10-K 1 pnw2017123110-k.htm 10-K Document

 
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
 
o            TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from              to             
Commission
File Number
 
Registrants; State of Incorporation;
Addresses; and Telephone Number
 
IRS Employer
Identification No.
1-8962
 
PINNACLE WEST CAPITAL CORPORATION
(An Arizona corporation)
400 North Fifth Street, P.O. Box 53999
Phoenix, Arizona 85072-3999
(602) 250-1000
 
86-0512431
1-4473
 
ARIZONA PUBLIC SERVICE COMPANY
(An Arizona corporation)
400 North Fifth Street, P.O. Box 53999
Phoenix, Arizona 85072-3999
(602) 250-1000
 
86-0011170
 
Securities registered pursuant to Section 12(b) of the Act:
 
 
Title Of Each Class
 
Name Of Each Exchange On Which Registered
PINNACLE WEST CAPITAL CORPORATION
 
Common Stock,
No Par Value
 
New York Stock Exchange
ARIZONA PUBLIC SERVICE COMPANY
 
None
 
None
 
Securities registered pursuant to Section 12(g) of the Act:
ARIZONA PUBLIC SERVICE COMPANY             Common Stock, Par Value $2.50 per share
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act
PINNACLE WEST CAPITAL CORPORATION
Yes x  No o
ARIZONA PUBLIC SERVICE COMPANY
Yes x  No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
PINNACLE WEST CAPITAL CORPORATION
Yes o  No x
ARIZONA PUBLIC SERVICE COMPANY
Yes o  No x
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
PINNACLE WEST CAPITAL CORPORATION
Yes x  No o
ARIZONA PUBLIC SERVICE COMPANY
Yes x  No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
PINNACLE WEST CAPITAL CORPORATION
Yes x  No o
ARIZONA PUBLIC SERVICE COMPANY
Yes x  No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or in any amendment to this Form 10-K.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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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.

a171106585x11apsretailservic.jpg

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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chart-753ef6b0205256c0a90.jpg

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 Confidence and 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 115th 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 52nd Street Superfund Site, Operable Unit 3 ("OU3") in Phoenix, Arizona.  APS has facilities that are within this Superfund site.  APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater

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

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 risks and 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.


40


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


41



(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. 

42


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

43


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.


44


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.



45


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.




46


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




47


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

 


48


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 borr