10-K 1 pnw12311410-k.htm 10-K PNW 12.31.14 10-K
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
FORM 10-K
 
(Mark One)
 
      x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2014
 
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, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (Check one):
 
PINNACLE WEST CAPITAL CORPORATION
 
 
Large accelerated filer x
 
Accelerated filer o
 
 
 
Non-accelerated filer o
 
Smaller reporting company o
(Do not check if a smaller reporting company)
 
 
ARIZONA PUBLIC SERVICE COMPANY
 
 
Large accelerated filer o
 
Accelerated filer o
 
 
 
Non-accelerated filer x
 
Smaller reporting company o
(Do not check if a smaller reporting company)
 
 
 
Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o  No x
 
State the aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of each registrant’s most recently completed second fiscal quarter:
PINNACLE WEST CAPITAL CORPORATION
 
$6,356,930,539 as of June 30, 2014
ARIZONA PUBLIC SERVICE COMPANY
 
$0 as of June 30, 2014
 
The number of shares outstanding of each registrant’s common stock as of February 13, 2015
PINNACLE WEST CAPITAL CORPORATION
 
110,575,187 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 20, 2015 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 Notes to Pinnacle West’s Consolidated Financial Statements, the majority of which also relates to APS, and Supplemental Notes, which only relate to APS’s Consolidated Financial Statements.
 

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GLOSSARY OF NAMES AND TECHNICAL TERMS

ac
Alternating Current
ACC
Arizona Corporation Commission
ADEQ
Arizona Department of Environmental Quality
AFUDC
Allowance for Funds Used During Construction
ANPP
Arizona Nuclear Power Project, also known as Palo Verde
APS
Arizona Public Service Company, a subsidiary of the Company
APSES
APS Energy Services Company, Inc., a subsidiary of the Company sold on August 19, 2011
ARO
Asset retirement obligations
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
Cholla
Cholla Power Plant
dc
Direct Current
DOE
United States Department of Energy
DOI
United States Department of the Interior
DSM
Demand side management
DSMAC
Demand side management adjustment charge
El Dorado
El Dorado Investment Company, a subsidiary of the Company
El Paso
El Paso Electric Company
EPA
United States Environmental Protection Agency
FERC
United States Federal Energy Regulatory Commission
Four Corners
Four Corners Power Plant
GWh
Gigawatt-hour, one billion watts per hour
kV
Kilovolt, one thousand volts
kWh
Kilowatt-hour, one thousand watts per hour
LFCR
Lost Fixed Cost Recovery Mechanism
MMBtu
One million British Thermal Units
MW
Megawatt, one million watts
MWh
Megawatt-hour, one million watts per hour
Native Load
Retail and wholesale sales supplied under traditional cost-based rate regulation
Navajo Plant
Navajo Generating Station
NERC
North American Electric Reliability Corporation
NRC
United States Nuclear Regulatory Commission
NTEC
Navajo Transitional Energy Company, LLC
OCI
Other comprehensive income
Palo Verde
Palo Verde Nuclear Generating Station or PVNGS
Pinnacle West
Pinnacle West Capital Corporation (any use of the words “Company,” “we,” and “our” refer to Pinnacle West)
PSA
Power supply adjustor approved by the ACC to provide for recovery or refund of variations in actual fuel and purchased power costs compared with the Base Fuel Rate
RES
Arizona Renewable Energy Standard and Tariff
Salt River Project or SRP
Salt River Project Agricultural Improvement and Power District
SCE
Southern California Edison Company
SunCor
SunCor Development Company, formerly a subsidiary of the Company
TCA
Transmission cost adjustor
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” and similar words.  Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements.  A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS.  In addition to the Risk Factors described in Item 1A and in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” these factors include, but are not limited to:

our ability to manage capital expenditures and operations and maintenance costs while maintaining reliability and customer service levels;
variations in demand for electricity, including those due to weather, the general economy, customer and sales growth (or decline), and the effects of energy conservation measures and distributed generation;
power plant and transmission system performance and outages;
competition in retail and wholesale power markets;
regulatory and judicial decisions, developments and proceedings;
new legislation or regulation, including those relating to environmental requirements, nuclear plant operations and potential deregulation of retail electric markets;
fuel and water supply availability;
our ability to achieve timely and adequate rate recovery of our costs, including returns on debt and equity capital;
our ability to meet renewable energy and energy efficiency mandates and recover related costs;
risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty;
current and future economic conditions in Arizona, particularly in real estate markets;
the 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 and other concerns surrounding coal-fired generation;
volatile fuel and purchased power costs;
the investment performance of the assets of our nuclear decommissioning trust, pension, and other postretirement benefit plans and the resulting impact on future funding requirements;
the liquidity of wholesale power markets and the use of derivative contracts in our business;
potential shortfalls in insurance coverage;
new accounting requirements or new interpretations of existing requirements;
generation, transmission and distribution facility and system conditions and operating costs;
the ability to meet the anticipated future need for additional baseload generation and associated transmission facilities in our region;
the willingness or ability of our counterparties, power plant participants and power plant land owners to meet contractual or other obligations or extend the rights for continued power plant operations; 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 and BCE.  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 6,426 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 2014, no single purchaser or user of energy accounted for more than 1.4% of our electric revenues.


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



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Energy Sources and Resource Planning
 To serve its customers, APS obtains power through its various generation stations and through purchased power agreements.  Resource planning is an important function necessary to meet Arizona’s future energy needs.  APS’s sources of energy by type during 2014 were as follows:
 

Generation Facilities
 
APS has ownership interests in or leases the coal, nuclear, gas, oil and solar generating facilities described below.  For additional information regarding these facilities, see Item 2.
 
Coal-Fueled Generating Facilities
 
Four Corners — Four Corners is a 5-unit coal-fired power plant located in the northwestern corner of New Mexico.  APS operates the plant and owns 100% of Four Corners Units 1, 2 and 3 and 63% of Four Corners Units 4 and 5 following the acquisition of SCE’s interest in Units 4 and 5 described below.  As of December 30, 2013, APS retired Units 1, 2 and 3.  APS has a total entitlement from Four Corners of 970 MW.
 
On November 8, 2010, APS and SCE entered into an asset purchase agreement (the “Asset Purchase Agreement”) providing for the purchase by APS of SCE’s 48% interest in each of Units 4 and 5 of Four Corners, allowing APS to acquire 739 MW from SCE.  On December 30, 2013, APS and SCE closed this transaction.  The final purchase price for SCE’s interest was approximately $182 million, subject to certain minor post-closing adjustments.

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In connection with APS’s most recent retail rate case with the ACC, the ACC reserved the right to review the prudence of the Four Corners transaction for cost recovery purposes upon the closing of the transaction.  On December 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. 
Concurrently with the closing of the SCE transaction, BHP Billiton, the parent company of BNCC, the coal supplier and operator of the mine that serves Four Corners, transferred its ownership of BNCC to NTEC, a company formed by the Navajo Nation to own the mine and develop other energy projects.  BHP Billiton will be retained by NTEC under contract as the mine manager and operator until July 2016.  Also occurring concurrently with the closing, the Four Corners’ co-owners executed a long-term agreement for the supply of coal to Four Corners from July 2016, when the current coal supply agreement expires, through 2031 (the “2016 Coal Supply Agreement”).  El Paso, a 7% owner in Units 4 and 5 of Four Corners, did not sign the 2016 Coal Supply Agreement.  Under the 2016 Coal Supply Agreement, APS has agreed to assume the 7% shortfall obligation.  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. The cash purchase price, which will be subject to certain adjustments at closing, is immaterial in amount, and the purchaser will assume El Paso's reclamation and decommissioning obligations associated with the 7% interest. Completion of the purchase is subject to the receipt of certain regulatory approvals and is expected to occur in July 2016.
When APS, or an affiliate of APS, ultimately acquires El Paso's interest in Four Corners, NTEC will have an option to purchase the interest within a certain timeframe pursuant to an option granted by APS to NTEC.  The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% shortfall obligations in the event NTEC does not exercise its option.
 
The Four Corners plant site is leased from the Navajo Nation and is also subject to an easement from the federal government.  APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation which extends the Four Corners leasehold interest from 2016 to 2041.  The Navajo Nation approved these amendments in March 2011.  The effectiveness of the amendments also requires the approval of the DOI, as does a related federal rights-of-way grant, which the Four Corners participants are pursuing.  A federal environmental review is underway as part of the DOI review process.  In March 2014, APS received a draft of the environmental impact statement ("DEIS") in connection with the DOI review process. As a proponent of Four Corners and the Navajo Mine Energy Project, APS, along with other members of the public, submitted comments on the DEIS. APS cannot predict whether these federal approvals will be granted and, if so, on a timely basis, or whether any conditions that may be attached to them will be acceptable to the Four Corners owners. On December 19, 2014, APS obtained a Prevention of Significant Deterioration (“PSD”) permit from EPA allowing APS to install selective catalytic reduction (“SCR”) control technology at Four Corners, as described below under “Environmental Matters — EPA Environmental Regulation.” 
 
Cholla — Cholla is a 4-unit coal-fired power plant located in northeastern Arizona.  APS operates the plant and owns 100% of Cholla Units 1, 2 and 3.  PacifiCorp owns Cholla Unit 4, and APS operates that unit for PacifiCorp.  APS has a total entitlement from Cholla of 647 MW.  APS purchases all of Cholla’s coal requirements from a coal supplier that mines all of the coal under long-term leases of coal reserves with the federal and state governments and private landholders.  The Cholla coal contract runs through 2024.  In addition, APS has a long-term coal transportation contract that runs through 2017 with plans to extend the contract beyond 2017. See "Current and Future Resources - Future Resources and Resource Plan" below for a discussion of future plans for Cholla.
 

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Navajo Generating Station — The Navajo Plant is a 3-unit coal-fired power plant located in northern Arizona.  Salt River Project operates the plant and APS owns a 14% interest in Navajo Units 1, 2 and 3.  APS has a total entitlement from the Navajo Plant of 315 MW.  The Navajo Plant’s coal requirements are purchased from a supplier with long-term leases from the Navajo Nation and the Hopi Tribe.  The Navajo Plant is under contract with its coal supplier through 2019, with extension rights through 2026.  The Navajo Plant site is leased from the Navajo Nation and is also subject to an easement from the federal government.  The current lease expires in 2019. See "Environmental Matters - EPA Environmental Regulation - Regional Haze Rules - Navajo Plant" below for a discussion of potential future plans for the Navajo Plant.
 
These coal-fueled plants face uncertainties, including those related to existing and potential legislation and regulation, that could significantly impact their economics and operations.  See “Environmental Matters” below and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview and Capital Expenditures” in Item 7 for developments impacting these coal-fueled facilities.  See Note 10 for information regarding APS’s coal mine reclamation obligations.
Nuclear
 Palo Verde Nuclear Generating Station — Palo Verde is a 3-unit nuclear power plant located 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 agreements expire at the end of 2015 and contain options to renew the leases or to purchase the property for fair market value at the end of the lease terms.  On July 7, 2014, APS notified the lessor trust entities of APS’s intent to exercise the fixed rate lease renewal options.  The length of the renewal options will result 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 and conversion services through 2018 and 45% of its requirements in 2019-2020.  The

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participants have also contracted for 100% of Palo Verde’s enrichment services through 2020; and all of Palo Verde’s fuel assembly fabrication services through 2022.

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 U.S. Court of Federal Claims for damages incurred due to DOE’s breach of the Standard Contract.  The Court of Federal Claims ruled in favor of APS and the Palo Verde participants in October 2010 and awarded $30.2 million in damages to APS and the Palo Verde participants for costs incurred through December 2006.
 
On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE. This lawsuit sought to recover damages incurred due to DOE’s failure to accept Palo Verde’s spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011. 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 regulatory liability and had no impact on current income.

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

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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 — 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 the National Environmental Policy Act (“NEPA”), requires either an environmental impact statement or a finding of no significant impact from the agency’s actions.  The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the 2010 Waste Confidence Decision update for further action consistent with NEPA.
 
On September 6, 2012, the NRC Commissioners issued a directive to the NRC staff to proceed directly with development of a generic environmental impact statement to support an updated Waste Confidence Decision.  The NRC Commissioners also directed the staff to establish a schedule to publish a final rule and environmental impact study within 24 months of September 6, 2012. 

In September 2013, the NRC issued its draft 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. The continued storage rule 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 August 26th final rule has been subject to continuing legal challenges before the NRC and the Court of Appeals.


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Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation (“ISFSI”) to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027.  Additionally, Palo Verde has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047.  If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.
 
Nuclear Decommissioning Costs — APS currently relies on an external sinking fund mechanism to meet the NRC financial assurance requirements for decommissioning its interests in Palo Verde Units 1, 2 and 3.  The decommissioning costs of Palo Verde Units 1, 2 and 3 are currently included in APS’s ACC jurisdictional rates.  Decommissioning costs are recoverable through a non-bypassable system benefits charge (paid by all retail customers taking service from the APS system).  See Note 19 for additional information about APS’s nuclear decommissioning trusts.
 
Palo Verde Liability and Insurance Matters — See “Palo Verde Nuclear Generating Station — Nuclear Insurance” in Note 10 for a discussion of the insurance maintained by the Palo Verde participants, including APS, for Palo Verde.
 
Impact of Earthquake and Tsunami in Japan on Nuclear Energy Industry — On March 11, 2011, an earthquake measuring 9.0 on the Richter Scale occurred off the coast of Japan causing a series of seven tsunamis.  As a result, the Fukushima Daiichi Nuclear Power Station experienced damage.

Following the earthquake and tsunamis, the NRC established a task force to conduct a systematic and methodical review of NRC processes and regulations to determine whether the agency should make additional improvements to its regulatory system.  On March 12, 2012, the NRC issued the first regulatory requirements based on the recommendations of the Near Term Task Force.  With respect to Palo Verde, the NRC issued two orders requiring safety enhancements regarding:  (1) mitigation strategies to respond to extreme natural events resulting in the loss of power at the plant; and (2) enhancement of spent fuel pool instrumentation.
 
The NRC has issued a number of guidance documents regarding implementation of these requirements.  Due to the developing nature of these requirements, we cannot predict the ultimate financial or operational impacts on Palo Verde or APS. However, to implement these recommendations, Palo Verde expects to spend approximately $40 million for capital enhancements to the plant over the next two years in addition to the approximate $80 million that has already been spent on capital enhancements as of December 31, 2014 (APS’s share is 29.1%).
 
Natural Gas and Oil Fueled Generating Facilities
 APS has six natural gas power plants located throughout Arizona, consisting of Redhawk, located near Palo Verde; Ocotillo, located in Tempe (discussed below); Sundance, located in Coolidge; West Phoenix, located in southwest Phoenix; Saguaro, located north of Tucson; and Yucca, located near Yuma.  Several of the units at Yucca run on either gas or oil.  APS has one oil-only power plant, Douglas, located in the town of Douglas, Arizona.  APS owns and operates each of these plants with the exception of one oil-only combustion turbine unit and one oil and gas steam unit at Yucca that are operated by APS and owned by the Imperial Irrigation District.  APS has a total entitlement from these plants of 3,179 MW.  Gas for these plants is financially hedged up to three years in advance of purchasing and the gas is generally purchased one month prior to delivery.  APS has long-term gas transportation agreements with three different companies, some of which are effective through 2024.  Fuel oil is acquired under short-term purchases delivered primarily to West Phoenix, where it is distributed to APS’s other oil power plants by truck.
 

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Ocotillo is a 330 MW 4-unit gas plant.  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 for summer 2018. The last milestone before construction begins was raised during the ACC's Integrated Resource Planning meeting in the fall of 2014. While there was support for the first 2 units which replace the existing steam units, questions were raised on the cost effectiveness for the additional three units. To address these matters, APS issued a request for proposal in late January 2015 for the incremental capacity, equivalent to 3 of the 5 units.
 
Solar Facilities
 To date, APS has begun operation of 150 MW of utility scale solar through its AZ Sun Program, discussed below.  These facilities are owned by APS and are located in multiple locations throughout Arizona.
 
Additionally, APS owns and operates more than forty small solar systems around the state.  Together they have the capacity to produce approximately 4 MW of renewable energy.  This fleet of solar systems includes a 3 MW facility located at the Prescott Airport and 1 MW of small solar in various locations across Arizona.  APS has also developed solar photovoltaic distributed energy systems installed as part of the Community Power Project in Flagstaff, Arizona.  The Community Power Project, approved by the ACC on April 1, 2010, is a pilot program through which APS owns, operates and receives energy from approximately 1 MW of solar photovoltaic distributed energy systems located within a certain test area in Flagstaff, Arizona.  Additionally, APS owns 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 a 10 MWdc (approximately 8.5 MWac) residential rooftop program. The first stage of the residential rooftop solar program is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with distributed storage. Under this program, APS will own, operate and maintain approximately 1,500 residential systems. The program will target specific distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who cannot easily install solar through transactions with third parties.
 
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, including its renewable energy portfolio, is summarized in the table below.  All capacity values are based on net capacity unless otherwise noted.

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Type
 
Dates Available
 
Capacity (MW)
Purchase Agreement (a)
 
Year-round through June 14, 2020
 
60

Exchange Agreement (b)
 
May 15 to September 15 annually through 2020
 
480

Tolling Agreement
 
Year-round through May 2017
 
514

Tolling Agreement
 
Summer seasons through October 2019
 
560

Day-Ahead Call Option Agreement
 
Summer seasons through September 2015
 
500

Day-Ahead Call Option Agreement
 
Summer seasons through summer 2016
 
150

Demand Response Agreement (c)
 
Summer seasons through 2024
 
25

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 5 MW increments in each of 2015 and 2016 and 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 2014 peak one-hour demand on its electric system was recorded on July 23, 2014 at 7,007 MW, compared to the 2013 peak of 6,927 MW recorded on July 8, 2013.  APS’s reserve margin at the time of the 2014 peak demand, calculated using system load serving capacity, was 34%.  Excluding certain contractual rights to call on additional capacity on short notice, which APS may use in the event of unusual weather or unplanned outages, the 2014 reserve margin was 24%.  APS anticipates the reserve margin for 2015 will be approximately 33% or 23% excluding contractual rights to call on additional capacity.  APS expects that our reserve margins will decrease over the next three years and that additional conventional resources will be needed around 2017.
    
Future Resources and Resource Plan
Under the ACC’s resource planning rule, APS will file by April 1 of each even-numbered year its resource plans for the next fifteen-year period.  The rule requires the ACC to issue an order with its acknowledgment of APS’s resource plan within approximately ten months following its submittal.  The ACC’s acknowledgment of APS’s resource plan will consider factors such as the total cost of electric energy services, demand management, analysis of supply-side options, system reliability and risk management.  APS filed its 2014 resource plan on April 1, 2014 and it will be filing its next resource plan by April 1, 2016. The ACC staff is exploring potential ways to improve the resource plan process.

After considering the costs to comply with environmental regulations, on September 11, 2014, APS announced that it will close Cholla Unit 2 by April 2016 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. APS filed an amendment to its resource plan with the ACC to request approval of the retirement of Cholla Unit 2. The ACC has not yet made a decision on this amendment. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering

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depreciation and a return on the net book value of the unit in base rates and plans to seek recovery of all of the unit’s retirement-related costs in its next retail rate case. If APS closes Cholla Unit 2, APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($128 million as of December 31, 2014), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted.
    
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 5% of retail electric sales in 2015 and increases annually until it reaches 15% in 2025.  In APS’s 2009 retail rate case settlement agreement (the “2009 Settlement Agreement”), APS committed to have 1,700 GWh of new renewable resources in service by year-end 2015 in addition to its 2008 renewable resource commitments.  Taken together, APS’s commitment is estimated to be approximately 12% of retail sales, by year-end 2015, which is more than double the RES target of 5% for that year.  A component of the RES is focused on stimulating development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties, such as rooftop solar systems).  Accordingly, under the RES, an increasing percentage of that requirement must be supplied from distributed energy resources.  This distributed energy requirement is 30% of the overall RES requirement of 5% in 2015.  The following table summarizes the RES requirement standard (not including the additional commitment required by the 2009 Settlement Agreement) and its timing:
 
 
2015
 
2020
 
2025
RES as a % of retail electric sales
5%
 
10%
 
15%
Percent of RES to be supplied from distributed energy resources
30%
 
30%
 
30%
Renewable Energy Portfolio.  To date, APS has a diverse portfolio of existing and planned renewable resources totaling 1,253 MW, including solar, wind, geothermal, biomass and biogas.  Of this portfolio, 1,194 MW are currently in operation and 59 MW are under contract for development or are under construction.  Renewable resources in operation include 169 MW of facilities owned by APS, 629 MW of long-term purchased power agreements, and an estimated 396 MW of customer-sited, third-party owned distributed energy resources.
 
APS’s strategy to achieve its RES requirements includes executing purchased power contracts for new facilities, ongoing development of distributed energy resources and procurement of new facilities to be owned by APS.  APS is developing owned solar resources through the AZ Sun Program.  Under this program to date, APS estimates its investment commitment will be approximately $674 million.  See Note 3 for additional details about the AZ Sun Program.


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The following table summarizes APS’s renewable energy sources currently in operation and under development.  Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the projects to the electric grid.
 
 
Location
 
Actual/
 Target
Commercial
Operation
Date
 
Term
(Years)
 
Net
 Capacity
 In Operation
(MW AC)
 
Net Capacity
 Planned/Under
Development
(MW AC)
APS Owned
 
 
 
 
 
 

 
 

 
 

Solar:
 
 
 
 
 
 

 
 

 
 

AZ Sun Program:
 
 
 
 
 
 

 
 

 
 

Paloma
 
Gila Bend, AZ
 
2011
 
 

 
17

 
 

Cotton Center
 
Gila Bend, AZ
 
2011
 
 

 
17

 
 

Hyder Phase 1
 
Hyder, AZ
 
2011
 
 

 
11

 
 

Hyder Phase 2
 
Hyder, AZ
 
2012
 
 

 
5

 
 

Chino Valley
 
Chino Valley, AZ
 
2012
 
 

 
19

 
 

Hyder II
 
Hyder, AZ
 
2013
 
 

 
14

 
 

Foothills
 
Yuma, AZ
 
2013
 
 

 
35

 
 

Gila Bend
 
Gila Bend, AZ
 
2014
 
 

 
32

 
 
Luke AFB
 
Glendale, AZ
 
2015
 
 
 
 
 
10

City of Phoenix
 
Buckeye, AZ
 
2015
 
 
 
 
 
10

Subtotal AZ Sun Program
 
 
 
 
 
 

 
150

 
20

Multiple Facilities
 
AZ
 
Various
 
 

 
4

 
 

Distributed Energy:
 
 
 
 
 
 

 
 

 
 

APS Owned (a)
 
AZ
 
Various
 
 

 
15

 
9

Total APS Owned
 
 
 
 
 
 

 
169

 
29

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
 
 

 
363

 
30

Agreement 1
 
Bagdad, AZ
 
2011
 
25

 
15

 
 

Agreement 2
 
AZ
 
2011-2012
 
20-21

 
18

 
 

Total Distributed Energy
 
 
 
 
 
 

 
396

 
30

Total Renewable Portfolio
 
 
 
 
 
 

 
1,194

 
59



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(a)
Includes Flagstaff Community Power Project, APS School and Government Program and APS Solar Partner Program.
(b)
Distributed generation is produced in DC and is converted to AC for reporting purposes.

Demand Side Management
 In December 2009, Arizona regulators placed an increased focus on energy efficiency and other demand side management programs to encourage customers to conserve energy, while incentivizing utilities to aid in these efforts that ultimately reduce the demand for energy.  The ACC initiated its Energy Efficiency rulemaking, with a proposed Energy Efficiency Standard (“EES”) of 22% cumulative annual energy savings by 2020.  This standard was adopted and became effective on January 1, 2011.  This standard will likely impact Arizona’s future energy resource needs.  (See Note 3 for energy efficiency and other demand side management obligations.)
 
Government Awards
 
Through various DOE initiatives, the Federal government made a number of programs available for utilities to develop renewable resources, improve reliability and create jobs.  APS continues its work on a $3 million financial award for a high penetration photovoltaic generation study related to the Community Power Project in Flagstaff, Arizona.  This award will conclude during 2015 and is contingent upon APS meeting certain project milestones, including DOE-established budget parameters.
 
Competitive Environment and Regulatory Oversight
 
Retail
 
The ACC regulates APS’s retail electric rates and its issuance of securities.  The ACC must also approve any significant transfer or encumbrance of APS’s property used to provide retail electric service and approve or receive prior notification of certain transactions between Pinnacle West, APS and their respective affiliates.
 
APS is subject to varying degrees of competition from other investor-owned electric and gas utilities in Arizona (such as Southwest Gas Corporation), as well as cooperatives, municipalities, electrical districts and similar types of governmental or non-profit organizations.  In addition, some customers, particularly industrial and large commercial customers, may own and operate generation facilities to meet some or all of their own energy requirements.  This practice is becoming more popular with customers installing or having installed products such as rooftop solar panels to meet or supplement their energy needs.
 
On April 14, 2010, the ACC issued a decision holding that solar vendors that install and operate solar facilities for non-profit schools and governments pursuant to a specific type of contract that calculates payments based on the energy produced are not “public service corporations” under the Arizona Constitution, and are therefore not regulated by the ACC.  A second matter is pending with the ACC to determine whether that ruling should extend to solar providers who serve a broader customer base under the same business model.  Use of such products by customers within our territory results in an increasing level of competition.  APS cannot predict when, and the extent to which, additional electric service providers will enter or re-enter APS’s service territory.
 
In 1999, the ACC approved rules for the introduction of retail electric competition in Arizona.  As a result, as of January 1, 2001, all of APS’s retail customers were eligible to choose alternate energy suppliers. 

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Although some very limited retail competition existed in APS’s service territory in 1999 and 2000, there are currently no active retail competitors offering unbundled energy or other utility services to APS’s customers.  In 2000, the Arizona Superior Court found that the rules were in part unconstitutional and in other respects unlawful, the latter finding being primarily on procedural grounds, and invalidated all ACC orders authorizing competitive electric services providers to operate in Arizona.  In 2004, the Arizona Court of Appeals invalidated some, but not all of the rules and upheld the invalidation of the orders authorizing competitive electric service providers.  In 2005, the Arizona Supreme Court declined to review the Court of Appeals’ decision.
 
In 2008, the ACC directed the ACC staff to investigate whether such retail competition was in the public interest and what legal impediments remain to competition in light of the Court of Appeals’ decision referenced above.  The ACC staff’s report on the results of its investigation was issued on August 12, 2010.  The report stated that additional analysis, discussion and study of all aspects of the issue are required in order to perform a proper evaluation.  While the report did not make any specific recommendations other than to conduct more workshops, the report did state that the current retail electric competition rules are incomplete and in need of modification.
 
On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.  The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state.  One of these considerations 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 advances and innovative changes within the electric utility industry.  A series of workshops in this docket were held in 2014 and another is currently scheduled for February 26, 2015.
 
Wholesale
 
FERC regulates rates for wholesale power sales and transmission services.  (See Note 3 for information regarding APS’s transmission rates.)  During 2014, approximately 7.3% of APS’s electric operating revenues resulted from such sales and services.  APS’s wholesale activity primarily consists of managing fuel and purchased power supplies to serve retail customer energy requirements.  APS also sells, in the wholesale market, its generation output that is not needed for APS’s Native Load and, in doing so, competes with other utilities, power marketers and independent power producers.  Additionally, subject to specified parameters, APS hedges both electricity and fuels.  The majority of these activities are undertaken to mitigate risk in APS’s portfolio.

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Environmental Matters
 
Climate Change
 
Legislative Initiatives. There have been no recent attempts by Congress to pass legislation that would regulate greenhouse gas (“GHG”) emissions, and it is unclear if and when the 114th Congress will consider a climate change bill. In the event climate change legislation ultimately passes, the actual economic and operational impact of such legislation on APS depends on a variety of factors, none of which can be fully known until a law is enacted and the specifics of the resulting program are established. These factors include the terms of the legislation with regard to allowed GHG emissions; the cost to reduce emissions; in the event a cap-and-trade program is established, whether any permitted emissions allowances will be allocated to source operators free of cost or auctioned (and, if so, the cost of those allowances in the marketplace) and whether offsets and other measures to moderate the costs of compliance will be available; and, in the event of a carbon tax, the amount of the tax per pound of carbon dioxide (“CO2”) equivalent emitted.

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

Regulatory Initiatives. In 2009, EPA determined that GHG emissions endanger public health and welfare. This determination was made in response to a 2007 United States Supreme Court ruling that GHGs fit within the Clean Air Act’s broad definition of “air pollutant” and, as a result, EPA has the authority to regulate GHG emissions of new motor vehicles under the Clean Air Act. As a result of this “endangerment finding,” EPA determined that the Clean Air Act required new regulatory requirements for new and modified major GHG emitting sources, including power plants. EPA issued a rule under the Clean Air Act, known as the “tailoring rule,” establishing new GHG emission thresholds that determine when sources, including power plants, must obtain air operating permits or New Source Review permits. “New Source Review,” or “NSR,” is a pre-construction permitting program under the Clean Air Act that requires analysis of pollution controls prior to building a new stationary source or making major modifications to an existing stationary source. The tailoring rule became applicable to power plants in January 2011 and, as a result, APS will generally be required to consider the impact of GHG emissions as part of its traditional NSR analysis for new sources and major modifications to existing plants.

Consistent with President Obama’s June 2013 Climate Action Plan addressing his plans to reduce GHG emissions in the United States, pursuant to its endangerment finding and its authority under Section 111(b) of the Clean Air Act, on September 20, 2013, EPA issued a proposed rule, which would establish New Source Performance Standards (“NSPS”) for new fossil-fired power plants. Subsequently, on June 2, 2014, EPA issued two additional 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 January 7, 2015, EPA announced that its carbon pollution standards for new, modified and reconstructed, and existing power plants would be finalized in summer 2015.

EPA’s proposed rule applicable to modified and reconstructed power plants would require fossil fuel-fired EGUs undergoing modification or reconstruction to meet CO2 performance standards based on a

17


combination of best operating practices and equipment upgrades. The rule would also require existing EGUs that are modified or reconstructed after becoming subject to state or federal standards of performance for existing power plants under Section 111(d) of the Clean Air Act to continue to meet those requirements. We cannot currently predict the shape of any final rules or standards for modified and reconstructed fossil-fired EGUs or assess how they might potentially impact the Company.

With respect to existing power plants, EPA’s proposed “Clean Power Plan” rule proposes state-specific goals or targets to achieve reductions in CO2 emissions from existing EGUs measured from a 2012 baseline. EPA’s proposed emission rates would not apply directly to specific units, but must be met on a state-wide basis. As proposed, each state’s goal is an emissions rate, which is a single number for the future carbon intensity of that state. The proposed rule provides guidelines to states to help develop their plans for meeting the interim (2020-2029) and final (2030 and beyond) emission rates set forth in the proposal. States would be required to submit their plans to EPA by summer 2016, although states may be eligible for one- or two-year extensions, provided they submit detailed explanations that contain specified information required by EPA in advance of the applicable due date. EPA’s proposal for Arizona would result in in-state coal-fired generation (with the exception of coal-fired generation located in Indian country) shifting to natural gas combined cycle 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. APS will continue to monitor these standards as they are developed.

As for sources in Indian country (which are not subject to state plans), on October 28, 2014, EPA issued a supplemental rule proposing carbon dioxide emission rates for U.S. territories and areas of Indian country with existing fossil fuel-fired EGUs, as well as guidelines for plans to achieve those rates. The supplemental proposal applies to Four Corners and the Navajo Plant, both of which are located on the Navajo Nation. With respect to these two plants, EPA applied the four building blocks described in its June 2, 2014 Clean Air Act Section 111(d) proposal to establish interim and final goals, expressed as CO2 emission rates. If finalized as proposed, it is unlikely the rule would require additional emission reductions as a result of the plants’ past and future actions to comply with the Best Available Retrofit Technology (“BART”) requirements of EPA’s Clean Air Visibility Rule. (See “EPA Environmental Regulation - Regional Haze Rules” discussion below.)

Company Response to Climate Change Initiatives. We have undertaken a number of initiatives to address emission concerns, including renewable energy procurement and development, promotion of programs and rates that promote energy conservation, renewable energy use, and energy efficiency. (See “Energy Sources and Resource Planning - Current and Future Resources” above for details of these plans and initiatives.) APS currently has a diverse portfolio of renewable resources, including solar, wind, geothermal, biogas, and biomass, and we expect the percentage of renewable energy in our resource portfolio to increase over the coming years.
APS prepares an inventory of GHG emissions from its operations. This inventory is reported to EPA under the EPA GHG Reporting Program and is voluntarily communicated to the public in Pinnacle West’s annual Corporate Responsibility Report, which is available on our website (www.pinnaclewest.com). The report provides information related to the Company and its approach to sustainability and its workplace and environmental performance. The information on Pinnacle West’s website, including the Corporate Responsibility Report, is not incorporated by reference into this report.
  
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,

18


including fossil-fired power plants. EPA subsequently issued the Clean Air Visibility Rule, which provides guidelines on how to perform a BART analysis.
The Four Corners and Navajo Plant participants’ obligations to comply with EPA’s final BART determinations (and Cholla’s obligations to comply with ADEQ’s and EPA’s determinations), coupled with the financial impact of potential future climate change legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of these plants or the ability of individual participants to continue their participation in these plants.
Cholla. In 2007, ADEQ required APS to perform a BART analysis for Cholla pursuant to the Clean Air Visibility Rule. APS completed the BART analysis for Cholla and submitted its BART recommendations to ADEQ in early 2008. The recommendations include the installation of certain pollution control equipment that APS believes constitutes BART. ADEQ reviewed APS’s recommendations and submitted its proposed BART State Implementation Plan (“SIP”) for Cholla and other sources in Arizona in early 2011.

On December 5, 2012, EPA issued a final BART rule applicable to Cholla. EPA approved ADEQ’s BART emissions limits for sulfur dioxide (“SO2”) and emissions of particulate matter (“PM”), but added a SO2 removal efficiency requirement of 95%. In addition, EPA disapproved ADEQ’s BART determinations for oxides of nitrogen (“NOx”) and promulgated a Federal Implementation Plan ("FIP") establishing a new, more stringent “bubbled” NOx emission rate applicable to the two BART-eligible Cholla units owned by APS and the other BART-eligible unit owned by PacifiCorp. In order to comply with this new rate, APS will be required to install SCR control technology on all three of the BART-eligible Cholla units. APS’s total costs for these post-combustion NOx controls would be approximately $200 million. This amount is not included in our current estimates for environmental capital expenditures in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Expenditures” in Item 7. Under the FIP, APS has five years from December 2012 to complete installation of the equipment and achieve the BART emission limit for NOx.

APS believes that EPA’s final rule as it applies to Cholla is unsupported and that EPA had no basis for disapproving Arizona’s SIP and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program. Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit. Briefing in the case was completed in February 2014, and the court scheduled oral argument for March 9, 2015.

In September 2014, APS met with EPA to propose a compromise BART strategy wherein, pending certain regulatory approvals, APS would permanently close Cholla Unit 2 by April 2016 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 to reduce regional haze is unlikely to be required in the future because retiring and converting the units as contemplated in the proposal is more cost-effective than, and will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA’s BART FIP. Because APS’s proposal involves state and federal rule-making processes, APS is unable to predict when or whether it may ultimately be approved.
Four Corners. On August 6, 2012, EPA issued its final BART determination for Four Corners, which requires APS to install and operate SCR control technology on Units 4 and 5 by July 31, 2018. (APS retired Four Corners Units 1-3 on December 30, 2013.) APS estimates that its 63% share of the cost of these controls for Four Corners Units 4 and 5 would be at least $350 million. APS expects to incur certain of these costs during the 2015 through 2017 timeframe, which are included in our capital expenditure estimates. (See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Expenditures” in Item 7 for such estimates and for a discussion of the capital expenditures related to the

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agreement to purchase El Paso's 7% interest in Units 4 and 5.) For PM emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lb/MMBtu and a 20 percent opacity limit, both of which are achievable through operation of Four Corners' existing baghouses. Although unrelated to BART, the final BART rule also imposes a 20 percent opacity limitation on certain fugitive dust emissions from Four Corners’ coal and material handling operations.
Navajo Plant. On January 18, 2013, EPA issued a proposed BART rule for the Navajo Plant, which would require installation of SCR technology in order to achieve a new, more stringent plant-wide NOx emission limit. In addition, EPA proposed a “better than BART” alternative and solicited comment on other options that could set longer time frames for installing pollution controls if the Navajo Plant can achieve additional emission reductions. On July 26, 2013, a group of stakeholders, including SRP, the operating agent for the Navajo Plant, submitted to EPA two suggested alternatives to BART, which would achieve greater NOx emission reductions and result in greater reasonable progress toward the national visibility goal than EPA’s proposed BART determination. On July 28, 2014, EPA issued a final Navajo Plant BART rule approving the alternative stakeholder plan. Depending on which alternate operating scenario the Navajo Plant participants ultimately select, the required NOx emission reductions could be achieved by either closing one of the three 750 MW units at the plant or curtailing energy production across all three units, such that the emission reductions are commensurate with the closure of approximately one of the Navajo Plant units. APS estimates that its share of costs for upgrades at the Navajo Plant could be up to approximately $200 million. These costs are not included in the capital expenditure estimates described in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Expenditures" in Item 7 since the majority of such costs are expected to be incurred after 2017. In October 2014, a coalition of environmental groups, an Indian tribe, and others filed petitions for review in the United States Court of Appeals for the Ninth Circuit asking the Court to review EPA’s final BART rule for the Navajo Plant. We cannot predict the outcome of this petition.
Mercury and other Hazardous Air Pollutants. On December 16, 2011, EPA issued the final Mercury and Air Toxics Standards (“MATS”) rule, which established maximum achievable control technology (“MACT”) standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired power plants. Generally, plants will have three years after the effective date of the rule to achieve compliance. In the case of Cholla and Four Corners, APS will have until April 16, 2016, or a total of four years after the MATS rule’s effective date, to comply with the new MACT standards because the respective permitting authorities granted APS’s requests for one-year compliance date extensions. Similarly, SRP will have until April 16, 2016 to comply with MATS at the Navajo Plant, as a result of a one-year extension granted by EPA and the Navajo Nation EPA.

The MATS rule will require APS to install additional pollution control equipment. APS has installed certain of the equipment necessary to meet the anticipated standards. APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $130 million for Cholla, which would be avoided if EPA approves APS’s compromise proposal discussed under “Regional Haze Rules - Cholla” above. These costs are not included in the capital expenditure estimates described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Expenditures” in Item 7. No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules. SRP, the operating agent for the Navajo Plant, is still evaluating compliance options under the rules.

Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of coal combustion residuals (“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

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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.

Because the Subtitle D rule is self-implementing, the CCR standards apply directly to the regulated facility, and facilities are directly responsible for ensuring that their operations comply with the rule’s requirements. 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.

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 $15 million, and its share of incremental costs for Cholla is approximately $85 million.  APS expects to incur certain of these costs during the 2015-2017 timeframe, which are included in the capital expenditure estimates in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Expenditures” in Item 7. The amount for Cholla contemplates the closure of Unit 2 in 2016. (See “EPA Environmental Regulation - Regional Haze Rules - Cholla” discussion above.) The Navajo Plant currently disposes of CCR in a dry landfill storage area. At this time, SRP, the operating agent for the Navajo Plant, is analyzing the operations that would be covered by the rule and any resulting compliance costs.

Effluent Limitation Guidelines. On April 19, 2013, EPA proposed revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil-fired EGUs. EPA’s proposal offers numerous options (four of which are “preferred alternatives”) that target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities, and non-chemical metal cleaning wastes operations. The preferred alternatives differ with respect to the scope of requirements that would be applicable to existing discharges of pollutants found in wastestreams generated at existing power plants. All four alternatives would establish a “zero discharge” effluent limit for all pollutants in fly ash transport water. However, requirements governing bottom ash transport water differ depending on which alternative EPA ultimately chooses and could range from effluent limits based on Best Available Technology Economically Achievable to “zero discharge” effluent limits. Depending on which alternative EPA finalizes, Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques. We cannot currently predict the shape of EPA’s final rule or whether this action will have a material adverse impact on our financial position, results of operations, or cash flows. EPA is currently subject to a consent decree deadline to finalize the revised guidelines by September 30, 2015.

Ozone National Ambient Air Quality Standards. On December 17, 2014, EPA published a proposal to revise the primary ground-level ozone national ambient air quality standards (“NAAQS”) currently set at a level of 75 parts per billion (“ppb”). The rule would set a new, more stringent primary standard (intended to protect human health) within the range of 65 to 70 ppb and revise the secondary standard (intended to protect human welfare) to within the same range. In addition, EPA is soliciting comment on alternative standard levels below 65 ppb, and as low as 60 ppb. EPA is accepting public comment on the proposed new ranges for the standards until March 17, 2015, and is under a court-ordered deadline of October 1, 2015 to finalize the rule. As ozone standards become more stringent, our fossil generation units may come under increasing pressure to reduce emissions of nitrogen oxides and volatile organic compounds and to generate emission offsets for new projects or facility expansions located in ozone nonattainment areas. At this time, APS is unable to predict what impact the adoption of these standards may have on its financial position, results of operations, or cash flows.

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

Clean Air Act Citizen Lawsuit. On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the NSR provisions of the Clean Air Act.  Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s NSPS program.  Among other things, the environmental plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS.  The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project.  On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss.  The case is being held in abeyance while the parties seek to negotiate a settlement.  On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay.  At such time as the stay is lifted, APS and the other Four Corners participants may reinstate their motions to dismiss.  We are unable to predict the outcome of this matter.

Superfund-Related Matters. The Comprehensive Environmental Response Compensation and Liability Act (“Superfund”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.  Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are potentially responsible parties (“PRPs”).  PRPs may be strictly, and often are jointly and severally, liable for clean-up.  On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona.  APS has facilities that are within this Superfund site.  APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study work plan.  We estimate that our costs related to this investigation and study will be approximately $2 million.  We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.
 
On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  We are unable to predict the outcome of this matter; 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.

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Navajo Nation Environmental Issues

Four Corners and the Navajo Plant are located on the Navajo Reservation and are held under easements granted by the federal government, as well as leases from the Navajo Nation. See “Energy Sources and Resource Planning - Generation Facilities - Coal-Fueled Generating Facilities” above for additional information regarding these plants.
In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act, and the Navajo Nation Pesticide Act (collectively, the “Navajo Acts”). The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners and the Navajo Plant. On October 17, 1995, the Four Corners participants and the Navajo Plant participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, challenging the applicability of the Navajo Acts as to Four Corners and the Navajo Plant. The Court has stayed these proceedings pursuant to a request by the parties, and the parties are seeking to negotiate a settlement.
In April 2000, the Navajo Nation Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. APS believes the Navajo Nation exceeded its authority when it adopted the operating permit regulations. On July 12, 2000, the Four Corners participants and the Navajo Plant participants each filed a petition with the Navajo Supreme Court for review of these regulations. Those proceedings have been stayed, pending the settlement negotiations mentioned above. APS cannot currently predict the outcome of this matter.
On May 18, 2005, APS, Salt River Project, as the operating agent for the Navajo Plant, and the Navajo Nation executed a Voluntary Compliance Agreement to resolve their disputes regarding the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the courts granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the Clean Air Act. The agreement does not address or resolve any dispute relating to other Navajo Acts. APS cannot currently predict the outcome of this matter.
Water Supply
Assured supplies of water are important for APS’s generating plants. At the present time, APS has adequate water to meet its needs. However, the Four Corners region, in which Four Corners is located, has been experiencing drought conditions that may affect the water supply for the plants if adequate moisture is not received in the watershed that supplies the area. APS is continuing to work with area stakeholders to implement agreements to minimize the effect, if any, on future operations of the plant. The effect of the drought cannot be fully assessed at this time, and APS cannot predict the ultimate outcome, if any, of the drought or whether the drought will adversely affect the amount of power available, or the price thereof, from Four Corners.
Conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions, which, in addition to future supply conditions, have the potential to impact APS’s operations.

San Juan River Adjudication. Both groundwater and surface water in areas important to APS’s operations have been the subject of inquiries, claims, and legal proceedings, which will require 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 action. As operating agent of Palo Verde, APS filed claims that dispute the court’s jurisdiction over the Palo Verde participants’ groundwater rights and their contractual rights to effluent relating to Palo Verde. Alternatively, APS seeks confirmation of such rights. Several of APS’s other power plants are also located within the geographic area subject to the summons. APS’s claims dispute the court’s jurisdiction over APS’s groundwater rights with respect to these plants. Alternatively, APS seeks confirmation of such rights. In November 1999, the Arizona Supreme Court issued a decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. In addition, in September 2000, the Arizona Supreme Court issued a decision affirming the lower court’s criteria for resolving groundwater claims. Litigation on both of these issues has continued in the trial court. In December 2005, APS and other parties filed a petition with the Arizona Supreme Court requesting interlocutory review of a September 2005 trial court order regarding procedures for determining whether groundwater pumping is affecting surface water rights. The Arizona Supreme Court denied the petition in May 2007, and the trial court is now proceeding with implementation of its 2005 order. No trial date concerning APS’s water rights claims has been set in this matter.

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

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

BUSINESS OF OTHER SUBSIDIARIES

Bright Canyon Energy

On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE.  BCE will focus 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 MidAmerican Transmission, LLC.  The joint venture, named TransCanyon, intends to focus on transmission opportunities within the Western Electricity Coordinating Council, excluding the retail service territories of the venture partners’ utility affiliates.  The joint venture submitted a bid into CAISO's competitive solicitation process to design, build and own a new 500 kV transmission line between Arizona and California, the Delaney to Colorado River Transmission Line.  The winner of the bidding process is expected to be announced in 2015.  This transmission line will connect a

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planned Delaney substation near Palo Verde in Arizona to the existing Colorado River substation located just west of Blythe, California.
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, 2014, El Dorado had total assets of approximately $9 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. 
 
SunCor
 
In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business.  On March 25, 2013, the bankruptcy plan submitted to the court and agreed to by SunCor and its creditors (the “Joint Plan”) became effective.  The Joint Plan provides for the full release of Pinnacle West and its affiliates from any and all claims related to SunCor, SunCor’s subsidiaries, and their respective estates.  SunCor and its subsidiaries have been formally dissolved.
OTHER INFORMATION
 
Pinnacle West, APS and El Dorado are all incorporated in the State of Arizona.  BCE is 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, 2014
Pinnacle West
 
400 North Fifth Street
Phoenix, AZ 85004
 
1985
 
83

APS
 
400 North Fifth Street
P.O. Box 53999
Phoenix, AZ 85072-3999
 
1920
 
6,279

BCE
 
400 North Fifth Street
Phoenix, AZ 85004
 
2014
 
4

El Dorado
 
400 North Fifth Street
Phoenix, AZ 85004
 
1983
 

Total
 
 
 
 
 
6,366

 
The APS number includes employees at jointly-owned generating facilities (approximately 2,830 employees) for which APS serves as the generating facility manager.  Approximately 1,673 APS employees are union employees, represented by the International Brotherhood of Electrical Workers ("IBEW") or the United Security Professionals of America ("USPA").  APS is currently negotiating with IBEW representatives over the collective bargaining agreement that expires on March 31, 2015. The Company concluded negotiations with the USPA over the terms of a new collective bargaining agreement in May of 2014, and the new agreement is in place until May 31, 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

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board and committee charters, Code of Ethics for Financial Executives, Code of Ethics and Business Practices and other corporate governance information is also available on the Pinnacle West website.  Pinnacle West will post any amendments to the Code of Ethics for Financial Executives and Code of Ethics and Business Practices, and any waivers that are required to be disclosed by the rules of either the SEC or the New York Stock Exchange, on its website.  The information on Pinnacle West’s website is not incorporated by reference into this report.
 
You can request a copy of these documents, excluding exhibits, by contacting Pinnacle West at the following address:  Pinnacle West Capital Corporation, Office of the Corporate Secretary, Mail Station 8602, P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-4400).

ITEM 1A.  RISK FACTORS
 
In addition to the factors affecting specific business operations identified in the description of these operations contained elsewhere in this report, set forth below are risks and uncertainties that could affect our financial results.  Unless otherwise indicated or the context otherwise requires, the following risks and uncertainties apply to Pinnacle West and its subsidiaries, including APS.
 
REGULATORY RISKS
 
Our financial condition depends upon APS’s ability to recover costs in a timely manner from customers through regulated rates and otherwise execute its business strategy.
 
APS is subject to comprehensive regulation by several federal, state and local regulatory agencies that significantly influence its business, liquidity, results of operations and its ability to fully recover costs from utility customers in a timely manner.  The ACC regulates APS’s retail electric rates and FERC regulates rates for wholesale power sales and transmission services.  The profitability of APS is affected by the rates it may charge and the timeliness of recovering costs incurred through its rates.  Consequently, our financial condition and results of operations are dependent upon the satisfactory resolution of any APS rate proceedings and ancillary matters which may come before the ACC and FERC.  Arizona, like certain other states, has a statute that allows the ACC to reopen prior decisions and modify 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 or local statutes, regulations and ACC requirements, and obtaining and maintaining certain regulatory permits, approvals and certificates.
 
APS must comply in good faith with all applicable statutes, regulations, rules, tariffs, and orders of agencies that regulate APS’s business, including FERC, NRC, EPA, the ACC, and state and local governmental agencies.  These agencies regulate many aspects of APS’s utility operations, including safety and performance, emissions, siting and construction of facilities, customer service and the rates that APS can charge retail and wholesale customers.  Failure to comply can subject APS to, among other things, fines and penalties.  For example, under the Energy Policy Act of 2005, FERC can impose penalties (up to one million dollars per day per violation) for failure to comply with mandatory electric reliability standards.  APS is also required to have numerous permits, approvals and certificates from these agencies.  APS believes the necessary permits, approvals and certificates have been obtained for its existing operations and that APS’s business is conducted in accordance with applicable laws in all material respects.  However, changes in regulations or the imposition

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of new or revised laws or regulations could have an adverse impact on our results of operations.  We are also unable to predict the impact on our business and operating results from pending or future regulatory activities of any of these agencies.
 
The operation of APS’s nuclear power plant exposes it to substantial regulatory oversight and potentially significant liabilities and capital expenditures.
 
The NRC has broad authority under federal law to impose safety-related, security-related and other licensing requirements for the operation of nuclear generation facilities.  Events at nuclear facilities of other operators or impacting the industry generally may lead the NRC to impose additional requirements and regulations on all nuclear generation facilities, including Palo Verde.  As a result of the March 2011 earthquake and tsunamis that caused significant damage to the Fukushima Daiichi Nuclear Power Plant in Japan, various industry organizations are working to analyze information from the Japan incident and develop action plans for U.S. nuclear power plants.  Additionally, the NRC has been performing its own independent review of the events at Fukushima Daiichi, including a review of the agency’s processes and regulations in order to determine whether the agency should promulgate additional regulations and possibly make more fundamental changes to the NRC’s system of regulation.  We cannot predict when or if the NRC will complete its formal actions as a result of its review.  As a result of the Fukushima event, however, the NRC has directed nuclear power plants to implement the first tier recommendations of the NRC’s Near Term Task Force.  In response to these recommendations, Palo Verde expects to spend approximately $40 million for capital enhancements to the plant over the next two years in addition to the approximate $80 million that has already been spent on capital enhancements as of December 31, 2014 (APS’s share is 29.1%). We cannot predict whether these amounts will increase or whether additional financial and/or operational requirements on Palo Verde and APS may be imposed.
 
In the event of noncompliance with its requirements, the NRC has the authority to impose a progressively increased inspection regime that could ultimately result in the shut-down of a unit or civil penalties, or both, depending upon the NRC’s assessment of the severity of the situation, until compliance is achieved.  The increased costs resulting from penalties, a heightened level of scrutiny and implementation of plans to achieve compliance with NRC requirements may adversely affect APS’s financial condition, results of operations and cash flows.
APS is subject to numerous environmental laws and regulations, and changes in, or liabilities under, existing or new laws or regulations may increase APS’s cost of operations or impact its business plans.
 
APS is, or may become, subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, discharges of wastewater and streams originating from fly ash and bottom ash handling facilities, solid waste, hazardous waste, and coal combustion products, which consist of bottom ash, fly ash, and air pollution control wastes.  These laws and regulations can result in increased capital, operating, and other costs, particularly with regard to enforcement efforts focused on power plant emissions obligations.  These laws and regulations generally require APS to obtain and comply with a wide variety of environmental licenses, permits, and other approvals.  If there is a delay or failure to obtain any required environmental regulatory approval, or if APS fails to obtain, maintain, or comply with any such approval, operations at affected facilities could be suspended or subject to additional expenses.  In addition, failure to comply with applicable environmental laws and regulations could result in civil liability as a result of government enforcement actions or private claims or criminal penalties.  Both public officials and private individuals may seek to enforce applicable environmental laws and regulations.  APS cannot predict the outcome (financial or operational) of any related litigation that may arise.
 
Environmental Clean Up.  APS has been named as a PRP for a Superfund site in Phoenix, Arizona, and it could be named a PRP in the future for other environmental clean-up at sites identified by a regulatory body.

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 APS cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up costs.  There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all PRPs.
 
Regional Haze.  APS has received final rulemakings imposing new requirements on Four Corners, Cholla and the Navajo Plant.  Pursuant to these rules, EPA and ADEQ will require these plants to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plants.  The financial impact of installing and operating the required pollution control equipment could jeopardize the economic viability of these plants or the ability of individual participants to continue their participation in these plants.
 
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 could incur significant additional costs for CCR disposal.

Effluent Limitation Guidelines.  EPA is expected to finalize revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil-fired EGUs in 2015.  EPA has indicated that it expects the revised standards to target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities and scrubber-related operations.  APS currently disposes of fly ash waste and bottom ash in ash ponds at Four Corners.  Changes required by the rule could significantly increase ash disposal costs at Four Corners.
 
Ozone National Ambient Air Quality Standards. In December 2014, EPA proposed revisions to the national ambient air quality standards, which would set new, more stringent standards intended to protect human health and human welfare. Depending on the stringency of the final standards and the 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.

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

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

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

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.
Financial Risks - Potential Greenhouse Gas Regulation. In 2014, EPA proposed a rule to limit carbon dioxide emissions from existing power plants. EPA expects to finalize the proposal in summer 2015. EPA’s proposal for Arizona would 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.
Physical and Operational Risks. Weather extremes such as drought and high temperature variations are common occurrences in the Southwest’s desert area, and these are risks that APS considers in the normal course of business in the engineering and construction of its electric system. Large increases in ambient temperatures could require evaluation of certain materials used within its system and represent a greater challenge.
Deregulation or restructuring of the electric industry may result in increased competition, which could have a significant adverse impact on APS’s business and its results of operations.
 
In 1999, the ACC approved rules for the introduction of retail electric competition in Arizona.  Retail competition could have a significant adverse financial impact on APS due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital.  Although some very limited retail competition existed in APS’s service area in 1999 and 2000, there are currently no active retail competitors offering unbundled energy or other utility services to APS’s customers.  On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.  The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state.  One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution.  On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter.  The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.  One of these options could be a continuation or expansion of APS’s existing AG (Alternative Generation) — 1 program, which essentially allows up to 200 MW of cumulative load to be served via a buy-through arrangement with competitive suppliers of generation.  We cannot predict future regulatory or legislative action that might result in increased competition.
 
In 2010, the ACC issued a decision holding that solar vendors that install and operate solar facilities for non-profit schools and governments pursuant to a specific type of contract that calculates payments based on the energy produced are not “public service corporations” under the Arizona Constitution, and are therefore not regulated by the ACC.  A second matter is pending with the ACC to determine whether that ruling should extend to solar providers who serve a broader customer base under the same business model.  The use of such products by customers within our territory results in some level of competition.  APS cannot predict whether the ACC will deem these vendors “public service corporations” subject to ACC regulation and when, and the extent to which, additional service providers will enter APS’s service territory, increasing the level of competition in the market.
 

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OPERATIONAL RISKS
 
APS’s results of operations can be adversely affected by various factors impacting demand for electricity.
 
Weather Conditions.  Weather conditions directly influence the demand for electricity and affect the price of energy commodities.  Electric power demand is generally a seasonal business.  In Arizona, demand for power peaks during the hot summer months, with market prices also peaking at that time.  As a result, APS’s overall operating results fluctuate substantially on a seasonal basis.  In addition, APS has historically sold less power, and consequently earned less income, when weather conditions are milder.  As a result, unusually mild weather could diminish APS’s financial condition, results of operations and cash flows.
 
Higher temperatures may decrease the snowpack, which might result in lowered soil moisture and an increased threat of forest fires.  Forest fires could threaten APS’s communities and electric transmission lines and facilities.  Any damage caused as a result of forest fires could negatively impact APS’s financial condition, results of operations or cash flows.
 
Effects of Energy Conservation Measures and Distributed Energy.  The ACC has enacted rules regarding energy efficiency that mandate a 22% annual energy savings requirement by 2020.  This will likely increase participation by APS customers in energy efficiency and conservation programs and other demand-side management efforts, which in turn will impact the demand for electricity.  The rules also include a requirement for the ACC to review and address financial disincentives, recovery of fixed costs and the recovery of net lost income/revenue that would result from lower sales due to increased energy efficiency requirements.  To that end, the settlement agreement in APS’s most recent retail rate case (the “2012 Settlement Agreement”) includes a mechanism, the LFCR, to address these matters.
 
APS must also meet certain distributed energy requirements.  A portion of APS’s total renewable energy requirement must be met with an increasing percentage of distributed energy resources (generally, small scale renewable technologies located on customers’ properties).  The distributed energy requirement was 25% of the overall RES requirement of 3% in 2011 and increased to 30% of the applicable RES requirement for 2012 and subsequent years.  Customer participation in distributed energy programs would result in lower demand, since customers would be meeting some or all of their own energy needs.  Reduced demand due to these energy efficiency and distributed energy requirements, unless substantially offset through ratemaking mechanisms, could have a material adverse impact on APS’s financial condition, results of operations and cash flows.
 
Customer and Sales Growth.  For the three years 2012 through 2014, APS’s retail customer growth averaged 1.3% per year.  We currently expect annual customer growth to average in the range of 2.0-3.0% for 2015 through 2017 based on our assessment of modestly improving economic conditions in Arizona.  For the three years 2012 through 2014, APS experienced annual decreases in retail electricity sales averaging 0.2%, adjusted to exclude the effects of weather variations.  We currently estimate that annual retail electricity sales in kWh will increase on average in the range of 0.5-1.5% during 2015 through 2017, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations.  Actual customer and sales growth may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and energy conservation, impacts of energy efficiency programs and growth in distributed 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 it declines, or if the Arizona economy fails to improve, we may be unable to reach our estimated demand level and sales projections, which could have a negative impact on our financial condition, results of operations and cash flows.

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The operation of power generation facilities and transmission systems involves risks that could result in reduced output or unscheduled outages, which could materially affect APS’s results of operations.
 
The operation of power generation, transmission and distribution facilities involves certain risks, including the risk of breakdown or failure of equipment, fuel interruption, and performance below expected levels of output or efficiency.  Unscheduled outages, including extensions of scheduled outages due to mechanical failures or other complications, occur from time to time and are an inherent risk of APS’s business.  Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the larger transmission power grid, and the operation or failure of our facilities could adversely affect the operations of others.  If APS’s facilities operate below expectations, especially during its peak seasons, it may lose revenue or incur additional expenses, including increased purchased power expenses.  Concerns over physical security of these assets is also increasing, which may require us to incur additional capital and operating costs to address. Damage to certain of our facilities due to vandalism or other deliberate acts could lead to outages or other adverse effects.
 
The inability to successfully develop or acquire generation resources to meet reliability requirements, new or evolving standards or regulations could adversely impact our business.
 
Potential changes in regulatory standards, impacts of new and existing laws and regulations, including environmental laws and regulations, and the need to obtain certain regulatory approvals create uncertainty surrounding our generation portfolio.  The current abundance of low, stably priced natural gas, together with environmental and other concerns surrounding coal-fired generation resources, create strategic questions related to the appropriate generation portfolio and fuel diversification mix.  In addition, APS is required by the ACC to meet certain energy resource portfolio requirements such as the EES and the RES.  The development of any generation facility is subject to many risks, including risks related to financing, siting, permitting, technology, the construction of sufficient transmission capacity to support these facilities and stresses to generation and transmission resources from intermittent generation characteristics of renewable resources.  APS’s inability to adequately develop or acquire the necessary generation resources could have a material adverse impact on our business and results of operations.
 
The lack of access to sufficient supplies of water could have a material adverse impact on APS’s business and results of operations.
 
Assured supplies of water are important for APS’s generating plants.  Water in the southwestern United States is limited, and various parties have made conflicting claims regarding the right to access and use such limited supply of water.  Both groundwater and surface water in areas important to APS’s generating plants have been and are the subject of inquiries, claims and legal proceedings.  In addition, the region in which APS’s power plants are located is prone to drought conditions, which could potentially affect the plants’ water supplies.  APS’s inability to access sufficient supplies of water could have a material adverse impact on our business and results of operations.

The ownership and operation of power generation and transmission facilities on Indian lands could result in uncertainty related to continued leases, easements and rights-of-way, which could have a significant impact on our business.
 
Certain APS power plants, including Four Corners, and portions of the transmission lines that carry power from these plants are located on Indian lands pursuant to leases, easements or other rights-of-way that are effective for specified periods.  APS is unable to predict the final outcome of pending and future approvals by applicable governing bodies with respect to renewals of these leases, easements and rights-of-way.
 

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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 $16.5 million per year) of liabilities arising out of a nuclear incident occurring not only at Palo Verde, but at any other nuclear power plant in the United States. Although we have no reason to anticipate a serious nuclear incident at Palo Verde, if an incident did occur, it could materially and adversely affect our results of operations and financial condition.  A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit and to promulgate new regulations that could require significant capital expenditures and/or increase operating costs.
 
The use of derivative contracts in the normal course of our business could result in financial losses that negatively impact our results of operations.
 
APS’s operations include managing market risks related to commodity prices.  APS is exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas and coal to the extent that unhedged positions exist.  We have established procedures to manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange traded futures and options and over-the-counter forwards, options, and swaps.  As part of our overall risk management program, we enter into derivative transactions to hedge purchases and sales of electricity and fuels.  The changes in market value of such contracts have a high correlation to price changes in the hedged commodity.  To the extent that commodity markets are illiquid, we may not be able to execute our risk management strategies, which could result in greater unhedged positions than we would prefer at a given time and financial losses that negatively impact our results of operations.
 
The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) contains measures aimed at increasing the transparency and stability of the over-the counter, or OTC, derivative markets and preventing excessive speculation. The Dodd-Frank Act could restrict, among other things, trading positions in the energy futures markets, require different collateral or settlement positions, or increase regulatory reporting over derivative positions. Based on the provisions included in the Dodd-Frank Act and the implementation of regulations, these changes could, among other things, impact our ability to hedge commodity price and interest rate risk or increase the costs associated with our hedging programs.
 
We are exposed to losses in the event of nonperformance or nonpayment by counterparties.  We use a risk management process to assess and monitor the financial exposure of all counterparties.  Despite the fact that the majority of APS’s trading counterparties are rated as investment grade by the rating agencies, there is still a possibility that one or more of these companies could default, which could result in a material adverse impact on our earnings for a given period.
 

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Changes in technology could create challenges for APS’s existing business.
 
Research and development activities are ongoing to develop and commercialize alternative technologies that produce power or reduce power consumption or emissions, including renewable technologies including photovoltaic (solar) cells, customer-sited generation, energy storage (batteries), and efficiency technologies.  Advances in these, or other technologies could reduce the cost of power production, making APS’s existing generating facilities less economical.  In addition, advances in technology and equipment/appliance efficiency could reduce the demand for power supply, which could adversely affect APS’s business.
 
APS has, and continues to pursue and implement, smart grid technologies, including advanced transmission and distribution system technologies, as well as digital meters enabling two-way communications between the utility and its customers.  Many of the products and processes resulting from these and other alternative technologies have not yet been widely used or tested on a long-term basis, and their use on large-scale systems is not as established or mature as APS’s existing technologies and equipment.  Widespread installation and acceptance of these technologies could enable the entry of new market participants, such as technology companies, into the interface between APS and its customers and could have other unpredictable effects on APS’s business.
 
We are subject to employee workforce factors that could adversely affect our business and financial condition.
 
Like most companies in the electric utility industry, our workforce is maturing, with approximately 37% of employees eligible to retire by the end of 2017.  Although we have undertaken efforts to recruit and train new employees, we face increased competition for talent.  We are subject to other employee workforce factors, such as the availability of qualified personnel, the need to negotiate collective bargaining agreements with union employees and potential work stoppages.  These or other employee workforce factors could negatively impact our business, financial condition or results of operations.
 
We are subject to information security risks and risks of unauthorized access to our systems.
 
In the regular course of our business, we handle a range of sensitive security, customer and business systems information. A security breach of our information systems such as theft or the inappropriate release of certain types of information, including confidential customer, employee, financial or system operating information, could have a material adverse impact on our financial condition, results of operations or cash flows. We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure.  Despite implementation of security measures, our technology systems are vulnerable to disability, failures or unauthorized access.  Our generation, transmission and distribution facilities, information technology systems and other infrastructure facilities and systems and physical assets could be targets of such unauthorized access.  Failures or breaches of our systems could impact the reliability of our generation, transmission and distribution systems and also subject us to financial harm.  If our technology systems were to fail or be breached and if we are unable to recover in a timely way, we may not be able to fulfill critical business functions and sensitive confidential data could be compromised, which could have a material adverse impact on our financial condition, results of operations or cash flows.

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 our operating systems, and is continually in the process of developing updated and additional requirements with which the utility industry must comply. The increasing promulgation of NERC rules and standards will increase our compliance costs and our exposure to the potential risk of violations of the standards.

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While we have experienced, and expect to continue to experience, these types of threats and attempted intrusions, none of them to date has been material to the Company. The implementation of additional security measures could increase costs and have a material adverse impact on our financial results. 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 may not cover the total loss or damage caused by a breach. These types of events could also require significant management attention and resources, and could adversely affect Pinnacle West’s and APS’s reputation with customers and the public. 
 
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

34


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.
 
Investment performance, changing interest rates and other economic factors could decrease the value of our benefit plan assets and nuclear decommissioning trust funds and increase the valuation of our related obligations, resulting in significant additional funding requirements.  We are subject to risks related to the provision of employee healthcare benefits and recent healthcare reform legislation.  Any inability to fully recover these costs in our utility rates would negatively impact our financial condition.
 
We have significant pension plan and other postretirement benefits plan obligations to our employees and retirees, and legal obligations to fund nuclear decommissioning trusts for Palo Verde.  We hold and invest substantial assets in these trusts that are designed to provide funds to pay for certain of these obligations as they arise.  Declines in market values of the fixed income and equity securities held in these trusts may increase our funding requirements into the related trusts.  Additionally, the valuation of liabilities related to our pension plan and other postretirement benefit plans are impacted by a discount rate, which is the interest rate used to discount future pension and other postretirement benefit obligations.  Declining interest rates decrease the discount rate, increase the valuation of the plan liabilities and may result in increases in pension and other postretirement benefit costs, cash contributions, regulatory assets, and charges to OCI.  Changes in demographics, including increased 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.  Increasing liabilities or otherwise increasing funding requirements under these plans, resulting from adverse changes in legislation or otherwise, could result in significant cash funding obligations that could have a material impact on our financial position, results of operations or cash flows.
 
We recover most of the pension costs and other postretirement benefit costs and all of the nuclear decommissioning costs in our regulated rates.  Any inability to fully recover these costs in a timely manner would have a material negative impact on our financial condition, results of operations or cash flows.
 
Employee healthcare costs in recent years have continued to rise.  The Patient Protection and Affordable Care Act is expected to result in additional healthcare cost increases.  Costs and other effects of the legislation, which may include the cost of compliance and potentially increased costs of providing for medical insurance for our employees, cannot be determined with certainty at this time. 
 
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.

35


 
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

36


the ability of our Board of Directors to issue additional shares of common stock and shares of preferred stock and to determine the price and, with respect to preferred stock, the other terms, including preferences and voting rights, of those shares without shareholder approval.
 
While these provisions have the effect of encouraging persons seeking to acquire control of us to negotiate with our Board of Directors, they could enable the Board of Directors to hinder or frustrate a transaction that some, or a majority, of our shareholders might believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors.

ITEM 1B.  UNRESOLVED STAFF COMMENTS
 
Neither Pinnacle West nor APS has received written comments regarding its periodic or current reports from the SEC staff that were issued 180 days or more preceding the end of its 2014 fiscal year and that remain unresolved.


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ITEM 2.  PROPERTIES
 
Generation Facilities
 
APS’s portfolio of owned and leased generating facilities is provided in the table below:
Name
 
No. of
Units
 
%
Owned (a)
 
Principal
Fuels
Used
 
Primary
Dispatch
Type
 
Owned
Capacity
(MW)
Nuclear:
 
 
 
 

 
 
 
 
 
 

Palo Verde (b)
 
3
 
29.1
%
 
Uranium
 
Base Load
 
1,146

Total Nuclear
 
 
 
 

 
 
 
 
 
1,146

Steam:
 
 
 
 

 
 
 
 
 
 

Four Corners 4, 5 (c)
 
2
 
63
%
 
Coal
 
Base Load
 
970

Cholla
 
3
 
 

 
Coal
 
Base Load
 
647

Navajo (d)
 
3
 
14
%
 
Coal
 
Base Load
 
315

Ocotillo
 
2
 
 

 
Gas
 
Peaking
 
220

Total Steam
 
 
 
 

 
 
 
 
 
2,152

Combined Cycle:
 
 
 
 

 
 
 
 
 
 

Redhawk
 
2
 
 

 
Gas
 
Load Following
 
984

West Phoenix
 
5
 
 

 
Gas
 
Load Following
 
887

Total Combined Cycle
 
 
 
 

 
 
 
 
 
1,871

Combustion Turbine:
 
 
 
 

 
 
 
 
 
 

Ocotillo
 
2
 
 

 
Gas
 
Peaking
 
110

Saguaro 1, 2
 
2
 
 

 
Gas/Oil
 
Peaking
 
110

Saguaro 3
 
1
 
 

 
Gas
 
Peaking
 
79

Douglas
 
1
 
 

 
Oil
 
Peaking
 
16

Sundance
 
10
 
 

 
Gas
 
Peaking
 
420

West Phoenix
 
2
 
 

 
Gas
 
Peaking
 
110

Yucca 1, 2, 3
 
3
 
 

 
Gas/Oil
 
Peaking
 
93

Yucca 4
 
1
 
 

 
Oil
 
Peaking
 
54

Yucca 5, 6
 
2
 
 

 
Gas
 
Peaking
 
96

Total Combustion Turbine
 
 
 
 

 
 
 
 
 
1,088

Solar:
 
 
 
 

 
 
 
 
 
 

Cotton Center
 
1
 
 

 
Solar
 
As Available
 
17

Hyder
 
1
 
 

 
Solar
 
As Available
 
16

Paloma
 
1
 
 

 
Solar
 
As Available
 
17

Chino Valley
 
1
 
 

 
Solar
 
As Available
 
19

Gila Bend
 
1
 
 
 
Solar
 
As Available
 
32

Hyder II
 
1
 
 

 
Solar
 
As Available
 
14

Foothills
 
1
 
 

 
Solar
 
As Available
 
35

APS Owned Distributed Energy
 
 
 
 

 
Solar
 
As Available
 
15

Multiple facilities
 
 
 
 

 
Solar
 
As Available
 
4

Total Solar
 
 
 
 

 
 
 
 
 
169

Total Capacity
 
 
 
 

 
 
 
 
 
6,426



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(a)
100% unless otherwise noted.
(b)
See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Generation Facilities — Nuclear” in Item 1 for details regarding leased interests in Palo Verde.  The other participants are Salt River Project (17.49%), SCE (15.8%), El Paso (15.8%), Public Service Company of New Mexico (10.2%), Southern California Public Power Authority (5.91%), and Los Angeles Department of Water & Power (5.7%).  The plant is operated by APS.
(c)
The other participants are Salt River Project (10%), Public Service Company of New Mexico (13%), Tucson Electric Power Company (7%) and El Paso (7%).  The plant is operated by APS.  As discussed under “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Generation Facilities — Coal-Fueled Generating Facilities — Four Corners” in Item 1, in December 2013 APS acquired SCE’s 48% interest in Units 4 and 5, and closed Units 1, 2 and 3.
(d)
The other participants are Salt River Project (21.7%), Nevada Power Company (11.3%), the United States Government (24.3%), Tucson Electric Power Company (7.5%) and Los Angeles Department of Water & Power (21.2%).  The plant is operated by Salt River Project.
See “Business of Arizona Public Service Company — Environmental Matters” in Item 1 with respect to matters having a possible impact on the operation of certain of APS’s generating facilities.
 
See “Business of Arizona Public Service Company” in Item 1 for a map detailing the location of APS’s major power plants and principal transmission lines.
 
Transmission and Distribution Facilities
 
Current Facilities.  APS’s transmission facilities consist of approximately 5,909 pole miles of overhead lines and approximately 49 miles of underground lines, 5,686 miles of which are located in Arizona.  APS’s distribution facilities consist of approximately 11,071 miles of overhead lines and approximately 17,908 miles of underground primary cable, all of which are located in Arizona. APS distribution facilities reflect an actual net gain of 167 miles in 2014.  APS shares ownership of some of its transmission facilities with other companies.  The following table shows APS’s jointly-owned interests in those transmission facilities recorded on the Consolidated Balance Sheets at December 31, 2014:
 
 
Percent Owned
(Weighted-Average)
Morgan — Pinnacle Peak System
64.4
%
Palo Verde — Estrella 500kV System
50.0
%
Round Valley System
50.0
%
ANPP 500kV System
33.6
%
Navajo Southern System
22.6
%
Four Corners Switchyards
47.5
%
Palo Verde — Yuma 500kV System
18.2
%
Phoenix — Mead System
17.1
%
Palo Verde — Morgan System
90.0
%
Hassayampa — North Gila System
80.0
%
 
Expansion.  Each year APS prepares and files with the ACC a ten-year transmission plan.  In APS’s 2015 plan, APS projects it will develop 275 miles of new lines over the next ten years.  One significant project currently under development is a new 500kV path that will span from the Palo Verde hub around the western and northern edges of the Phoenix metropolitan area and terminate at a bulk substation in the northeast part of Phoenix.  The project consists of four phases.  The first phase, Morgan to Pinnacle Peak 500kV, is currently in-service. The second and third phases, Delaney to Palo Verde 500kV and Delaney to Sun Valley 500kV, are

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under construction.  The fourth phase, Morgan to Sun Valley 500kV, has been permitted and is in final design and development.  In total, the projects consist of over 100 miles of new 500kV lines, with many of those miles constructed with the capability to string a 230kV line as a second circuit.

APS continues to work with regulators to identify transmission projects necessary to support renewable energy facilities.  Two such projects, which are included in APS’s 2015 transmission plan, are the Delaney to Palo Verde line and the North Gila to Hassayampa line, both of which are intended to support the transmission of renewable energy to Phoenix and California. The North Gila to Hassayampa line is under construction and expected to be in service before the summer of 2015.

Physical Security Standards. On March 7, 2014, FERC issued an order requiring NERC to act within 90 days to develop standards that will require utilities to take steps, or to demonstrate that they have taken steps, to address physical security risks and vulnerabilities related to the reliable operation of the bulk-power system.  On May 23, 2014, NERC filed a petition with FERC for approval of the proposed Physical Security Reliability Standard CIP-014-1.  On November 20, 2014, FERC approved the Physical Security Reliability Standard CIP-014-1, and on January 21, 2015, FERC issued an order granting rehearing for further consideration. The Physical Security Reliability Standard 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 will determine whether it has any critical transmission stations and substations and associated primary control centers that will be required to comply with the standard. Until APS has made such determination, we cannot predict the extent of any financial or operational impacts on APS.
 
Plant and Transmission Line Leases and Rights-of-Way on Indian Lands
 
The Navajo Plant and Four Corners are located on land held under leases from the Navajo Nation and also under rights-of-way from the federal government.  The right-of-way and lease for the Navajo Plant expire in 2019 and the right-of-way and lease for Four Corners expire in 2016.  On March 7, 2011, the Navajo Nation Council signed a resolution approving a 25-year extension to the existing Four Corners lease term and providing Navajo Nation consent to renewal of the related rights-of-way.   APS is filing applications for renewal of these rights-of-way with the DOI.  Before it may approve the Four Corners lease extension and issue the renewed rights-of-way, the United States must complete an analysis under the federal National Environmental Policy Act, the ESA and related statutes.
 
Certain portions of the transmission lines that carry power from several of our power plants are located on Indian lands pursuant to rights-of-way that are effective for specified periods.  Some of these rights-of-way have expired and our renewal applications have not yet been acted upon by the appropriate Indian tribes or federal agencies.  Other rights expire at various times in the future and renewal action by the applicable tribe or federal agencies will be required at that time.  In recent negotiations, certain of the affected Indian tribes have required payments substantially in excess of amounts that we have paid in the past for such rights-of-way.  The ultimate cost of renewal of certain of the rights-of-way for our transmission lines is therefore uncertain.
 

40


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

ITEM 4.  MINE SAFETY DISCLOSURES
 
Not applicable.


41


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 20, 2015, current positions and principal occupations for the past five years are as follows:
 
Name
 
Age
 
Position
 
Period
Donald E. Brandt
 
60
 
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
 
59
 
Senior Vice President, Site Operations, PVNGS, of APS
 
2010-Present
 
 
 
 
Vice President, Nuclear Operations of APS
 
2007-2010
Denise R. Danner
 
59
 
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
Patrick Dinkel
 
51
 
Vice President, Transmission and Distribution Operations of APS
 
2014-Present
 
 
 
 
Vice President, Resource Management of APS
 
2012-2014
 
 
 
 
Vice President, Power Marketing, Resource Planning and Acquisition of APS
 
2011-2012
 
 
 
 
Vice President, Power Marketing and Resource Planning of APS
 
2010-2011
 
 
 
 
General Manager, Strategic Planning and Resource Acquisition of APS
 
2009-2010
Randall K. Edington
 
61
 
Executive Vice President and Chief Nuclear Officer, PVNGS, of APS
 
2007-Present
David P. Falck
 
61
 
Executive Vice President and General Counsel of Pinnacle West and APS
 
2009-Present
 
 
 
 
Secretary of Pinnacle West and APS
 
2009-2012
Daniel T. Froetscher
 
53
 
Senior Vice President, Transmission, Distribution & Customers of APS
 
2014-Present
 
 
 
 
Vice President, Energy Delivery of APS
 
2008-2014
Jeffrey B. Guldner
 
49
 
Senior Vice President, Public Policy of APS
 
2014-Present
 
 
 
 
Senior Vice President, Customers and Regulation of APS
 
2012-2014
 
 
 
 
Vice President, Rates and Regulation of APS
 
2007-2012
James R. Hatfield
 
57
 
Executive Vice President of Pinnacle West and APS
 
2012-Present
 
 
 
 
Chief Financial Officer of Pinnacle West and APS
 
2008-Present
 
 
 
 
Senior Vice President of Pinnacle West and APS
 
2008-2012
 
 
 
 
Treasurer of Pinnacle West and APS
 
2009-2010
John S. Hatfield
 
49
 
Vice President, Communications of APS
 
2010-Present
 
 
 
 
Director, Corporate Communications of SCE
 
2004-2010
Tammy D. McLeod
 
53
 
Vice President, Resource Management of APS
 
2014-Present
 
 
 
 
Vice President and Chief Customer Officer of APS
 
2007-2014
Lee R. Nickloy
 
48
 
Vice President and Treasurer of Pinnacle West and APS
 
2010-Present
 
 
 
 
Assistant Treasurer and Director Corporate Finance of Ameren Corporation
 
2000-2010
Mark A. Schiavoni
 
59
 
Executive Vice President and Chief Operating Officer of APS
 
2014-Present
 
 
 
 
Executive Vice President, Operations of APS
 
2012-2014
 
 
 
 
Senior Vice President, Fossil Operations of APS
 
2009-2012


42


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 13, 2015, Pinnacle West’s common stock was held of record by approximately 21,649 shareholders.
 
QUARTERLY STOCK PRICES AND DIVIDENDS PAID PER SHARE
STOCK SYMBOL: PNW
 
 
 
 
 
 
 
 
Dividends
2014
 
High
 
Low
 
Close
 
Per Share
1st Quarter
 
$
55.99

 
$
51.15

 
$
54.66

 
$
0.5675

2nd Quarter
 
58.06

 
53.71

 
57.84

 
0.5675

3rd Quarter
 
57.95

 
52.13

 
54.64

 
0.5675

4th Quarter
 
71.11

 
54.59

 
68.31

 
0.595

 
 
 
 
 
 
 
 
 
Dividends
2013
 
High
 
Low
 
Close
 
Per Share
1st Quarter
 
$
57.96

 
$
51.50

 
$
57.89

 
$
0.545

2nd Quarter
 
61.89

 
51.56

 
55.47

 
0.545

3rd Quarter
 
60.33

 
52.03

 
54.74

 
0.545

4th Quarter
 
58.70

 
52.32

 
52.92

 
0.5675

 
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 2014 and 2013.
 
Common Stock Dividends
(Dollars in Thousands)
Quarter
 
2014
 
2013
1st Quarter
 
$
62,500

 
$
59,800

2nd Quarter
 
62,600

 
59,900

3rd Quarter
 
62,700

 
59,900

4th Quarter
 
65,800

 
62,500

 
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, 2014, APS did not have any outstanding preferred stock.

43



Issuer Purchases of Equity Securities
 
The following table contains information about our purchases of our common stock during the fourth quarter of 2014.
Period
 
Total
Number of
Shares
Purchased
(1)
 
Average
Price Paid
per Share
 
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs
 
Maximum Number of
Shares that May Yet Be
Purchased Under the
Plans or Programs
October 1 – October 31, 2014
 
56,107

 
$
58.73

 

 

November 1 – November 30, 2014
 

 

 

 

December 1 – December 31, 2014
 

 

 

 

Total
 
56,107

 
$
58.73

 

 


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


44


ITEM 6.  SELECTED FINANCIAL DATA
PINNACLE WEST CAPITAL CORPORATION – CONSOLIDATED
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
 
(dollars in thousands, except per share amounts)
OPERATING RESULTS
 
 

 
 

 
 

 
 

 
 

Operating revenues
 
$
3,491,632

 
$
3,454,628

 
$
3,301,804

 
$
3,241,379

 
$
3,189,199

Income from continuing operations
 
$
423,696

 
$
439,966

 
$
418,993

 
$
355,634

 
$
344,851

Income (loss) from discontinued operations – net of income taxes (a)
 

 

 
(5,829
)
 
11,306

 
25,358

Net income
 
423,696

 
439,966

 
413,164

 
366,940

 
370,209

Less: Net income attributable to noncontrolling interests
 
26,101

 
33,892

 
31,622

 
27,467

 
20,156

Net income attributable to common shareholders
 
$
397,595

 
$
406,074

 
$
381,542

 
$
339,473

 
$
350,053

COMMON STOCK DATA
 
 

 
 

 
 

 
 

 
 

Book value per share – year-end
 
$
39.50

 
$
38.07

 
$
36.20

 
$
34.98

 
$
33.86

Earnings per weighted-average common share outstanding:
 
 

 
 

 
 

 
 

 
 

Continuing operations attributable to common shareholders – basic
 
$
3.59

 
$
3.69

 
$
3.54

 
$
3.01

 
$
3.05

Net income attributable to common shareholders – basic
 
$
3.59

 
$
3.69

 
$
3.48

 
$
3.11

 
$
3.28

Continuing operations attributable to common shareholders – diluted
 
$
3.58

 
$
3.66

 
$
3.50

 
$
2.99

 
$
3.03

Net income attributable to common shareholders – diluted
 
$
3.58

 
$
3.66

 
$
3.45

 
$
3.09

 
$
3.27

Dividends declared per share
 
$
2.33

 
$
2.23

 
$
2.67

 
$
2.10

 
$
2.10

Weighted-average common shares outstanding – basic
 
110,626,101

 
109,984,160

 
109,510,296

 
109,052,840

 
106,573,348

Weighted-average common shares outstanding – diluted
 
111,178,141

 
110,805,943

 
110,527,311

 
109,864,243

 
107,137,785

BALANCE SHEET DATA
 
 

 
 

 
 

 
 

 
 

Total assets
 
$
14,313,532

 
$
13,508,686

 
$
13,379,615

 
$
13,111,018

 
$
12,392,998

Liabilities and equity:
 
 

 
 

 
 

 
 

 
 

Current liabilities
 
$
1,559,143

 
$
1,618,644

 
$
1,083,542

 
$
1,342,705

 
$
1,449,704

Long-term debt less current maturities
 
3,031,215

 
2,796,465

 
3,199,088

 
3,019,054

 
3,045,794

Deferred credits and other
 
5,204,072

 
4,753,117

 
4,994,696

 
4,818,673

 
4,122,274

Total liabilities
 
9,794,430

 
9,168,226

 
9,277,326

 
9,180,432

 
8,617,772

Total equity
 
4,519,102

 
4,340,460

 
4,102,289

 
3,930,586

 
3,775,226

Total liabilities and equity
 
$
14,313,532

 
$
13,508,686

 
$
13,379,615

 
$
13,111,018

 
$
12,392,998


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

45


SELECTED FINANCIAL DATA
ARIZONA PUBLIC SERVICE COMPANY – CONSOLIDATED
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
 
(dollars in thousands)
OPERATING RESULTS
 
 

 
 

 
 

 
 

 
 

Electric operating revenues
 
$
3,488,946

 
$
3,451,251

 
$
3,293,489

 
$
3,237,241

 
$
3,180,807

Fuel and purchased power costs
 
1,179,829

 
1,095,709

 
994,790

 
1,009,464

 
1,046,815

Other operating expenses
 
1,716,325

 
1,733,677

 
1,693,170

 
1,673,394

 
1,584,955

Operating income
 
592,792

 
621,865

 
605,529

 
554,383

 
549,037

Other income
 
36,358

 
20,797

 
16,358

 
24,974

 
20,138

Interest expense — net of allowance for borrowed funds
 
181,830

 
183,801

 
194,777

 
215,584

 
213,349

Net income
 
447,320

 
458,861

 
427,110

 
363,773

 
355,826

Less: Net income attributable to noncontrolling interests
 
26,101

 
33,892

 
31,613

 
27,524

 
20,163

Net income attributable to common shareholder
 
$
421,219

 
$
424,969

 
$
395,497

 
$
336,249

 
$
335,663

BALANCE SHEET DATA
 
 

 
 

 
 

 
 

 
 

Total assets
 
$
14,215,004

 
$
13,381,377

 
$
13,242,542

 
$
13,032,237

 
$
12,271,877

Liabilities and equity:
 
 

 
 

 
 

 
 

 
 

Total equity
 
$
4,629,852

 
$
4,454,874

 
$
4,222,483

 
$
4,051,406

 
$
3,916,037

Long-term debt less current maturities
 
2,906,215

 
2,671,465

 
3,074,088

 
2,894,054

 
3,045,794

Total capitalization
 
7,536,067

 
7,126,339

 
7,296,571

 
6,945,460

 
6,961,831

Current liabilities
 
1,532,464

 
1,580,847

 
1,043,087

 
1,322,714

 
1,234,865

Deferred credits and other
 
5,146,473

 
4,674,191

 
4,902,884

 
4,764,063

 
4,075,181

Total liabilities and equity
 
$
14,215,004

 
$
13,381,377

 
$
13,242,542

 
$
13,032,237

 
$
12,271,877

 

46


ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

OVERVIEW
 
Pinnacle West owns all of the outstanding common stock of APS.  APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.  APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so.
 
Areas of Business Focus
 
Operational Performance, Reliability and Recent Developments.
 
Nuclear.  APS operates and is a joint owner of Palo Verde.  The March 2011 earthquake and tsunamis in Japan and the resulting accident at Japan’s Fukushima Daiichi nuclear power station had a significant impact on nuclear power operators worldwide.  In the aftermath of the accident, the NRC conducted an independent assessment to consider actions to address lessons learned from the Fukushima events.  The independent assessment, named the Near Term Task Force, recommended a number of proposed enhancements to U.S. commercial nuclear power plant equipment and emergency plans. The NRC has directed nuclear power plants to begin implementing some of the Near Term Task Force’s recommendations. To implement these recommendations, Palo Verde expects to spend approximately $40 million for capital enhancements to the plant over the next two years in addition to the approximate $80 million that has already been spent on capital enhancements as of December 31, 2014 (APS’s share is 29.1%).
 
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 June 2, 2014, EPA proposed a rule to limit carbon dioxide emissions from existing power plants.  EPA expects to finalize the proposal in summer 2015.  EPA’s proposal for Arizona would 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.  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.

Cholla

On September 11, 2014, APS announced that it will close its 260 MW Unit 2 at Cholla by April 2016 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

47


rules. APS will also ask the ACC to approve the plan contemplated by the proposal. (See Note 3 for details related to the resulting regulatory asset and Note 10 for details of the proposal.) 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.

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, subject to certain minor post-closing adjustments.  In connection with APS’s most recent retail rate case with the ACC, the ACC reserved the right to review the prudence of the Four Corners transaction for cost recovery purposes upon the closing of the transaction.  On December 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.

Concurrently with the closing of the SCE transaction, BHP Billiton, the parent company of BNCC, the coal supplier and operator of the mine that serves Four Corners, transferred its ownership of BNCC to NTEC, a company formed by the Navajo Nation to own the mine and develop other energy projects. BHP Billiton will be retained by NTEC under contract as the mine manager and operator until July 2016. Also occurring concurrently with the closing, the Four Corners’ co-owners executed the 2016 Coal Supply Agreement for the supply of coal to Four Corners from July 2016, when the current coal supply agreement expires, 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 has agreed to assume the 7% shortfall obligation. 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. The cash purchase price, which will be subject to certain adjustments at closing, is immaterial in amount, and the purchaser will assume El Paso's reclamation and decommissioning obligations associated with the 7% interest. Completion of the purchase is subject to the receipt of certain regulatory approvals and is expected to occur in July 2016.

When APS, or an affiliate of APS, ultimately acquires El Paso's interest in Four Corners, NTEC will have an option to purchase the interest within a certain timeframe pursuant to an option granted by APS to NTEC. The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% shortfall obligations in the event NTEC does not exercise its option.
 
Pollution Control Investments and Shutdown of Units 1, 2 and 3.   EPA, in its final regional haze rule for Four Corners, required the Four Corners’ owners to elect one of two emissions alternatives to apply to the plant.  On December 30, 2013, APS, on behalf of the co-owners, notified EPA that they chose the alternative BART compliance strategy requiring the permanent closure of Units 1, 2 and 3 by January 1, 2014 and installation and operation of SCR controls on Units 4 and 5 by July 31, 2018.  On December 30, 2013, APS retired Units 1, 2 and 3.
 
Lease Extension.   APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation, which extends the Four Corners leasehold interest from 2016 to 2041.  The Navajo Nation approved these amendments in March 2011.  The effectiveness of the amendments also requires the approval of the DOI, as does a related federal rights-of-way grant which the Four Corners participants are pursuing.  A federal environmental review is underway as part of the DOI review process.  In March 2014, APS received a draft of the environmental impact statement in connection with the DOI review process.  As a proponent of Four Corners and the Navajo Mine Energy Project, APS, along with other members of the public, submitted comments on the draft impact statement.  APS cannot predict whether these federal approvals will be granted and, if so, on a timely basis, or whether any conditions that may be attached to them

48


will be acceptable to the Four Corners owners. On December 19, 2014, APS obtained a PSD permit from EPA allowing APS to install SCR control technology at Four Corners. 
 
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 through 2017, along with other transmission costs for upgrades and replacements.  APS is also working to establish and expand smart grid technologies throughout its service territory to provide long-term benefits both to APS and its customers.  APS is strategically deploying a variety of technologies that are intended to allow customers to better monitor their energy use and needs, minimize system outage durations, as well as the number of customers that experience outages, and facilitate greater cost savings to APS through improved reliability and the automation of certain distribution functions, including remote meter reading and remote connects and disconnects.
 
Renewable Energy.  The ACC approved the RES in 2006.  The renewable energy requirement is 5% of retail electric sales in 2015 and increases annually until it reaches 15% in 2025.  In the 2009 Settlement Agreement, APS agreed to exceed the RES standards, committing to use APS’s best efforts to obtain 1,700 GWh of new renewable resources to be in service by year-end 2015, in addition to its 2008 renewable resource commitments.  Taken together, APS’s commitment is currently estimated to be approximately 12% of APS’s estimated retail energy sales by year-end 2015, which is more than double the existing RES target of 5% for that year.  A component of the RES targets development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties). 

On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million.  In a final order dated January 7, 2014, the ACC approved the requested budget.  Also in 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits.  On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits.  On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information.  The ACC adopted these changes on December 18, 2014.  The revised rules are expected to become effective in the second quarter of 2015.

In accordance with the ACC’s decision on the 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 MW of APS-owned utility scale solar under the AZ Sun Program.  In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of utility scale solar with 10 MW (approximately 1,500 customers) of APS-owned residential solar that will not be under the AZ Sun Program. On December 19, 2014, the ACC voted that it had no objection to APS implementing its residential rooftop solar program. The first stage of the residential rooftop solar program is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with distributed storage. The program will target specific distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who cannot easily install solar through transactions with third parties. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes shall not be made until the project is fully in service and APS requests cost recovery in a future rate case.


49


On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 million. On December 31, 2014, the ACC issued a decision approving the 2015 RES implementation plan with minor modifications, including reducing the budget to approximately $152 million.
 
Demand Side Management.  In December 2009, Arizona regulators placed an increased focus on energy efficiency and other demand side management programs to encourage customers to conserve energy, while incentivizing utilities to aid in these efforts that ultimately reduce the demand for energy.  The ACC initiated an Energy Efficiency rulemaking, with a proposed EES of 22% cumulative annual energy savings by 2020.  The 22% figure represents the cumulative reduction in future energy usage through 2020 attributable to energy efficiency initiatives.  This standard became effective on January 1, 2011. 

On June 1, 2012, APS filed its 2013 DSM Plan.  In 2013, the standards required APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales.  Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million. 

On March 11, 2014, the ACC issued an order approving APS’s 2013 DSM Plan.  The ACC approved a budget of $68.9 million for each of 2013 and 2014.  The ACC also approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings for improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan.  Consistent with the ACC’s March 11, 2014 order, APS intends to continue its approved DSM programs in 2015. 

On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified.  The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Utility Energy Efficiency Standards.  The draft proposed substantial changes to the rules and energy efficiency standards.    The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014.  A formal rule making has not been initiated and there has been no additional action on the draft to date.
 
Rate Matters.  APS needs timely recovery through rates of its capital and operating expenditures to maintain its financial health.  APS’s retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by FERC.  On June 1, 2011, APS filed a rate case with the ACC.  APS and other parties to the retail rate case subsequently entered into the 2012 Settlement Agreement detailing the terms upon which the parties have agreed to settle the rate case.  See Note 3 for details regarding the 2012 Settlement Agreement terms and for information on APS’s FERC rates. 

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

As part of APS’s acquisition of SCE’s interest in Units 4 and 5 of Four Corners, APS and SCE agreed, via a “Transmission Termination Agreement” that, upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this

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termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination.  APS and SCE negotiated an alternate arrangement under which SCE would assign its 1,555 MW capacity rights over the Arizona Transmission System to third parties, including 300 MW to APS’s marketing and trading group.  However, this alternative arrangement was not approved by FERC.  In late March 2014, APS and SCE filed requests for rehearing with FERC.  Both requests for rehearing were denied on August 14, 2014. Although APS and SCE continue to evaluate potential paths forward, it is possible that the terms of the Transmission Termination Agreement may again control.  APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement.  If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration.  APS is unable to predict the outcome of this matter if it proceeds to arbitration.  If the matter proceeds to arbitration and APS is not successful, APS may be required to record a charge to its results of operations.

Deregulation.  On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.  The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state.  One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution.  On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter.  The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.  The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry.  A series of workshops in this docket were held in 2014 and another is currently scheduled for February 26, 2015.
 
Net Metering.  On July 12, 2013, APS filed an application with the ACC proposing a solution to address the cost shift brought by the current net metering rules.  On December 3, 2013, the ACC issued its order on APS’s net metering proposal.  The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013, and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases.  The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid. 
 
In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid.  ACC staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists.  The fixed charge does not increase APS’s revenue because it is credited to the LFCR, but it will modestly reduce the impact of the cost shift on non-solar customers.  The ACC acknowledged that the new charge addresses only a portion of the cost shift.  The ACC also required APS to file its next rate case in June 2015, the earliest date contemplated in the 2012 Settlement Agreement.
 
In May 2014, the ACC began conducting a series of workshops to, among other things, evaluate the role and value of the electric grid as it relates to rooftop solar and other issues regarding net metering.
 
On July 22, 2014, the ACC Commissioners voted to reopen the December 2013 net metering decision for the limited purpose of deciding whether to eliminate the requirement that APS file its next rate case in June 2015.  The vote included a request that parties comment in the docket about their thoughts on removing the filing date requirement and on the process for the broader discussion regarding rate design. On August 12,

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2014, the ACC Commissioners voted to lift the requirement that APS file its next general rate case by June 2015. On September 29, 2014, the staff of the ACC filed in a new docket a proposal for permitting a utility to request ACC approval of its proposed rate design outside of and before a general rate case. On October 20, 2014, APS and other interested stakeholders filed comments to this proposal. No further action has been taken in this docket.
 
Financial Strength and Flexibility.  Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities, and may readily access these facilities ensuring adequate liquidity for each company.  Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.
 
Other Subsidiaries.

Bright Canyon Energy. On July 31, 2014, Pinnacle West announced its creation of a wholly owned subsidiary, BCE.  BCE will focus 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 MidAmerican Transmission, LLC.  The joint venture, named TransCanyon, intends to focus on transmission opportunities within the Western Electricity Coordinating Council, excluding the retail service territories of the venture partners’ utility affiliates.  The joint venture submitted a bid into CAISO's competitive solicitation process to design, build and own a new 500 kV transmission line between Arizona and California, the Delaney to Colorado River Transmission Line.  The winner of the bidding process is expected to be announced in 2015.  This transmission line will connect a planned Delaney substation near Palo Verde in Arizona to the existing Colorado River substation located just west of Blythe, California.

El Dorado.  The operations of El Dorado are not expected to have any material impact on our financial results, or to require any material amounts of capital, over the next three years.
 
Key Financial Drivers
 
In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below.  We closely monitor these factors to plan for the Company’s current needs, and to adjust our expectations, financial budgets and forecasts appropriately.
 
Electric Operating Revenues.  For the years 2012 through 2014, retail electric revenues comprised approximately 93% of our total electric operating revenues.  Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms.  These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.
 
Customer and Sales Growth.  Retail customers in APS’s service territory increased 1.4% for the year ended December 31, 2014 compared with the prior-year.  For the three years 2012 through 2014, APS’s customer growth averaged 1.3% per year.  We currently expect annual customer growth to average in the range of 2.0-3.0% for 2015 through 2017 based on our assessment of modestly improving economic conditions in Arizona.  Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, were flat for the year ended December 31, 2014 compared with the prior-year, reflecting the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, partially offset by improving economic conditions and customer growth.  For the three years 2012 through 2014, APS experienced annual decreases in

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retail electricity sales averaging 0.2%, adjusted to exclude the effects of weather variations.  We currently estimate that annual retail electricity sales in kWh will increase on average in the range of 0.5-1.5% during 2015 through 2017, 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 could further impact these estimates.
Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and energy conservation, impacts of energy efficiency programs and growth in distributed generation, and responses to retail price changes.  Based on past experience, a reasonable range of variation in our kWh sales projection attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of up to $10 million.
 
Weather.  In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data.  Historically, extreme weather variations have resulted in annual variations in net income in excess of $20 million.  However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.
 
Fuel and Purchased Power Costs.  Fuel and purchased power costs included on our Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, changes in our generation resource allocation, our hedging program for managing such costs and PSA deferrals and the related amortization.
 
Operations and Maintenance Expenses Operations and maintenance expenses are impacted by customer and sales growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors.  In the 2009 Settlement Agreement, APS committed to operational expense reductions from 2010 through 2014. On September 30, 2014, Pinnacle West announced plan design changes to the group life and medical postretirement benefit plan, which required an interim remeasurement of the benefit obligation for the plan. This remeasurement is expected to reduce net periodic benefit costs on a prospective basis. See Note 7. In October 2014, the Society of Actuaries' Retirement Plans Experience Committee issued its final report on mortality tables ("RP-2014 Mortality Tables Report"). At December 31, 2014, we updated our mortality assumptions using a modification of these tables, which better reflects our employees' demographics. See Note 7 for additional details.
 
Depreciation and Amortization Expenses.  Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates.  See “Capital Expenditures” below for information regarding the planned additions to our facilities.  See Note 3 regarding deferral of certain costs pursuant to an ACC order.
 
Property Taxes.  Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates.  The average property tax rate in Arizona for APS, which owns essentially all of our property, was 10.7% of the assessed value for 2014, 10.5% for 2013, and 9.6% for 2012.  We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units, transmission and distribution facilities.  (See Note 3 for property tax deferrals contained in the 2012 Settlement Agreement).
 

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Income Taxes.  Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions and non-taxable items, such as AFUDC.  In addition, income taxes may also be affected by the settlement of issues with taxing authorities.
 
Interest Expense.  Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (see Note 6).  The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, equity issuances and internally generated cash flow.  An allowance for borrowed funds used during construction offsets a portion of interest expense while capital projects are under construction.  We stop accruing AFUDC on a project when it is placed in commercial operation.


RESULTS OF OPERATIONS
 
Pinnacle West’s only reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities and includes electricity generation, transmission and distribution.
 
Operating Results – 2014 compared with 2013.

Our consolidated net income attributable to common shareholders for the year ended December 31, 2014 was $398 million, compared with net income of $406 million for the prior year.  The results reflect a decrease of approximately $4 million for the regulated electricity segment primarily due to higher fossil generation costs, lower retail sales due to the effects of weather, higher property taxes, and lower retail transmission revenues. These negative factors were partially offset by lower operations and maintenance expenses related to lower employee benefit costs, higher other income, and increased revenues for lost fixed cost recovery. All other segment's income was lower by $4 million primarily related to El Dorado's investment losses.
 
The following table presents net income attributable to common shareholders by business segment compared with the prior year:
 
Year Ended
December 31,
 
 
 
2014
 
2013
 
Net Change
 
(dollars in millions)
Regulated Electricity Segment:
 

 
 

 
 

Operating revenues less fuel and purchased power expenses
$
2,309

 
$
2,356

 
$
(47
)
Operations and maintenance
(908
)
 
(925
)
 
17

Depreciation and amortization
(417
)
 
(416
)
 
(1
)
Taxes other than income taxes
(172
)
 
(164
)
 
(8
)
All other income and expenses, net
28

 
11

 
17

Interest charges, net of allowance for borrowed funds used during construction
(185
<