,312		167,443		276,072		21,629		488,456
Earnings Per Share:
Net income attributable to common shareholders — Basic	$	0.21	$	1.50	$	2.47	$	0.19	$	4.37
Net income attributable to common shareholders — Diluted	0.21		1.49		2.46		0.19		4.35

	2016 Quarter Ended								2016
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	677,167	$	915,394	$	1,166,922	$	739,199	$	3,498,682
Operations and maintenance	243,195		242,279		217,568		208,277		911,319
Operating income	50,162		231,748		451,258		122,816		855,984
Income taxes	1,914		65,742		141,446		27,309		236,411
Net income	9,326		126,182		267,900		58,119		461,527
Net income attributable to common shareholders	4,453		121,308		263,027		53,246		442,034
Earnings Per Share:
Net income attributable to common shareholders — Basic	$	0.04	$	1.09	$	2.36	$	0.48	$	3.97
Net income attributable to common shareholders — Diluted	0.04		1.08		2.35		0.47		3.95

ARIZONA PUBLIC SERVICE COMPANY

Selected Quarterly Financial Information [Line Items]

Selected Quarterly Financial Data (Unaudited)

Selected Quarterly Financial Data (Unaudited) - APS

APS's quarterly financial information for 2017 and 2016 is as follows (dollars in thousands):

	2017 Quarter Ended,								2017
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	676,869	$	942,615	$	1,178,106	$	756,549	$	3,554,139
Operations and maintenance	212,218		208,286		215,264		255,361		891,129
Operating income	65,468		212,790		322,053		79,258		679,569
Net income attributable to common shareholder	23,162		169,108		284,256		27,783		504,309

	2016 Quarter Ended,								2016
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	676,632	$	909,757	$	1,166,359	$	737,006	$	3,489,754
Operations and maintenance	238,711		233,712		209,366		197,319		879,108
Operating income	48,930		165,684		307,601		95,765		617,980
Net income attributable to common shareholder	7,253		127,188		269,220		58,480		462,141

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Fair Value Measurements

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

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.

Level 2 — Other significant observable inputs, including 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). 

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.

Certain instruments have been valued using the concept of NAV, as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV, as a practical expedient are included in our fair value disclosures however, in accordance with GAAP are not classified within the fair value hierarchy levels.

Recurring Fair Value Measurements

We apply recurring fair value measurements to certain cash equivalents, derivative instruments, and investments held in our coal reclamation escrow accounts and nuclear decommissioning trust. On an annual basis we apply fair value measurements to plan assets held in our retirement and other benefit plans.  See Note 7 for 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, characteristics of the product, 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.

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.

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 Nuclear Decommissioning Trust and Coal Reclamation Escrow

The nuclear decommissioning trust invests in fixed income securities, equity securities, and may hold cash and cash equivalents. The coal reclamation escrow account invests in fixed income instruments and may also hold cash and cash equivalents. See Note 19 for additional discussion about our investment accounts.

The nuclear decommissioning trust's equity security investments are held indirectly through commingled funds.  The commingled funds are valued using the funds' NAV as a practical expedient. The funds' NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds. We may transact in these commingled funds on a semi-monthly basis at the NAV.  The commingled 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 funds' shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy.

Fixed income securities issued by the U.S. Treasury are valued using quoted active market prices and are typically 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 fixed income 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.

Cash equivalents reported within Level 1 represent investments held in short-term investment exchange-traded mutual funds. These short-term investment accounts invest in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, commercial paper, and other short term instruments.

We price investment securities using information provided by our trustees for our nuclear decommissioning trust assets, and provided by our escrow agent for coal reclamation escrow assets. Our trustee and escrow agent use pricing services that utilize the valuation methodologies described above 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 and escrow agent's internal operating controls and valuation processes. 

Fair Value Tables

The following table presents the fair value at December 31, 2017 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

	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, 2017
Assets
Cash equivalents	$	10,630	$	—		$	—		$	—			$	10,630
Risk management activities — derivative instruments:
Commodity contracts	—		5,683			1,036			(4,737		)	(b)	1,982
Coal reclamation escrow account (c):	455		31,562			—			525				32,542
Nuclear decommissioning trust:
Cash and cash equivalents	7,224		—			—			109			(d)	7,333
U.S. commingled equity funds	—		—			—			417,390			(e)	417,390
Fixed income securities:
U.S. Treasury	127,662		—			—			—				127,662
Corporate debt	—		114,007			—			—				114,007
Mortgage-backed securities	—		111,874			—			—				111,874
Municipal bonds	—		79,049			—			—				79,049
Other	—		13,685			—			—				13,685
Subtotal nuclear decommissioning trust	134,886		318,615			—			417,499				871,000
Total Assets	$	145,971	$	355,860		$	1,036		$	413,287			$	916,154
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(78,646	)	$	(19,292	)	$	1,516		(b)	$	(96,422	)

(a) Primarily consists of long-dated electricity contracts.

(b) Represents counterparty netting, margin, and collateral. See Note 16.

(c) Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Consolidated Balance Sheets. Primarily consists of fixed income municipal bonds.

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

(e) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

The following table presents the fair value at December 31, 2016 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

	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, 2016
Assets
Coal reclamation trust (b):	$	14,521	$	—		$	—		$	—			$	14,521
Risk management activities — derivative instruments:
Commodity contracts	—		43,722			11,076			(35,103		)	(c)	19,695
Nuclear decommissioning trust:
U.S. commingled equity funds	—		—			—			353,261			(d)	353,261
Fixed income securities:
Cash and cash equivalent funds	—		—			—			795			(e)	795
U.S. Treasury	95,441		—			—			—				95,441
Corporate debt	—		111,623			—			—				111,623
Mortgage-backed securities	—		115,337			—			—				115,337
Municipal bonds	—		80,997			—			—				80,997
Other	—		22,132			—			—				22,132
Subtotal nuclear decommissioning trust	95,441		330,089			—			354,056				779,586
Total	$	109,962	$	373,811		$	11,076		$	318,953			$	813,802
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(45,641	)	$	(58,482	)	$	31,049		(c)	$	(73,074	)

(a) Primarily consists of long-dated electricity contracts.

(b) Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Consolidated Balance Sheets. Primarily consists of cash equivalents. Presented as Coal reclamation escrow in 2017.

(c) Represents counterparty netting, margin and collateral. See Note 16.

(d) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

(e) 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.  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.

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, 2017 and December 31, 2016:

	December 31, 2017 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Commodity Contracts	Assets		Liabilities
Electricity:
Forward Contracts (a)	$	21	$	15,485	Discounted cash flows	Electricity forward price (per MWh)	$18.51 - $38.75	$	27.89
Natural Gas:
Forward Contracts (a)	1,015		3,807		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.33 - $3.11	$	2.71
Total	$	1,036	$	19,292

(a) Includes swaps and physical and financial contracts.

	December 31, 2016 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Commodity Contracts	Assets		Liabilities
Electricity:
Forward Contracts (a)	$	10,648	$	32,042	Discounted cash flows	Electricity forward price (per MWh)	$16.43 - $41.07	$	29.86
Natural Gas:
Forward Contracts (a)	428		26,440		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.32 - $3.60	$	2.81
Total	$	11,076	$	58,482

(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, 2017 and 2016 (dollars in thousands):

	Year Ended December 31,
Commodity Contracts	2017			2016
Net derivative balance at beginning of period	$	(47,406	)	$	(32,979	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			—
Included in OCI	3			88
Deferred as a regulatory asset or liability	(13,643		)	(37,543		)
Settlements	5,834			15,146
Transfers into Level 3 from Level 2	(10,026		)	1,900
Transfers from Level 3 into Level 2	46,982			5,982
Net derivative balance at end of period	$	(18,256	)	$	(47,406	)
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 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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Earnings Per Share

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for continuing operations attributable to common shareholders for the years ended December 31, 2017, 2016 and 2015 (in thousands, except per share amounts):

	2017		2016		2015
Net income attributable to common shareholders	$	488,456	$	442,034	$	437,257
Weighted average common shares outstanding — basic	111,839		111,409		111,026
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	528		637		526
Weighted average common shares outstanding — diluted	112,367		112,046		111,552
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders - basic	$	4.37	$	3.97	$	3.94
Net Income attributable to common shareholders - diluted	$	4.35	$	3.95	$	3.92

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Stock-Based Compensation

12 Months Ended

Dec. 31, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock-Based Compensation

Stock-Based Compensation

Pinnacle West has incentive compensation plans under which stock-based compensation is granted to officers, key-employees, and non-officer members of the Board of Directors. Awards granted under the 2012 Long-Term Incentive Plan (“2012 Plan”) may be in the form of stock grants, restricted stock units, stock units, performance shares, restricted stock, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights.  The 2012 Plan authorizes up to 4.6 million common shares to be available for grant.  As of December 31, 2017, 2.2 million common shares were available for issuance under the 2012 Plan. During 2017, 2016, and 2015, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. Awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”), and no new awards may be granted under the 2007 Plan.

Stock-Based Compensation Expense and Activity

During the fourth quarter of 2016, we adopted new stock-based compensation accounting guidance prescribed by ASU 2016-09. Prior to the adoption of this guidance we had certain awards that were accounted for as liability awards due to the ability of the employee to withhold taxes beyond the minimum statutory tax withholding rate. Under the new standard, the tax withholding terms of our awards no longer trigger liability treatment. Accordingly, effective January 1, 2016 certain awards that were previously classified as liability awards are now accounted for as equity awards. The impacts of this accounting change relating to prior years have been applied using a modified retrospective approach, resulting in a $6 million cumulative-effect adjustment, net of income tax expense of $3 million, to increase Retained Earnings as of January 1, 2016. The impacts of this accounting change relating to 2016 resulted in a pre-tax $12 million adjustment to decrease operations and maintenance expense that was recognized during the fourth quarter of 2016. The following amounts related to years ended 2017 and 2016 expense and activity include the effects of adopting this new accounting standard; however, expense and activities relating to 2015 reflect the historical accounting treatment. The new standard also requires excess income tax benefits and deficiencies arising from stock based compensation to now be recognized in the period incurred, simplifies accounting for forfeitures, and clarifies certain cash flow presentation matters. These other provisions of the standard did not have a material impact on our consolidated financial statements.

Compensation cost included in net income for stock-based compensation plans was $21 million in 2017, $19 million in 2016, and $19 million in 2015.  The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $15 million in 2017, $10 million in 2016, and $7 million in 2015.

As of December 31, 2017, there were approximately $12 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. We expect to recognize these costs over a weighted-average period of 2 years. 

The total fair value of shares vested was $22 million in 2017, $22 million in 2016 and $21 million in 2015.

The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2017, 2016 and 2015.

	Restricted Stock Units, Stock Grants, and Stock Units (a)						Performance Shares (b)
	2017		2016		2015		2017		2016		2015
Units granted	161,963		141,811		152,651		147,706		166,666		151,430
Weighted-average grant date fair value	$	72.60	$	67.34	$	64.12	$	78.99	$	66.60	$	64.97

(a) Units granted includes awards that will be cash settled of 67,599 in 2017, 43,952 in 2016, and 45,104 in 2015.

(b) Reflects the target payout level.

The following table is a summary of the status of non-vested awards as of December 31, 2017 and changes during the year.

	Restricted Stock Units, Stock Grants, and Stock Units					Performance Shares
	Shares			Weighted-Average Grant Date Fair Value		Shares (b)		Weighted-Average Grant Date Fair Value
Nonvested at January 1, 2017	335,259			$	62.04	312,724		$	65.32
Granted	161,963			72.60		147,706		78.99
Change in performance factor	—			—		18,266		64.97
Vested	(202,327	)		59.19		(164,396	)	63.87
Forfeited (c)	(3,607	)		69.58		(4,798	)	69.77
Nonvested at December 31, 2017	291,288		(a)	69.78		309,502		72.46
Vested Awards Outstanding at December 31, 2017	89,928					164,396

(a) Includes 133,373 of awards that will be cash settled.

(b) The nonvested performance shares are reflected at target payout level.  The performance metric component 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.

(c) We account for forfeitures as they occur.

Share-based liabilities paid relating to restricted stock units were $4 million, $3 million and $10 million in 2017, 2016 and 2015, respectively. This includes cash used to settle restricted stock units of $4 million, $3 million and $3 million in 2017, 2016 and 2015, respectively. Restricted stock units that are cash settled are classified as liability awards. Share-based liabilities paid relating to performance shares were $16 million in 2015. In 2017 and 2016, performance shares were classified as equity awards.

Restricted Stock Units, Stock Grants, and Stock Units

Restricted stock units are granted to officers and key employees.  Restricted stock units typically vest and settle in equal annual installments over a 4-year period after the grant date.  Vesting is typically dependent upon continuous service during the vesting period; however, awards granted to retirement-eligible employees will vest upon the employee's retirement. Awardees elect to receive payment in either 100% stock, 100% cash, or 50% in cash and 50% in stock. Restricted stock unit awards typically include a dividend equivalent feature. This feature allows each award to accrue dividend rights equal to the dividends they would have received had they directly owned the stock. Interest on dividend rights compounds quarterly. If the award is forfeited the employee is not entitled to the dividends on those shares.

In December 2012, the Company granted a retention award of 50,617 performance-linked restricted stock units to the Chairman of the Board and Chief Executive Officer of Pinnacle West.  This award vested on December 31, 2016, because he remained employed with the Company through that date.  The Board did increase the number of awards that vested by 33,745 restricted stock units, payable in stock because certain performance requirements were met. In February 2017, 84,362 restricted stock units were released.

Compensation cost for restricted stock unit awards is based on the fair value of the award, with the fair value being the market price of our stock on the measurement date. Restricted stock unit awards that will be settled in cash 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. Restricted stock unit awards that will be settled in shares are accounted for as equity awards, with compensation cost calculated using the Company's closing stock price on the date of grant. Compensation cost is recognized over the requisite service period based on the fair value of the award.

Stock grants are issued to non-officer members of the Board of Directors. They may elect to receive the stock grant, or to defer receipt until a later date and receive 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 100% stock, or 50% in cash and 50% in stock.  Each stock unit is convertible to one share of stock. The 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 or 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.

Performance Share Awards

Performance share awards are granted to officers and key employees.  The awards contain two separate performance criteria that affect the number of shares that may be received if after the end of a 3-year performance period the performance criteria are met. For the first criteria, the number of shares that will vest is based on non-financial performance metrics (i.e., the metric component). The other criteria is based upon Pinnacle West's total shareholder return ('TSR') in relation to the TSR of other companies in a specified utility index (i.e., the TSR component). 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 recipients 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. If the award is forfeited or if the performance criteria are not achieved, the employee is not entitled to the dividends on those shares.

Performance share awards are accounted for as equity awards, with compensation cost based on the fair value of the award on the grant date. Compensation cost relating to the metric component of the award is based on the Company’s closing stock price on the date of grant, with compensation cost recognized over the requisite service period based on the number of shares expected to vest. Management evaluates the probability of meeting the metric component at each balance sheet date. If the metric component criteria are not ultimately achieved, no compensation cost is recognized relating to the metric component, and any previously recognized compensation cost is reversed. Compensation cost relating to the TSR component of the award is determined using a Monte Carlo simulation valuation model, with compensation cost recognized ratably over the requisite service period, regardless of the number of shares that actually vest.

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Derivative Accounting

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Accounting

Derivative Accounting

Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and interest rates.  Risks associated with market volatility are managed 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.  Derivative instruments are also entered into for economic hedging purposes.  While economic hedges may 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.

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 13 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.

For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses 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, 2017, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

		Quantity
Commodity	Unit of Measure	December 31, 2017	December 31, 2016
Power	GWh	583	1,314
Gas	Billion cubic feet	240	194

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, 2017, 2016 and 2015 (dollars in thousands):

	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2017			2016			2015
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	OCI — derivative instruments	$	(59	)	$	47		$	(615	)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	(3,519		)	(3,926		)	(5,988		)

(a) During the years ended December 31, 2017, 2016, and 2015, we had no 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 $2 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, most 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, 2017, 2016 and 2015 (dollars in thousands):

	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2017			2016		2015
Net Gain (Loss) Recognized in Income	Operating revenues	$	(1,192	)	$	771	$	574
Net Gain (Loss) Recognized in Income	Fuel and purchased power (a)	(87,991		)	25,711		(108,973		)
Total		$	(89,183	)	$	26,482	$	(108,399	)

(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.

As of December 31, 2017, we no longer have derivative instruments that are designated as cash flow hedging instruments. As of December 31, 2016, the Consolidated Balance Sheets included $2 million of gross liabilities related to derivative instruments designated as cash flow 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, 2017 and 2016.  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, 2017: (dollars in thousands)	Gross  Recognized  Derivatives (a)			Amounts  Offset (b)			Net Recognized Derivatives			Other (c)			Amount  Reported on  Balance Sheet
Current assets	$	5,427		$	(3,796	)	$	1,631		$	300		$	1,931
Investments and other assets	1,292			(1,241		)	51			—			51
Total assets	6,719			(5,037		)	1,682			300			1,982
Current liabilities	(59,527		)	3,796			(55,731		)	(3,521		)	(59,252		)
Deferred credits and other	(38,411		)	1,241			(37,170		)	—			(37,170		)
Total liabilities	(97,938		)	5,037			(92,901		)	(3,521		)	(96,422		)
Total	$	(91,219	)	$	—		$	(91,219	)	$	(3,221	)	$	(94,440	)

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

(b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c) Represents cash collateral and cash 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 $3,521 and cash margin provided to counterparties of $300.

As of December 31, 2016: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset  (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	48,094		$	(28,400	)	$	19,694		$	—		$	19,694
Investments and other assets	6,704			(6,703		)	1			—			1
Total assets	54,798			(35,103		)	19,695			—			19,695
Current liabilities	(50,182		)	28,400			(21,782		)	(4,054		)	(25,836		)
Deferred credits and other	(53,941		)	6,703			(47,238		)	—			(47,238		)
Total liabilities	(104,123		)	35,103			(69,020		)	(4,054		)	(73,074		)
Total	$	(49,325	)	$	—		$	(49,325	)	$	(4,054	)	$	(53,379	)

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

(b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c) Represents cash collateral and cash 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 $4,054.

Credit Risk and Credit Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of December 31, 2017, Pinnacle West has no counterparties with positive exposures of greater than 10% of risk management assets. 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 counterparties 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, 2017 (dollars in thousands):

	December 31, 2017
Aggregate fair value of derivative instruments in a net liability position	$	97,938
Cash collateral posted	—
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)	91,071

(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 $110 million if our debt credit ratings were to fall below investment grade.

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Other Income and Other Expense

12 Months Ended

Dec. 31, 2017

Component of Other Income and Other Expense Nonoperating [Line Items]

Other Income and Other Expense

Other Income and Other Expense

The following table provides detail of Pinnacle West's Consolidated other income and other expense for 2017, 2016 and 2015 (dollars in thousands):

	2017			2016			2015
Other income:
Interest income	$	3,497		$	884		$	493
Miscellaneous	509			17			128
Total other income	$	4,006		$	901		$	621
Other expense:
Non-operating costs	$	(11,749	)	$	(9,235	)	$	(11,292	)
Investment losses — net	(4,113		)	(1,747		)	(2,080		)
Miscellaneous	(5,677		)	(4,355		)	(4,451		)
Total other expense	$	(21,539	)	$	(15,337	)	$	(17,823	)

ARIZONA PUBLIC SERVICE COMPANY

Component of Other Income and Other Expense Nonoperating [Line Items]

Other Income and Other Expense

Other Income and Other Expense - APS

The following table provides detail of APS’s other income and other expense for 2017, 2016 and 2015 (dollars in thousands):

	2017			2016			2015
Other income:
Interest income	$	2,858		$	261		$	163
Gain on disposition of property	2,048			5,745			716
Miscellaneous	1,620			2,601			1,955
Total other income	$	6,526		$	8,607		$	2,834
Other expense:
Non-operating costs (a)	$	(12,395	)	$	(11,034	)	$	(11,648	)
Loss on disposition of property	(5,424		)	(1,246		)	(2,219		)
Miscellaneous	(5,561		)	(5,234		)	(5,152		)
Total other expense	$	(23,380	)	$	(17,514	)	$	(19,019	)

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

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Palo Verde Sale Leaseback Variable Interest Entities

12 Months Ended

Dec. 31, 2017

Variable Interest Entities [Abstract]

Palo Verde Sale Leaseback Variable Interest Entities

Palo Verde Sale Leaseback Variable Interest Entities

In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities.  APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually for the period 2018 through 2023, and about $16 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

The leases' terms give APS the ability to utilize the assets for a significant portion of the assets' economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs' economic performance. Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income of $19 million for 2017, 2016 and 2015. The increase in net income is entirely attributable to the noncontrolling interests.  Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Consolidated Balance Sheets at December 31, 2017 and December 31, 2016 include the following amounts relating to the VIEs (dollars in thousands):

	December 31, 2017		December 31, 2016
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation	$	109,645	$	113,515
Equity-Noncontrolling interests	129,040		132,290

Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders.  These assets are reported on our consolidated financial statements.

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 and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $293 million beginning in 2018, and up to $456 million over the lease extension term.

For regulatory ratemaking purposes, the agreements 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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Investments

12 Months Ended

Dec. 31, 2017

Investments, Debt and Equity Securities [Abstract]

Investments

Investments

We have investments in debt and equity securities held in Nuclear Decommissioning Trusts and Coal Reclamation Escrow Accounts. These investments are classified as available for sale securities, and as a result we record the investments at their fair value on our Consolidated Balance Sheets. See Note 13 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning and coal reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities. The costs of securities sold are determined on the basis of specific identification.

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.  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, 2017 and December 31, 2016 (dollars in thousands):

	December 31, 2017							December 31, 2016
	Fair Value		Total  Unrealized  Gains		Total  Unrealized  Losses			Fair Value		Total  Unrealized  Gains		Total  Unrealized  Losses
Equity securities	$	417,390	$	248,623	$	—		$	353,261	$	188,091	$	—
Fixed income securities	446,277		11,537		(2,996		)	425,530		9,820		(4,962		)
Cash and cash equivalents	7,224		—		—			—		—		—
Net receivables (a)	109		—		—			795		—		—
Total	$	871,000	$	260,160	$	(2,996	)	$	779,586	$	197,911	$	(4,962	)

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

The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in thousands):

	Nuclear Decommissioning
	Year Ended December 31,
	2017			2016			2015
Realized gains	$	21,813		$	11,213		$	5,189
Realized losses	(13,146		)	(10,106		)	(6,225		)
Proceeds from the sale of securities (a)	542,246			633,410			478,813

(a) Proceeds are reinvested in the trust/account.

Coal Reclamation Escrow Accounts

APS has investments restricted for coal mine reclamation funding related to Four Corners. As of December 31, 2017, APS’s coal reclamation escrow accounts are invested in fixed income securities with a fair value of $30 million. The realized and unrealized gains and losses relating to these fixed income securities was immaterial for the twelve months ended December 31, 2017 and December 31, 2016. The proceeds from the sale of securities for the twelve months endedDecember 31, 2017 was $4 million. There were no proceeds from the sale of securities for the twelve months endedDecember 31, 2016. The proceeds are reinvested in the escrow accounts. 

4CA also has investments restricted for coal mine reclamation funding relating to Four Corners invested in fixed income securities. The 4CA fixed income investments have a fair value of $2 million as of December 31, 2017. The realized and unrealized gains and losses relating to these fixed income securities was immaterial for the twelve months endedDecember 31, 2017 and 2016.

Fixed Income Securities Contractual Maturities

The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2017 is as follows (dollars in thousands):

	Nuclear Decommissioning Trusts		Escrow Accounts		Total
Less than one year	$	24,668	$	455	$	25,123
1 year – 5 years	100,289		2,494		102,783
5 years – 10 years	129,239		8,615		137,854
Greater than 10 years	192,081		20,453		212,534
Total	$	446,277	$	32,017	$	478,294

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Changes in Accumulated Other Comprehensive Loss

12 Months Ended

Dec. 31, 2017

Changes in accumulated other comprehensive income (loss) including reclassification adjustments, by component:

Changes in Accumulated Other Comprehensive Loss

Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2017 and 2016 (dollars in thousands): 

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2015	$	(37,593	)		$	(7,155	)		$	(44,748	)
OCI (loss) before reclassifications	(4,509		)		(538		)		(5,047		)
Amounts reclassified from accumulated other comprehensive loss	3,032			(a)	2,941			(b)	5,973
Balance December 31, 2016	(39,070		)		(4,752		)		(43,822		)
OCI (loss) before reclassifications	(6,438		)		(35		)		(6,473		)
Amounts reclassified from accumulated other comprehensive loss	3,068			(a)	2,225			(b)	5,293
Balance December 31, 2017	$	(42,440	)		$	(2,562	)		$	(45,002	)

(a) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.

(b) 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 16.

ARIZONA PUBLIC SERVICE COMPANY

Changes in accumulated other comprehensive income (loss) including reclassification adjustments, by component:

Changes in Accumulated Other Comprehensive Loss

Changes in Accumulated Other Comprehensive Loss - APS

The following table shows the changes in APS's accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2017 and 2016 (dollars in thousands): 

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2015	$	(19,942	)		$	(7,155	)		$	(27,097	)
OCI (loss) before reclassifications	(3,821		)		(538		)		(4,359		)
Amounts reclassified from accumulated other comprehensive loss	3,092			(a)	2,941			(b)	6,033
Balance December 31, 2016	(20,671		)		(4,752		)		(25,423		)
OCI (loss) before reclassifications	(6,884		)		(35		)		(6,919		)
Amounts reclassified from accumulated other comprehensive loss	3,134			(a)	2,225			(b)	5,359
Balance December 31, 2017	$	(24,421	)		$	(2,562	)		$	(26,983	)

(a) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.

(b) 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 16.

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

12 Months Ended

Dec. 31, 2017

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)

	Year Ended December 31,
	2017			2016			2015
Operating revenues	$	119		$	370		$	550
Operating expenses	24,298			26,424			12,733
Operating loss	(24,179		)	(26,054		)	(12,183		)
Other
Equity in earnings of subsidiaries	507,495			462,027			446,508
Other expense	(2,715		)	(1,771		)	(3,302		)
Total	504,780			460,256			443,206
Interest expense	5,633			3,151			2,672
Income before income taxes	474,968			431,051			428,351
Income tax benefit	(13,488		)	(10,983		)	(8,906		)
Net income attributable to common shareholders	488,456			442,034			437,257
Other comprehensive income (loss) — attributable to common shareholders	(1,180		)	926			23,393
Total comprehensive income — attributable to common shareholders	$	487,276		$	442,960		$	460,650

See Combined Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED BALANCE SHEETS

(dollars in thousands)

	December 31,
	2017			2016
ASSETS
Current assets
Cash and cash equivalents	$	41		$	41
Accounts receivable	93,554			81,751
Income tax receivable	19,124			—
Other current assets	267			340
Total current assets	112,986			82,132
Investments and other assets
Investments in subsidiaries	5,465,137			5,084,035
Deferred income taxes	54,352			53,805
Other assets	44,613			38,500
Total investments and other assets	5,564,102			5,176,340
Total Assets	$	5,677,088		$	5,258,472
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	7,638		$	5,421
Accrued taxes	8,927			12,050
Common dividends payable	77,667			72,926
Short-term borrowings	95,400			41,700
Current maturities of long-term debt	—			125,000
Other current liabilities	17,417			31,182
Total current liabilities	207,049			288,279
Long-term debt less current maturities	298,421			—
Pension liabilities	20,758			21,057
Other	15,130			13,224
Total deferred credits and other	35,888			34,281
Common stock equity
Common stock	2,609,181			2,591,897
Accumulated other comprehensive loss	(45,002		)	(43,822		)
Retained earnings	2,442,511			2,255,547
Total Pinnacle West Shareholders’ equity	5,006,690			4,803,622
Noncontrolling interests	129,040			132,290
Total Equity	5,135,730			4,935,912
Total Liabilities and Equity	$	5,677,088		$	5,258,472

See Combined Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

(dollars in thousands)

	Year Ended December 31,
	2017			2016			2015
Cash flows from operating activities
Net income	$	488,456		$	442,034		$	437,257
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries — net	(507,495		)	(462,027		)	(446,508		)
Depreciation and amortization	76			85			92
Deferred income taxes	(264		)	(12,402		)	12,967
Accounts receivable	(2,106		)	15,823			11,336
Accounts payable	(11,162		)	10,402			637
Accrued taxes and income tax receivables — net	(22,247		)	20,041			(12,882		)
Dividends received from subsidiaries	296,800			239,300			266,900
Other	15,092			5,514			(6,995		)
Net cash flow provided by operating activities	257,150			258,770			262,804
Cash flows from investing activities
Construction work in progress	—			(18,457		)	(3,462		)
Investments in subsidiaries	(178,027		)	(19,242		)	(3,491		)
Repayments of loans from subsidiaries	2,987			1,026			157
Advances of loans to subsidiaries	(6,388		)	(2,092		)	(1,010		)
Net cash flow used for investing activities	(181,428		)	(38,765		)	(7,806		)
Cash flows from financing activities
Issuance of long-term debt	298,761			—			—
Short-term debt borrowings under revolving credit facility	58,000			40,000			—
Short-term debt repayments under revolving credit facility	(32,000		)	—			—
Commercial paper - net	27,700			1,700			—
Dividends paid on common stock	(289,793		)	(274,229		)	(260,027		)
Repayment of long-term debt	(125,000		)	—			—
Common stock equity issuance - net of purchases	(13,390		)	(4,867		)	19,373
Net cash flow used for financing activities	(75,722		)	(237,396		)	(240,654		)
Net increase (decrease) in cash and cash equivalents	—			(17,391		)	14,344
Cash and cash equivalents at beginning of year	41			17,432			3,088
Cash and cash equivalents at end of year	$	41		$	41		$	17,432

     See Combined Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

NOTES TO FINANCIAL STATEMENTS OF HOLDING COMPANY

The Combined Notes to Consolidated Financial Statements in Part II, Item 8 should be read in conjunction with the Pinnacle West Capital Corporation Holding Company Financial Statements.

The Pinnacle West Capital Corporation Holding Company Financial Statements have been prepared to present the financial position, results of operations and cash flows of Pinnacle West Capital Corporation on a stand-alone basis as a holding company. Investments in subsidiaries are accounted for using the equity method.

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SCHEDULE II - RESERVE FOR UNCOLLECTIBLES

12 Months Ended

Dec. 31, 2017

Reserve for uncollectibles

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES

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:
2017	$	3,037	$	6,836	$	—	$	7,360	$	2,513
2016	3,125		4,025		—		4,113		3,037
2015	3,094		4,073		—		4,042		3,125

ARIZONA PUBLIC SERVICE COMPANY

Reserve for uncollectibles

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:
2017	$	3,037	$	6,836	$	—	$	7,360	$	2,513
2016	3,125		4,025		—		4,113		3,037
2015	3,094		4,073		—		4,042		3,125

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

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, El Dorado, BCE and 4CA. 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.  El Dorado is an investment firm. BCE is a subsidiary that was formed in 2014 that focuses on growth opportunities that leverage the Company's core expertise in the electric energy industry. BCE is currently pursuing transmission opportunities through a joint venture arrangement. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners.

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries:  APS, El Dorado, BCE and 4CA. 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 18).

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 a more condensed form on the Consolidated Balance Sheets than in the prior year. The prior year amounts were reclassified to conform to the current year presentation. These reclassifications have no impact on accumulated other comprehensive loss. The following tables show the impacts of the reclassifications of the prior year (previously reported) amounts (dollars in thousands):

Pinnacle West Capital Corporation Consolidated Balance Sheets- December 31, 2016	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Accumulated other comprehensive loss:
Pension and other postretirement benefits	$	(39,070	)	$	39,070		$	—
Derivative instruments	(4,752		)	4,752			—
Total accumulated other comprehensive loss	(43,822		)	43,822			—
Accumulated other comprehensive loss	—			(43,822		)	(43,822		)

Arizona Public Service Company Consolidated Balance Sheets - December 31, 2016	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Accumulated other comprehensive loss:
Pension and other postretirement benefits	$	(20,671	)	$	20,671		$	—
Derivative instruments	(4,752		)	4,752			—
Total accumulated other comprehensive loss	(25,423		)	25,423			—
Accumulated other comprehensive loss	—			(25,423		)	(25,423		)

Accounting Records and Use of Estimates

Accounting Records and Use of Estimates

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

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 amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to 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.

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.

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.

Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West.

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 11.

APS records a regulatory liability 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 and amortization 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, 2017 were as follows:

•Fossil plant — 21 years;

•Nuclear plant — 26 years;

•Other generation — 25 years;

•Transmission — 38 years;

•Distribution — 33 years; and

•General plant — 6 years.

Asset Retirement Obligations

Asset Retirement Obligations

APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation 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.  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 and coal ash pond closures. 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 transmission and distribution assets. Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites.

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 Statements 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 6.68% for 2017, 7.17% for 2016, and 8.02% for 2015.  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, coal reclamation escrow accounts, 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.

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 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.

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 Postretirement Benefits

Retirement Plans and Other Postretirement 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 its 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.

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 charged APS $0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero.  In accordance with a settlement agreement with the DOE in August 2014, we will now accrue a receivable for incurred claims and an offsetting regulatory liability through the settlement period ending December of 2019.

Income Taxes

Income Taxes

Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes and are based on currently enacted tax rates.  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.

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.

Investments

Investments

El Dorado holds investments in both debt and equity securities.  Investments in debt securities are generally accounted for as held-to-maturity and investments in equity securities are accounted for using either the equity method (if significant influence) or the cost method (if less than 20% ownership and no significant influence).

Our investments in the nuclear decommissioning trust fund, and coal reclamation escrow, are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities.

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.

New Accounting Standards

New Accounting Standards

ASU 2014-09, Revenue from Contracts with Customers

In May 2014, a new revenue recognition accounting standard was issued. This standard provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, became effective for us on January 1, 2018. The standard may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application.

We adopted this standard on January 1, 2018 using the modified retrospective transition approach. The adoption of this standard will not have significant impact on our financial statement results. Our revenues are derived primarily from sales of electricity to our regulated retail customers, and based on our assessment the adoption of this guidance does not generally impact the timing of our revenue recognition relating to these customers. The adoption of the new standard will result in expanded revenue related disclosures.

ASU 2016-01, Financial Instruments: Recognition and Measurement

In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new standard became effective for us on January 1, 2018. Certain aspects of the standard require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We adopted this standard on a prospective basis on January 1, 2018. The adoption of this standard will not have a significant impact on our financial statement results, as we did not have significant equity investments impacted by this standard.

ASU 2016-02, Leases

In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. In January 2018, additional lease guidance was issued specifically relating to land easements and how entities may elect to account for these arrangements at transition. The new standard, and related amendments, will be effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition.

We plan on adopting this standard, and related amendments, on January 1, 2019, and are evaluating the transition practical expedients we may elect. Our evaluation of this new accounting standard and the impacts it will have on our financial statements is on-going. We expect the adoption of the new guidance will impact our Consolidated Balance Sheets as we will be required to reflect lease assets and lease liabilities relating to certain operating lease arrangements. We are currently evaluating the significance of the expected balance sheet impacts, and the impacts, if any, the lease guidance will have on our other financial statements. Our evaluation includes assessing leasing activities, implementing new processes and procedures, and preparing the expanded lease disclosures.

ASU 2016-13, Financial Instruments: Measurement of Credit Losses

In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard will require entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments

In August 2016, a new accounting standard was issued that clarifies how entities should present certain specific cash flow activities on the statement of cash flows. The guidance is intended to eliminate diversity in practice in how entities classify these specific activities between cash flows from operating activities, investing activities and financing activities. The specific activities addressed include debt prepayments and extinguishment costs, proceeds from the settlement of insurance claims, proceeds from corporate owned life insurance policies, and other activities. The standard also addresses how entities should apply the predominance principle when a transaction includes separately identifiable cash flows. The new standard is effective for us, and will be adopted, during the first quarter of 2018 using a retrospective transition method. The adoption of this guidance will not have a significant impact on our financial statements, as either our statement of cash flow presentation is consistent with the new prescribed guidance or we do not have significant activities relating to the specific transactions that are addressed by the new standard.

ASU 2016-18, Statement of Cash Flows: Restricted Cash

In November 2016, a new accounting standard was issued that clarifies how restricted cash and restricted cash equivalents should be presented on the statement of cash flows. The new guidance requires entities to include restricted cash and restricted cash equivalents as a component of the beginning and ending cash and cash equivalent balances on the statement of cash flows. The new standard is effective for us, and will be adopted, during the first quarter of 2018 using a retrospective transition method. We do not expect the adoption of this guidance will impact our financial statements, as our holdings and activities designated as restricted cash and restricted cash equivalents are generally insignificant.

ASU 2017-01, Business Combinations: Clarifying the Definition of a Business

In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business.  The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The new standard became effective for us on January 1, 2018 using a prospective approach. We adopted this new standard on January 1, 2018, using a prospective approach with no impacts on our financial statements on the date of adoption.

ASU 2017-05, Other Income: Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets

In February 2017, a new accounting standard was issued that intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard became effective for us on January 1, 2018. The guidance may be applied using either a retrospective or modified retrospective transition approach. We adopted this standard on January 1, 2018 using a modified retrospective transition approach. The adoption of this guidance did not have a significant impact on our financial statement results.

ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs). The presentation changes will require net benefit costs to be disaggregated on the income statement by the various components that comprise these costs. Specifically, only the service cost component will be eligible for presentation as an operating income item, and all other cost components will be presented as non-operating items. This presentation change must be applied retrospectively. Furthermore, the new standard only allows the service cost component to be eligible for capitalization. The change in capitalization requirements must be applied prospectively. The new guidance became effective for us on January 1, 2018.

We adopted this new accounting standard on January 1, 2018. Beginning in the first quarter of 2018, we will present the non-service cost components of net benefit costs in other income instead of operating income. Prior year non-service cost components will also be reclassified from operating income to other income. Upon adoption, we will no longer capitalize a portion of the non-service cost components of net benefit costs. In 2018, because the non-service cost components are a reduction to total benefit costs, we estimate this change will result in the capitalization of an additional $15 million of net benefit costs, with a corresponding increase to pretax income. See note 7 for additional information related to our pension plans and other postretirement benefits.

ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities

In August 2017, a new accounting standard was issued that modifies hedge accounting guidance with the intent of simplifying the application of hedge accounting. The new standard is effective for us on January 1, 2019, with early application permitted. At transition, the guidance requires the changes to be applied to hedging relationships existing on the date of adoption, with the effect of adoption reflected as of the beginning of the fiscal year of adoption using a cumulative effect adjustment approach. The presentation and disclosure changes may be applied prospectively. We are evaluating the new guidance, but at this time we do not expect the adoption of this guidance will have a significant impact on our financial statement results as we are currently not applying hedge accounting.

ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

In February 2018, new accounting guidance was issued that allows entities an optional election to reclassify the income tax effects of the 2017 Tax Cuts and Jobs Act legislation on items within accumulated other comprehensive income to retained earnings. Amounts eligible for reclassification must relate to the effects from the Tax Cuts and Jobs Act remaining in accumulated other comprehensive income. The new guidance also requires expanded disclosures. This guidance is effective for us on January 1, 2019 with early application permitted. The guidance should be applied either in the period of adoption or retrospectively to each period in which the effect of the Tax Cuts and Jobs Act was recognized. We are currently evaluating this new guidance to determine whether we will elect this reclassification adjustment. The adoption of this guidance will not impact our income from continuing operations. See Note 4 for additional discussion of the Tax Cuts and Jobs Act.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Schedule of reclassifications of the prior year

The following tables show the impacts of the reclassifications of the prior year (previously reported) amounts (dollars in thousands):

Pinnacle West Capital Corporation Consolidated Balance Sheets- December 31, 2016	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Accumulated other comprehensive loss:
Pension and other postretirement benefits	$	(39,070	)	$	39,070		$	—
Derivative instruments	(4,752		)	4,752			—
Total accumulated other comprehensive loss	(43,822		)	43,822			—
Accumulated other comprehensive loss	—			(43,822		)	(43,822		)

Arizona Public Service Company Consolidated Balance Sheets - December 31, 2016	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Accumulated other comprehensive loss:
Pension and other postretirement benefits	$	(20,671	)	$	20,671		$	—
Derivative instruments	(4,752		)	4,752			—
Total accumulated other comprehensive loss	(25,423		)	25,423			—
Accumulated other comprehensive loss	—			(25,423		)	(25,423		)

Schedule of property, plant and equipment

Pinnacle West’s property, plant and equipment included in the December 31, 2017 and 2016 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:	2017			2016
Generation	$	7,963,998		$	7,874,898
Transmission	2,836,578			2,746,508
Distribution	6,025,856			5,738,801
General plant	971,629			981,681
Plant in service and held for future use	17,798,061			17,341,888
Accumulated depreciation and amortization	(6,128,535		)	(5,970,100		)
Net	11,669,526			11,371,788
Construction work in progress	1,291,498			1,019,947
Palo Verde sale leaseback, net of accumulated depreciation	109,645			113,515
Intangible assets, net of accumulated amortization	257,189			90,022
Nuclear fuel, net of accumulated amortization	117,408			119,004
Total property, plant and equipment	$	13,445,266		$	12,714,276

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):

	Year ended December 31,
	2017		2016		2015
Cash paid during the period for:
Income taxes, net of refunds	$	2,186	$	9,956	$	6,550
Interest, net of amounts capitalized	189,288		184,462		170,209
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	130,404	$	114,855	$	83,798
Dividends declared but not paid	77,667		72,926		69,363

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Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2017

Regulated Operations [Abstract]

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 (liability) for 2017 and 2016 (dollars in thousands):

	Twelve Months Ended December 31,
	2017		2016
Beginning balance	$	12,465	$	(9,688	)
Deferred fuel and purchased power costs — current period	48,405		60,303
Amounts refunded/(charged) to customers	14,767		(38,150		)
Ending balance	$	75,637	$	12,465

Schedule of regulatory assets

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

S		December 31, 2017				December 31, 2016
	Amortization Through	Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	576,188	$	—	$	711,059
Retired power plant costs	2033	27,402		188,843		9,913		117,591
Income taxes - AFUDC equity	2047	3,828		142,852		6,305		152,118
Deferred fuel and purchased power — mark-to-market (Note 16)	2020	52,100		34,845		—		42,963
Four Corners cost deferral	2024	8,077		48,305		6,689		56,894
Income taxes — investment tax credit basis adjustment	2046	1,066		26,218		2,120		54,356
Lost fixed cost recovery (b)	2018	59,844		—		61,307		—
Palo Verde VIEs (Note 18)	2046	—		19,395		—		18,775
Deferred compensation	2036	—		36,413		—		35,595
Deferred property taxes	2027	8,569		74,926		—		73,200
Loss on reacquired debt	2038	1,637		15,305		1,637		16,942
AG-1 deferral	2022	2,654		8,472		—		5,868
Demand side management (b)	2017	—		—		3,744		—
Tax expense of Medicare subsidy	2024	1,236		7,415		1,513		10,589
Mead-Phoenix transmission line CIAC	2050	332		10,376		332		10,708
Deferred fuel and purchased power (b) (c)	2018	75,637		—		12,465		—
Coal reclamation	2026	1,068		12,396		418		5,182
Other	Various	4,638		353		432		1,588
Total regulatory assets (d)		$	248,088	$	1,202,302	$	106,875	$	1,313,428

(a) This asset represents the future recovery of pension 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 7 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, Transmission Cost Adjustor and Other Transmission Matters.”

Schedule of regulatory liabilities

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

		December 31, 2017				December 31, 2016
	Amortization Through	Current		Non-Current		Current		Non-Current
Excess deferred income taxes - Tax Cuts and Jobs Act	(a)	$	—	$	1,520,274	$	—	$	—
Asset retirement obligations	2057	—		332,171		—		279,976
Removal costs	(b)	18,238		209,191		29,899		223,145
Other post retirement benefits	(d)	37,642		151,985		32,662		123,913
Income taxes - deferred investment tax credit	2046	2,164		52,497		4,368		108,827
Income taxes - change in rates	2046	2,573		70,537		1,771		70,898
Spent nuclear fuel	2027	6,924		62,132		—		71,726
Renewable energy standard (c)	2018	23,155		—		26,809		—
Demand side management (c)	2019	3,066		4,921		—		20,472
Sundance maintenance	2030	—		16,897		—		15,287
Deferred gains on utility property	2022	4,423		10,988		2,063		8,895
Four Corners coal reclamation	2038	1,858		18,921		—		18,248
Other	Various	43		2,022		2,327		7,529
Total regulatory liabilities		$	100,086	$	2,452,536	$	99,899	$	948,916

(a) See Note 4. While the majority of the excess deferred tax balance shown is subject to special amortization rules under federal income tax laws, which require amortization of the balance over the remaining regulatory life of the related property, treatment of a portion of the liability, and the month in which pass-through of the excess deferred tax balance will begin is subject to regulatory approval. This approval will be sought through the Company's TEAM adjustor mechanism and FERC filings in 2018. As a result, the Company cannot estimate the amount of this regulatory liability which is expected to reverse within the next 12 months.

(b) 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 11).

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

(d) See Note 7.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Schedule of unrecognized tax benefits roll forward

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):

	Pinnacle West Consolidated									APS Consolidated
	2017			2016			2015			2017			2016			2015
Total unrecognized tax benefits, January 1	$	36,075		$	34,447		$	44,775		$	36,075		$	34,447		$	44,775
Additions for tax positions of the current year	2,937			2,695			2,175			2,937			2,695			2,175
Additions for tax positions of prior years	4,783			886			—			4,783			886			—
Reductions for tax positions of prior years for:
Changes in judgment	(1,829		)	(1,953		)	(10,244		)	(1,829		)	(1,953		)	(10,244		)
Settlements with taxing authorities	—			—			—			—			—			—
Lapses of applicable statute of limitations	—			—			(2,259		)	—			—			(2,259		)
Total unrecognized tax benefits, December 31	$	41,966		$	36,075		$	34,447		$	41,966		$	36,075		$	34,447

Summary of unrecognized tax benefits

Included in the balances of unrecognized tax benefits are the following tax positions that, if recognized, would decrease our effective tax rate (dollars in thousands):

	Pinnacle West Consolidated						APS Consolidated
	2017		2016		2015		2017		2016		2015
Tax positions, that if recognized, would decrease our effective tax rate	$	16,373	$	11,313	$	9,523	$	16,373	$	11,313	$	9,523

The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands): 

	Pinnacle West Consolidated							APS Consolidated
	2017		2016		2015			2017		2016		2015
Unrecognized tax benefit interest expense/(benefit) recognized	$	577	$	529	$	(161	)	$	577	$	529	$	(161	)

Following are the total amount of accrued liabilities for interest recognized related to unrecognized benefits that could reverse and decrease our effective tax rate to the extent matters are settled favorably (dollars in thousands):

	Pinnacle West Consolidated						APS Consolidated
	2017		2016		2015		2017		2016		2015
Unrecognized tax benefit interest accrued	$	1,910	$	1,333	$	804	$	1,910	$	1,333	$	804

Components of income tax expense

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

	Pinnacle West Consolidated							APS Consolidated
	Year Ended December 31,							Year Ended December 31,
	2017		2016		2015			2017		2016		2015
Current:
Federal	$	11,624	$	8,630	$	(12,335	)	$	21,512	$	711	$	6,485
State	3,052		1,259		4,763			2,778		4,276		7,813
Total current	14,676		9,889		(7,572		)	24,290		4,987		14,298
Deferred:
Federal	223,729		201,743		221,505			221,078		215,178		208,326
State	19,867		24,779		23,787			23,800		25,677		23,217
Total deferred	243,596		226,522		245,292			244,878		240,855		231,543
Income tax expense	$	258,272	$	236,411	$	237,720		$	269,168	$	245,842	$	245,841

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 at the 35% federal income tax rate to income tax expense (dollars in thousands):

	Pinnacle West Consolidated									APS Consolidated
	Year Ended December 31,									Year Ended December 31,
	2017			2016			2015			2017			2016			2015
Federal income tax expense at 35% statutory rate	$	268,177		$	244,278		$	242,869		$	277,540		$	254,617		$	250,267
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	14,897			16,311			18,265			17,276			18,750			20,433
Credits and favorable adjustments related to prior years resolved in current year	—			—			(2,169		)	—			—			(1,892		)
Medicare Subsidy Part-D	853			844			837			853			844			837
Stock compensation	(6,659		)	(2,951		)	—			(3,489		)	(1,937		)	—
Excess Deferred Income Taxes - Tax Cuts and Jobs Act	9,348			—			—			9,431			—			—
Allowance for equity funds used during construction (see Note 1)	(12,937		)	(11,724		)	(9,711		)	(12,937		)	(11,724		)	(9,711		)
Palo Verde VIE noncontrolling interest (see Note 18)	(6,823		)	(6,823		)	(6,626		)	(6,823		)	(6,823		)	(6,626		)
Investment tax credit amortization	(6,715		)	(5,887		)	(5,527		)	(6,715		)	(5,887		)	(5,527		)
Other	(1,869		)	2,363			(218		)	(5,968		)	(1,998		)	(1,940		)
Income tax expense	$	258,272		$	236,411		$	237,720		$	269,168		$	245,842		$	245,841

Components of the net deferred income tax liability

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

	Pinnacle West Consolidated						APS Consolidated
	December 31,						December 31,
	2017			2016			2017			2016
DEFERRED TAX ASSETS
Risk management activities	$	25,103		$	26,614		$	25,103		$	26,614
Regulatory liabilities:
Excess Deferred Income Taxes - Tax Cuts and Jobs Act	376,906			—			376,906			—
Asset retirement obligation and removal costs	135,847			200,140			135,847			200,140
Unamortized investment tax credits	54,661			113,195			54,661			113,195
Other postretirement benefits	47,021			60,375			47,021			60,375
Other	37,489			63,311			37,489			63,311
Pension liabilities	83,126			204,436			77,280			194,981
Renewable energy incentives	33,546			56,379			33,546			56,379
Credit and loss carryforwards	53,946			75,944			1,920			1,645
Other	102,432			158,421			108,223			187,453
Total deferred tax assets	950,077			958,815			897,996			904,093
DEFERRED TAX LIABILITIES
Plant-related	(2,220,886		)	(3,297,989		)	(2,220,886		)	(3,297,989		)
Risk management activities	(491		)	(7,594		)	(491		)	(7,594		)
Other postretirement assets	(66,134		)	(63,477		)	(65,733		)	(62,819		)
Regulatory assets:
Allowance for equity funds used during construction	(36,365		)	(61,088		)	(36,365		)	(61,088		)
Deferred fuel and purchased power — mark-to-market	(40,778		)	(21,396		)	(40,778		)	(21,396		)
Pension benefits	(142,848		)	(274,184		)	(142,848		)	(274,184		)
Retired power plant costs (see Note 3)	(53,611		)	(49,166		)	(53,611		)	(49,166		)
Other	(74,423		)	(123,987		)	(74,423		)	(123,987		)
Other	(5,346		)	(5,166		)	(5,346		)	(5,165		)
Total deferred tax liabilities	(2,640,882		)	(3,904,047		)	(2,640,481		)	(3,903,388		)
Deferred income taxes — net	$	(1,690,805	)	$	(2,945,232	)	$	(1,742,485	)	$	(2,999,295	)

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Lines of Credit and Short-Term Borrowings (Tables)

12 Months Ended

Dec. 31, 2017

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, 2017 and 2016 (dollars in thousands):

	December 31, 2017								December 31, 2016
	Pinnacle West			APS		Total			Pinnacle West			APS			Total
Commitments under Credit Facilities	$	325,000		$	1,000,000	$	1,325,000		$	275,000		$	1,000,000		$	1,275,000
Outstanding Commercial Paper and Revolving Credit Facility Borrowings	(95,400		)	—		(95,400		)	(41,700		)	(135,500		)	(177,200		)
Amount of Credit Facilities Available	$	229,600		$	1,000,000	$	1,229,600		$	233,300		$	864,500		$	1,097,800
Weighted-Average Commitment Fees	0.125%			0.100%					0.125%			0.100%

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Long-Term Debt and Liquidity Matters (Tables)

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

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, 2017 and 2016 (dollars in thousands):

	Maturity	Interest	December 31,
	Dates (a)	Rates	2017			2016
APS
Pollution control bonds:
Variable	2029	(b)	$	35,975		$	35,975
Fixed	2024-2029	1.75%-4.70%	147,150			147,150
Total pollution control bonds			183,125			183,125
Senior unsecured notes	2019-2046	2.20%-8.75%	4,275,000			3,725,000
Term loans	2018-2019	(c)	150,000			150,000
Unamortized discount			(11,288		)	(11,816		)
Unamortized premium			8,049			4,506
Unamortized debt issuance cost			(31,594		)	(29,030		)
Total APS long-term debt			4,573,292			4,021,785
Less current maturities			82,000			—
Total APS long-term debt less current maturities			4,491,292			4,021,785
Pinnacle West
Term loan	2017	(d)	—			125,000
Senior unsecured notes	2020	2.25%	300,000			—
Unamortized discount			(184		)	—
Unamortized debt issuance cost			(1,395		)	—
Total PNW long-term debt			298,421			125,000
Less current maturities			—			125,000
Total PNW long-term debt less current maturities			298,421			—
TOTAL LONG-TERM DEBTLESS CURRENT MATURITIES			$	4,789,713		$	4,021,785

(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 1.77% at December 31, 2017 and 0.81% at December 31, 2016.

(c) The weighted-average interest rate was 2.236% at December 31, 2017, and 1.427% at December 31, 2016.

(d) The interest rate was 1.520% at December 31, 2016.

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 thousands):

Year	Consolidated Pinnacle West		Consolidated APS
2018	$	82,000	$	82,000
2019	600,000		600,000
2020	550,000		250,000
2021	—		—
2022	—		—
Thereafter	3,676,125		3,676,125
Total	$	4,908,125	$	4,608,125

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 thousands):

	As of December 31, 2017				As of December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	298,421	$	298,608	$	125,000	$	125,000
APS	4,573,292		5,006,348		4,021,785		4,300,789
Total	$	4,871,713	$	5,304,956	$	4,146,785	$	4,425,789

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Retirement Plans and Other Benefits (Tables)

12 Months Ended

Dec. 31, 2017

Retirement Benefits [Abstract]

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 or liability) (dollars in thousands):

	Pension									Other Benefits
	2017			2016			2015			2017			2016			2015
Service cost-benefits earned during the period	$	54,858		$	53,792		$	59,627		$	17,119		$	14,993		$	16,827
Interest cost on benefit obligation	129,756			131,647			123,983			29,959			29,721			28,102
Expected return on plan assets	(174,271		)	(173,906		)	(179,231		)	(53,401		)	(36,495		)	(36,855		)
Amortization of:
Prior service cost (credit)	81			527			594			(37,842		)	(37,883		)	(37,968		)
Net actuarial loss	47,900			40,717			31,056			5,118			4,589			4,881
Net periodic benefit cost	$	58,324		$	52,777		$	36,029		$	(39,047	)	$	(25,075	)	$	(25,013	)
Portion of cost charged to expense	$	27,295		$	26,172		$	20,036		$	(18,274	)	$	(12,435	)	$	(10,391	)

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 2017 and 2016 (dollars in thousands):

	Pension						Other Benefits
	2017			2016			2017			2016
Change in Benefit Obligation
Benefit obligation at January 1	$	3,204,462		$	3,033,803		$	716,445		$	647,020
Service cost	54,858			53,792			17,119			14,993
Interest cost	129,756			131,647			29,959			29,721
Benefit payments	(166,342		)	(142,247		)	(30,144		)	(26,231		)
Actuarial loss	171,452			127,467			20,014			50,942
Benefit obligation at December 31	3,394,186			3,204,462			753,393			716,445
Change in Plan Assets
Fair value of plan assets at January 1	2,675,357			2,542,774			882,651			833,017
Actual return on plan assets	428,374			166,408			139,367			63,463
Employer contributions	100,000			100,000			353			819
Benefit payments	(146,704		)	(133,825		)	—			(14,648		)
Fair value of plan assets at December 31	3,057,027			2,675,357			1,022,371			882,651
Funded Status at December 31	$	(337,159	)	$	(529,105	)	$	268,978		$	166,206

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, 2017 and 2016 (dollars in thousands):

	2017		2016
Projected benefit obligation	$	3,394,186	$	3,204,462
Accumulated benefit obligation	3,227,233		3,049,406
Fair value of plan assets	3,057,027		2,675,357

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, 2017 and 2016 (dollars in thousands):

	Pension						Other Benefits
	2017			2016			2017		2016
Noncurrent asset	$	—		$	—		$	268,978	$	166,206
Current liability	(9,859		)	(19,795		)	—		—
Noncurrent liability	(327,300		)	(509,310		)	—		—
Net amount recognized	$	(337,159	)	$	(529,105	)	$	268,978	$	166,206

Schedule of accumulated other comprehensive loss

The following table shows the details related to accumulated other comprehensive loss as of December 31, 2017 and 2016 (dollars in thousands): 

	Pension						Other Benefits
	2017			2016			2017			2016
Net actuarial loss	$	643,199		$	773,750		$	75,439		$	146,509
Prior service cost (credit)	—			81			(265,575		)	(303,417		)
APS’s portion recorded as a regulatory (asset) liability	(576,188		)	(711,059		)	189,627			156,575
Income tax expense (benefit)	(24,915		)	(24,202		)	853			833
Accumulated other comprehensive loss	$	42,096		$	38,570		$	344		$	500

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 and liabilities into net periodic benefit cost in 2018 (dollars in thousands):

	Pension		Other Benefits
Net actuarial loss	$	28,334	$	—
Prior service credit	—		(37,842		)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2018	$	28,334	$	(37,842	)

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,
	2017		2016		2017		2016		2015
Discount rate – pension	3.65	%	4.08	%	4.08	%	4.37	%	4.02	%
Discount rate – other benefits	3.71	%	4.17	%	4.17	%	4.52	%	4.14	%
Rate of compensation increase	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%
Expected long-term return on plan assets - pension	N/A		N/A		6.55	%	6.90	%	6.90	%
Expected long-term return on plan assets - other benefits	N/A		N/A		6.05	%	4.45	%	4.45	%
Initial healthcare cost trend rate (pre-65 participants)	7.00	%	7.00	%	7.00	%	7.00	%	7.00	%
Initial healthcare cost trend rate (post-65 participants)	4.75	%	5.00	%	5.00	%	5.00	%	5.00	%
Ultimate healthcare cost trend rate	4.75	%	5.00	%	5.00	%	5.00	%	5.00	%
Number of years to ultimate trend rate (pre-65 participants)	8		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 on our December 31, 2017 amounts (dollars in thousands): 

	1% Increase		1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	$	8,424	$	(5,616	)
Effect on service and interest cost components of net periodic other postretirement benefit costs	9,145		(7,037		)
Effect on the accumulated other postretirement benefit obligation	128,203		(98,143		)

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, 2016, by asset category, are as follows (dollars in thousands):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Other (a)		Balance at December 31, 2016
Pension Plan:
Cash and cash equivalents	$	13,995	$	—	$	—	$	13,995
Fixed income securities:
Corporate	—		1,210,453		—		1,210,453
U.S. Treasury	112,583		—		—		112,583
Other (b)	—		102,170		—		102,170
Common stock equities (c)	235,109		—		—		235,109
Mutual funds (d)	251,506		—		—		251,506
Common and collective trusts:
Equities	—		—		266,840		266,840
Real estate	—		—		161,449		161,449
Partnerships	—		—		208,915		208,915
Short-term investments and other (e)	—		—		112,337		112,337
Total	$	613,193	$	1,312,623	$	749,541	$	2,675,357
Other Benefits:
Cash and cash equivalents	$	304	$	—	$	—	$	304
Fixed income securities:
Corporate	—		268,193		—		268,193
U.S. Treasury	145,255		—		—		145,255
Other (b)	—		34,506		—		34,506
Common stock equities (c)	243,741		—		—		243,741
Mutual funds (d)	67,418		—		—		67,418
Common and collective trusts:
Equities	—		—		95,814		95,814
Real estate	—		—		14,509		14,509
Partnerships	—		—		3,060		3,060
Short-term investments and other (e)	—		—		9,851		9,851
Total	$	456,718	$	302,699	$	123,234	$	882,651

(a) These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy.

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

(c) This category primarily consists of U.S. common stock equities.

(d) These funds invest in U.S. and international common stock equities.

(e) This category includes plan receivables and payable

The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2017:

	Other Benefits
	Actual Allocation
Long-term fixed income assets	67	%
Return-generating assets	33	%
Total	100	%

Based on the IPS, and given the pension plan's funded status at year-end 2017, the target and actual allocation for the pension plan at December 31, 2017 are as follows:

	Pension
	Target Allocation		Actual Allocation
Long-term fixed income assets	62	%	58	%
Return-generating assets	38	%	42	%
Total	100	%	100	%

The permissible range is within +/- 3% of the target allocation shown in the above table, and also considers the Plan's funded status.

The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-generating assets:

Asset Class	Target Allocation
Equities in US and other developed markets	18	%
Equities in emerging markets	6	%
Alternative investments	14	%
Total	38	%

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2017, by asset category, are as follows (dollars in thousands):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Other (a)		Balance at December 31, 2017
Pension Plan:
Cash and cash equivalents	$	3,830	$	—	$	—	$	3,830
Fixed income securities:
Corporate	—		1,365,194		—		1,365,194
U.S. Treasury	221,291		—		—		221,291
Other (b)	—		100,599		—		100,599
Common stock equities (c)	228,088		—		—		228,088
Mutual funds (d)	233,732		—		—		233,732
Common and collective trusts:
Equities	—		—		408,763		408,763
Real estate	—		—		171,569		171,569
Fixed Income	—		—		90,869		90,869
Partnerships	—		—		133,379		133,379
Short-term investments and other (e)	—		1,208		98,505		99,713
Total	$	686,941	$	1,467,001	$	903,085	$	3,057,027
Other Benefits:
Cash and cash equivalents	$	143	$	—	$	—	$	143
Fixed income securities:
Corporate	—		306,008		—		306,008
U.S. Treasury	336,963		—		—		336,963
Other (b)	—		32,508		—		32,508
Common stock equities (c)	196,153		—		—		196,153
Mutual funds (d)	39,269		—		—		39,269
Common and collective trusts:
Equities	—		—		75,310		75,310
Real estate	—		—		15,422		15,422
Short-term investments and other (e)	11,268		149		9,178		20,595
Total	$	583,796	$	338,665	$	99,910	$	1,022,371

(a) These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy.

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

(c) This category primarily consists of U.S. common stock equities.

(d) These funds invest in U.S. and international common stock equities.

(e) This category includes plan receivables and payables.

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
2018	$	175,383	$	31,891
2019	181,902		34,000
2020	191,586		35,658
2021	196,583		37,090
2022	201,463		37,860
Years 2023-2027	1,068,568		191,207

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Leases (Tables)

12 Months Ended

Dec. 31, 2017

Leases [Abstract]

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 thousands):

Year	Pinnacle West Consolidated		APS
2018	$	13,412	$	13,110
2019	11,054		10,802
2020	9,641		9,392
2021	7,105		6,858
2022	4,609		4,510
Thereafter	55,940		53,605
Total future lease commitments	$	101,761	$	98,277

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Jointly-Owned Facilities (Tables)

12 Months Ended

Dec. 31, 2017

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

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, 2017 (dollars in thousands):

	Percent Owned			Plant in Service		Accumulated Depreciation		Construction Work in Progress
Generating facilities:
Palo Verde Units 1 and 3	29.1	%		$	1,872,104	$	1,092,049	$	24,257
Palo Verde Unit 2 (a)	16.8	%		619,263		364,516		14,672
Palo Verde Common	28.0	%	(b)	726,223		262,065		46,577
Palo Verde Sale Leaseback			(a)	351,050		241,405		—
Four Corners Generating Station	63.0	%		1,196,683		568,304		240,514
Cholla common facilities (c)	50.5	%		180,907		69,633		1,091
Transmission facilities:
ANPP 500kV System	34.0	%	(b)	130,767		46,400		684
Navajo Southern System	27.5	%	(b)	85,299		28,915		180
Palo Verde — Yuma 500kV System	18.1	%	(b)	14,765		6,614		486
Four Corners Switchyards	63.2	%	(b)	66,386		12,605		327
Phoenix — Mead System	17.1	%	(b)	39,383		17,600		41
Palo Verde — Rudd 500kV System	50.0	%		97,600		23,884		245
Morgan — Pinnacle Peak System	64.6	%	(b)	117,721		14,569		1
Round Valley System	50.0	%		515		141		—
Palo Verde — Morgan System	90.9	%	(b)	137,887		3,948		94,350
Hassayampa — North Gila System	80.0	%		142,541		6,953		—
Cholla 500kV Switchyard	85.7	%		5,243		1,312		190
Saguaro 500kV Switchyard	60.0	%		20,473		12,574		—
Kyrene — Knox System	50.0	%		578		297		—

(a) See Note 18.

(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.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Summary of estimated coal take-or-pay commitments

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

	Years Ended December 31,
	2018		2019		2020		2021		2022		Thereafter
Coal take-or-pay commitments (a)	$	159,997	$	185,365	$	186,632	$	190,607	$	194,678	$	1,750,739

(a) Total take-or-pay commitments are approximately $2.7 billion.  The total net present value of these commitments is approximately $1.9 billion.

Summary of actual take-or-pay commitments

	Year Ended December 31,
	2017		2016		2015
Total purchases	$	165,220	$	160,066	$	211,327

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Change in asset retirement obligations

The following table shows the change in our asset retirement obligations for 2017 and 2016 (dollars in thousands):

	2017		2016
Asset retirement obligations at the beginning of year	$	624,475	$	443,576
Changes attributable to:
Accretion expense	33,104		26,656
Settlements	—		(15,732		)
Estimated cash flow revisions	21,950		151,046
Newly incurred or acquired obligations	—		18,929
Asset retirement obligations at the end of year	$	679,529	$	624,475

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Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2017

Selected Quarterly Financial Information [Line Items]

Schedule of quarterly financial information

Consolidated quarterly financial information for 2017 and 2016 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.

	2017 Quarter Ended								2017
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	677,728	$	944,587	$	1,183,322	$	759,659	$	3,565,296
Operations and maintenance	219,976		214,013		224,305		266,149		924,443
Operating income	73,506		304,229		466,082		90,610		934,427
Income taxes	4,211		88,967		144,319		20,775		258,272
Net income	28,185		172,317		280,945		26,502		507,949
Net income attributable to common shareholders	23,312		167,443		276,072		21,629		488,456
Earnings Per Share:
Net income attributable to common shareholders — Basic	$	0.21	$	1.50	$	2.47	$	0.19	$	4.37
Net income attributable to common shareholders — Diluted	0.21		1.49		2.46		0.19		4.35

	2016 Quarter Ended								2016
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	677,167	$	915,394	$	1,166,922	$	739,199	$	3,498,682
Operations and maintenance	243,195		242,279		217,568		208,277		911,319
Operating income	50,162		231,748		451,258		122,816		855,984
Income taxes	1,914		65,742		141,446		27,309		236,411
Net income	9,326		126,182		267,900		58,119		461,527
Net income attributable to common shareholders	4,453		121,308		263,027		53,246		442,034
Earnings Per Share:
Net income attributable to common shareholders — Basic	$	0.04	$	1.09	$	2.36	$	0.48	$	3.97
Net income attributable to common shareholders — Diluted	0.04		1.08		2.35		0.47		3.95

ARIZONA PUBLIC SERVICE COMPANY

Selected Quarterly Financial Information [Line Items]

Schedule of quarterly financial information

APS's quarterly financial information for 2017 and 2016 is as follows (dollars in thousands):

	2017 Quarter Ended,								2017
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	676,869	$	942,615	$	1,178,106	$	756,549	$	3,554,139
Operations and maintenance	212,218		208,286		215,264		255,361		891,129
Operating income	65,468		212,790		322,053		79,258		679,569
Net income attributable to common shareholder	23,162		169,108		284,256		27,783		504,309

	2016 Quarter Ended,								2016
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	676,632	$	909,757	$	1,166,359	$	737,006	$	3,489,754
Operations and maintenance	238,711		233,712		209,366		197,319		879,108
Operating income	48,930		165,684		307,601		95,765		617,980
Net income attributable to common shareholder	7,253		127,188		269,220		58,480		462,141

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

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, 2017 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

	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, 2017
Assets
Cash equivalents	$	10,630	$	—		$	—		$	—			$	10,630
Risk management activities — derivative instruments:
Commodity contracts	—		5,683			1,036			(4,737		)	(b)	1,982
Coal reclamation escrow account (c):	455		31,562			—			525				32,542
Nuclear decommissioning trust:
Cash and cash equivalents	7,224		—			—			109			(d)	7,333
U.S. commingled equity funds	—		—			—			417,390			(e)	417,390
Fixed income securities:
U.S. Treasury	127,662		—			—			—				127,662
Corporate debt	—		114,007			—			—				114,007
Mortgage-backed securities	—		111,874			—			—				111,874
Municipal bonds	—		79,049			—			—				79,049
Other	—		13,685			—			—				13,685
Subtotal nuclear decommissioning trust	134,886		318,615			—			417,499				871,000
Total Assets	$	145,971	$	355,860		$	1,036		$	413,287			$	916,154
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(78,646	)	$	(19,292	)	$	1,516		(b)	$	(96,422	)

(a) Primarily consists of long-dated electricity contracts.

(b) Represents counterparty netting, margin, and collateral. See Note 16.

(c) Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Consolidated Balance Sheets. Primarily consists of fixed income municipal bonds.

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

(e) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

The following table presents the fair value at December 31, 2016 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

	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, 2016
Assets
Coal reclamation trust (b):	$	14,521	$	—		$	—		$	—			$	14,521
Risk management activities — derivative instruments:
Commodity contracts	—		43,722			11,076			(35,103		)	(c)	19,695
Nuclear decommissioning trust:
U.S. commingled equity funds	—		—			—			353,261			(d)	353,261
Fixed income securities:
Cash and cash equivalent funds	—		—			—			795			(e)	795
U.S. Treasury	95,441		—			—			—				95,441
Corporate debt	—		111,623			—			—				111,623
Mortgage-backed securities	—		115,337			—			—				115,337
Municipal bonds	—		80,997			—			—				80,997
Other	—		22,132			—			—				22,132
Subtotal nuclear decommissioning trust	95,441		330,089			—			354,056				779,586
Total	$	109,962	$	373,811		$	11,076		$	318,953			$	813,802
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(45,641	)	$	(58,482	)	$	31,049		(c)	$	(73,074	)

(a) Primarily consists of long-dated electricity contracts.

(b) Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Consolidated Balance Sheets. Primarily consists of cash equivalents. Presented as Coal reclamation escrow in 2017.

(c) Represents counterparty netting, margin and collateral. See Note 16.

(d) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

(e) 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

The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2017 and December 31, 2016:

	December 31, 2017 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Commodity Contracts	Assets		Liabilities
Electricity:
Forward Contracts (a)	$	21	$	15,485	Discounted cash flows	Electricity forward price (per MWh)	$18.51 - $38.75	$	27.89
Natural Gas:
Forward Contracts (a)	1,015		3,807		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.33 - $3.11	$	2.71
Total	$	1,036	$	19,292

(a) Includes swaps and physical and financial contracts.

	December 31, 2016 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Commodity Contracts	Assets		Liabilities
Electricity:
Forward Contracts (a)	$	10,648	$	32,042	Discounted cash flows	Electricity forward price (per MWh)	$16.43 - $41.07	$	29.86
Natural Gas:
Forward Contracts (a)	428		26,440		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.32 - $3.60	$	2.81
Total	$	11,076	$	58,482

(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, 2017 and 2016 (dollars in thousands):

	Year Ended December 31,
Commodity Contracts	2017			2016
Net derivative balance at beginning of period	$	(47,406	)	$	(32,979	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			—
Included in OCI	3			88
Deferred as a regulatory asset or liability	(13,643		)	(37,543		)
Settlements	5,834			15,146
Transfers into Level 3 from Level 2	(10,026		)	1,900
Transfers from Level 3 into Level 2	46,982			5,982
Net derivative balance at end of period	$	(18,256	)	$	(47,406	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

Schedule of earnings per weighted average common share outstanding

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for continuing operations attributable to common shareholders for the years ended December 31, 2017, 2016 and 2015 (in thousands, except per share amounts):

	2017		2016		2015
Net income attributable to common shareholders	$	488,456	$	442,034	$	437,257
Weighted average common shares outstanding — basic	111,839		111,409		111,026
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	528		637		526
Weighted average common shares outstanding — diluted	112,367		112,046		111,552
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders - basic	$	4.37	$	3.97	$	3.94
Net Income attributable to common shareholders - diluted	$	4.35	$	3.95	$	3.92

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Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of Nonvested Restricted Stock, Stock Grants and Stock Units

The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2017, 2016 and 2015.

	Restricted Stock Units, Stock Grants, and Stock Units (a)						Performance Shares (b)
	2017		2016		2015		2017		2016		2015
Units granted	161,963		141,811		152,651		147,706		166,666		151,430
Weighted-average grant date fair value	$	72.60	$	67.34	$	64.12	$	78.99	$	66.60	$	64.97

(a) Units granted includes awards that will be cash settled of 67,599 in 2017, 43,952 in 2016, and 45,104 in 2015.

(b) Reflects the target payout level.

The following table is a summary of the status of non-vested awards as of December 31, 2017 and changes during the year.

	Restricted Stock Units, Stock Grants, and Stock Units					Performance Shares
	Shares			Weighted-Average Grant Date Fair Value		Shares (b)		Weighted-Average Grant Date Fair Value
Nonvested at January 1, 2017	335,259			$	62.04	312,724		$	65.32
Granted	161,963			72.60		147,706		78.99
Change in performance factor	—			—		18,266		64.97
Vested	(202,327	)		59.19		(164,396	)	63.87
Forfeited (c)	(3,607	)		69.58		(4,798	)	69.77
Nonvested at December 31, 2017	291,288		(a)	69.78		309,502		72.46
Vested Awards Outstanding at December 31, 2017	89,928					164,396

(a) Includes 133,373 of awards that will be cash settled.

(b) The nonvested performance shares are reflected at target payout level.  The performance metric component 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.

(c) We account for forfeitures as they occur.

Summary of Nonvested Performance Shares

The following table is a summary of the status of non-vested awards as of December 31, 2017 and changes during the year.

	Restricted Stock Units, Stock Grants, and Stock Units					Performance Shares
	Shares			Weighted-Average Grant Date Fair Value		Shares (b)		Weighted-Average Grant Date Fair Value
Nonvested at January 1, 2017	335,259			$	62.04	312,724		$	65.32
Granted	161,963			72.60		147,706		78.99
Change in performance factor	—			—		18,266		64.97
Vested	(202,327	)		59.19		(164,396	)	63.87
Forfeited (c)	(3,607	)		69.58		(4,798	)	69.77
Nonvested at December 31, 2017	291,288		(a)	69.78		309,502		72.46
Vested Awards Outstanding at December 31, 2017	89,928					164,396

(a) Includes 133,373 of awards that will be cash settled.

(b) The nonvested performance shares are reflected at target payout level.  The performance metric component 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.

(c) We account for forfeitures as they occur.

The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2017, 2016 and 2015.

	Restricted Stock Units, Stock Grants, and Stock Units (a)						Performance Shares (b)
	2017		2016		2015		2017		2016		2015
Units granted	161,963		141,811		152,651		147,706		166,666		151,430
Weighted-average grant date fair value	$	72.60	$	67.34	$	64.12	$	78.99	$	66.60	$	64.97

(a) Units granted includes awards that will be cash settled of 67,599 in 2017, 43,952 in 2016, and 45,104 in 2015.

(b) Reflects the target payout level.

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Derivative Accounting (Tables)

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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

As of December 31, 2017, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

		Quantity
Commodity	Unit of Measure	December 31, 2017	December 31, 2016
Power	GWh	583	1,314
Gas	Billion cubic feet	240	194

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, 2017, 2016 and 2015 (dollars in thousands):

	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2017			2016			2015
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	OCI — derivative instruments	$	(59	)	$	47		$	(615	)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	(3,519		)	(3,926		)	(5,988		)

(a) During the years ended December 31, 2017, 2016, and 2015, we had no 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, 2017, 2016 and 2015 (dollars in thousands):

	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2017			2016		2015
Net Gain (Loss) Recognized in Income	Operating revenues	$	(1,192	)	$	771	$	574
Net Gain (Loss) Recognized in Income	Fuel and purchased power (a)	(87,991		)	25,711		(108,973		)
Total		$	(89,183	)	$	26,482	$	(108,399	)

(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 on offsetting liabilities

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, 2017 and 2016.  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, 2017: (dollars in thousands)	Gross  Recognized  Derivatives (a)			Amounts  Offset (b)			Net Recognized Derivatives			Other (c)			Amount  Reported on  Balance Sheet
Current assets	$	5,427		$	(3,796	)	$	1,631		$	300		$	1,931
Investments and other assets	1,292			(1,241		)	51			—			51
Total assets	6,719			(5,037		)	1,682			300			1,982
Current liabilities	(59,527		)	3,796			(55,731		)	(3,521		)	(59,252		)
Deferred credits and other	(38,411		)	1,241			(37,170		)	—			(37,170		)
Total liabilities	(97,938		)	5,037			(92,901		)	(3,521		)	(96,422		)
Total	$	(91,219	)	$	—		$	(91,219	)	$	(3,221	)	$	(94,440	)

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

(b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c) Represents cash collateral and cash 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 $3,521 and cash margin provided to counterparties of $300.

As of December 31, 2016: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset  (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	48,094		$	(28,400	)	$	19,694		$	—		$	19,694
Investments and other assets	6,704			(6,703		)	1			—			1
Total assets	54,798			(35,103		)	19,695			—			19,695
Current liabilities	(50,182		)	28,400			(21,782		)	(4,054		)	(25,836		)
Deferred credits and other	(53,941		)	6,703			(47,238		)	—			(47,238		)
Total liabilities	(104,123		)	35,103			(69,020		)	(4,054		)	(73,074		)
Total	$	(49,325	)	$	—		$	(49,325	)	$	(4,054	)	$	(53,379	)

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

(b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c) Represents cash collateral and cash 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

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

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, 2017 and 2016.  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, 2017: (dollars in thousands)	Gross  Recognized  Derivatives (a)			Amounts  Offset (b)			Net Recognized Derivatives			Other (c)			Amount  Reported on  Balance Sheet
Current assets	$	5,427		$	(3,796	)	$	1,631		$	300		$	1,931
Investments and other assets	1,292			(1,241		)	51			—			51
Total assets	6,719			(5,037		)	1,682			300			1,982
Current liabilities	(59,527		)	3,796			(55,731		)	(3,521		)	(59,252		)
Deferred credits and other	(38,411		)	1,241			(37,170		)	—			(37,170		)
Total liabilities	(97,938		)	5,037			(92,901		)	(3,521		)	(96,422		)
Total	$	(91,219	)	$	—		$	(91,219	)	$	(3,221	)	$	(94,440	)

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

(b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c) Represents cash collateral and cash 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 $3,521 and cash margin provided to counterparties of $300.

As of December 31, 2016: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset  (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	48,094		$	(28,400	)	$	19,694		$	—		$	19,694
Investments and other assets	6,704			(6,703		)	1			—			1
Total assets	54,798			(35,103		)	19,695			—			19,695
Current liabilities	(50,182		)	28,400			(21,782		)	(4,054		)	(25,836		)
Deferred credits and other	(53,941		)	6,703			(47,238		)	—			(47,238		)
Total liabilities	(104,123		)	35,103			(69,020		)	(4,054		)	(73,074		)
Total	$	(49,325	)	$	—		$	(49,325	)	$	(4,054	)	$	(53,379	)

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

(b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c) Represents cash collateral and cash 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 $4,054.

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, 2017 (dollars in thousands):

	December 31, 2017
Aggregate fair value of derivative instruments in a net liability position	$	97,938
Cash collateral posted	—
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)	91,071

(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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Other Income and Other Expense (Tables)

12 Months Ended

Dec. 31, 2017

Component of Other Income and Other Expense Nonoperating [Line Items]

Detail of other income and other expense

The following table provides detail of Pinnacle West's Consolidated other income and other expense for 2017, 2016 and 2015 (dollars in thousands):

	2017			2016			2015
Other income:
Interest income	$	3,497		$	884		$	493
Miscellaneous	509			17			128
Total other income	$	4,006		$	901		$	621
Other expense:
Non-operating costs	$	(11,749	)	$	(9,235	)	$	(11,292	)
Investment losses — net	(4,113		)	(1,747		)	(2,080		)
Miscellaneous	(5,677		)	(4,355		)	(4,451		)
Total other expense	$	(21,539	)	$	(15,337	)	$	(17,823	)

ARIZONA PUBLIC SERVICE COMPANY

Component of Other Income and Other Expense Nonoperating [Line Items]

Detail of other income and other expense

The following table provides detail of APS’s other income and other expense for 2017, 2016 and 2015 (dollars in thousands):

	2017			2016			2015
Other income:
Interest income	$	2,858		$	261		$	163
Gain on disposition of property	2,048			5,745			716
Miscellaneous	1,620			2,601			1,955
Total other income	$	6,526		$	8,607		$	2,834
Other expense:
Non-operating costs (a)	$	(12,395	)	$	(11,034	)	$	(11,648	)
Loss on disposition of property	(5,424		)	(1,246		)	(2,219		)
Miscellaneous	(5,561		)	(5,234		)	(5,152		)
Total other expense	$	(23,380	)	$	(17,514	)	$	(19,019	)

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

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Palo Verde Sale Leaseback Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2017

Variable Interest Entities [Abstract]

Amounts relating to the VIEs included in Consolidated Balance Sheets

Our Consolidated Balance Sheets at December 31, 2017 and December 31, 2016 include the following amounts relating to the VIEs (dollars in thousands):

	December 31, 2017		December 31, 2016
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation	$	109,645	$	113,515
Equity-Noncontrolling interests	129,040		132,290

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Investments (Tables)

12 Months Ended

Dec. 31, 2017

Investments, Debt and Equity Securities [Abstract]

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, 2017 and December 31, 2016 (dollars in thousands):

	December 31, 2017							December 31, 2016
	Fair Value		Total  Unrealized  Gains		Total  Unrealized  Losses			Fair Value		Total  Unrealized  Gains		Total  Unrealized  Losses
Equity securities	$	417,390	$	248,623	$	—		$	353,261	$	188,091	$	—
Fixed income securities	446,277		11,537		(2,996		)	425,530		9,820		(4,962		)
Cash and cash equivalents	7,224		—		—			—		—		—
Net receivables (a)	109		—		—			795		—		—
Total	$	871,000	$	260,160	$	(2,996	)	$	779,586	$	197,911	$	(4,962	)

(a) Net receivables/(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 thousands):

	Nuclear Decommissioning
	Year Ended December 31,
	2017			2016			2015
Realized gains	$	21,813		$	11,213		$	5,189
Realized losses	(13,146		)	(10,106		)	(6,225		)
Proceeds from the sale of securities (a)	542,246			633,410			478,813

(a) Proceeds are reinvested in the trust/account.

Fair value of fixed income securities, summarized by contractual maturities

The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2017 is as follows (dollars in thousands):

	Nuclear Decommissioning Trusts		Escrow Accounts		Total
Less than one year	$	24,668	$	455	$	25,123
1 year – 5 years	100,289		2,494		102,783
5 years – 10 years	129,239		8,615		137,854
Greater than 10 years	192,081		20,453		212,534
Total	$	446,277	$	32,017	$	478,294

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Changes in Accumulated Other Comprehensive Loss (Tables)

12 Months Ended

Dec. 31, 2017

Changes in accumulated other comprehensive income (loss) including reclassification adjustments, by component:

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

The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2017 and 2016 (dollars in thousands): 

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2015	$	(37,593	)		$	(7,155	)		$	(44,748	)
OCI (loss) before reclassifications	(4,509		)		(538		)		(5,047		)
Amounts reclassified from accumulated other comprehensive loss	3,032			(a)	2,941			(b)	5,973
Balance December 31, 2016	(39,070		)		(4,752		)		(43,822		)
OCI (loss) before reclassifications	(6,438		)		(35		)		(6,473		)
Amounts reclassified from accumulated other comprehensive loss	3,068			(a)	2,225			(b)	5,293
Balance December 31, 2017	$	(42,440	)		$	(2,562	)		$	(45,002	)

(a) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.

(b) 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 16.

ARIZONA PUBLIC SERVICE COMPANY

Changes in accumulated other comprehensive income (loss) including reclassification adjustments, by component:

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

The following table shows the changes in APS's accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2017 and 2016 (dollars in thousands): 

	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2015	$	(19,942	)		$	(7,155	)		$	(27,097	)
OCI (loss) before reclassifications	(3,821		)		(538		)		(4,359		)
Amounts reclassified from accumulated other comprehensive loss	3,092			(a)	2,941			(b)	6,033
Balance December 31, 2016	(20,671		)		(4,752		)		(25,423		)
OCI (loss) before reclassifications	(6,884		)		(35		)		(6,919		)
Amounts reclassified from accumulated other comprehensive loss	3,134			(a)	2,225			(b)	5,359
Balance December 31, 2017	$	(24,421	)		$	(2,562	)		$	(26,983	)

(a) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 7.

(b) 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 16.

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Summary of Significant Accounting Policies - Narrative (Details) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended			36 Months Ended
	May 31, 2014 $ / kWh	Dec. 31, 2017 USD ($) $ / shares shares	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2017 USD ($) $ / shares shares	Jul. 06, 2016
Approximate remaining average useful lives of utility property
Cost of services, depreciation		$ 453	$ 422	$ 430
Depreciation rates (as a percent)		2.80%	2.66%	2.74%
Allowance for Funds Used During Construction
Composite rate used to calculate AFUDC (as a percent)		6.68%	7.17%	8.02%
Income Taxes
Percent likelihood largest tax benefit amount is realized (greater than)		50.00%
Intangible Assets
Amortization expense		$ 72	$ 58	$ 58
Estimated amortization expense on existing intangible assets over the next five years
2018		53			$ 53
2019		38			38
2020		28			28
2021		22			22
2022		$ 17			$ 17
Remaining amortization period for intangible assets		6 years
Pinnacle West
Preferred Stock
Preferred stock, shares authorized (in shares) | shares		10,000,000			10,000,000
ARIZONA PUBLIC SERVICE COMPANY
Nuclear Fuel
Charges for the permanent disposal of spent nuclear fuel (in dollars per kWh) | $ / kWh	0.001
Preferred Stock
Preferred stock, shares authorized (in shares) | shares		15,535,000			15,535,000
Preferred stock par or stated value per share 1 (in dollars per share) | $ / shares		$ 25			$ 25
Preferred stock par or stated value per share 2 (in dollars per share) | $ / shares		50			50
Preferred stock par or stated value per share 3 (in dollars per share) | $ / shares		$ 100			$ 100
Minimum
Approximate remaining average useful lives of utility property
Depreciation rates (as a percent)					0.18%
Maximum
Approximate remaining average useful lives of utility property
Depreciation rates (as a percent)					16.44%
Investments
Ownership percentage for classification as cost method investments by El Dorado		20.00%
Fossil plant
Approximate remaining average useful lives of utility property
Average useful life		21 years
Nuclear plant
Approximate remaining average useful lives of utility property
Average useful life		26 years
Other generation
Approximate remaining average useful lives of utility property
Average useful life		25 years
Transmission
Approximate remaining average useful lives of utility property
Average useful life		38 years
Distribution
Approximate remaining average useful lives of utility property
Average useful life		33 years
General plant
Approximate remaining average useful lives of utility property
Average useful life		6 years
El Paso's Interest in Four Corners | 4CA
Utility Plant and Depreciation [Line Items]
Ownership interest acquired (as a percent)		7.00%			7.00%	7.00%

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Summary of Significant Accounting Policies - Schedule of Reclassification of Prior Period Adjustments (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Pension and other postretirement benefits		$ 0
Derivative instruments		0
Total accumulated other comprehensive loss		0
Accumulated other comprehensive loss	$ (45,002,000)	(43,822,000)
As previously reported
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Pension and other postretirement benefits		(39,070,000)
Derivative instruments		(4,752,000)
Total accumulated other comprehensive loss		(43,822,000)
Accumulated other comprehensive loss		0
Reclassifications to conform to current year presentation
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Pension and other postretirement benefits		39,070,000
Derivative instruments		4,752,000
Total accumulated other comprehensive loss		43,822,000
Accumulated other comprehensive loss		(43,822,000)
ARIZONA PUBLIC SERVICE COMPANY
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Pension and other postretirement benefits		0
Derivative instruments		0
Total accumulated other comprehensive loss		0
Accumulated other comprehensive loss	$ (26,983,000)	(25,423,000)
ARIZONA PUBLIC SERVICE COMPANY | As previously reported
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Pension and other postretirement benefits		(20,671,000)
Derivative instruments		(4,752,000)
Total accumulated other comprehensive loss		(25,423,000)
Accumulated other comprehensive loss		0
ARIZONA PUBLIC SERVICE COMPANY | Reclassifications to conform to current year presentation
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Pension and other postretirement benefits		20,671,000
Derivative instruments		4,752,000
Total accumulated other comprehensive loss		25,423,000
Accumulated other comprehensive loss		$ (25,423,000)

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Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Utility Plant and Depreciation [Line Items]
Net	$ 11,669,526	$ 11,371,788
Construction work in progress	1,291,498	1,019,947
Palo Verde sale leaseback, net of accumulated depreciation	109,645	113,515
Intangible assets, net of accumulated amortization	257,189	90,022
Nuclear fuel, net of accumulated amortization	117,408	119,004
Total property, plant and equipment	13,445,266	12,714,276
Electric Service
Utility Plant and Depreciation [Line Items]
Generation	7,963,998	7,874,898
Transmission	2,836,578	2,746,508
Distribution	6,025,856	5,738,801
General plant	971,629	981,681
Plant in service and held for future use	17,798,061	17,341,888
Accumulated depreciation and amortization	(6,128,535)	(5,970,100)
Net	11,669,526	11,371,788
Construction work in progress	1,291,498	1,019,947
Palo Verde sale leaseback, net of accumulated depreciation	109,645	113,515
Intangible assets, net of accumulated amortization	257,189	90,022
Nuclear fuel, net of accumulated amortization	117,408	119,004
Total property, plant and equipment	$ 13,445,266	$ 12,714,276

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Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Income tax (benefit), net of refunds	$ 2,186	$ 9,956	$ 6,550
Interest, net of amounts capitalized	189,288	184,462	170,209
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Accrued capital expenditures	130,404	114,855	83,798
Dividends declared but not paid	$ 77,667	$ 72,926	$ 69,363

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New Accounting Standards (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($)
Accounting Standards Update 2017-07 | Scenario, Forecast
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net benefit costs capitalized	$ 15

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Regulatory Matters Regulatory Matters - Retail Rate Case Filing (Details) - Retail Rate Case Filing with Arizona Corporation Commission - ACC - ARIZONA PUBLIC SERVICE COMPANY	Jan. 03, 2018 Customer	Nov. 13, 2017 USD ($)	Mar. 27, 2017 USD ($) $ / kWh	Mar. 26, 2017 $ / kWh	Jun. 01, 2016 USD ($)	Dec. 31, 2015 USD ($)	Jun. 01, 2011 USD ($)
Public Utilities, General Disclosures [Line Items]
Net retail rate increase					$ 165,900,000		$ 95,500,000
Adjuster account balance transferred into base rates						$ 267,600,000
Approximate percentage of increase in average customer bill			3.28%		5.74%
Approximate percentage of increase in average residential customer bill			4.54%		7.96%
Settlement agreement, net retail base rate increase			$ 94,600,000
Settlement agreement, non-fuel, non-depreciation, base rate increase			87,200,000
Fuel-related base rate decrease			53,600,000
Base rate increase, changes in depreciation schedules			$ 61,000,000
Authorized return on common equity (as a percent)			10.00%
Percentage of debt in capital structure			44.20%
Percentage of common equity in capital structure			55.80%
Environmental surcharge cap rate (in dollars per kWh) | $ / kWh			0.00050	0.00016
Resource comparison proxy for exported energy (in dollars per kWh) | $ / kWh			0.129
Monthly metering infrastructure opt-out fee		$ 5
AZ Sun II Program
Public Utilities, General Disclosures [Line Items]
Minimum annual renewable energy standard and tariff			$ 10,000,000
Maximum annual renewable energy standard and tariff			$ 15,000,000
Subsequent Event
Public Utilities, General Disclosures [Line Items]
Number of customers which signed complaint | Customer	25

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Regulatory Matters - Narrative (Details)																			1 Months Ended		2 Months Ended	12 Months Ended
	Feb. 22, 2018 USD ($)	Feb. 15, 2018 USD ($)	Feb. 09, 2018	Feb. 01, 2018 $ / kWh	Jan. 08, 2018 USD ($)	Nov. 20, 2017 USD ($)	Aug. 19, 2017 $ / kWh	Jun. 01, 2017 USD ($)	Feb. 01, 2017 $ / kWh	Jan. 13, 2017 USD ($)	Dec. 20, 2016 $ / kWh	Jun. 01, 2016 USD ($)	Feb. 01, 2016 $ / kWh	Jan. 15, 2016 USD ($)	Jan. 01, 2016 USD ($)	Feb. 01, 2015 $ / kWh	Nov. 04, 2014	Jun. 01, 2011 USD ($)	Sep. 30, 2016	Dec. 31, 2014 penetration_feeder storage_system MW	Apr. 30, 2014 workshop	Dec. 31, 2017 USD ($) $ / kWh	Dec. 31, 2012 $ / kWh	Nov. 14, 2017 USD ($)	Sep. 01, 2017 USD ($)	Jun. 30, 2017 USD ($)	Jan. 27, 2017 USD ($)	Jul. 01, 2016 USD ($)	Nov. 25, 2015 USD ($)	Mar. 20, 2015 project
APS
Regulatory Matters [Line Items]
Requested rate decrease for tax act																						$ (377,000,000)
APS | Lost Fixed Cost Recovery Mechanism
Regulatory Matters [Line Items]
Fixed costs recoverable per residential power lost (in dollars per kWh) | $ / kWh																							0.031
Fixed costs recoverable per non-residential power lost (in dollars per kWh) | $ / kWh																							0.023
Fixed costs recoverable per power lost (in dollars per kWh) | $ / kWh																						0.025
Rate matter cap percentage of retail revenue																						1.00%
Amount of adjustment approved representing prorated sales losses										$ 63,700,000				$ 46,400,000
Increase in amount of adjustment representing prorated sales losses										$ 17,300,000				$ 7,900,000
APS | ACC | Retail Rate Case Filing with Arizona Corporation Commission
Regulatory Matters [Line Items]
Net retail rate increase												$ 165,900,000						$ 95,500,000
Reduced system benefits charge, amount															$ 14,600,000
APS | ACC | Arizona Renewable Energy Standard and Tariff
Regulatory Matters [Line Items]
Plan term																						5 years
APS | ACC | Arizona Renewable Energy Standard and Tariff 2017
Regulatory Matters [Line Items]
Amount of approved budget																												$ 150,000,000
APS | ACC | Arizona Renewable Energy Standard and Tariff 2018
Regulatory Matters [Line Items]
Amount of proposed budget																										$ 90,000,000
APS | ACC | Modernization and Expansion of the Renewal Energy Standard
Regulatory Matters [Line Items]
Proposed renewal energy standard, percent of retail sales																			30.00%
Current renewal energy standard, percent of retail sales																			15.00%
APS | ACC | 2015 DSMAC
Regulatory Matters [Line Items]
Amount of approved budget																													$ 68,900,000
Rate matter number of resource savings projects | project																														3
APS | ACC | 2017 DSMAC
Regulatory Matters [Line Items]
Amount of approved budget																											$ 66,600,000
Amount of proposed budget												62,600,000
APS | ACC | Demand Side Management Adjustor Charge 2018
Regulatory Matters [Line Items]
Amount of proposed budget																								$ 52,600,000	$ 52,600,000
APS | ACC | Electric Energy Efficiency Standard
Regulatory Matters [Line Items]
Public utilities, cost effective energy efficiency programs, number of workshops | workshop																					3
Public utilities, cost effective efficiency programs, number of days to convene a workshop																	120 days
APS | ACC | Power Supply Adjustor (PSA)
Regulatory Matters [Line Items]
PSA rate (in dollars per kWh) | $ / kWh							0.000555		(0.001348)
Forward component of PSA rate (in dollars per kWh) | $ / kWh							0.000876		(0.001027)
Historical component of PSA rate (in dollars per kWh) | $ / kWh							(0.000321)		(0.000321)
APS | ACC | Net Metering
Regulatory Matters [Line Items]
Cost of service, resource comparison proxy method, maximum annual percentage decrease											10.00%
Cost of service for interconnected DG system customers, grandfathered period											20 years
Guaranteed export price period											10 years
Settlement agreement, energy price for exported energy (in dollars per kWh) | $ / kWh											0.129
APS | FERC | Transmission rates, transmission cost adjustor and other transmission matters
Regulatory Matters [Line Items]
Increase (decrease) in annual wholesale transmission rates								$ 35,100,000				$ 24,900,000
Cost Recovery Mechanisms | APS | ACC | Power Supply Adjustor (PSA)
Regulatory Matters [Line Items]
Maximum increase (decrease) in PSA rate (in dollars per kWh) | $ / kWh																0.004
PSA Rate in Prior Years | $ / kWh													0.001678
Subsequent Event
Regulatory Matters [Line Items]
Ballot initiative, proposed required energy supply to be obtained from renewable sources (as a percent)			50.00%
Subsequent Event | APS | Lost Fixed Cost Recovery Mechanism
Regulatory Matters [Line Items]
Increase in amount of adjustment representing prorated sales losses		$ 3,000,000
Amount of adjustment approved representing prorated sales losses pending approval		$ 60,700,000
Subsequent Event | APS | ACC
Regulatory Matters [Line Items]
Requested rate decrease for tax act					$ 119,100,000
Approved rate decrease for tax act	$ 119,100,000
Subsequent Event | APS | ACC | Power Supply Adjustor (PSA)
Regulatory Matters [Line Items]
PSA rate (in dollars per kWh) | $ / kWh				0.004555
Forward component of PSA rate (in dollars per kWh) | $ / kWh				0.002009
Historical component of PSA rate (in dollars per kWh) | $ / kWh				0.002546
Alternative to AZ Sun Program, Phase 1 | APS | Arizona Renewable Energy Standard and Tariff 2014
Regulatory Matters [Line Items]
Rate matter additional capacity from AZ Sun projects | MW																				8
Solar Partner Program Phase 2 | APS | Arizona Renewable Energy Standard and Tariff 2014
Regulatory Matters [Line Items]
Rate matter additional capacity from AZ Sun projects | MW																				2
Solar storage system, capacity (in MW) | MW																				2
Number of energy storage systems | storage_system																				2
Number of high solar penetration feeders | penetration_feeder																				2
Solar Communities | APS | ACC | Arizona Renewable Energy Standard and Tariff 2018
Regulatory Matters [Line Items]
Program term						3 years
Minimum | Solar Communities | APS | ACC | Arizona Renewable Energy Standard and Tariff 2018
Regulatory Matters [Line Items]
Required annual capital investment						$ 10,000,000
Maximum | Solar Communities | APS | ACC | Arizona Renewable Energy Standard and Tariff 2018
Regulatory Matters [Line Items]
Required annual capital investment						$ 15,000,000

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Regulatory Matters Regulatory Matters - Deferred Fuel and Purchased Power Regulatory Asset (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Change in regulatory asset
Deferred fuel and purchased power	$ 48,405	$ 60,303	$ (14,997)
Deferred fuel and purchased power amortization	14,767	(38,152)	(1,617)
ARIZONA PUBLIC SERVICE COMPANY
Change in regulatory asset
Deferred fuel and purchased power	48,405	60,303	(14,997)
Deferred fuel and purchased power amortization	14,767	(38,152)	(1,617)
ACC | ARIZONA PUBLIC SERVICE COMPANY | Power Supply Adjustor (PSA)
Change in regulatory asset
Beginning balance	12,465	(9,688)
Deferred fuel and purchased power	48,405	60,303
Deferred fuel and purchased power amortization	14,767	(38,150)
Ending balance	$ 75,637	$ 12,465	$ (9,688)

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Regulatory Matters - Four Corners, Cholla and Navajo Plant (Details) - APS - USD ($) $ in Millions			3 Months Ended	12 Months Ended
	Dec. 23, 2014	Dec. 30, 2013	Jun. 30, 2016	Dec. 31, 2017	Dec. 31, 2015
Retired power plant costs
Acquisition
Regulatory asset, net book value				$ 105.0
Navajo Plant
Acquisition
Regulatory asset, net book value				99.0
SCE | Four Corners
Acquisition
Regulatory assets					$ 12.0
Regulatory assets, write of amount			$ 12.0
Four Corners Units 4 and 5 | SCE
Acquisition
Ownership interest acquired (as a percent)		48.00%
Settlement agreement, ACC approved rate adjustment, annualized customer impact	$ 57.1
Transmission termination agreement net receipt due to negotiation of alternate arrangement		$ 40.0
Four Corners Units 4 and 5 | SCE | Four Corners cost deferral
Acquisition
Regulatory assets				$ 56.0
Amortization period				10 years

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Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Detail of regulatory assets
Regulatory assets, current	$ 248,088	$ 106,875
Regulatory assets, non-current	1,202,302	1,313,428
Pension
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	576,188	711,059
Retired power plant costs
Detail of regulatory assets
Regulatory assets, current	27,402	9,913
Regulatory assets, non-current	188,843	117,591
Income taxes - AFUDC equity
Detail of regulatory assets
Regulatory assets, current	3,828	6,305
Regulatory assets, non-current	142,852	152,118
Deferred fuel and purchased power - mark-to-market
Detail of regulatory assets
Regulatory assets, current	52,100	0
Regulatory assets, non-current	34,845	42,963
Four Corners cost deferral
Detail of regulatory assets
Regulatory assets, current	8,077	6,689
Regulatory assets, non-current	48,305	56,894
Income taxes — investment tax credit basis adjustment
Detail of regulatory assets
Regulatory assets, current	1,066	2,120
Regulatory assets, non-current	26,218	54,356
Lost fixed cost recovery
Detail of regulatory assets
Regulatory assets, current	59,844	61,307
Regulatory assets, non-current	0	0
Palo Verde VIE
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	19,395	18,775
Deferred compensation
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	36,413	35,595
Deferred property taxes
Detail of regulatory assets
Regulatory assets, current	8,569	0
Regulatory assets, non-current	74,926	73,200
Loss on reacquired debt
Detail of regulatory assets
Regulatory assets, current	1,637	1,637
Regulatory assets, non-current	15,305	16,942
AG-1 deferral
Detail of regulatory assets
Regulatory assets, current	2,654	0
Regulatory assets, non-current	8,472	5,868
Demand side management
Detail of regulatory assets
Regulatory assets, current	0	3,744
Regulatory assets, non-current	0	0
Tax expense of Medicare subsidy
Detail of regulatory assets
Regulatory assets, current	1,236	1,513
Regulatory assets, non-current	7,415	10,589
Mead-Phoenix transmission line CIAC
Detail of regulatory assets
Regulatory assets, current	332	332
Regulatory assets, non-current	10,376	10,708
Deferred fuel and purchased power
Detail of regulatory assets
Regulatory assets, current	75,637	12,465
Regulatory assets, non-current	0	0
Coal reclamation
Detail of regulatory assets
Regulatory assets, current	1,068	418
Regulatory assets, non-current	12,396	5,182
Other
Detail of regulatory assets
Regulatory assets, current	4,638	432
Regulatory assets, non-current	$ 353	$ 1,588

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Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Detail of regulatory liabilities
Regulatory liabilities, current	$ 100,086	$ 99,899
Regulatory liabilities, non-current	2,452,536	948,916
Excess deferred income taxes - Tax Cuts and Jobs Act
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	1,520,274	0
Asset retirement obligations
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	332,171	279,976
Removal costs
Detail of regulatory liabilities
Regulatory liabilities, current	18,238	29,899
Regulatory liabilities, non-current	209,191	223,145
Other post retirement benefits
Detail of regulatory liabilities
Regulatory liabilities, current	37,642	32,662
Regulatory liabilities, non-current	151,985	123,913
Income taxes - deferred investment tax credit
Detail of regulatory liabilities
Regulatory liabilities, current	2,164	4,368
Regulatory liabilities, non-current	52,497	108,827
Income taxes - change in rates
Detail of regulatory liabilities
Regulatory liabilities, current	2,573	1,771
Regulatory liabilities, non-current	70,537	70,898
Spent nuclear fuel
Detail of regulatory liabilities
Regulatory liabilities, current	6,924	0
Regulatory liabilities, non-current	62,132	71,726
Renewable energy program
Detail of regulatory liabilities
Regulatory liabilities, current	23,155	26,809
Regulatory liabilities, non-current	0	0
Demand side management
Detail of regulatory liabilities
Regulatory liabilities, current	3,066	0
Regulatory liabilities, non-current	4,921	20,472
Sundance maintenance
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	16,897	15,287
Deferred gains on utility property
Detail of regulatory liabilities
Regulatory liabilities, current	4,423	2,063
Regulatory liabilities, non-current	10,988	8,895
Four Corners coal reclamation
Detail of regulatory liabilities
Regulatory liabilities, current	1,858	0
Regulatory liabilities, non-current	18,921	18,248
Other
Detail of regulatory liabilities
Regulatory liabilities, current	43	2,327
Regulatory liabilities, non-current	$ 2,022	$ 7,529

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Income Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Income Taxes
Reduction in net deferred income tax liabilities	$ 1,140,000,000
Regulatory liabilities, non-current	2,452,536,000	$ 948,916,000
Income tax expense recognized for tax reform	9,300,000
Interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS (less than)	1,000,000
General business tax credit carryforwards that will begin to expire in 2031	79,000,000
Amount of federal and state loss carryforwards which will begin to expire in 2019	6,000,000
increase (decrease) in deferred income taxes due to regulation adoption	31,000,000
ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Reduction in net deferred income tax liabilities	1,140,000,000
Regulatory liabilities, non-current	2,452,536,000	948,916,000
Gross-up for revenue requirement of rate regulation	377,000,000
Palo Verde VIE
Income Taxes
Income tax expense benefit attributable to non controlling interests	0
Excess deferred income taxes - Tax Cuts and Jobs Act
Income Taxes
Regulatory liabilities, non-current	1,520,274,000	$ 0
Excess deferred income taxes - Tax Cuts and Jobs Act | ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Regulatory liabilities, non-current	$ 1,520,000,000

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Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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, beginning of the year	$ 36,075	$ 34,447	$ 44,775
Additions for tax positions of the current year	2,937	2,695	2,175
Additions for tax positions of prior years	4,783	886	0
Reductions for tax positions of prior years for:
Changes in judgment	(1,829)	(1,953)	(10,244)
Settlements with taxing authorities	0	0	0
Lapses of applicable statute of limitations	0	0	(2,259)
Total unrecognized tax benefits, end of the year	41,966	36,075	34,447
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
Total unrecognized tax benefits, beginning of the year	36,075	34,447	44,775
Additions for tax positions of the current year	2,937	2,695	2,175
Additions for tax positions of prior years	4,783	886	0
Reductions for tax positions of prior years for:
Changes in judgment	(1,829)	(1,953)	(10,244)
Settlements with taxing authorities	0	0	0
Lapses of applicable statute of limitations	0	0	(2,259)
Total unrecognized tax benefits, end of the year	$ 41,966	$ 36,075	$ 34,447

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Income Taxes - Summary of Unrecognized Tax Benefits (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax [Line Items]
Tax positions, that if recognized, would decrease our effective tax rate	$ 16,373,000	$ 11,313,000	$ 9,523,000
Unrecognized tax benefit interest expense/(benefit) recognized	577,000	529,000	(161,000)
Unrecognized tax benefit interest accrued	1,910,000	1,333	804
ARIZONA PUBLIC SERVICE COMPANY
Income Tax [Line Items]
Tax positions, that if recognized, would decrease our effective tax rate	16,373,000	11,313,000	9,523,000
Unrecognized tax benefit interest expense/(benefit) recognized	577,000	529,000	(161,000)
Unrecognized tax benefit interest accrued	$ 1,910	$ 1,333	$ 804

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Income Taxes - Components of Income Tax Expense (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current:
Federal									$ 11,624	$ 8,630	$ (12,335)
State									3,052	1,259	4,763
Total current									14,676	9,889	(7,572)
Deferred:
Federal									223,729	201,743	221,505
State									19,867	24,779	23,787
Total deferred									243,596	226,522	245,292
Income tax expense	$ 20,775	$ 144,319	$ 88,967	$ 4,211	$ 27,309	$ 141,446	$ 65,742	$ 1,914	258,272	236,411	237,720
ARIZONA PUBLIC SERVICE COMPANY
Current:
Federal									21,512	711	6,485
State									2,778	4,276	7,813
Total current									24,290	4,987	14,298
Deferred:
Federal									221,078	215,178	208,326
State									23,800	25,677	23,217
Total deferred									244,878	240,855	231,543
Income tax expense									$ 269,168	$ 245,842	$ 245,841

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Income Taxes - Effective Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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%
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]
Federal income tax expense at 35% statutory rate									$ 268,177	$ 244,278	$ 242,869
State income tax net of federal income tax benefit									14,897	16,311	18,265
Credits and favorable adjustments related to prior years resolved in current year									0	0	(2,169)
Medicare Subsidy Part-D									853	844	837
Stock compensation									(6,659)	(2,951)	0
Excess Deferred Income Taxes - Tax Cuts and Jobs Act									9,348	0	0
Allowance for equity funds used during construction (see Note 1)									(12,937)	(11,724)	(9,711)
Palo Verde VIE noncontrolling interest (see Note 18)									(6,823)	(6,823)	(6,626)
Investment tax credit amortization									(6,715)	(5,887)	(5,527)
Other									(1,869)	2,363	(218)
Income tax expense	$ 20,775	$ 144,319	$ 88,967	$ 4,211	$ 27,309	$ 141,446	$ 65,742	$ 1,914	$ 258,272	$ 236,411	$ 237,720
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%
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]
Federal income tax expense at 35% statutory rate									$ 277,540	$ 254,617	$ 250,267
State income tax net of federal income tax benefit									17,276	18,750	20,433
Credits and favorable adjustments related to prior years resolved in current year									0	0	(1,892)
Medicare Subsidy Part-D									853	844	837
Stock compensation									(3,489)	(1,937)	0
Excess Deferred Income Taxes - Tax Cuts and Jobs Act									9,431	0	0
Allowance for equity funds used during construction (see Note 1)									(12,937)	(11,724)	(9,711)
Palo Verde VIE noncontrolling interest (see Note 18)									(6,823)	(6,823)	(6,626)
Investment tax credit amortization									(6,715)	(5,887)	(5,527)
Other									(5,968)	(1,998)	(1,940)
Income tax expense									$ 269,168	$ 245,842	$ 245,841

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Income Taxes - Components of Deferred Income Tax Liability (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
DEFERRED TAX ASSETS
Risk management activities	$ 25,103	$ 26,614
Regulatory liabilities:
Excess Deferred Income Taxes - Tax Cuts and Jobs Act	376,906	0
Asset retirement obligation and removal costs	135,847	200,140
Unamortized investment tax credits	54,661	113,195
Other postretirement liabilities	47,021	60,375
Other	37,489	63,311
Pension liabilities	83,126	204,436
Renewable energy incentives	33,546	56,379
Credit and loss carryforwards	53,946	75,944
Other	102,432	158,421
Total deferred tax assets	950,077	958,815
DEFERRED TAX LIABILITIES
Plant-related	(2,220,886)	(3,297,989)
Risk management activities	(491)	(7,594)
Other postretirement assets	(66,134)	(63,477)
Regulatory assets:
Allowance for equity funds used during construction	(36,365)	(61,088)
Deferred fuel and purchased power — mark-to-market	(40,778)	(21,396)
Pension benefits	(142,848)	(274,184)
Retired power plant costs (see Note 3)	(53,611)	(49,166)
Other	(74,423)	(123,987)
Other	(5,346)	(5,166)
Total deferred tax liabilities	(2,640,882)	(3,904,047)
Deferred income taxes — net	(1,690,805)	(2,945,232)
ARIZONA PUBLIC SERVICE COMPANY
DEFERRED TAX ASSETS
Risk management activities	25,103	26,614
Regulatory liabilities:
Excess Deferred Income Taxes - Tax Cuts and Jobs Act	376,906	0
Asset retirement obligation and removal costs	135,847	200,140
Unamortized investment tax credits	54,661	113,195
Other postretirement liabilities	47,021	60,375
Other	37,489	63,311
Pension liabilities	77,280	194,981
Renewable energy incentives	33,546	56,379
Credit and loss carryforwards	1,920	1,645
Other	108,223	187,453
Total deferred tax assets	897,996	904,093
DEFERRED TAX LIABILITIES
Plant-related	(2,220,886)	(3,297,989)
Risk management activities	(491)	(7,594)
Other postretirement assets	(65,733)	(62,819)
Regulatory assets:
Allowance for equity funds used during construction	(36,365)	(61,088)
Deferred fuel and purchased power — mark-to-market	(40,778)	(21,396)
Pension benefits	(142,848)	(274,184)
Retired power plant costs (see Note 3)	(53,611)	(49,166)
Other	(74,423)	(123,987)
Other	(5,346)	(5,165)
Total deferred tax liabilities	(2,640,481)	(3,903,388)
Deferred income taxes — net	$ (1,742,485)	$ (2,999,295)

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Lines of Credit and Short-Term Borrowings - Schedule of Credit Facilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Pinnacle West
Lines of Credit and Short-Term Borrowings
Commitment fees (as a percent)	0.125%	0.125%
ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Commitment fees (as a percent)	0.10%	0.10%
Revolving credit facility
Lines of Credit and Short-Term Borrowings
Amount committed	$ 1,325,000	$ 1,275,000
Commercial paper	(95,400)	(177,200)
Unused amount	1,229,600	1,097,800
Revolving credit facility | Pinnacle West
Lines of Credit and Short-Term Borrowings
Amount committed	325,000	275,000
Commercial paper	(95,400)	(41,700)
Unused amount	229,600	233,300
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Amount committed	1,000,000	1,000,000
Commercial paper	0	(135,500)
Unused amount	$ 1,000,000	$ 864,500

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Lines of Credit and Short-Term Borrowings (Details)		12 Months Ended
	Jul. 31, 2017 USD ($)	Dec. 31, 2017 USD ($) Facility	Jun. 29, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 15, 2016 USD ($)	Aug. 31, 2016 USD ($)	May 13, 2016 USD ($)	Feb. 06, 2013 USD ($)	Feb. 05, 2013 USD ($)
Lines of Credit and Short-Term Borrowings
Short-term borrowings		$ 95,400,000		$ 177,200,000
Pinnacle West
Lines of Credit and Short-Term Borrowings
Short-term borrowings		95,400,000		41,700,000
ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Short-term borrowings		0		135,500,000
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					$ 5,100,000,000			$ 5,100,000,000.0	$ 4,200,000,000.0
Revolving credit facility
Lines of Credit and Short-Term Borrowings
Amount committed		1,325,000,000		1,275,000,000
Long-term line of credit		95,400,000		177,200,000
Revolving credit facility | Pinnacle West
Lines of Credit and Short-Term Borrowings
Amount committed		325,000,000		275,000,000
Long-term line of credit		$ 95,400,000		41,700,000
Revolving credit facility | Pinnacle West | Revolving credit facility maturing August 2017
Lines of Credit and Short-Term Borrowings
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders						$ 75,000,000
Revolving credit facility | Pinnacle West | Revolving credit facility maturing July 2018
Lines of Credit and Short-Term Borrowings
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders	$ 125,000,000
Debt instrument, term		364 days
Short-term borrowings		$ 66,000,000
Revolving credit facility | Pinnacle West | Revolving credit facility maturing May 2021
Lines of Credit and Short-Term Borrowings
Amount committed							$ 200,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders		300,000,000
Long-term line of credit		0
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Amount committed		1,000,000,000		1,000,000,000
Long-term line of credit		0		$ 135,500,000
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facility maturing September 2020
Lines of Credit and Short-Term Borrowings
Amount committed			$ 500,000,000
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facility maturing June 2022
Lines of Credit and Short-Term Borrowings
Amount committed		500,000,000	$ 500,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders		700,000,000
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facilities maturing in 2021 and 2022
Lines of Credit and Short-Term Borrowings
Amount committed		1,000,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders		1,400,000,000
Long-term line of credit		$ 0
Number of credit facilities | Facility		2
Revolving credit facility | ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facility maturing May 2021
Lines of Credit and Short-Term Borrowings
Amount committed		$ 500,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders		700,000,000
Letter of credit | Pinnacle West | Revolving credit facility maturing May 2021
Lines of Credit and Short-Term Borrowings
Outstanding letters of credit		0
Letter of credit | ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Outstanding letters of credit		5,000,000
Commercial paper | Pinnacle West | Revolving credit facility maturing May 2021
Lines of Credit and Short-Term Borrowings
Commercial paper		29,400,000
Commercial paper | ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Maximum commercial paper support available under credit facility		500,000,000
Commercial paper | ARIZONA PUBLIC SERVICE COMPANY | Revolving credit facilities maturing in 2021 and 2022
Lines of Credit and Short-Term Borrowings
Long-term line of credit		$ 0
LIBOR | Revolving credit facility | Pinnacle West | Revolving credit facility maturing July 2018
Lines of Credit and Short-Term Borrowings
Debt instrument, basis spread on variable rate	0.80%

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Long-Term Debt and Liquidity Matters (Details) - USD ($)		12 Months Ended
	Nov. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 11, 2017	Dec. 15, 2016	May 06, 2016	Feb. 06, 2013	Feb. 05, 2013
Debt Provisions
Total shareholder equity		$ 5,006,690,000	$ 4,803,622,000
Maximum
Debt Provisions
Ratio of consolidated debt to consolidated capitalization (as a percent)		65.00%
Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Contribution to subsidiaries	$ 150,000,000	$ 178,027,000	19,242,000	$ 3,491,000
Debt Provisions
Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)		50.00%
Total shareholder equity		$ 5,006,690,000	4,803,622,000
ARIZONA PUBLIC SERVICE COMPANY
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%
Total shareholder equity		$ 5,256,829,000	$ 4,905,680,000
ARIZONA PUBLIC SERVICE COMPANY | ACC
Debt Provisions
Total shareholder equity		5,300,000,000
Total capitalization		10,000,000,000
Dividend restrictions, shareholder equity required		$ 4,000,000,000
Long term debt authorization						$ 5,100,000,000		$ 5,100,000,000.0	$ 4,200,000,000.0
ARIZONA PUBLIC SERVICE COMPANY | Minimum | ACC
Debt Provisions
Required common equity ratio ordered by ACC (as a percent) (at least)		40.00%
Senior unsecured notes | Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Notes issued	$ 300,000,000
Interest rate (as a percent)	2.25%	2.25%
Term loans | ARIZONA PUBLIC SERVICE COMPANY | Term loan
Long-Term Debt and Liquidity Matters [Line Items]
Principal balance repaid	$ 125,000,000
Unsecured Senior Notes 4.35 Percent Mature on 15 November, 2045 | ARIZONA PUBLIC SERVICE COMPANY | Senior notes
Long-Term Debt and Liquidity Matters [Line Items]
Notes issued							$ 250,000,000
Interest rate (as a percent)							4.35%
Unsecured Senior Notes 2.95 Percent Mature on 15 September, 2027 | ARIZONA PUBLIC SERVICE COMPANY | Senior notes
Long-Term Debt and Liquidity Matters [Line Items]
Notes issued					$ 300,000,000
Interest rate (as a percent)					2.95%

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Long-Term Debt and Liquidity Matters - Components of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Nov. 30, 2017	Dec. 31, 2016
Long-Term Debt and Liquidity Matters [Line Items]
Total long-term debt	$ 4,871,713		$ 4,146,785
Long-term debt less current maturities	4,789,713		4,021,785
Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	4,908,125
Unamortized discount	(184)		0
Unamortized debt issue costs	(1,395)		0
Total long-term debt	298,421		125,000
Less current maturities	0		125,000
Total long-term debt less current maturities	298,421		0
Long-term debt less current maturities	298,421		0
APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	4,608,125
Unamortized discount	(11,288)		(11,816)
Unamortized premium	8,049		4,506
Unamortized debt issue costs	(31,594)		(29,030)
Total long-term debt	4,573,292		4,021,785
Less current maturities	82,000		0
Total long-term debt less current maturities	4,491,292		4,021,785
Pollution Control Bonds - Variable | APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 35,975		$ 35,975
Pollution Control Bonds - Variable | APS | Minimum
Long-Term Debt and Liquidity Matters [Line Items]
Weighted-average interest rate (as a percent)	1.77%		0.81%
Pollution Control Bonds - Fixed | APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 147,150		$ 147,150
Pollution Control Bonds - Fixed | APS | Minimum
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)	1.75%		1.75%
Pollution Control Bonds - Fixed | APS | Maximum
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)	4.70%		4.70%
Total Pollution Control Bonds | APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 183,125		$ 183,125
Senior unsecured notes | APS
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 4,275,000		$ 3,725,000
Senior unsecured notes | APS | Minimum
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)	2.20%		2.20%
Senior unsecured notes | APS | Maximum
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)	8.75%		8.75%
Term loan facility | Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 0		$ 125,000
Weighted-average interest rate (as a percent)			1.52%
Senior unsecured notes | Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 300,000		$ 0
Interest rate (as a percent)	2.25%	2.25%
Term loan | APS
Long-Term Debt and Liquidity Matters [Line Items]
Weighted-average interest rate (as a percent)	2.236%		1.427%
Term loan | Term loans | APS
Long-Term Debt and Liquidity Matters [Line Items]
Term loans	$ 150,000		$ 150,000

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Long-Term Debt and Liquidity Matters - Future Principal Payments (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Pinnacle West
Principal payments due on long-term debt
2018	$ 82,000
2019	600,000
2020	550,000
2021	0
2022	0
Thereafter	3,676,125
Total	4,908,125
ARIZONA PUBLIC SERVICE COMPANY
Principal payments due on long-term debt
2018	82,000
2019	600,000
2020	250,000
2021	0
2022	0
Thereafter	3,676,125
Total	$ 4,608,125

XML

Long-Term Debt and Liquidity Matters - Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Estimated fair value of long-term debt, including current maturities
Carrying Amount	$ 4,871,713	$ 4,146,785
Fair Value	5,304,956	4,425,789
Pinnacle West
Estimated fair value of long-term debt, including current maturities
Carrying Amount	298,421	125,000
Fair Value	298,608	125,000
ARIZONA PUBLIC SERVICE COMPANY
Estimated fair value of long-term debt, including current maturities
Carrying Amount	4,573,292	4,021,785
Fair Value	$ 5,006,348	$ 4,300,789

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Retirement Plans and Other Benefits Retirement Plans and Other Benefits (Details)	1 Months Ended	12 Months Ended
	Jul. 31, 2012	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Jan. 01, 2015 Age
Plan Design Changes [Abstract]
Amount of other postretirement benefit trust assets for union employee medical costs		$ 186,000,000
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				$ 5,000,000	$ 8,000,000	$ 8,000,000	$ 4,000,000
Partnership funding commitments, contribution amount (up to)		75,000,000
Partnership funding commitments, funded amount		$ 58,000,000
Pension Benefits
Plan Design Changes [Abstract]
Expected long-term return on plan assets for next fiscal year (as a percent)		6.05%
Contributions
Employer's contributions under the plan		$ 100,000,000	$ 100,000,000	100,000,000
Minimum contributions under MAP-21
Minimum contributions under MAP-21		0
Voluntary employer contributions over next three years (up to)		$ 250,000,000
Other Benefits
Plan Design Changes [Abstract]
Age eligible for benefit | Age									65
Effect of plan amendment on accumulated benefit obligation				316,000,000
Expected long-term return on plan assets for next fiscal year (as a percent)		5.55%
Contributions
Employer's contributions under the plan		$ 353,000	819,000	1,000,000
Pinnacle West
Employee savings plan benefits
Expenses recorded for the defined contribution savings plan		$ 10,000,000	10,000,000	9,000,000
ARIZONA PUBLIC SERVICE COMPANY
Employee savings plan benefits
APS's employees share of total cost of the plans (as a percent)		99.00%
ARIZONA PUBLIC SERVICE COMPANY | Pension Benefits
Contributions
Employer's contributions under the plan		$ 100,000,000	100,000,000	100,000,000
ARIZONA PUBLIC SERVICE COMPANY | Other Benefits
Contributions
Employer's contributions under the plan		$ 1,000,000	$ 1,000,000	$ 1,000,000

XML

Retirement Plans and Other Benefits - Net Periodic Benefit Costs and Portion including Portion Charged to Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost-benefits earned during the period	$ 54,858	$ 53,792	$ 59,627
Interest cost on benefit obligation	129,756	131,647	123,983
Expected return on plan assets	(174,271)	(173,906)	(179,231)
Amortization of prior service cost (credit)	81	527	594
Amortization of net actuarial loss	47,900	40,717	31,056
Net periodic benefit cost	58,324	52,777	36,029
Portion of cost charged to expense	27,295	26,172	20,036
Other Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost-benefits earned during the period	17,119	14,993	16,827
Interest cost on benefit obligation	29,959	29,721	28,102
Expected return on plan assets	(53,401)	(36,495)	(36,855)
Amortization of prior service cost (credit)	(37,842)	(37,883)	(37,968)
Amortization of net actuarial loss	5,118	4,589	4,881
Net periodic benefit cost	(39,047)	(25,075)	(25,013)
Portion of cost charged to expense	$ (18,274)	$ (12,435)	$ (10,391)

XML

Retirement Plans and Other Benefits - Changes Benefit Obligations and Funded Status (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits
Change in Benefit Obligation
Benefit obligation at the beginning of the period	$ 3,204,462	$ 3,033,803
Service cost	54,858	53,792	$ 59,627
Interest cost	129,756	131,647	123,983
Benefit payments	(166,342)	(142,247)
Actuarial (gain) loss	171,452	127,467
Benefit obligation at the end of the period	3,394,186	3,204,462	3,033,803
Change in Plan Assets
Balance at the beginning of the period	2,675,357	2,542,774
Actual return on plan assets	428,374	166,408
Employer's contributions under the plan	100,000	100,000	100,000
Benefit payments	(146,704)	(133,825)
Balance at the end of the period	3,057,027	2,675,357	2,542,774
Funded Status at the end of the period	(337,159)	(529,105)
Other Benefits
Change in Benefit Obligation
Benefit obligation at the beginning of the period	716,445	647,020
Service cost	17,119	14,993	16,827
Interest cost	29,959	29,721	28,102
Benefit payments	(30,144)	(26,231)
Actuarial (gain) loss	20,014	50,942
Benefit obligation at the end of the period	753,393	716,445	647,020
Change in Plan Assets
Balance at the beginning of the period	882,651	833,017
Actual return on plan assets	139,367	63,463
Employer's contributions under the plan	353	819	1,000
Benefit payments	0	(14,648)
Balance at the end of the period	1,022,371	882,651	$ 833,017
Funded Status at the end of the period	$ 268,978	$ 166,206

XML

Retirement Plans and Other Benefits - Projected Benefit Obligation for Pension Plans (Details) - Pension Benefits - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets
Projected benefit obligation	$ 3,394,186	$ 3,204,462
Accumulated benefit obligation	3,227,233	3,049,406
Fair value of plan assets	$ 3,057,027	$ 2,675,357

XML

Retirement Plans and Other Benefits - Amounts Recognized on the Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Amounts recognized on the Consolidated Balance Sheets
Noncurrent asset	$ 268,978	$ 166,206
Pension Benefits
Amounts recognized on the Consolidated Balance Sheets
Noncurrent asset	0	0
Current liability	(9,859)	(19,795)
Noncurrent liability	(327,300)	(509,310)
Net amount recognized	(337,159)	(529,105)
Other Benefits
Amounts recognized on the Consolidated Balance Sheets
Noncurrent asset	268,978	166,206
Current liability	0	0
Noncurrent liability	0	0
Net amount recognized	$ 268,978	$ 166,206

XML

Retirement Plans and Other Benefits - Impact to Accumulated Other Comprehensive Loss (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Details related to accumulated other comprehensive loss
Accumulated other comprehensive loss		$ 0
Pension Benefits
Details related to accumulated other comprehensive loss
Net actuarial loss	$ 643,199,000	773,750,000
Prior service cost (credit)	0	81,000
APS’s portion recorded as a regulatory (asset) liability	(576,188,000)	(711,059,000)
Income tax expense (benefit)	(24,915,000)	(24,202,000)
Accumulated other comprehensive loss	42,096,000	38,570,000
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
Net actuarial loss	28,334,000
Prior service credit	0
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2018	28,334,000
Other Benefits
Details related to accumulated other comprehensive loss
Net actuarial loss	75,439,000	146,509,000
Prior service cost (credit)	(265,575,000)	(303,417,000)
APS’s portion recorded as a regulatory (asset) liability	189,627,000	156,575,000
Income tax expense (benefit)	853,000	833,000
Accumulated other comprehensive loss	344,000	$ 500,000
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
Net actuarial loss	0
Prior service credit	(37,842,000)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2018	$ (37,842,000)

XML

Retirement Plans and Other Benefits - Weighted-Average Assumptions for Pensions and Other Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Weighted-average assumptions used to determine benefit obligations
Rate of compensation increase (as a percent)	4.00%	4.00%
Initial pre-65 healthcare cost trend rate (as a percent)	7.00%	7.00%
Initial post-65 healthcare cost trend rate (as a percent)	4.75%	5.00%
Ultimate health care cost trend rate (as a percent)	4.75%	5.00%
Number of years to ultimate trend rate (pre-65 participants)	8 years	4 years
Weighted-average assumptions used to determine net periodic benefit costs
Initial pre-65 health care cost trend rate (as a percent)	7.00%	7.00%	7.00%
Initial post-65 health care cost trend rate (as a percent)	5.00%	5.00%	5.00%
Ultimate healthcare cost trend rate (as a percent)	5.00%	5.00%	5.00%
Number of years to ultimate trend rate (pre-65 participants)	4 years	4 years	4 years
Pension Benefits
Weighted-average assumptions used to determine benefit obligations
Discount rate (as a percent)	3.65%	4.08%
Weighted-average assumptions used to determine net periodic benefit costs
Discount rate (as a percent)	4.08%	4.37%	4.02%
Rate of compensation increase (as a percent)	4.00%	4.00%	4.00%
Expected long-term return on plan assets (as a percent)	6.55%	6.90%	6.90%
Other Benefits
Weighted-average assumptions used to determine benefit obligations
Discount rate (as a percent)	3.71%	4.17%
Weighted-average assumptions used to determine net periodic benefit costs
Discount rate (as a percent)	4.17%	4.52%	4.14%
Expected long-term return on plan assets (as a percent)	6.05%	4.45%	4.45%
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	$ 8,424
Effect of 1% decrease on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	(5,616)
Effect of 1% increase on service and interest cost components of net periodic other postretirement benefit costs	9,145
Effect of 1% decrease on service and interest cost components of net periodic other postretirement benefit costs	(7,037)
Effect of 1% increase on the accumulated other postretirement benefit obligation	128,203
Effect of 1% decrease on the accumulated other postretirement benefit obligation	$ (98,143)

XML

Retirement Plans and Other Benefits - Asset Allocation (Details)	Dec. 31, 2017
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Target allocation (as a percent)	100.00%
Actual asset allocation (as a percent)	100.00%
Pension Benefits | Fixed income securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation (as a percent)	62.00%
Actual asset allocation (as a percent)	58.00%
Pension Benefits | Return-generating assets
Defined Benefit Plan Disclosure [Line Items]
Target allocation (as a percent)	38.00%
Actual asset allocation (as a percent)	42.00%
Pension Benefits | Equities in US and other developed markets
Defined Benefit Plan Disclosure [Line Items]
Target allocation (as a percent)	18.00%
Pension Benefits | Equities in emerging markets
Defined Benefit Plan Disclosure [Line Items]
Target allocation (as a percent)	6.00%
Pension Benefits | Alternative investments
Defined Benefit Plan Disclosure [Line Items]
Target allocation (as a percent)	14.00%
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Actual asset allocation (as a percent)	100.00%
Other Benefits | Fixed income securities
Defined Benefit Plan Disclosure [Line Items]
Actual asset allocation (as a percent)	67.00%
Other Benefits | Return-generating assets
Defined Benefit Plan Disclosure [Line Items]
Actual asset allocation (as a percent)	33.00%

XML

Retirement Plans and Other Benefits - Fair Value of Pinnacle West's Pension Plan (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	$ 3,057,027	$ 2,675,357	$ 2,542,774
Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	903,085	749,541
Fair value of plan assets	3,057,027	2,675,357
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
Gross fair value of plan assets	686,941	613,193
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
Gross fair value of plan assets	1,467,001	1,312,623
Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	1,022,371	882,651	$ 833,017
Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	99,910	123,234
Fair value of plan assets	1,022,371	882,651
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
Gross fair value of plan assets	583,796	456,718
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
Gross fair value of plan assets	338,665	302,699
Cash and cash equivalents | 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	3,830	13,995
Cash and cash equivalents | 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
Gross fair value of plan assets	3,830	13,995
Cash and cash equivalents | 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	143	304
Cash and cash equivalents | 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
Gross fair value of plan assets	143	304
Corporate | 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	1,365,194	1,210,453
Corporate | 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
Gross fair value of plan assets	1,365,194	1,210,453
Corporate | 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	306,008	268,193
Corporate | 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
Gross fair value of plan assets	306,008	268,193
U.S. Treasury | 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	221,291	112,583
U.S. Treasury | 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
Gross fair value of plan assets	221,291	112,583
U.S. Treasury | 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	336,963	145,255
U.S. Treasury | 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
Gross fair value of plan assets	336,963	145,255
Other | 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	100,599	102,170
Other | 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
Gross fair value of plan assets	100,599	102,170
Other | 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	32,508	34,506
Other | 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
Gross fair value of plan assets	32,508	34,506
Common stock equities | 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	228,088	235,109
Common stock equities | 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
Gross fair value of plan assets	228,088	235,109
Common stock equities | 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	196,153	243,741
Common stock equities | 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
Gross fair value of plan assets	196,153	243,741
Mutual funds | 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	233,732	251,506
Mutual funds | 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
Gross fair value of plan assets	233,732	251,506
Mutual funds | 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	39,269	67,418
Mutual funds | 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
Gross fair value of plan assets	39,269	67,418
Equities | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	408,763	266,840
Fair value of plan assets	408,763	266,840
Equities | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	75,310	95,814
Fair value of plan assets	75,310	95,814
Real estate | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	171,569	161,449
Fair value of plan assets	171,569	161,449
Real estate | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	15,422	14,509
Fair value of plan assets	15,422	14,509
Fixed income securities | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	90,869
Fair value of plan assets	90,869
Partnerships | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	133,379	208,915
Fair value of plan assets	133,379	208,915
Partnerships | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other		3,060
Fair value of plan assets		3,060
Short-term investments and other | Pension Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	98,505	112,337
Fair value of plan assets	99,713	112,337
Short-term investments and other | 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
Gross fair value of plan assets	1,208
Short-term investments and other | Other Benefits | Pinnacle West
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	9,178	9,851
Fair value of plan assets	20,595	$ 9,851
Short-term investments and other | 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
Gross fair value of plan assets	11,268
Short-term investments and other | 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
Gross fair value of plan assets	$ 149

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Retirement Plans and Other Benefits - Estimated Future Benefit Payments (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Pension Benefits
Estimated Future Benefit Payments
2018	$ 175,383
2019	181,902
2020	191,586
2021	196,583
2022	201,463
Years 2023-2027	1,068,568
Other Benefits
Estimated Future Benefit Payments
2018	31,891
2019	34,000
2020	35,658
2021	37,090
2022	37,860
Years 2023-2027	$ 191,207

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Leases (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($) Trust	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 1986 Trust
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
Lease expense	$ 18,000	$ 16,000	$ 17,000
Pinnacle West
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
2018	13,412
2019	11,054
2020	9,641
2021	7,105
2022	4,609
Thereafter	55,940
Total future lease commitments	101,761
Palo Verde Lessor Trusts
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
Number of VIE lessor trusts | Trust				3
APS
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
2018	13,110
2019	10,802
2020	9,392
2021	6,858
2022	4,510
Thereafter	53,605
Total future lease commitments	98,277
Lease expense	$ 17,000	$ 15,000	$ 14,000
Number of VIE lessor trusts | Trust	3			3

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Jointly-Owned Facilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Jul. 06, 2016
4CA
Interests in jointly-owned facilities
Plant in Service	$ 141,000
Accumulated Depreciation	83,000
Construction work in progress	$ 25,000
Palo Verde Units 1 and 3 | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	29.10%
Plant in Service	$ 1,872,104
Accumulated Depreciation	1,092,049
Construction work in progress	$ 24,257
Palo Verde Unit 2 | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	16.80%
Plant in Service	$ 619,263
Accumulated Depreciation	364,516
Construction work in progress	$ 14,672
Palo Verde Common | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	28.00%
Plant in Service	$ 726,223
Accumulated Depreciation	262,065
Construction work in progress	46,577
Palo Verde Sale Leaseback | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Plant in Service	351,050
Accumulated Depreciation	241,405
Construction work in progress	$ 0
Four Corners Generating Station | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	63.00%
Plant in Service	$ 1,196,683
Accumulated Depreciation	568,304
Construction work in progress	$ 240,514
Cholla Common Facilities | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	50.50%
Plant in Service	$ 180,907
Accumulated Depreciation	69,633
Construction work in progress	$ 1,091
ANPP 500kV System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	34.00%
Plant in Service	$ 130,767
Accumulated Depreciation	46,400
Construction work in progress	$ 684
Navajo Southern System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	27.50%
Plant in Service	$ 85,299
Accumulated Depreciation	28,915
Construction work in progress	$ 180
Palo Verde — Yuma 500kV System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	18.10%
Plant in Service	$ 14,765
Accumulated Depreciation	6,614
Construction work in progress	$ 486
Four Corners Switchyards | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	63.20%
Plant in Service	$ 66,386
Accumulated Depreciation	12,605
Construction work in progress	$ 327
Phoenix — Mead System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	17.10%
Plant in Service	$ 39,383
Accumulated Depreciation	17,600
Construction work in progress	$ 41
Palo Verde — Rudd 500kV System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	50.00%
Plant in Service	$ 97,600
Accumulated Depreciation	23,884
Construction work in progress	$ 245
Morgan — Pinnacle Peak System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	64.60%
Plant in Service	$ 117,721
Accumulated Depreciation	14,569
Construction work in progress	$ 1
Round Valley System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	50.00%
Plant in Service	$ 515
Accumulated Depreciation	141
Construction work in progress	$ 0
Palo Verde — Morgan System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	90.90%
Plant in Service	$ 137,887
Accumulated Depreciation	3,948
Construction work in progress	$ 94,350
Hassayampa — North Gila System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	80.00%
Plant in Service	$ 142,541
Accumulated Depreciation	6,953
Construction work in progress	$ 0
Cholla 500kV Switchyard | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	85.70%
Plant in Service	$ 5,243
Accumulated Depreciation	1,312
Construction work in progress	$ 190
Saguaro 500kV Switchyard | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	60.00%
Plant in Service	$ 20,473
Accumulated Depreciation	12,574
Construction work in progress	$ 0
Kyrene - Knox System | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Percent Owned	50.00%
Plant in Service	$ 578
Accumulated Depreciation	297
Construction work in progress	$ 0
Navajo Plant | ARIZONA PUBLIC SERVICE COMPANY
Interests in jointly-owned facilities
Ownership interest by noncontrolling owners (as a percent)	14.00%
El Paso's Interest in Four Corners | 4CA
Interests in jointly-owned facilities
Ownership interest acquired (as a percent)	7.00%	7.00%

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Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details)		3 Months Ended	12 Months Ended
	Aug. 18, 2014 USD ($)	Dec. 31, 2017 USD ($) Trust	Dec. 31, 2017 USD ($) Trust time_period claim	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 1986 Trust
ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
Maximum insurance against public liability per occurrence for a nuclear incident			$ 13,400,000,000.0
Maximum available nuclear liability insurance			450,000,000
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program			13,000,000,000
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 | Trust		3	3			3
Maximum potential retrospective assessment per incident of APS			$ 111,100,000
Annual payment limitation with respect to maximum potential retrospective assessment			16,600,000
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde			2,800,000,000
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment			24,000,000
Collateral assurance provided based on rating triggers			$ 64,800,000
Period to provide collateral assurance based on rating triggers			20 days
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2018		$ 715,000,000	$ 715,000,000
2019		578,000,000	578,000,000
2020		548,000,000	548,000,000
2021		548,000,000	548,000,000
2022		554,000,000	554,000,000
Thereafter		6,500,000,000	6,500,000,000
ARIZONA PUBLIC SERVICE COMPANY | Coal take-or-pay commitments
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2018		159,997,000	159,997,000
2019		185,365,000	185,365,000
2020		186,632,000	186,632,000
2021		190,607,000	190,607,000
2022		194,678,000	194,678,000
Thereafter		1,750,739,000	1,750,739,000
Total obligation		2,668,018,000	2,668,018,000
Present value of commitments		1,900,000,000	1,900,000,000
Total purchases			165,220,000	$ 160,066,000	$ 211,327,000
ARIZONA PUBLIC SERVICE COMPANY | Renewable energy credits
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2018		40,000,000	40,000,000
2019		40,000,000	40,000,000
2020		40,000,000	40,000,000
2021		40,000,000	40,000,000
2022		40,000,000	40,000,000
Thereafter		370,000,000	370,000,000
ARIZONA PUBLIC SERVICE COMPANY | Coal Mine Reclamation Obligations
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2018		31,000,000	31,000,000
2019		32,000,000	32,000,000
2020		21,000,000	21,000,000
2021		20,000,000	20,000,000
2022		22,000,000	22,000,000
Thereafter		191,000,000	191,000,000
ARIZONA PUBLIC SERVICE COMPANY | Coal Mine Reclamation Balance Sheet Obligations
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
Total obligation		216,000,000	216,000,000	207,000,000
4CA | Coal Mine Reclamation Obligations
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2018		1,000,000	1,000,000
2019		1,000,000	1,000,000
2020		2,000,000	2,000,000
2021		2,000,000	2,000,000
2022		2,000,000	2,000,000
Thereafter		16,000,000	16,000,000
4CA | Coal Mine Reclamation Balance Sheet Obligations
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
Total obligation		16,000,000	16,000,000	$ 15,000,000
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal
Palo Verde Nuclear Generating Station [Abstract]
Settlement amount, awarded to company	$ 57,400,000	9,000,000
Proceeds from legal settlements			$ 65,200,000
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal | ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
Settlement amount, awarded to company	$ 16,700,000	$ 2,600,000
New claims filed | claim			3
Number of settlement agreement time periods | time_period			3
Proceeds from legal settlements			$ 19,000,000

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Commitments and Contingencies - Superfund-Related Matters and Southwest Power Outage (Details) - ARIZONA PUBLIC SERVICE COMPANY - Contaminated groundwater wells $ in Millions			12 Months Ended
	Dec. 16, 2016 plaintiff	Aug. 06, 2013 Defendant	Dec. 31, 2017 USD ($)
Superfund
Costs related to investigation and study under Superfund site | $			$ 2
Number of defendants against whom Roosevelt Irrigation District ("RID") filed lawsuit | Defendant		24
Number of plaintiffs | plaintiff	2

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Commitments and Contingencies Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) $ in Millions			12 Months Ended
	Jun. 13, 2017 USD ($)	Jul. 06, 2016 guarantee	Dec. 31, 2017 USD ($)
Payment Guarantee
Financial Assurances
Number of parental guarantees | guarantee		4
Letter of credit | ARIZONA PUBLIC SERVICE COMPANY
Financial Assurances
Outstanding letters of credit			$ 5
Equity Lessors Sale Leaseback Letter of Credit | ARIZONA PUBLIC SERVICE COMPANY
Financial Assurances
Outstanding letters of credit			62
Four Corners | NTEC
Environmental Matters [Abstract]
Option to purchase, ownership interest (as a percent)		7.00%
Four Corners | 4CA
Environmental Matters [Abstract]
Percentage share cost of control		7.00%
Four Corners | Coal Supply Agreement Arbitration
Environmental Matters [Abstract]
Damages sought	$ 30
Four Corners | Coal Supply Agreement Arbitration | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Damages sought	$ 17
Four Corners | Coal Supply Agreement Arbitration | NTEC
Environmental Matters [Abstract]
Option to purchase, ownership interest (as a percent)		7.00%
Four Corners | Coal Supply Agreement Arbitration | 4CA
Environmental Matters [Abstract]
Payment received for coal supply agreement			10
Operating and maintenance cost reimbursement receivable			20
Regional Haze Rules | Navajo Generating Station | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Expected environmental cost			$ 200
Regional Haze Rules | Four Corners Units 4 and 5 | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Percentage share cost of control			63.00%
Expected environmental cost			$ 400
Regional Haze Rules | Four Corners Units 4 and 5 | Four Corners | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost			$ 45
Regional Haze Rules | Four Corners Units 4 and 5 | Natural Gas Tolling Letter of Credit | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional percentage share of cost of control			7.00%
Coal Combustion Waste | Four Corners | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost			$ 22
Coal Combustion Waste | Navajo Generating Station | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost			1
Coal Combustion Waste | Minimum | Cholla | ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost			$ 20
El Paso's Interest in Four Corners | 4CA
Financial Assurances
Ownership interest acquired (as a percent)		7.00%	7.00%

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Asset Retirement Obligations (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($) turbine_unit
ARIZONA PUBLIC SERVICE COMPANY
Change in asset retirement obligations
Asset retirement obligations at the beginning of year	$ 624,475	$ 443,576
Changes attributable to:
Accretion expense	33,104	26,656
Settlements	0	(15,732)
Estimated cash flow revisions	21,950	151,046
Newly incurred or acquired obligations	0	18,929
Asset retirement obligations at the end of year	679,529	$ 624,475
Navajo Generating Station | ARIZONA PUBLIC SERVICE COMPANY
Asset Retirement Obligations
Increase in regulatory asset	2,000
Decrease in regulatory liability	20,000
Changes attributable to:
Newly incurred or acquired obligations	$ 22,000
Ocotillo Steam Units | ARIZONA PUBLIC SERVICE COMPANY
Asset Retirement Obligations
Number of constructed turbine units | turbine_unit		5
Changes attributable to:
Newly incurred or acquired obligations		$ 10,000
El Paso's Share of Four Corners Units 4 & 5 | 4CA
Changes attributable to:
Newly incurred or acquired obligations		9,000
Four Corners | ARIZONA PUBLIC SERVICE COMPANY
Changes attributable to:
Settlements		(16,000)
Palo Verde Nuclear Generating Station | ARIZONA PUBLIC SERVICE COMPANY
Asset Retirement Obligations
Decrease in regulatory liability		20,000
Increase in plant services		131,000
Changes attributable to:
Estimated cash flow revisions		$ 151,000

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Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Selected Quarterly Financial Information [Line Items]
OPERATING REVENUES	$ 759,659	$ 1,183,322	$ 944,587	$ 677,728	$ 739,199	$ 1,166,922	$ 915,394	$ 677,167	$ 3,565,296	$ 3,498,682	$ 3,495,443
Operations and maintenance	266,149	224,305	214,013	219,976	208,277	217,568	242,279	243,195	924,443	911,319	868,377
Operating income	90,610	466,082	304,229	73,506	122,816	451,258	231,748	50,162	934,427	855,984	854,602
Income taxes	20,775	144,319	88,967	4,211	27,309	141,446	65,742	1,914	258,272	236,411	237,720
Net income	26,502	280,945	172,317	28,185	58,119	267,900	126,182	9,326	507,949	461,527	456,190
Net income attributable to common shareholders	$ 21,629	$ 276,072	$ 167,443	$ 23,312	$ 53,246	$ 263,027	$ 121,308	$ 4,453	$ 488,456	$ 442,034	$ 437,257
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders - basic (in dollars per share)	$ 0.19	$ 2.47	$ 1.50	$ 0.21	$ 0.48	$ 2.36	$ 1.09	$ 0.04	$ 4.37	$ 3.97	$ 3.94
Net income attributable to common shareholders — diluted (in dollars per share)	$ 0.19	$ 2.46	$ 1.49	$ 0.21	$ 0.47	$ 2.35	$ 1.08	$ 0.04	$ 4.35	$ 3.95	$ 3.92
ARIZONA PUBLIC SERVICE COMPANY
Selected Quarterly Financial Information [Line Items]
Operating revenues	$ 756,549	$ 1,178,106	$ 942,615	$ 676,869	$ 737,006	$ 1,166,359	$ 909,757	$ 676,632	$ 3,554,139	$ 3,489,754	$ 3,492,357
Operations and maintenance	255,361	215,264	208,286	212,218	197,319	209,366	233,712	238,711	891,129	879,108	853,135
Operating income	79,258	322,053	212,790	65,468	95,765	307,601	165,684	48,930	679,569	617,980	611,984
Income taxes									269,168	245,842	245,841
Net income									523,802	481,634	469,207
Net income attributable to common shareholders	$ 27,783	$ 284,256	$ 169,108	$ 23,162	$ 58,480	$ 269,220	$ 127,188	$ 7,253	$ 504,309	$ 462,141	$ 450,274

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Fair Value Measurements - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Assets
Nuclear decommissioning trust	$ 871,000	$ 779,586
Total assets	1,036	11,076
Fair value measurement on a recurring basis
Assets
Cash equivalents	10,630
Coal reclamation escrow account	32,542	14,521
Coal reclamation escrow account, other	525
Other	(4,737)	(35,103)
Derivative assets	1,982	19,695
Other	417,499	354,056
Nuclear decommissioning trust	871,000	779,586
Other	413,287	318,953
Total assets	916,154	813,802
Liabilities
Other	1,516	31,049
Derivative Liability	(96,422)	(73,074)
Fair value measurement on a recurring basis | Cash and cash equivalents
Assets
Other	109	795
Nuclear decommissioning trust	7,333	795
Fair value measurement on a recurring basis | US commingled equity funds
Assets
Other	417,390	353,261
Nuclear decommissioning trust	417,390	353,261
Fair value measurement on a recurring basis | U.S. Treasury
Assets
Nuclear decommissioning trust	127,662	95,441
Fair value measurement on a recurring basis | Corporate
Assets
Nuclear decommissioning trust	114,007	111,623
Fair value measurement on a recurring basis | Mortgage-backed securities
Assets
Nuclear decommissioning trust	111,874	115,337
Fair value measurement on a recurring basis | Municipal bonds
Assets
Nuclear decommissioning trust	79,049	80,997
Fair value measurement on a recurring basis | Other
Assets
Nuclear decommissioning trust	13,685	22,132
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Cash equivalents	10,630
Coal reclamation escrow account	455	14,521
Decommissioning fund investments, gross fair value	134,886	95,441
Gross assets, fair value disclosure	145,971	109,962
Liabilities
Gross derivative liability	0	0
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash and cash equivalents
Assets
Decommissioning fund investments, gross fair value		0
Nuclear decommissioning trust	7,224
Fair value measurement on a recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury
Assets
Decommissioning fund investments, gross fair value	127,662	95,441
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2)
Assets
Gross derivative assets	5,683	43,722
Coal reclamation escrow account	31,562
Decommissioning fund investments, gross fair value	318,615	330,089
Gross assets, fair value disclosure	355,860	373,811
Liabilities
Gross derivative liability	(78,646)	(45,641)
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Corporate
Assets
Decommissioning fund investments, gross fair value	114,007	111,623
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Mortgage-backed securities
Assets
Decommissioning fund investments, gross fair value	111,874	115,337
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Municipal bonds
Assets
Decommissioning fund investments, gross fair value	79,049	80,997
Fair value measurement on a recurring basis | Significant Other Observable Inputs (Level 2) | Other
Assets
Decommissioning fund investments, gross fair value	13,685	22,132
Fair value measurement on a recurring basis | Significant Unobservable Inputs (Level 3)
Assets
Gross derivative assets	1,036	11,076
Gross assets, fair value disclosure	1,036	11,076
Liabilities
Gross derivative liability	$ (19,292)	$ (58,482)

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Fair Value Measurements - Level 3 Quantitative Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($) $ / MMBTU $ / MWh	Dec. 31, 2016 USD ($) $ / MMBTU $ / MWh
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 1,036	$ 11,076
Liabilities	19,292	58,482
Electricity forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	21	10,648
Liabilities	$ 15,485	$ 32,042
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) | $ / MWh	18.51	16.43
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) | $ / MWh	38.75	41.07
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) | $ / MWh	27.89	29.86
Natural gas forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 1,015	$ 428
Liabilities	$ 3,807	$ 26,440
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) | $ / MMBTU	2.33	2.32
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) | $ / MMBTU	3.11	3.60
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
Electricity forward price (per MWh) | $ / MWh	2.71
Natural gas forward price (per MMbtu) | $ / MMBTU		2.81

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Fair Value Measurements Fair Value Measurements - Changes in Fair Value of Risk Management Assets and Liabilities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Total net gains (losses) realized/unrealized:
Net derivative beginning balance	$ (47,406,000)	$ (32,979,000)
Included in earnings	0	0
Included in OCI	3,000	88,000
Deferred as a regulatory asset or liability	(13,643,000)	(37,543,000)
Settlements	5,834,000	15,146,000
Transfers into Level 3 from Level 2	(10,026,000)	1,900,000
Transfers from Level 3 into Level 2	46,982,000	5,982,000
Net derivative ending balance	(18,256,000)	(47,406,000)
Net unrealized gains included in earnings related to instruments still held at end of period	0	$ 0
Significant level 1 transfers	$ 0

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Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share [Abstract]
Net income attributable to common shareholders	$ 21,629	$ 276,072	$ 167,443	$ 23,312	$ 53,246	$ 263,027	$ 121,308	$ 4,453	$ 488,456	$ 442,034	$ 437,257
Weighted Average common shares outstanding — basic (in shares)									111,839	111,409	111,026
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units									528	637	526
Weighted average common shares outstanding — diluted (in shares)									112,367	112,046	111,552
Earnings per average common share attributable to common shareholders — basic (in dollars per share)	$ 0.19	$ 2.47	$ 1.50	$ 0.21	$ 0.48	$ 2.36	$ 1.09	$ 0.04	$ 4.37	$ 3.97	$ 3.94
Earnings per average common share attributable to common shareholders — diluted (in dollars per share)	$ 0.19	$ 2.46	$ 1.49	$ 0.21	$ 0.47	$ 2.35	$ 1.08	$ 0.04	$ 4.35	$ 3.95	$ 3.92

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Stock-Based Compensation (Details) $ in Thousands	1 Months Ended		3 Months Ended								12 Months Ended
	Feb. 28, 2017 shares	Dec. 31, 2012 shares	Dec. 31, 2017 USD ($) shares	Sep. 30, 2017 USD ($)	Jun. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2017 USD ($) performance_criteria shares	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Stock-Based Compensation
Stock compensation cumulative effect adjustments							$ 45,855					$ 45,855
Operations and maintenance			$ (266,149)	$ (224,305)	$ (214,013)	$ (219,976)	(208,277)	$ (217,568)	$ (242,279)	$ (243,195)	$ (924,443)	(911,319)	$ (868,377)
Compensation cost that has been charged against income											21,000	19,000	19,000
Total income tax benefit recognized											15,000	10,000	7,000
Total unrecognized compensation cost related to nonvested share-based compensation arrangements granted			$ 12,000								$ 12,000
Expected weighted-average period of recognition of unrecognized compensation cost											2 years
Total fair value of shares vested											$ 22,000	22,000	21,000
Performance Shares
Number of performance element criteria | performance_criteria											2
Performance period											3 years
Restricted stock unit awards
Stock-Based Compensation
Share-based liabilities paid											$ 4,000	3,000	10,000
Cash flow effect, cash used to settle awards											$ 4,000	3,000	3,000
Restricted Stock Units, Stock Grants and Stock Units
Vesting period											4 years
Percentage of cash that the participant may elect as a dividend for the first option available under the plan											50.00%
Percentage of stock that the participant may elect as dividend under second option of plan											50.00%
Restricted Stock Units, Stock Grants, and Stock Units
Restricted Stock Units, Stock Grants and Stock Units
Granted (in shares) | shares											161,963
Shares released during period (in shares) | shares											3,607
Performance Shares
Stock-Based Compensation
Share-based liabilities paid													$ 16,000
Restricted Stock Units, Stock Grants and Stock Units
Granted (in shares) | shares											147,706
Shares released during period (in shares) | shares											4,798
Performance Shares | Maximum
Performance Shares
Exact number of shares issued as a percentage of the target award											200.00%
Performance Shares | Minimum
Performance Shares
Exact number of shares issued as a percentage of the target award											0.00%
Officers and Key Employees | Restricted stock unit awards
Restricted Stock Units, Stock Grants and Stock Units
Percentage of fully transferable shares of stock that the participant may elect as a deferral for the first option available under the plan											100.00%
Percentage of fully transferable shares of stock in that participant may receive cash											100.00%
Chief Executive Officer | Retention units
Restricted Stock Units, Stock Grants and Stock Units
Granted (in shares) | shares		50,617
Additional shares to be granted as retention award if performance requirements are met | shares		33,745
Shares released during period (in shares) | shares	84,362
Non-Officer Board of Director Member | Restricted stock unit awards
Restricted Stock Units, Stock Grants and Stock Units
Percentage of fully transferable shares of stock that the participant may elect as a deferral for the first option available under the plan											100.00%
Percentage of cash that the participant may elect as a dividend for the first option available under the plan											50.00%
Percentage of stock that the participant may elect as dividend under second option of plan											50.00%
Percentage of cash that the participant may elect as a dividend equivalent deferral for 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%
2012 Plan
Stock-Based Compensation
Common shares available for grant (in shares) | shares			4,600,000								4,600,000
Common shares available for issuance (in shares) | shares			2,200,000								2,200,000
Retained Earnings
Stock-Based Compensation
Stock compensation cumulative effect adjustments							5,475					5,475
Accounting Standards Update 2016-09
Stock-Based Compensation
Operations and maintenance												12,000
Accounting Standards Update 2016-09 | Retained Earnings
Stock-Based Compensation
Stock compensation cumulative effect adjustments							6,000					$ 6,000
Net income tax expense							$ 3,000

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Stock-Based Compensation - Summary of Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restricted Stock Units, Stock Grants, and Stock Units
Stocks granted and the weighted average fair value
Units granted (in shares)	161,963	141,811	152,651
Grant date fair value (in dollars per share)	$ 72.60	$ 67.34	$ 64.12
Number of granted awards to be settled in cash (in shares)	67,599	43,952	45,104
Performance Shares
Stocks granted and the weighted average fair value
Units granted (in shares)	147,706	166,666	151,430
Grant date fair value (in dollars per share)	$ 78.99	$ 66.60	$ 64.97

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Stock-Based Compensation - Status of Nonvested Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restricted Stock Units, Stock Grants, and Stock Units
Nonvested shares
Balance at the beginning of the period (in shares)	335,259
Granted (in shares)	161,963
Change in performance factor (in shares)	0
Vested (in shares)	(202,327)
Forfeited (in shares)	(3,607)
Balance at the end of the period (in shares)	291,288	335,259
Weighted-Average Grant-Date Fair Value
Balance at the beginning of the period (in dollars per share)	$ 62.04
Granted (in dollars per share)	72.60	$ 67.34	$ 64.12
Change in performance factor (in dollars per share)	0.00
Vested (in dollars per share)	59.19
Forfeited (in dollars per share)	69.58
Balance at the end of the period (in dollars per share)	$ 69.78	$ 62.04
Vested Awards Outstanding at December 31, 2017	89,928
Vested Awards Outstanding at December 31, 2015 (in shares)
Number of nonvested awards to be settled in cash (in shares)	133,373
Performance Shares
Nonvested shares
Balance at the beginning of the period (in shares)	312,724
Granted (in shares)	147,706
Change in performance factor (in shares)	18,266
Vested (in shares)	(164,396)
Forfeited (in shares)	(4,798)
Balance at the end of the period (in shares)	309,502	312,724
Weighted-Average Grant-Date Fair Value
Balance at the beginning of the period (in dollars per share)	$ 65.32
Granted (in dollars per share)	78.99	$ 66.60	$ 64.97
Change in performance factor (in dollars per share)	64.97
Vested (in dollars per share)	63.87
Forfeited (in dollars per share)	69.77
Balance at the end of the period (in dollars per share)	$ 72.46	$ 65.32
Vested Awards Outstanding at December 31, 2017	164,396
Vested Awards Outstanding at December 31, 2015 (in shares)

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Derivative Accounting (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Designated as Hedging Instruments
Derivative [Line Items]
Derivative liability	$ 0	$ 2,000
ARIZONA PUBLIC SERVICE COMPANY
Derivative [Line Items]
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment before accounting treatment change	100.00%
Commodity Contracts
Derivative [Line Items]
Derivative liability	$ 96,422	$ 73,074
Additional collateral to counterparties for energy related non-derivative instrument contracts	110,000
Commodity Contracts | Designated as Hedging Instruments
Derivative [Line Items]
Estimated net gain (loss) before income taxes to be reclassified from accumulated other comprehensive income	$ (2,000)

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Derivative Accounting - Outstanding Gross Notional Amounts Outstanding (Details)	12 Months Ended
	Dec. 31, 2017 MWh Bcf	Dec. 31, 2016 MWh Bcf
Outstanding gross notional amount of derivatives
Power (in MWh) | MWh	583,000	1,314,000
Gas (in bcf) | Bcf	240	194

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Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Designated as Hedging Instruments
Derivative Instruments in Designated Cash Flows Hedges
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	$ (59,000)	$ 47,000	$ (615,000)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion Realized)	(3,519,000)	(3,926,000)	(5,988,000)
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges	0	0	0
Not Designated as Hedging Instruments
Derivative Instruments Not Designated as Cash Flows Hedges
Net Gain (Loss) Recognized in Income	(89,183,000)	26,482,000	(108,399,000)
Revenue | Not Designated as Hedging Instruments
Derivative Instruments Not Designated as Cash Flows Hedges
Net Gain (Loss) Recognized in Income	(1,192,000)	771,000	574,000
Fuel and purchased power | Not Designated as Hedging Instruments
Derivative Instruments Not Designated as Cash Flows Hedges
Net Gain (Loss) Recognized in Income	$ (87,991,000)	$ 25,711,000	$ (108,973,000)

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Derivative Accounting - Derivative Instruments in the Balance Sheet (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Commodity Contracts
Assets
Gross Recognized Derivatives	$ 6,719,000	$ 54,798,000
Amounts Offset	(5,037,000)	(35,103,000)
Net Recognized Derivatives	1,682,000	19,695,000
Other	300,000	0
Amount Reported on Balance Sheet	1,982,000	19,695,000
Liabilities
Gross Recognized Derivatives	(97,938,000)	(104,123,000)
Amounts Offset	5,037,000	35,103,000
Net Recognized Derivatives	(92,901,000)	(69,020,000)
Other	(3,521,000)	(4,054,000)
Amount Reported on Balance Sheet	(96,422,000)	(73,074,000)
Assets and Liabilities
Gross Recognized Derivatives	(91,219,000)	(49,325,000)
Amounts Offset	0	0
Net Recognized Derivatives	(91,219,000)	(49,325,000)
Other	(3,221,000)	(4,054,000)
Amount Reported on Balance Sheet	(94,440,000)	(53,379,000)
Commodity Contracts | Current Assets
Assets
Gross Recognized Derivatives	5,427,000	48,094,000
Amounts Offset	(3,796,000)	(28,400,000)
Net Recognized Derivatives	1,631,000	19,694,000
Other	300,000	0
Amount Reported on Balance Sheet	1,931,000	19,694,000
Commodity Contracts | Investments and Other Assets
Assets
Gross Recognized Derivatives	1,292,000	6,704,000
Amounts Offset	(1,241,000)	(6,703,000)
Net Recognized Derivatives	51,000	1,000
Other	0	0
Amount Reported on Balance Sheet	51,000	1,000
Commodity Contracts | Current Liabilities
Liabilities
Gross Recognized Derivatives	(59,527,000)	(50,182,000)
Amounts Offset	3,796,000	28,400,000
Net Recognized Derivatives	(55,731,000)	(21,782,000)
Other	(3,521,000)	(4,054,000)
Amount Reported on Balance Sheet	(59,252,000)	(25,836,000)
Commodity Contracts | Deferred Credits and Other
Liabilities
Gross Recognized Derivatives	(38,411,000)	(53,941,000)
Amounts Offset	1,241,000	6,703,000
Net Recognized Derivatives	(37,170,000)	(47,238,000)
Other	0	0
Amount Reported on Balance Sheet	(37,170,000)	(47,238,000)
Designated as Hedging Instruments
Liabilities
Amount Reported on Balance Sheet	$ 0	$ (2,000,000)

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Derivative Accounting - Credit Risk and Related Contingent Features (Details) - Commodity Contracts $ in Thousands	Dec. 31, 2017 USD ($)
Credit Risk and Credit-Related Contingent Features
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$ 97,938
Cash Collateral Posted	0
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered	$ 91,071

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Other Income and Other Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other income:
Interest income	$ 3,497	$ 884	$ 493
Miscellaneous	509	17	128
Total other income	4,006	901	621
Other expense:
Non-operating costs	(11,749)	(9,235)	(11,292)
Investment losses — net	(4,113)	(1,747)	(2,080)
Miscellaneous	(5,677)	(4,355)	(4,451)
Total other expense	(21,539)	(15,337)	(17,823)
ARIZONA PUBLIC SERVICE COMPANY
Other income:
Interest income	2,858	261	163
Gain on disposition of property	2,048	5,745	716
Miscellaneous	1,620	2,601	1,955
Total other income	6,526	8,607	2,834
Other expense:
Non-operating costs	(12,395)	(11,034)	(11,648)
Loss on disposition of property	(5,424)	(1,246)	(2,219)
Miscellaneous	(5,561)	(5,234)	(5,152)
Total other expense	$ (23,380)	$ (17,514)	$ (19,019)

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Palo Verde Sale Leaseback Variable Interest Entities (Details) $ in Thousands		12 Months Ended
	Jan. 01, 2018 USD ($)	Dec. 31, 2017 USD ($) Trust Lease	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 1986 Trust
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts		$ 19,493	$ 19,493	$ 18,933
ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Sale Leaseback Variable Interest Entities
Number of VIE lessor trusts | Trust		3			3
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts		$ 19,493	19,493	18,933
ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts		$ 19,000	$ 19,000	$ 19,000
Period Through 2023 | ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Number of leases under which assets are retained | Lease		1
Period Through 2033 | ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Number of leases under which assets are retained | Lease		2
Period 2017 through 2023 | ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments		$ 23,000
Period 2024 through 2033 | ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Annual lease payments		$ 16,000
Maximum | Period 2024 through 2033 | ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
Lease period		2 years
Scenario, Forecast | ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Palo Verde Sale Leaseback Variable Interest Entities
VIE entity initial loss exposure to noncontrolling interests during lease extension period, amount	$ 293,000
VIE entity maximum loss exposure to noncontrolling interests during lease extension period, amount	$ 456,000

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Palo Verde Sale Leaseback Variable Interest Entities Palo Verde Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback, net of accumulated depreciation	$ 109,645	$ 113,515
Equity - noncontrolling interests	129,040	132,290
ARIZONA PUBLIC SERVICE COMPANY
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback, net of accumulated depreciation	109,645	113,515
Equity - noncontrolling interests	129,040	132,290
ARIZONA PUBLIC SERVICE COMPANY | Consolidation of VIEs
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Palo Verde sale leaseback, net of accumulated depreciation	109,645	113,515
Equity - noncontrolling interests	$ 129,040	$ 132,290

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Investments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Nuclear decommissioning trust fund assets
Fair Value	$ 871,000	$ 779,586
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Realized gains	21,813	11,213	$ 5,189
Realized losses	(13,146)	(10,106)	(6,225)
Proceeds from the sale of securities	542,246	633,410	478,813
Fair value of fixed income securities, summarized by contractual maturities
Total	871,000	779,586
Fixed income securities
Nuclear decommissioning trust fund assets
Fair Value	478,294
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	25,123
1 year - 5 years	102,783
5 years - 10 years	137,854
Greater than 10 years	212,534
Total	478,294
Nuclear Decommissioning Trusts
Nuclear decommissioning trust fund assets
Fair Value	446,277
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	24,668
1 year - 5 years	100,289
5 years - 10 years	129,239
Greater than 10 years	192,081
Total	446,277
Escrow Accounts
Nuclear decommissioning trust fund assets
Fair Value	32,017
Fair value of fixed income securities, summarized by contractual maturities
Less than one year	455
1 year - 5 years	2,494
5 years - 10 years	8,615
Greater than 10 years	20,453
Total	32,017
ARIZONA PUBLIC SERVICE COMPANY
Nuclear decommissioning trust fund assets
Fair Value	871,000	779,586
Total Unrealized Gains	260,160	197,911
Total Unrealized Losses	(2,996)	(4,962)
Net receivables for securities purchases	109	795
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
Proceeds from the sale of securities	542,246	633,410	$ 478,813
Fair value of fixed income securities, summarized by contractual maturities
Total	871,000	779,586
ARIZONA PUBLIC SERVICE COMPANY | Equity securities
Nuclear decommissioning trust fund assets
Fair Value	417,390	353,261
Total Unrealized Gains	248,623	188,091
Total Unrealized Losses	0	0
Fair value of fixed income securities, summarized by contractual maturities
Total	417,390	353,261
ARIZONA PUBLIC SERVICE COMPANY | Fixed income securities
Nuclear decommissioning trust fund assets
Fair Value	446,277	425,530
Total Unrealized Gains	11,537	9,820
Total Unrealized Losses	(2,996)	(4,962)
Fair value of fixed income securities, summarized by contractual maturities
Total	446,277	425,530
ARIZONA PUBLIC SERVICE COMPANY | Cash and cash equivalents
Nuclear decommissioning trust fund assets
Fair Value	7,224	0
Total Unrealized Gains	0	0
Total Unrealized Losses	0	0
Fair value of fixed income securities, summarized by contractual maturities
Total	$ 7,224	$ 0

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Investments - Narrative (Details) - Fixed income securities - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
ARIZONA PUBLIC SERVICE COMPANY
Schedule of Held-to-maturity Securities [Line Items]
Coal reclamation escrow account	$ 30,000,000
Proceeds from sale of securities	4,000,000	$ 0
4CA
Schedule of Held-to-maturity Securities [Line Items]
Coal reclamation escrow account	$ 2,000,000

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Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	$ 4,935,912	$ 4,719,457
Ending balance	5,135,730	4,935,912
Pension and Other Postretirement Benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(39,070)	(37,593)
OCI (loss) before reclassifications	(6,438)	(4,509)
Amounts reclassified from accumulated other comprehensive loss	3,068	3,032
Ending balance	(42,440)	(39,070)
Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(4,752)	(7,155)
OCI (loss) before reclassifications	(35)	(538)
Amounts reclassified from accumulated other comprehensive loss	2,225	2,941
Ending balance	(2,562)	(4,752)
Total
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(43,822)	(44,748)
OCI (loss) before reclassifications	(6,473)	(5,047)
Amounts reclassified from accumulated other comprehensive loss	5,293	5,973
Ending balance	(45,002)	(43,822)
ARIZONA PUBLIC SERVICE COMPANY
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	5,037,970	4,814,794
Ending balance	5,385,869	5,037,970
ARIZONA PUBLIC SERVICE COMPANY | Pension and Other Postretirement Benefits
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(20,671)	(19,942)
OCI (loss) before reclassifications	(6,884)	(3,821)
Amounts reclassified from accumulated other comprehensive loss	3,134	3,092
Ending balance	(24,421)	(20,671)
ARIZONA PUBLIC SERVICE COMPANY | Derivative Instruments
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(4,752)	(7,155)
OCI (loss) before reclassifications	(35)	(538)
Amounts reclassified from accumulated other comprehensive loss	2,225	2,941
Ending balance	(2,562)	(4,752)
ARIZONA PUBLIC SERVICE COMPANY | Total
Changes in accumulated other comprehensive income (loss) by component
Beginning balance	(25,423)	(27,097)
OCI (loss) before reclassifications	(6,919)	(4,359)
Amounts reclassified from accumulated other comprehensive loss	5,359	6,033
Ending balance	$ (26,983)	$ (25,423)

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Statement of Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CONDENSED FINANCIAL STATEMENTS
Operating revenues	$ 759,659	$ 1,183,322	$ 944,587	$ 677,728	$ 739,199	$ 1,166,922	$ 915,394	$ 677,167	$ 3,565,296	$ 3,498,682	$ 3,495,443
Operating expenses									2,630,869	2,642,698	2,640,841
OPERATING INCOME	90,610	466,082	304,229	73,506	122,816	451,258	231,748	50,162	934,427	855,984	854,602
Other
Total									29,478	27,704	18,013
Interest expense									219,796	205,720	194,964
Income tax benefit	20,775	144,319	88,967	4,211	27,309	141,446	65,742	1,914	258,272	236,411	237,720
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 21,629	$ 276,072	$ 167,443	$ 23,312	$ 53,246	$ 263,027	$ 121,308	$ 4,453	488,456	442,034	437,257
Other comprehensive income									(1,180)	926	23,393
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS									487,276	442,960	460,650
Pinnacle West
CONDENSED FINANCIAL STATEMENTS
Operating revenues									119	370	550
Operating expenses									24,298	26,424	12,733
OPERATING INCOME									(24,179)	(26,054)	(12,183)
Other
Equity in earnings of subsidiaries									507,495	462,027	446,508
Other expense									(2,715)	(1,771)	(3,302)
Total									504,780	460,256	443,206
Interest expense									5,633	3,151	2,672
INCOME BEFORE INCOME TAXES									474,968	431,051	428,351
Income tax benefit									(13,488)	(10,983)	(8,906)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS									488,456	442,034	437,257
Other comprehensive income									(1,180)	926	23,393
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS									$ 487,276	$ 442,960	$ 460,650

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Consolidated Balance Sheets (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 13,892,000	$ 8,881,000	$ 39,488,000	$ 7,604,000
Accounts receivable	305,147,000	250,491,000
Income tax receivable	0	3,751,000
Other current assets	48,039,000	45,028,000
Total current assets	1,016,288,000	822,219,000
Investments and other assets
Other assets	84,531,000	69,063,000
Total investments and other assets	955,582,000	848,650,000
Total Assets	17,019,082,000	16,004,253,000
Current liabilities
Accounts payable	256,442,000	264,631,000
Accrued taxes	148,946,000	138,964,000
Common dividends payable	77,667,000	72,926,000
Short-term borrowings	95,400,000	177,200,000
Current maturities of long-term debt	82,000,000	125,000,000
Other current liabilities	246,529,000	244,000,000
Total current liabilities	1,197,852,000	1,292,946,000
Deferred credits and other
Long-term debt less current maturities	4,789,713,000	4,021,785,000
Other	148,909,000	156,784,000
Total deferred credits and other	5,895,787,000	5,753,610,000
Common stock equity
Common stock	2,614,805,000	2,596,030,000
Accumulated other comprehensive loss	(45,002,000)	(43,822,000)
Retained earnings	2,442,511,000	2,255,547,000
Total shareholders’ equity	5,006,690,000	4,803,622,000
Noncontrolling interests	129,040,000	132,290,000
Total equity	5,135,730,000	4,935,912,000	4,719,457,000	4,519,102,000
Total Liabilities and Equity	17,019,082,000	16,004,253,000
Pinnacle West
Current assets
Cash and cash equivalents	41,000	41,000	$ 17,432,000	$ 3,088,000
Accounts receivable	93,554,000	81,751,000
Income tax receivable	19,124,000	0
Other current assets	267,000	340,000
Total current assets	112,986,000	82,132,000
Investments and other assets
Investments in subsidiaries	5,465,137,000	5,084,035,000
Deferred income taxes	54,352,000	53,805,000
Other assets	44,613,000	38,500,000
Total investments and other assets	5,564,102,000	5,176,340,000
Total Assets	5,677,088,000	5,258,472,000
Current liabilities
Accounts payable	7,638,000	5,421,000
Accrued taxes	8,927,000	12,050,000
Common dividends payable	77,667,000	72,926,000
Short-term borrowings	95,400,000	41,700,000
Current maturities of long-term debt	0	125,000,000
Other current liabilities	17,417,000	31,182,000
Total current liabilities	207,049,000	288,279,000
Deferred credits and other
Long-term debt less current maturities	298,421,000	0
Pension liabilities	20,758,000	21,057,000
Other	15,130,000	13,224,000
Total deferred credits and other	35,888,000	34,281,000
Common stock equity
Common stock	2,609,181,000	2,591,897,000
Accumulated other comprehensive loss	(45,002,000)	(43,822,000)
Retained earnings	2,442,511,000	2,255,547,000
Total shareholders’ equity	5,006,690,000	4,803,622,000
Noncontrolling interests	129,040,000	132,290,000
Total equity	5,135,730,000	4,935,912,000
Total Liabilities and Equity	$ 5,677,088,000	$ 5,258,472,000

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Consolidated Statements of Cash Flows (Details) - USD ($)		3 Months Ended								12 Months Ended
	Nov. 30, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash Flows from Operating Activities
Net income		$ 26,502,000	$ 280,945,000	$ 172,317,000	$ 28,185,000	$ 58,119,000	$ 267,900,000	$ 126,182,000	$ 9,326,000	$ 507,949,000	$ 461,527,000	$ 456,190,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization										610,629,000	565,011,000	571,664,000
Deferred income taxes										248,164,000	206,870,000	236,819,000
Accounts receivable										(93,797,000)	(2,489,000)	(22,219,000)
Accounts payable										(23,769,000)	(66,917,000)	(34,266,000)
Net cash flow provided by operating activities										1,118,036,000	1,023,390,000	1,094,327,000
Cash flows from investing activities
Net cash flow used for investing activities										(1,428,537,000)	(1,252,078,000)	(1,066,233,000)
Cash flows from financing activities
Issuance of long-term debt										848,239,000	693,151,000	842,415,000
Short-term debt borrowings under revolving credit facility										58,000,000	40,000,000	0
Short-term debt repayments under revolving credit facility										(32,000,000)	0	0
Dividends paid on common stock										(289,793,000)	(274,229,000)	(260,027,000)
Repayment of long-term debt										(125,000,000)	(370,430,000)	(415,570,000)
Common stock equity issuance and purchases - net										(13,390,000)	(4,867,000)	19,373,000
Net cash flow provided by financing activities										315,512,000	198,081,000	3,790,000
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS										5,011,000	(30,607,000)	31,884,000
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR					8,881,000				39,488,000	8,881,000	39,488,000	7,604,000
CASH AND CASH EQUIVALENTS AT END OF YEAR		13,892,000				8,881,000				13,892,000	8,881,000	39,488,000
Pinnacle West
Cash Flows from Operating Activities
Net income										488,456,000	442,034,000	437,257,000
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries - net										(507,495,000)	(462,027,000)	(446,508,000)
Depreciation and amortization										76,000	85,000	92,000
Deferred income taxes										(264,000)	(12,402,000)	12,967,000
Accounts receivable										(2,106,000)	15,823,000	11,336,000
Accounts payable										(11,162,000)	10,402,000	637,000
Accrued taxes and income tax receivable - net										(22,247,000)	20,041,000	(12,882,000)
Dividends received from subsidiaries										296,800,000	239,300,000	266,900,000
Other										15,092,000	5,514,000	(6,995,000)
Net cash flow provided by operating activities										257,150,000	258,770,000	262,804,000
Cash flows from investing activities
Construction work in progress										0	(18,457,000)	(3,462,000)
Investments in subsidiaries	$ (150,000,000)									(178,027,000)	(19,242,000)	(3,491,000)
Repayments of loans from subsidiaries										2,987,000	1,026,000	157,000
Advances of loans to subsidiaries										(6,388,000)	(2,092,000)	(1,010,000)
Net cash flow used for investing activities										(181,428,000)	(38,765,000)	(7,806,000)
Cash flows from financing activities
Issuance of long-term debt										298,761,000	0	0
Short-term debt borrowings under revolving credit facility										58,000,000	40,000,000	0
Short-term debt repayments under revolving credit facility										(32,000,000)	0	0
Commercial Paper - net										27,700,000	1,700,000	0
Dividends paid on common stock										(289,793,000)	(274,229,000)	(260,027,000)
Repayment of long-term debt										(125,000,000)	0	0
Common stock equity issuance and purchases - net										(13,390,000)	(4,867,000)	19,373,000
Net cash flow provided by financing activities										(75,722,000)	(237,396,000)	(240,654,000)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS										0	(17,391,000)	14,344,000
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR					$ 41,000				$ 17,432,000	41,000	17,432,000	3,088,000
CASH AND CASH EQUIVALENTS AT END OF YEAR		$ 41,000				$ 41,000				$ 41,000	$ 41,000	$ 17,432,000

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SCHEDULE II - RESERVE FOR UNCOLLECTIBLES (Details) - Reserve for uncollectibles. - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pinnacle West
Changes in reserve for uncollectibles
Balance at beginning of period	$ 3,037	$ 3,125	$ 3,094
Additions, Charged to cost and expenses	6,836	4,025	4,073
Additions, Charged to other accounts	0	0	0
Deductions	7,360	4,113	4,042
Balance at end of period	2,513	3,037	3,125
ARIZONA PUBLIC SERVICE COMPANY
Changes in reserve for uncollectibles
Balance at beginning of period	3,037	3,125	3,094
Additions, Charged to cost and expenses	6,836	4,025	4,073
Additions, Charged to other accounts	0	0	0
Deductions	7,360	4,113	4,042
Balance at end of period	$ 2,513	$ 3,037	$ 3,125

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