10-K 1 a12-3670_410k.htm 10-K

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

 

WASHINGTON, D.C. 20549

 


 

FORM 10-K

 

(Mark One)

 

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

 

For the fiscal year ended December 31, 2011

 

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

$4,848,522,427 as of June 30, 2011

ARIZONA PUBLIC SERVICE COMPANY

$0 as of June 30, 2011

 

The number of shares outstanding of each registrant’s common stock as of February 15, 2012

PINNACLE WEST CAPITAL CORPORATION

109,254,312 shares

ARIZONA PUBLIC SERVICE COMPANY

Common Stock, $2.50 par value, 71,264,947 shares. Pinnacle West Capital Corporation is the sole holder of Arizona Public Service Company’s Common Stock.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of Pinnacle West Capital Corporation’s definitive Proxy Statement relating to its Annual Meeting of Shareholders to be held on May 16, 2012 are incorporated by reference into Part III hereof.

 

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

 

 

 



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TABLE OF CONTENTS

 

 

Page

GLOSSARY OF NAMES AND TECHNICAL TERMS

1

 

 

FORWARD-LOOKING STATEMENTS

2

 

 

 

PART I

 

3

Item 1.

Business

3

Item 1A.

Risk Factors

26

Item 1B.

Unresolved Staff Comments

37

Item 2.

Properties

38

Item 3.

Legal Proceedings

41

Item 4.

Mine Safety Disclosures

41

Executive Officers of Pinnacle West

42

 

 

PART II

 

45

Item 5.

Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

45

Item 6.

Selected Financial Data

47

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

49

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

75

Item 8.

Financial Statements and Supplementary Data

76

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

172

Item 9A.

Controls and Procedures

172

Item 9B.

Other Information

173

 

 

 

PART III

 

173

Item 10.

Directors, Executive Officers and Corporate Governance of Pinnacle West

173

Item 11.

Executive Compensation

173

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

173

Item 13.

Certain Relationships and Related Transactions, and Director Independence

174

Item 14.

Principal Accountant Fees and Services

174

 

 

 

PART IV

 

175

Item 15.

Exhibits and Financial Statement Schedules

175

 

 

 

SIGNATURES

217

 

This combined Form 10-K is separately filed by Pinnacle West and APS.  Each registrant is filing on its own behalf all of the information contained in this Form 10-K that relates to such registrant and, where required, its subsidiaries.  Except as stated in the preceding sentence, neither registrant is filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.  The information required with respect to each company is set forth within the applicable items.  Item 8 of this report includes Consolidated Financial Statements of Pinnacle West and Consolidated Financial Statements of APS.  Item 8 also includes Notes to Pinnacle West’s Consolidated Financial Statements, the majority of which also relates to APS, and Supplemental Notes, which only relate to APS’s Consolidated Financial Statements.

 

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GLOSSARY OF NAMES AND TECHNICAL TERMS

 

AC

Alternating Current

ACC

Arizona Corporation Commission

ADEQ

Arizona Department of Environmental Quality

AFUDC

Allowance for Funds Used During Construction

ANPP

Arizona Nuclear Power Project, also known as Palo Verde

APS

Arizona Public Service Company, a subsidiary of the Company

APSES

APS Energy Services Company, Inc., a subsidiary of the Company sold on August 19, 2011

Base Fuel Rate

The portion of APS’s retail base rates attributable to fuel and purchased power costs

Cholla

Cholla Power Plant

DC

Direct Current

DOE

United States Department of Energy

El Dorado

El Dorado Investment Company, a subsidiary of the Company

EPA

United States Environmental Protection Agency

FASB

Financial Accounting Standards Board

FERC

United States Federal Energy Regulatory Commission

Four Corners

Four Corners Power Plant

GWh

Gigawatt-hour, one billion watts per hour

IFRS

International Financial Reporting Standards

kV

Kilovolt, one thousand volts

kWh

Kilowatt-hour, one thousand watts per hour

MMBtu

One million British Thermal Units

MW

Megawatt, one million watts

Native Load

Retail and wholesale sales supplied under traditional cost-based rate regulation

Navajo Plant

Navajo Generating Station

NRC

United States Nuclear Regulatory Commission

OCI

Other comprehensive income

Palo Verde

Palo Verde Nuclear Generating Station

Pinnacle West

Pinnacle West Capital Corporation (any use of the words “Company,” “we,” and “our” refer to Pinnacle West)

PRP

Potentially responsible party under Superfund

PSA

Power supply adjustor approved by the ACC to provide for recovery or refund of variations in actual fuel and purchased power costs compared with the Base Fuel Rate

RES

Arizona Renewable Energy Standard and Tariff

Salt River Project or SRP

Salt River Project Agricultural Improvement and Power District

SCE

Southern California Edison Company

SunCor

SunCor Development Company, a subsidiary of the Company

TCA

Transmission cost adjustor

VIE

Variable interest entity

West Phoenix

West Phoenix Power Plant

 



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FORWARD-LOOKING STATEMENTS

 

This document contains forward-looking statements based on current expectations.  These forward-looking statements are often identified by words such as “estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume” and similar words.  Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements.  A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS.  In addition to the Risk Factors described in Item 1A and in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” these factors include, but are not limited to:

 

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

·                              our ability to manage capital expenditures and other costs while maintaining reliability and customer service levels;

·                              variations in demand for electricity, including those due to weather, the general economy, customer and sales growth (or decline), and the effects of energy conservation measures and distributed generation;

·                             power plant and transmission system performance and outages;

·                              volatile fuel and purchased power costs;

·                              fuel and water supply availability;

·                              regulatory and judicial decisions, developments and proceedings;

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

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

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

·                              competition in retail and wholesale power markets;

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

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

·                              changes to our credit ratings;

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

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

·                              potential shortfalls in insurance coverage;

·                              new accounting requirements or new interpretations of existing requirements;

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

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

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

·                             technological developments affecting the electric industry; and

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

 

These and other factors are discussed in 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.

 

Operating Revenues (in thousands):

 

 

 

Year Ended December 31,

 

 

 

2011

 

2010

 

2009

 

APS

 

$

3,237,241

 

$

3,180,807

 

$

3,149,500

 

 

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

 

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

 

BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY

 

APS currently provides electric service to approximately 1.1 million customers.  We own or lease approximately 6,340 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 2011, 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.

 

GRAPHIC

 

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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 fuel type during 2011 were as follows:

 

 

Generation Facilities

 

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

 

Coal Fueled Generating Facilities

 

Four Corners — Four Corners is a 5-unit coal-fired power plant located in the northwestern corner of New Mexico.  APS operates the plant and owns 100% of Four Corners Units 1, 2 and 3 and 15% of Units 4 and 5.  APS has a total entitlement from Four Corners of 791 MW.  The Four Corners plant site is leased from the Navajo Nation and is also subject to an easement from the federal government.  APS purchases all of Four Corners’ coal requirements from a supplier with a long-term lease of coal reserves with the Navajo Nation.  The Four Corners coal contract runs through 2016.

 

On November 8, 2010, APS and SCE entered into an asset purchase agreement providing for the purchase by APS of SCE’s 48% interest in each of Units 4 and 5 of Four Corners.  If consummated, APS would acquire 739 MW from SCE.  Completion of the purchase by APS, which is expected to occur in the second half of 2012, is conditioned upon the receipt of regulatory approvals from the ACC, the California Public Utilities Commission and the FERC, the execution of a new coal supply contract, expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and other typical closing conditions.

 

APS, on behalf of the Four Corners participants, has negotiated amendments to an existing facility lease with the Navajo Nation which would extend the term of the Four Corners leasehold

 

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interest from 2016 to 2041. Execution by the Navajo Nation of the lease amendments is a condition to closing of the purchase by APS of SCE’s interests in Four Corners.  The execution of these amendments by the Navajo Nation requires the approval of the Navajo Nation Council, which became effective in March 2011.  The effectiveness of the amendments also requires the approval of the U.S. Department of the Interior (“DOI”), as does a related Federal rights-of-way grant, which the Four Corners participants will pursue.  A Federal environmental review is underway as part of the DOI review process.

 

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

 

Cholla — Cholla is a 4-unit coal-fired power plant located in northeastern Arizona.  APS operates the plant and owns 100% of Cholla Units 1, 2 and 3.  PacifiCorp owns Cholla Unit 4, and APS operates that Unit for PacifiCorp.  APS has a total entitlement from Cholla of 647 MW.  APS purchases all of Cholla’s coal requirements from a coal supplier that mines all of the coal under long-term leases of coal reserves with the federal government and private landholders.  The Cholla coal contract runs through 2024.  APS has the ability under the contract to reduce its annual coal commitment and purchase a portion of Cholla’s coal requirements on the spot market to take advantage of competitive pricing options and to purchase coal required for increased operating capacity.  APS believes that the current fuel contracts and competitive fuel supply options ensure the continued operation of Cholla for its useful life.  In addition, APS has a long-term coal transportation contract.

 

Navajo Generating Station — The Navajo Plant is a 3-unit coal-fired power plant located in northern Arizona.  Salt River Project operates the plant and APS owns a 14% interest in Navajo Units 1, 2 and 3.  APS has a total entitlement from the Navajo Plant of 315 MW.  The Navajo Plant’s coal requirements are purchased from a supplier with long-term leases from the Navajo Nation and the Hopi Tribe.  The Navajo Plant is under contract with its coal supplier through 2019.  The Navajo Plant site is leased from the Navajo Nation and is also subject to an easement from the federal government.

 

These coal 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 facilities.  See Note 11 for information regarding APS’s coal mine reclamation obligations.

 

Nuclear

 

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

 

Palo Verde Leases — In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back about 42% of its share of Palo Verde Unit 2 and certain common facilities.  In accordance with the VIE accounting guidance, APS consolidates the lessor trust entities for financial

 

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reporting purposes, and eliminates lease accounting for these transactions.  The agreements have terms of 29.5 years (expiring at the end of 2015) and contain options to renew the leases or to purchase the property for fair market value at the end of the lease terms.  APS must give notice to the respective lessor trusts between December 31, 2010 and December 31, 2012 if it wishes to exercise, or not exercise, either of these options.  We are analyzing these options.  See Note 20 for additional information regarding the Palo Verde Unit 2 sale leaseback transactions.

 

Palo Verde Operating LicensesOperation 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.  The full power operating licenses, each valid for a period of 40 years, authorize APS, as operating agent for Palo Verde, to operate the three Palo Verde Units.  On December 15, 2008, APS applied for renewed operating licenses for the Palo Verde Units for a period of 20 years beyond the expirations of the current licenses.  On April 21, 2011, the NRC approved APS’s application for renewed operating licenses for the Palo Verde Units, extending 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 95% of Palo Verde’s requirements for uranium concentrates through 2015, 90% of its requirements in 2016 — 2017 and 80% of its requirements in 2018.  The participants have also contracted for all of Palo Verde’s conversion services through 2015 and 95% of its requirements in 2016 — 2018, all of Palo Verde’s enrichment services through 2020 and all of Palo Verde’s fuel assembly fabrication services through 2016.

 

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

 

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, DOE submitted its application to the NRC to authorize construction of the Yucca Mountain repository.  In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca Mountain construction authorization application that was pending before the NRC.  Several

 

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interested parties have intervened in the NRC proceeding, and the proceeding has not been conclusively decided by the NRC or the courts.  Additionally, a number of interested parties have filed a variety of lawsuits in different jurisdictions around the country challenging the DOE’s authority to withdraw the Yucca Mountain construction authorization application.  None of these lawsuits have been conclusively decided by the courts.

 

On January 26, 2012, the Blue Ribbon Commission on America’s Nuclear Future (the “Blue Ribbon Commission”) made recommendations on managing the back end of the nuclear fuel cycle.  The Commission was established in early 2010 at the direction of President Obama.  The President’s directive was based on his assessment that the nation’s approach to managing used nuclear fuel, primarily through the repository at Yucca Mountain, has proven to be ineffective.

 

The Blue Ribbon Commission’s report recommended a strategy with several key elements including: a new, consent-based approach to siting future nuclear waste management facilities; a new organization dedicated solely to implementing the waste management program; access to the funds nuclear utility ratepayers are providing for the purpose of nuclear waste management; prompt efforts to develop geologic disposal facilities, consolidated storage facilities and to prepare for the eventual large-scale transport of spent nuclear fuel and high-level waste to consolidated storage and disposal facilities.  We are monitoring this matter, but cannot predict the proposed timing for implementation of the recommended strategy.

 

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.

 

In addition to the spent fuel stored at Palo Verde’s on-site ISFSI, Palo Verde also generates certain types of low level radioactive waste that are stored on-site.  Currently, the Class B and Class C waste (the higher radioactivity of the low level wastes) is stored on-site since industry access to a disposal site was eliminated several years ago.  The NRC is considering regulations that would allow the industry to eliminate much of this waste by blending it with lower level Class A waste so that it can be disposed of at a facility such as the one Palo Verde utilizes in Utah.

 

Nuclear Decommissioning CostsAPS 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 23 for additional information about APS’s nuclear decommissioning costs.

 

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

 

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Impact of Earthquake and Tsunami in Japan on Nuclear Energy Industry — On March 11, 2011, a 9.0 magnitude earthquake occurred off the northeastern coast of Japan.  The earthquake produced a tsunami that caused significant damage to the Fukushima Daiichi Nuclear Power Station in Japan.  Following these events, the NRC Commissioners launched a two-pronged review of U.S. nuclear power plant safety.  The NRC supported the establishment of an agency task force to conduct both a near- and long-term analysis of the lessons that can be learned from the situation in Japan.  The near-term task force issued a report on July 12, 2011, and on October 3, 2011, the NRC staff issued a plan for implementing the near-term task force’s recommendations.

 

On October 18, 2011, the NRC Commissioners directed the NRC staff to implement, without delay, the near-term task force recommendations, subject to certain conditions.  One such condition is that the agency should strive to complete and implement lessons learned from the earthquake and tsunami in Japan within five years.  A second condition is that the staff should designate the recommendation for a rulemaking to address extended loss of offsite power to be completed within 24 to 30 months.

 

Until further action is taken by the NRC as a result of this event, we cannot predict any financial or operational impacts on Palo Verde or APS.

 

Natural Gas and Oil Fueled Generating Facilities

 

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

 

Solar Facilities

 

To date, APS has begun operation of 50 MW of utility scale solar through its AZ Sun Program, discussed below.  These facilities are owned by APS and are located in multiple locations throughout Arizona.

 

Additionally, APS owns and operates more than forty small solar systems around the state.  Together they have the capacity to produce about 5 MW of renewable energy.  This fleet of solar systems includes a 3 MW facility located at the Prescott Airport, a 1 MW facility located at APS’s Saguaro power plant and 1 MW of small solar in various locations across Arizona.  APS is in the final stages of developing 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 will own, operate and receive energy from approximately 1.5 MW of solar photovoltaic distributed energy systems located within a certain test area in Flagstaff, Arizona.

 

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Purchased Power Contracts

 

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

 

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

 

Type

 

Dates Available

 

Capacity (MW)

 

Purchase Agreement (a)

 

Year-round through December 2014

 

104

 

Purchase Agreement (b)

 

Year-round through June 14, 2020

 

60

 

Exchange Agreement (c)

 

May 15 to September 15 annually through 2020

 

480

 

Tolling Agreement

 

Year-round through May 2017

 

500

 

Tolling Agreement

 

Summer seasons through October 2019

 

560

 

Day-Ahead Call Option Agreement

 

Summer seasons through September 2015

 

500

 

Day-Ahead Call Option Agreement

 

Summer seasons through summer 2016

 

150

 

Demand Response Agreement (d)

 

Summer seasons through 2024

 

100

 

Renewable Energy (e)

 

Various

 

232

 

 


(a)                                  The capacity under this agreement varies by month, with a maximum capacity of 104 MW.

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

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

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

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

 

Current and Future Resources

 

Current Demand and Reserve Margin

 

Electric power demand is generally seasonal.  In Arizona, demand for power peaks during the hot summer months.  APS’s 2011 peak one-hour demand on its electric system was recorded on August 24, 2011 at 7,087 MW, compared to the 2010 peak of 6,936 MW recorded on July 15, 2010.  APS’s operable generating capacity, together with purchased power capacity, resulted in an actual reserve margin at the time of the 2011 peak demand of 28.7%.  The power actually available to APS from its resources fluctuates from time to time due in part to planned and unplanned plant and transmission outages.

 

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Future Resources and Resource Plan

 

Under the ACC’s resource planning rule, APS will file by April 1st of each even year its resource plans for the next fifteen-year period.  The first resource plan filing will be due by April 1, 2012.  The rule requires the ACC to issue an order with its acknowledgment of APS’s resource plan within approximately ten months following its submittal.  The ACC’s acknowledgment of APS’s resource plan will consider factors such as the total cost of electric energy services, demand management, analysis of supply-side options, system reliability and risk management.

 

Renewable Energy Standard

 

In 2006, the ACC adopted the RES.  Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies.  The renewable energy requirement is 3.5% of retail electric sales in 2012 and increases annually until it reaches 15% in 2025.  In APS’s 2009 retail rate case settlement agreement, APS committed to have 1,700 GWh of new renewable resources in service by year-end 2015 in addition to its 2008 renewable resource commitments.  Taken together, APS’s commitment is estimated to be 3,400 GWh, or approximately 10% of retail sales, by year-end 2015, which is double the existing RES target of 5% for that year.  A component of the RES is focused on stimulating development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties).  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 3.5% in 2012.  The following table summarizes these requirement standards and their timing:

 

 

 

2012

 

2015

 

2020

 

2025

 

 

 

 

 

 

 

 

 

 

 

RES as a % of retail electric sales

 

3.5

%

5

%

10

%

15

%

Percent of RES to be supplied from distributed energy resources

 

30

%

30

%

30

%

30

%

 

Renewable Energy Portfolio.  To date, APS has a diverse portfolio of existing and planned renewable resources totaling 946 MW, including wind, geothermal, solar, biomass and biogas.  Of this portfolio, 423 MW are currently in operation and 523 MW are under contract for development or are under construction.  Renewable resources in operation include 55 MW of facilities owned by APS, 232 MW of long-term purchased power agreements, and an estimated 136 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 continues to develop owned solar resources through the AZ Sun Program.  The AZ Sun Program allows APS to own up to 200 MW of solar photovoltaic power plants across Arizona by investing up to $975 million through 2015.  Under this program to date, APS has executed contracts for the development of 83 MW of new solar generation, representing an investment commitment of approximately $375 million.  See Note 3 for additional details about the AZ Sun Program, including the related cost recovery.

 

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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

 

Luke AFB

 

Glendale, AZ

 

2013 (a)

 

 

 

 

 

14

 

Subtotal AZ Sun Program (b)

 

 

 

 

 

 

 

50

 

33

 

Multiple Facilities

 

AZ

 

Various

 

 

 

5

 

 

 

Total APS Owned

 

 

 

 

 

 

 

55

 

33

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power Agreements

 

 

 

 

 

 

 

 

 

 

 

Solar:

 

 

 

 

 

 

 

 

 

 

 

Solana (c)

 

Gila Bend, AZ

 

2013

 

30

 

 

 

250

 

RE Ajo

 

Ajo, AZ

 

2011

 

25

 

5

 

 

 

Sun E AZ 1

 

Prescott, AZ

 

2011

 

30

 

10

 

 

 

Solar 1 (d)

 

Tonopah, AZ

 

2012

 

30

 

 

 

15

 

Solar 2 (d)

 

Tonopah, AZ

 

2013

 

30

 

 

 

15

 

Solar 3 (d)

 

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

 

 

 

Landfill 1 (d)

 

Surprise, AZ

 

2012

 

20

 

 

 

3

 

Total Purchased Power Agreements

 

 

 

 

 

 

 

232

 

397

 

 

 

 

 

 

 

 

 

 

 

 

 

Distributed Energy

 

 

 

 

 

 

 

 

 

 

 

Solar (e)

 

 

 

 

 

 

 

 

 

 

 

APS Owned (f)

 

AZ

 

various

 

 

 

 

 

1

 

Third-party Owned (g) 

 

AZ

 

various

 

 

 

121

 

58

 

Agreement 1

 

Bagdad, AZ

 

2011

 

25

 

15

 

 

 

Agreement 2 (h)

 

AZ

 

2012-2014

 

20-25

 

 

 

34

 

Total Distributed Energy

 

 

 

 

 

 

 

136

 

93

 

Total Renewable Portfolio

 

 

 

 

 

 

 

423

 

523

 

 

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(a)                                  Subject to approval by the United States Department of Defense.

(b)                                 Under the AZ Sun Program, 117 MW remains to be contracted.

(c)                                  Represents contracted capacity.

(d)                                 Details of these agreements have not yet been publicly announced.

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

(f)                                    Reflects Community Power Project.

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

(h)                                 Agreement ramps up to 40 MW over three years.

 

Demand Side Management

 

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

 

Economic Stimulus Projects

 

Through the American Recovery and Reinvestment Act of 2009 (“ARRA”), the Federal government made a number of programs available for utilities to develop renewable resources, improve reliability and create jobs by using economic stimulus funding.  Certain programs are also available through the State of Arizona.

 

APS has two active awards with the DOE.  The first is a $3 million high penetration photovoltaic generation study related to the Community Power Project in Flagstaff, Arizona.  Second, APS is a sub-recipient under an approximately $4 million ARRA award received through the State of Arizona for the implementation of various distributed energy and energy efficiency programs in Arizona.  DOE funding for these awards will continue to be 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

 

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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 roof top solar panels to meet or supplement their energy needs.

 

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

 

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

 

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

 

Wholesale

 

The FERC regulates rates for wholesale power sales and transmission services.  (See Note 3 for information regarding APS’s transmission rates.)  During 2011, approximately 4.8% of APS’s electric operating revenues resulted from such sales and services.  APS’s wholesale activity primarily consists of managing fuel and purchased power supplies to serve retail customer energy requirements.  APS also sells, in the wholesale market, its generation output that is not needed for APS’s Native Load and, in doing so, competes with other utilities, power marketers and independent power producers.  Additionally, subject to specified parameters, APS hedges both electricity and fuels.  The majority of these activities are undertaken to mitigate risk in APS’s portfolio.

 

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Environmental Matters

 

Climate Change

 

Legislative Initiatives.  In the past several years, the United States Congress has considered bills that would regulate domestic greenhouse gas emissions.  There have been no attempts by the 112th Congress to pass legislation that would regulate greenhouse gas emissions.  With Congress’s focus on the economy, it is unclear when it will again consider a climate change bill.  In the event climate change legislation is ultimately passed, the actual economic and operational impact of such legislation on APS depends on a variety of factors, none of which can be fully known until a law is enacted and the specifics of the resulting program are established.  These factors include the terms of the legislation with regard to allowed emissions; whether any permitted emissions allowances will be allocated to source operators free of cost or auctioned; the cost to reduce emissions or buy allowances in the marketplace; and the availability of offsets and mitigating factors to moderate the costs of compliance.

 

In addition to federal legislative initiatives, state-specific initiatives may also impact our business.  While Arizona has no pending legislation and no proposed agency rule regulating greenhouse gases in Arizona, the California legislature enacted AB 32 and SB 1368 in 2006 to address greenhouse gas emissions.  In October 2011, the California Air Resources Board approved final regulations that will establish a state-wide cap on greenhouse gas emissions beginning on January 1, 2013 and will establish a greenhouse gas allowance trading program under that cap.  The first phase of the program, which will apply to, among other entities, electric utilities and importers of electricity, is scheduled to commence on January 1, 2013.  In addition, in 2010 the New Mexico Environmental Improvement Board enacted a greenhouse gas cap-and-trade program, which was repealed on February 6, 2012, and an emissions cap, which is scheduled to become effective in 2013 but is undergoing further review.

 

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

 

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

 

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continues.  At the present time, we cannot predict whether the parties challenging the endangerment finding or the tailoring rule will be successful.

 

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

 

On December 30, 2010, pursuant to its authority under the Clean Air Act, the EPA finalized a greenhouse gas Federal Implementation Plan (“FIP”) for Arizona relating to pre-construction permits for construction of new sources or major modifications of existing sources.  As a result of this action, effective January 2, 2011, the EPA assumed responsibility for acting on permit applications for only the greenhouse gas portion of such pre-construction permits.  State permitting authorities will continue to retain responsibility for the remaining parts of pre-construction permits that are unrelated to emissions of greenhouse gasses.  To the extent Arizona seeks and receives from the EPA a delegation of permitting authority for greenhouse gas emissions, the state will assume responsibility for issuing both the greenhouse gas and non-greenhouse gas portions of pre-construction permits.  The greenhouse gas FIP will remain in place until such time as the EPA approves a State Implementation Plan (“SIP”) that applies pre-construction permit requirements to greenhouse gas-emitting stationary sources in Arizona.  APS does not expect the greenhouse gas FIP to have a significant impact on its current operations.

 

Pursuant to its authority under the Clean Air Act, the EPA has also drafted proposed New Source Performance Standards (“NSPS”) for greenhouse gas emissions from certain new and modified electric generating units.  The proposed standards are currently under review at the White House Office of Management and Budget, and a final rule is expected in 2012.  In addition, it is possible that the EPA will propose standards setting federal emission guidelines for existing electric generating facilities in 2012.  The NSPS for greenhouse gas emissions are expected to apply to Four Corners, Cholla, and the Navajo Plant.  We cannot currently predict the impact of these anticipated rules on APS’s operations.

 

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

 

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

 

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Pinnacle West prepares an annual Corporate Responsibility Report, which is available on our website (www.pinnaclewest.com).  The report provides information related to the Company and its approach to sustainability and its workplace and environmental performance.  The information on Pinnacle West’s website, including the Corporate Responsibility Report, is not incorporated by reference into this report.

 

Climate Change Lawsuit.  In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in federal court in the Northern District of California against nine oil companies, fourteen power companies (including Pinnacle West), and a coal company, alleging that the defendants’ emissions of carbon dioxide contribute to global warming and constitute a public and private nuisance under both federal and state law.  The plaintiffs also allege that the effects of global warming will require the relocation of the village, and they are seeking an unspecified amount of monetary damages.  In June 2008, the defendants filed motions to dismiss the action, which were granted.  The plaintiffs filed an appeal with the Ninth Circuit Court of Appeals in November 2009, and Pinnacle West filed its reply on June 30, 2010.  On January 24, 2011, the defendants filed a motion, which was later granted, to defer calendaring of oral argument until after the United States Supreme Court ruled in a similar nuisance lawsuit, American Electric Power Co., Inc. v. Connecticut.

 

On June 20, 2011, the Supreme Court issued its opinion in Connecticut holding, among other things, that the Clean Air Act and the EPA actions authorized by the act, which are aimed at controlling greenhouse gas emissions, displace any federal common law right to seek abatement of greenhouse gas emissions from fossil fuel-fired power plants.  However, the Court left open the issue of whether such claims may be available under state law.  Oral argument in the Kivalina case was heard on November 28, 2011; the parties await the court’s decision.  We believe the action in Kivalina is without merit and will continue to defend against both the federal and state claims.

 

EPA Environmental Regulation

 

Regional Haze Rules.  Over a decade ago, the 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, the EPA) to determine what pollution control technologies constitute the “best available retrofit technology” (“BART”) for certain older major stationary sources.  The 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 the EPA’s final BART determinations (and Cholla’s obligations to comply with ADEQ’s determinations), coupled with the financial impact of potential future climate change legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of these plants or the ability of individual participants to continue their participation in these plants.

 

Cholla.  In 2007, ADEQ required APS to perform a BART analysis for Cholla pursuant to the Clean Air Visibility Rule.  APS completed the BART analysis for Cholla and submitted its BART recommendations to ADEQ on February 4, 2008.  The recommendations include the installation of certain pollution control equipment that APS believes constitutes BART. ADEQ reviewed APS’s recommendations and submitted its proposed BART SIP for Cholla and other sources within the state on March 2, 2011.  The EPA may accept the proposed SIP or reject part or all of it if the EPA determines the SIP is inadequate.  If the EPA rejects the proposed SIP provisions applicable to Cholla,

 

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it could issue a FIP for the plant that includes more stringent pollution control technology requirements and emission limits.

 

On December 2, 2011, the EPA provided notice of a proposed consent decree to address a lawsuit filed by a number of environmental organizations, which alleged that the EPA failed to promulgate FIPs for states that have not yet submitted all or part of the required BART SIPs.  The proposed consent decree establishes proposed and final promulgation deadlines (May 15, 2012 and November 15, 2012, respectively) for the EPA to promulgate regional haze FIPs or approve regional haze SIPs for 34 states, including Arizona.  On January 3, 2012, APS submitted comments to the EPA regarding the proposed consent decree.

 

Once APS receives a final determination as to what constitutes BART for Cholla, we will have up to five years to complete the installation of the equipment and to achieve the BART emission limits.  However, in order to coordinate with the plant’s other scheduled activities, APS is currently implementing portions of its recommended plan for Cholla on a voluntary basis.  Costs related to the implementation of these portions of our recommended plan are included in our environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Expenditures” in Item 7).

 

Four Corners and the Navajo Plant.  The EPA previously requested that APS, as the operating agent for Four Corners, and SRP, as the operating agent for the Navajo Plant, perform a BART analysis for Four Corners and the Navajo Plant, respectively.  APS and SRP each submitted an analysis to the EPA concluding that certain combustion control equipment constitutes BART for these plants.  Based on the analyses and comments received through EPA’s rulemaking process, the EPA will determine what it believes constitutes BART for each plant.

 

On October 6, 2010, the EPA issued its proposed BART determination for Four Corners.  The proposed rule would require the installation of post-combustion controls on each of Units 1-5 at Four Corners to reduce nitrogen oxides (“NOx”) emissions. Current estimates indicate that APS’s total costs for these controls could be up to approximately $400 million for Four Corners.  If APS’s purchase of SCE’s interest in Units 4 and 5 is consummated and Units 1-3 are closed, APS’s total costs for these controls would be approximately $300 million.  (See “Energy Sources and Resource Planning — Generation Facilities — Coal Fueled Generating Facilities — Four Corners” for details of this proposed transaction.)  The EPA also indicated in the proposal that it may require the installation of electrostatic precipitators or baghouses on Units 1, 2, and 3 to reduce particulate matter emissions. APS estimates that its total costs for such particulate removal equipment is approximately $220 million, which may also be required under the mercury rules. (See “Environmental Matters — Mercury and Other Hazardous Air Pollutants” below for additional information on these rules.)  The EPA proposed a 10% stack opacity limitation for all five units and a 20% opacity limitation on certain fugitive dust emissions, although the proposed fugitive dust provision is unrelated to BART.

 

On November 24, 2010, APS submitted a letter to the EPA proposing an alternative to the EPA’s October BART proposal.  Specifically, APS proposed to close Four Corners Units 1, 2, and 3 by 2014 and to install post-combustion pollution controls for NOx on Units 4 and 5 by the end of 2018, provided that the EPA agrees to a contemporaneous resolution of Four Corners’ obligations or liability, if any, under the regional haze and reasonably attributable visibility impairment programs, the New Source Review program, and NSPS programs of the Clean Air Act.

 

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On February 10, 2011, the EPA signed a Supplemental Notice Requesting Comment, related to the BART rulemaking for Four Corners.  In the Supplemental Notice, the EPA proposed to find that a different alternative emission control strategy, based upon APS’s November 2010 proposal, would achieve more progress than the EPA’s October 2010 BART proposal.  The Supplemental Notice proposes that Units 1, 2, and 3 would close by 2014, post-combustion pollution controls for NOx would be installed on Units 4 and 5 by July 31, 2018, and the NOx emission limitation for Units 4 and 5 would be 0.098 lbs/MMBtu, rather than the 0.11 lbs/MMBtu proposed by the EPA in October 2010.  APS provided comments to the EPA on both proposals and continues to evaluate them.

 

The EPA has not yet issued a proposed rule for the Navajo Plant.  SRP’s recommended plan for the Navajo Plant includes the installation of combustion control equipment, with an estimated cost to APS of approximately $6 million based on APS’s Navajo Plant ownership interest.  If the EPA determines that post-combustion controls are required, APS’s total costs could be up to approximately $93 million for the Navajo Plant. The Four Corners and the Navajo Plant participants will have up to five years after the EPA issues its final determinations to achieve compliance with their respective BART requirements.

 

In order to coordinate with each plant’s other scheduled activities, the plants are currently implementing portions of their recommended plans described above on a voluntary basis.  APS’s share of the costs related to the implementation of these portions of the recommended plans are included in our environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Expenditures” in Item 7).

 

Mercury and other Hazardous Air Pollutants.  On December 16, 2011, the EPA issued the final Mercury and Air Toxics Standards (“MATS”), which established maximum achievable control technology (“MACT”) standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired power plants.  APS will have three (potentially four if the permitting authority grants a one-year extension) years after the effective date of the rule to achieve compliance.

 

The MATS will require APS to install additional pollution control equipment.  APS has installed, and continues to install, certain of the equipment necessary to meet the anticipated standards.  APS estimates that the cost for equipment necessary to meet these standards is approximately $220 million for Four Corners Units 1-3 and $89 million for Cholla Units 1-3.  The estimated costs for Four Corners Units 1-3 are not included in our current environmental expenditure estimates since our estimates assume the consummation of APS’s purchase of SCE’s interest in Four Corners Units 4 and 5 and the subsequent shut down of Units 1-3.  Cholla’s estimated costs for the next three years are included in our environmental expenditure estimates.  (See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Expenditures” in Item 7 for details of our capital expenditure estimates).  SRP, the operating agent for the Navajo Plant, is still evaluating compliance options under the MATS.  If it is determined that the installation of polishing baghouses is required, APS’s total costs could be up to approximately $92 million for the Navajo Plant.

 

Cooling Water Intake Structures.  The EPA issued its proposed cooling water intake structures rule on April 20, 2011, which provides national standards applicable to certain cooling water intake structures at existing power plants and other facilities pursuant to Section 316(b) of the Clean Water Act.  The proposed standards are intended to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures).  To minimize impingement mortality, the proposed rule would require

 

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facilities, such as Four Corners and the Navajo Plant, to either demonstrate that impingement mortality at its cooling water intakes does not exceed a specified rate or reduce the flow at those structures to less than a specified velocity, and to take certain protective measures with respect to impinged fish.  To minimize entrainment mortality, the proposed rule would also require these facilities to conduct a “structured site-specific analysis” to determine what site-specific controls, if any, should be required.  Additional studies and a peer review process will also be required at these facilities.

 

As proposed, existing facilities subject to the rule would have to comply with the impingement mortality requirements as soon as possible, but in no event later than eight years after the effective date of the rule, and would have to comply with the entrainment requirements as soon as possible under a schedule of compliance established by the permitting authority.  APS is performing analyses to determine the costs of compliance with the proposed rule.  APS filed comments on the proposed rule on July 21, 2011.

 

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

 

APS filed comments on the proposed rule during the public comment period, which ended on November 19, 2010.  Although we do not know when the EPA will issue a final rule or by when compliance will ultimately be required, it is expected that the agency may take final action on the rule in 2012.  We cannot currently predict the outcome of the EPA’s actions or whether such actions will have a material adverse impact on our financial position, results of operations, or cash flows.

 

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

 

New Source ReviewOn April 6, 2009, APS received a request from the EPA under Section 114 of the Clean Air Act seeking detailed information regarding projects at and operations of Four Corners.  This request is part of an enforcement initiative that the EPA has undertaken under the Clean Air Act.  The EPA has taken the position that many utilities have made certain physical or operational changes at their plants that should have triggered additional regulatory requirements under the New Source Review provisions of the Clean Air Act.  Other electric utilities have received and responded to similar Section 114 requests, and several of them have been the subject of notices of violation and

 

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lawsuits by the EPA.  APS responded to the EPA’s request in August 2009 and is currently unable to predict the timing or content of the EPA’s response, if any, or any resulting actions.

 

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 Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act.  Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s NSPS program.  Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required PSD permits and complies with the NSPS.  The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project.  APS believes the claims in this matter are without merit and will vigorously defend against them.

 

Endangered Species Act.  On January 30, 2011, the Center for Biological Diversity, Dine Citizens Against Ruining Our Environment, and San Juan Citizens Alliance filed a lawsuit against the Office of Surface Mining Reclamation and Enforcement (“OSM”) and the DOI, alleging that OSM failed to engage in mandatory Endangered Species Act (“ESA”) consultation with the Fish and Wildlife Service prior to authorizing the renewal of an operating permit for the mine that serves Four Corners.  The lawsuit alleges that activities at the mine, including mining and the disposal of coal combustion residue, will adversely affect several endangered species and their critical habitats.  The lawsuit requests the court to vacate and remand the mining permit and enjoin all activities carried out under the permit until OSM has complied with the ESA.  Although we are not a party to the lawsuit, we continue to evaluate the lawsuit to determine its potential impact on plant operations.

 

SuperfundThe 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 PRPs.  PRPs may be strictly, and often are jointly and severally, liable for clean-up.  On September 3, 2003, the EPA advised APS that the 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 the EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with the 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.  APS estimates that its costs related to this investigation and study will be approximately $1 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 we cannot accurately estimate our total expenditures.

 

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 operations.

 

San Juan River Adjudication.  Both groundwater and surface water in areas important to APS’s operations have been the subject of inquiries, claims, and legal proceedings, which will require

 

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a number of years to resolve.  APS is one of a number of parties in a proceeding, filed March 13, 1975, before the Eleventh Judicial District Court in New Mexico to adjudicate rights to a stream system from which water for Four Corners is derived.  An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss.

 

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

 

Little Colorado River Adjudication.  APS has also 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.

 

A number of parties, including APS, the Navajo Nation, the Hopi Tribe, and other claimants in the Little Colorado River Adjudication have been engaged in settlement negotiations to resolve competing water claims.  On June 3, 2011, counsel for all the parties to the settlement discussions, including APS, signed, on behalf of their respective clients, a document expressing their agreement to recommend that the settlement be approved by their respective clients.  Negotiations among the parties continue.  If ultimately approved by the parties, the United States Congress, and the Arizona legislature, APS believes this settlement would be beneficial in protecting APS’s interest through its resolution of any and all claims that the Navajo Nation and the Hopi Tribe may have to the Little Colorado River system and source in Arizona.

 

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

 

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BUSINESS OF OTHER SUBSIDIARIES

 

The operations of our other first-tier subsidiaries (described below) are not expected to contribute in any material way to our future financial performance nor will they require any material amounts of capital over the next three years.  We continue to focus on our core utility business and streamlining the Company.  In August 2011, we sold our competitive energy services subsidiary, APSES, for an after tax gain of $10 million.

 

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, 2011, El Dorado had total assets of $20 million.

 

SunCor

 

SunCor was a developer of residential, commercial and industrial real estate projects in Arizona, Idaho, New Mexico and Utah.  Due to the continuing distressed conditions in the real estate markets, in 2009 SunCor undertook a program to dispose of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to eliminate its outstanding debt.  As of December 31, 2011, SunCor had no existing bank debt and had total assets remaining on its books of $9 million, consisting of $7 million of intercompany receivables and $2 million of other assets.  On February 24, 2012, SunCor filed for protection under the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Arizona to complete an orderly liquidation of its business.  We do not expect SunCor’s bankruptcy to have a material impact on Pinnacle West’s financial position, results of operations or cash flows.

 

Financial Summary

 

 

 

2011

 

2010

 

2009

 

 

 

(dollars in millions)

 

Revenues (a)

 

$

2

 

$

102

 

$

158

 

Net loss attributable to common shareholders (b)

 

$

(2

)

$

(9

)

$

(279

)

Total assets at December 31

 

$

9

 

$

16

 

$

166

 

 


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

(b)                                 The 2009 amount includes a $266 million (pre-tax) real estate impairment charge.

 

OTHER INFORMATION

 

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

 

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Principal Executive Office
Address

 

Year of
Incorporation

 

Approximate
Number of
Employees at
December 31, 2011

Pinnacle West

 

400 North Fifth Street
Phoenix, AZ 85004

 

1985

 

80

 

 

 

 

 

 

 

APS

 

400 North Fifth Street
P.O. Box 53999
Phoenix, AZ 85072-3999

 

1920

 

6,580

 

 

 

 

 

 

 

SunCor

 

80 East Rio Salado Parkway
Suite 410
Tempe, AZ 85281

 

1965

 

3

 

 

 

 

 

 

 

El Dorado

 

400 North Fifth Street
Phoenix, AZ 85004

 

1983

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

6,663

 

The APS number includes employees at jointly-owned generating facilities (approximately 3,050 employees) for which APS serves as the generating facility manager.  Approximately 1,930 APS employees are union employees.  APS entered into a new three-year collective bargaining agreement with union employees in the fossil generation, energy delivery and customer service business areas that expires in April 2014.  The agreement with union employees serving as Palo Verde security officers expires in 2013.

 

WHERE TO FIND MORE INFORMATION

 

We use our website www.pinnaclewest.com as a channel of distribution for material Company information.  The following filings are available free of charge on our website as soon as reasonably practicable after they are electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”): Annual Reports on Form 10-K, definitive proxy statements for our annual shareholder meetings, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports.  Our board and committee charters, Code of Ethics for Financial Executives, Ethics Policy and Standards of 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 Ethics Policy and Standards of 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 Secretary, Station 9068, P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-3252).

 

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ITEM 1A.  RISK FACTORS

 

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

 

REGULATORY RISKS

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, wastewater discharges, solid waste, hazardous waste, and 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 or criminal penalties.  Both public officials and private individuals may seek to enforce applicable environmental laws and regulations.  APS cannot predict the outcome (financial or operational) of any related litigation that may arise.

 

Environmental Clean Up.  APS has been named as a PRP for a Superfund site in Phoenix, Arizona and it could be named a PRP in the future for other environmental clean up at sites identified by a regulatory body.  APS cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean up costs.  There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

 

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Regional Haze.  APS is currently awaiting a final rulemaking from the EPA that could impose new requirements on Four Corners and the Navajo Plant.  APS is also awaiting the EPA’s issuance of a FIP or partial FIP that could impose new requirements on Cholla.  The EPA and ADEQ will require these plants to install pollution control equipment that constitutes the best available retrofit technology to lessen the impacts of emissions on visibility surrounding the plants.  Depending upon the agencies’ final determinations of what constitutes BART for these plants, the financial impact of installing and operating the required pollution control equipment could jeopardize the economic viability of the plants or the ability of individual participants to continue their participation in these plants, resulting in plant closures and asset impairments.

 

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

 

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

 

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

 

Concern over climate change, deemed by many to be induced by rising levels of greenhouse gases in the atmosphere, has led to significant legislative and regulatory efforts to limit CO2, which is a major byproduct of the combustion of fossil fuel, and other greenhouse gas emissions.  In addition, lawsuits have been filed against companies that emit greenhouse gases, including a lawsuit filed by the Native Village of Kivalina and the City of Kivalina, Alaska against us and several other utilities seeking damages related to climate change.

 

Financial Risks — Potential Legislation and Regulation.  It is possible that some form of legislation or EPA action to regulate domestic greenhouse gas emissions may occur in the future at the

 

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federal level.  If the United States Congress, or individual states or groups of states in which APS operates, ultimately pass legislation, or if the EPA promulgates additional regulations regulating the emissions of greenhouse gases, any resulting limitations on CO2 and other greenhouse gas emissions could result in the creation of substantial additional capital expenditures and operating costs in the form of taxes, emissions allowances, or required equipment upgrades and could have a material adverse impact on all fossil-fuel-fired generation facilities (particularly coal-fired facilities, which constitute approximately 28% of APS’s generation capacity).

 

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

 

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

 

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

 

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

 

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

 

OPERATIONAL RISKS

 

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

 

Weather Conditions.  Weather conditions directly influence the demand for electricity and affect the price of energy commodities.  Electric power demand is generally a seasonal business.  In

 

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

 

Higher temperatures may decrease the snowpack, which might result in lowered soil moisture and an increased threat of forest fires.  Forest fires could threaten APS’s communities and electric transmission lines.  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 proposed Settlement Agreement in APS’s current retail rate case includes a mechanism to address these matters.  The 2009 retail rate case settlement agreement also established energy efficiency goals for APS that began in 2010 that extend through 2012, subjecting APS to energy efficiency requirements slightly greater for the first two of those years than required under the rules described above.

 

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

 

Reduced demand due to these energy efficiency and distributed energy requirements, unless offset through ratemaking mechanisms, such as those proposed in the Settlement Agreement, could have a material adverse impact on APS’s financial condition, results of operations and cash flows.

 

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

 

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

 

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

 

Potential changes in regulatory standards, impacts of new and existing laws and regulations, including environmental laws and regulations, and the need to obtain certain regulatory approvals create uncertainty surrounding our generation portfolio.  For example, APS’s acquisition of SCE’s interest in Four Corners is contingent upon regulatory approval.  If not approved, we could face increased costs for replacement power or the need to acquire or develop alternate resources.  In addition, APS is required by the ACC to meet certain energy resource portfolio requirements and the RES.  The development of any renewable generation facilities resulting from the RES is subject to many other risks, including risks related to financing, siting, permitting, technology, the construction of sufficient transmission capacity to support these facilities and stresses to generation and transmission resources from intermittent generation characteristics of renewable resources.  APS’s inability to adequately develop or acquire the necessary generation resources to meet the required standards could have a material adverse impact on our business and results of operations.

 

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

 

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

 

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

 

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

 

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

 

APS has an ownership interest in and operates, on behalf of a group of participants, Palo Verde, which is the largest nuclear electric generating facility in the United States.  Palo Verde 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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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FINANCIAL RISKS

 

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

 

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

 

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

 

Changes in economic conditions, monetary policy or other factors could result in higher interest rates, which would increase our interest expense on our debt and reduce funds available to us for our current plans.  Additionally, an increase in our leverage could adversely affect us by:

 

·                                          causing a downgrade of our credit ratings;

·                                          increasing the cost of future debt financing and refinancing;

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

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

 

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

 

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

 

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Investment performance, changing interest rates and other economic factors could decrease the value of our benefit plan assets and nuclear decommissioning trust funds and increase the valuation of our related obligations, resulting in significant additional funding requirements.  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 or poor investment results may adversely affect the values of the fixed income and equity securities held in these trusts and increase our funding requirements.  Additionally, the valuation of liabilities related to our pension plan and other postretirement benefit plans are impacted by a discount rate, which is the interest rate used to discount future pension and other postretirement benefit obligations.  Declining interest rates decrease the discount rate, increase the valuation of the plan liabilities and may result in increases in pension and other postretirement benefit costs, cash contributions, regulatory assets, and charges to other comprehensive income.  Changes in demographics, including increased numbers of retirements or changes in life expectancy and changes in other actuarial assumptions, may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans.  The minimum contributions required under these plans have increased, and could continue to do so, resulting 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.

 

We may be required to adopt IFRS. The ultimate adoption of such standards could negatively impact our business, financial condition or results of operations.

 

IFRS is a comprehensive series of accounting standards published by the International Accounting Standards Board (“IASB”) that is being considered by the SEC to replace accounting principles generally accepted in the United States of America (“GAAP”) for use in preparation of financial statements.  If the SEC requires mandatory adoption of IFRS, we may lose our ability to use regulatory accounting treatment, and would follow IFRS rather than GAAP for the preparation of our financial statements beginning no earlier than 2015.  In the meantime, the FASB and the IASB are working on several accounting standards jointly to converge certain accounting differences.  The implementation and adoption of these new standards and the inability to use regulatory accounting could negatively impact our business, financial condition or results of operations.

 

Our cash flow largely depends on the performance of APS.

 

We conduct our operations primarily through our subsidiary, APS.  Essentially all of our consolidated assets are held by APS.  Accordingly, our cash flow and our ability to pay dividends on our common stock is dependent upon the earnings and cash flows of APS and its distributions to us.  APS is a separate and distinct legal entity and has no obligation to make distributions to us.

 

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

 

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

 

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

 

The market price of our common stock may be volatile.

 

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

 

·                                          variations in our quarterly operating results;

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

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

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

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

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

·                                          favorable or adverse regulatory or legislative developments;

·                                          our dividend policy;

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

·                                          general domestic and international economic conditions.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Since 2009, SunCor has been engaged in a program to dispose of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to eliminate its outstanding debt.  SunCor is focusing on concluding an orderly wind-down of its business.  This effort includes addressing contingent liabilities, such as warranty and construction claims that may be brought by property owners and potential funding obligations to local taxing districts that financed infrastructure at certain of its real estate developments.

 

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

 

ITEM 1B.  UNRESOLVED STAFF COMMENTS

 

Neither Pinnacle West nor APS has received written comments regarding its periodic or current reports from the SEC staff that were issued 180 days or more preceding the end of its 2011 fiscal year and that remain unresolved.

 

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ITEM 2.  PROPERTIES

 

Generation Facilities

 

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

 

Name

 

No. of
Units

 

%
Owned (a)

 

Principal
Fuels
Used

 

Primary
Dispatch
Type

 

Owned
Capacity

(MW)

 

Nuclear:

 

 

 

 

 

 

 

 

 

 

 

Palo Verde (b)

 

3

 

29.1%

 

Uranium

 

Base Load

 

1,146

 

Total Nuclear

 

 

 

 

 

 

 

 

 

1,146

 

 

 

 

 

 

 

 

 

 

 

 

 

Steam:

 

 

 

 

 

 

 

 

 

 

 

Four Corners 1, 2, 3

 

3

 

 

 

Coal

 

Base Load

 

560

 

Four Corners 4, 5 (c)

 

2

 

15%

 

Coal

 

Base Load

 

231

 

Cholla

 

3

 

 

 

Coal

 

Base Load

 

647

 

Navajo (d)

 

3

 

14%

 

Coal

 

Base Load

 

315

 

Ocotillo

 

2

 

 

 

Gas

 

Peaking

 

220

 

Saguaro

 

2

 

 

 

Gas/Oil

 

Peaking

 

210

 

Total Steam

 

 

 

 

 

 

 

 

 

2,183

 

 

 

 

 

 

 

 

 

 

 

 

 

Combined Cycle:

 

 

 

 

 

 

 

 

 

 

 

Redhawk

 

2

 

 

 

Gas

 

Load Following

 

984

 

West Phoenix

 

5

 

 

 

Gas

 

Load Following

 

887

 

Total Combined Cycle

 

 

 

 

 

 

 

 

 

1,871

 

 

 

 

 

 

 

 

 

 

 

 

 

Combustion Turbine:

 

 

 

 

 

 

 

 

 

 

 

Ocotillo

 

2

 

 

 

Gas

 

Peaking

 

110

 

Saguaro 1, 2

 

2

 

 

 

Gas/Oil

 

Peaking

 

110

 

Saguaro 3

 

1

 

 

 

Gas

 

Peaking

 

79

 

Douglas

 

1

 

 

 

Oil

 

Peaking

 

16

 

Sundance

 

10

 

 

 

Gas

 

Peaking

 

420

 

West Phoenix

 

2

 

 

 

Gas

 

Peaking

 

110

 

Yucca 1, 2, 3

 

3

 

 

 

Gas/Oil

 

Peaking

 

93

 

Yucca 4

 

1

 

 

 

Oil

 

Peaking

 

54

 

Yucca 5, 6

 

2

 

 

 

Gas

 

Peaking

 

96

 

Total Combustion Turbine

 

 

 

 

 

 

 

 

 

1,088

 

 

 

 

 

 

 

 

 

 

 

 

 

Solar:

 

 

 

 

 

 

 

 

 

 

 

Cotton Center

 

1

 

 

 

Solar

 

As Available

 

17

 

Hyder

 

1

 

 

 

Solar

 

As Available

 

16

 

Paloma

 

1

 

 

 

Solar

 

As Available

 

17

 

Multiple facilities

 

 

 

 

 

Solar

 

As Available

 

5

 

Total Solar

 

 

 

 

 

 

 

 

 

55

 

Total Capacity

 

 

 

 

 

 

 

 

 

6,343

 

 


(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 Electric Company (15.8%), Public Service Company of New Mexico (10.2%),

 

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Southern California Public Power Authority (5.91%), and Los Angeles Department of Water & Power (5.7%).  The plant is operated by APS.

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

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

 

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

 

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

 

Transmission and Distribution Facilities

 

Current Facilities. APS’s transmission facilities consist of approximately 5,866 pole miles of overhead lines and approximately 49 miles of underground lines, 5,643 miles of which are located in Arizona. APS’s distribution facilities consist of approximately 11,376 miles of overhead lines and approximately 17,561 miles of underground primary cable, all of which are located in Arizona. APS shares ownership of some of its transmission facilities with other companies. The following table shows APS’s jointly-owned interests in those transmission facilities recorded on the Consolidated Balance Sheets at December 31, 2011:

 

 

 

Percent Owned
(Weighted Average)

 

North Valley System

 

69.3

%

Palo Verde — Estrella 500kV System

 

50.0

%

Round Valley System

 

50.0

%

ANPP 500kV System

 

33.0

%

Navajo Southern System

 

25.9

%

Four Corners Switchyards

 

39.6

%

Palo Verde — Yuma 500kV System

 

44.1

%

Phoenix — Mead System

 

17.5

%

 

Expansion.  Each year APS prepares and files with the ACC a ten-year transmission plan.  In APS’s 2012 plan, APS projects it will invest approximately $550 million in new transmission projects (115 kV and above) over the next ten years, which includes 269 miles of new lines.  This investment will increase the import capability into metropolitan Phoenix and the Yuma area.  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 phase, Delaney to Palo Verde

 

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

 

APS continues to work with regulators to identify transmission projects necessary to support renewable energy facilities.  Two such projects, which are included in APS’s 2012 transmission plan, are the Delaney to Palo Verde line and the North Gila to Palo Verde line, both of which are intended to support the transmission of renewable energy to Phoenix and California.

 

Plant and Transmission Line Leases and Easements on Indian Lands

 

The Navajo Plant and Four Corners are located on land held under leases from the Navajo Nation and also under easements from the federal government.  The easement and lease for the Navajo Plant expire in 2019 and the easement 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 easements.   APS is now preparing to file applications for renewal of these easements with the DOI.  Before it may approve the Four Corners lease extension and issue the renewed easements, 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 easements or other 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.  Other rights expire at various times in the future and renewal action by the applicable tribe will be required at that time.  The majority of our transmission lines residing on Indian lands are on the Navajo Nation.   In March 2011, the Navajo Nation provided its consent to renew the easements for the transmission lines specified in the lease extension.  However, some of our easements are not covered by the leases, or are granted by other Indian tribes.  In recent negotiations with other utilities or companies for renewal of similar rights-of-way, certain of the affected Indian tribes have required payments substantially in excess of amounts that we have paid in the past for such rights-of-way or that are typical for similar permits across non-Indian lands; however, we are unaware of the underlying agreements and/or specific circumstances surrounding these renewals.  The ultimate cost of renewal of the rights-of-way for our transmission lines not addressed in the lease extension is uncertain.  We are monitoring these easement issues and have had extensive discussions with the Navajo Nation regarding the easements.  We are currently unable to predict the outcome of this matter.

 

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ITEM 3.  LEGAL PROCEEDINGS

 

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

 

See Note 3 for ACC and FERC-related matters.

 

See Note 11 for information relating to the FERC proceedings on Pacific Northwest energy market issues and matters related to a September 2011 power outage.

 

ITEM 4.  MINE SAFETY DISCLOSURES

 

Not applicable.

 

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EXECUTIVE OFFICERS OF PINNACLE WEST

 

Pinnacle West’s executive officers are elected no less often than annually and may be removed by the Board of Directors at any time.  The executive officers, their ages at February 24, 2012, current positions and principal occupations for the past five years are as follows:

 

Name

 

Age

 

Position

 

Period

 

 

 

 

 

 

 

Donald E. Brandt

 

57

 

Chairman of the Board and Chief Executive Officer of Pinnacle West; Chairman of the Board of APS

 

2009-Present

 

 

 

 

President of Pinnacle West

 

2008-Present

 

 

 

 

Chief Executive Officer of APS

 

2008-Present

 

 

 

 

Chief Operating Officer of Pinnacle West

 

2008-2009

 

 

 

 

President of APS

 

2006-2009

 

 

 

 

Executive Vice President of Pinnacle West; Chief Financial Officer of APS

 

2003-2008

 

 

 

 

Chief Financial Officer of Pinnacle West

 

2002-2008

 

 

 

 

Executive Vice President of APS

 

2003-2006

 

 

 

 

 

 

 

Donald G. Robinson

 

58

 

President and Chief Operating Officer of APS

 

2009-Present

 

 

 

 

Senior Vice President, Planning and Administration of APS

 

2007-2009

 

 

 

 

Vice President, Planning of APS

 

2003-2007

 

 

 

 

 

 

 

Denise R. Danner

 

56

 

Vice President, Controller and Chief Accounting Officer of Pinnacle West; Chief Accounting Officer of APS

 

2010-Present

 

 

 

 

Vice President and Controller of APS

 

2009-Present

 

 

 

 

Senior Vice President, Controller and Chief Accounting Officer of Allied Waste Industries, Inc.

 

2007-2008

 

 

 

 

Vice President, Controller and Chief Accounting Officer of Phelps Dodge Corporation

 

2004-2007

 

 

 

 

 

 

 

Patrick Dinkel

 

48

 

Vice President, Power Marketing, Resource Planning and Acquisition

 

2011-Present

 

 

 

 

Vice President, Power Marketing and Resource Planning

 

2010-2011

 

 

 

 

General Manager, Strategic Planning and Resource Acquisition

 

2009-2010

 

 

 

 

Director of Resource Acquisitions and Renewables

 

2007-2009

 

 

 

 

Director of Planning and Resource Acquisitions

 

2004-2007

 

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Table of Contents

 

Randall K. Edington

 

58

 

Executive Vice President and Chief Nuclear Officer of APS

 

2007-Present

 

 

 

 

Senior Vice President and Chief Nuclear Officer of APS

 

2007

 

 

 

 

Site Vice President and Chief Nuclear Officer of Cooper Generating Station with Entergy Corporation

 

2003-2007

 

 

 

 

 

 

 

David P. Falck

 

58

 

Executive Vice President, General Counsel and Secretary of Pinnacle West and APS

 

2009-Present

 

 

 

 

Senior Vice President — Law of Public Service Enterprise Group Inc.

 

2007-2009

 

 

 

 

Partner — Pillsbury Winthrop Shaw Pittman LLP

 

1987-2007

 

 

 

 

 

 

 

Daniel T. Froetscher

 

50

 

Vice President, Energy Delivery

 

2008-Present

 

 

 

 

General Manager of Rural Arizona Delivery

 

2007-2008

 

 

 

 

General Manager North Arizona Operations

 

2004-2007

 

 

 

 

 

 

 

Jeffrey B. Guldner

 

46

 

Vice President, Rates & Regulation

 

2007-Present

 

 

 

 

Director of Federal Regulation and Compliance

 

2006-2007

 

 

 

 

 

 

 

James R. Hatfield

 

54

 

Senior Vice President and Chief Financial Officer of Pinnacle West and APS

 

2008-Present

 

 

 

 

Treasurer of Pinnacle West and APS

 

2009-2010

 

 

 

 

Senior Vice President and Chief Financial Officer of OGE Energy Corp.

 

1999-2008

 

 

 

 

 

 

 

John S. Hatfield

 

46

 

Vice President, Communications of APS

 

2010-Present

 

 

 

 

Director, Corporate Communications of Southern California Edison

 

2004-2010

 

 

 

 

 

 

 

Tammy D. McLeod

 

50

 

Vice President and Chief Customer Officer

 

2007-Present

 

 

 

 

General Manager Customer Service/Southern Arizona Operations

 

2004-2007

 

 

 

 

 

 

 

Lee R. Nickloy

 

45

 

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

 

56

 

Senior Vice President, Fossil Operations of APS

 

2009-Present

 

 

 

 

Senior Vice President of Exelon Generation and President of Exelon Power

 

2004-2009

 

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Table of Contents

 

Lori S. Sundberg

 

48

 

Senior Vice President, Human Resources and Ethics of APS

 

2011-Present

 

 

 

 

Vice President, Human Resources and Ethics of APS

 

2010-2011

 

 

 

 

Vice President, Human Resources of APS

 

2007-2010

 

 

 

 

Vice President, Employee Relations, Safety, Compliance & Embrace of American Express Company

 

2007

 

 

 

 

Vice President, HR Relationship Leader, Global Corporate Travel Division of American Express Company

 

2003-2007

 

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PART II

 

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

 

Pinnacle West’s common stock is publicly held and is traded on the New York Stock Exchange.  At the close of business on February 15, 2012, Pinnacle West’s common stock was held of record by approximately 25,595 shareholders.

 

QUARTERLY STOCK PRICES AND DIVIDENDS PAID PER SHARE
STOCK SYMBOL: PNW

 

 

 

 

 

 

 

 

 

Dividends

 

2011

 

High

 

Low

 

Close

 

Per Share

 

 

 

 

 

 

 

 

 

 

 

1st Quarter

 

$

44.07

 

 

$

40.70

 

 

$

42.79

 

 

$

0.525

 

 

2nd Quarter

 

45.64

 

 

41.93

 

 

44.58

 

 

0.525

 

 

3rd Quarter

 

45.15

 

 

37.28

 

 

42.94

 

 

0.525

 

 

4th Quarter

 

48.87

 

 

40.87

 

 

48.18

 

 

0.525

 

 

 

 

 

 

 

 

 

 

 

Dividends

 

2010

 

High

 

Low

 

Close

 

Per Share

 

 

 

 

 

 

 

 

 

 

 

1st Quarter

 

$

38.37

 

 

$

34.62

 

 

$

37.73

 

 

$

0.525

 

 

2nd Quarter

 

39.10

 

 

32.31

 

 

36.36

 

 

0.525

 

 

3rd Quarter

 

41.75

 

 

35.71

 

 

41.27

 

 

0.525

 

 

4th Quarter

 

42.68

 

 

39.97

 

 

41.45

 

 

0.525

 

 

 

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

 

The chart below sets forth the dividends paid on APS’s common stock for each of the four quarters for 2011 and 2010.

 

Common Stock Dividends

(Dollars in Thousands)

 

Quarter

 

2011

 

2010

 

1st Quarter

 

$

57,100

 

 

$

42,500

 

 

2nd Quarter

 

57,200

 

 

56,900

 

 

3rd Quarter

 

57,300

 

 

56,900

 

 

4th Quarter

 

57,300

 

 

26,100

 

 

 

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, 2011, APS did not have any outstanding preferred stock.

 

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Issuer Purchases of Equity Securities

 

The following table contains information about our purchases of our common stock during the fourth quarter of 2011.

 

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, 2011

 

 

 

 

 

November 1 — November 30, 2011

 

 

 

 

 

December 1 — December 31, 2011

 

2,433

 

$

47.80

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

2,433

 

$

47.80

 

 

 

 


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

 

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ITEM 6.  SELECTED FINANCIAL DATA

PINNACLE WEST CAPITAL CORPORATION - CONSOLIDATED

 

 

 

2011

 

2010

 

2009

 

2008

 

2007

 

 

 

(dollars in thousands, except per share amounts)

 

OPERATING RESULTS

 

 

 

 

 

 

 

 

 

 

 

Operating revenues:

 

 

 

 

 

 

 

 

 

 

 

Regulated electricity

 

$

3,237,194

 

$

3,180,678

 

$

3,149,187

 

$

3,127,383

 

$

2,918,163

 

Marketing and trading

 

 

 

 

66,897

 

138,247

 

Other revenues

 

4,185

 

8,521

 

4,469

 

2,253

 

999

 

Total operating revenues

 

$

3,241,379

 

$

3,189,199

 

$

3,153,656

 

$

3,196,533

 

$

3,057,409

 

Income from continuing operations

 

$

355,634

 

$

344,851

 

$

256,048

 

$

277,366

 

$

302,360

 

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

 

11,306

 

25,358

 

(183,284

)

(17,746

)

20,631

 

Net income

 

366,940

 

370,209

 

72,764

 

259,620

 

322,991

 

Less: Net income attributable to noncontrolling interests

 

27,467

 

20,156

 

4,434

 

17,495

 

15,848

 

Net income attributable to common shareholders

 

$

339,473

 

$

350,053

 

$

68,330

 

$

242,125

 

$

307,143

 

 

 

 

 

 

 

 

 

 

 

 

 

COMMON STOCK DATA

 

 

 

 

 

 

 

 

 

 

 

Book value per share — year-end

 

$

34.98

 

$

33.86

 

$

32.69

 

$

34.16

 

$

35.15

 

Earnings per weighted-average common share outstanding:

 

 

 

 

 

 

 

 

 

 

 

Continuing operations attributable to common shareholders — basic

 

$

3.01

 

$

3.05

 

$

2.34

 

$

2.58

 

$

2.86

 

Net income attributable to common shareholders — basic

 

$

3.11

 

$

3.28

 

$

0.68

 

$

2.40

 

$

3.06

 

Continuing operations attributable to common shareholders — diluted

 

$

2.99

 

$

3.03

 

$

2.34

 

$

2.57

 

$

2.84

 

Net income attributable to common shareholders — diluted

 

$

3.09

 

$

3.27

 

$

0.67

 

$

2.40

 

$

3.05

 

Dividends declared per share

 

$

2.10

 

$

2.10

 

$

2.10

 

$

2.10

 

$

2.10

 

Weighted-average common shares outstanding — basic

 

109,052,840

 

106,573,348

 

101,160,659

 

100,690,838

 

100,255,807

 

Weighted-average common shares outstanding — diluted

 

109,864,243

 

107,137,785

 

101,263,795

 

100,964,920

 

100,834,871

 

 

 

 

 

 

 

 

 

 

 

 

 

BALANCE SHEET DATA

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

13,111,018

 

$

12,392,998

 

$

12,035,253

 

$

11,780,876

 

$

11,324,278

 

Liabilities and equity:

 

 

 

 

 

 

 

 

 

 

 

Current liabilities

 

$

1,342,705

 

$

1,449,704

 

$

1,279,288

 

$

1,582,661

 

$

1,408,429

 

Long-term debt less current maturities

 

3,019,054

 

3,045,794

 

3,496,524

 

3,183,386

 

3,300,663

 

Deferred credits and other

 

4,818,673

 

4,122,274

 

3,831,437

 

3,443,860

 

2,955,119

 

Total liabilities

 

9,180,432

 

8,617,772

 

8,607,249

 

8,209,907

 

7,664,211

 

Total equity

 

3,930,586

 

3,775,226

 

3,428,004

 

3,570,969

 

3,660,067

 

Total liabilities and equity

 

$

13,111,018

 

$

12,392,998

 

$

12,035,253

 

$

11,780,876

 

$

11,324,278

 

 


(a)                Amounts primarily related to SunCor’s real estate impairment charges (see Note 22) and APSES discontinued operations (see Note 21).

 

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Table of Contents

 

SELECTED FINANCIAL DATA

ARIZONA PUBLIC SERVICE COMPANY - CONSOLIDATED

 

 

 

2011

 

2010

 

2009

 

2008

 

2007

 

 

 

(dollars in thousands)

 

OPERATING RESULTS

 

 

 

 

 

 

 

 

 

 

 

Electric operating revenues

 

$

3,237,241

 

$

3,180,807

 

$

3,149,500

 

$

3,133,496

 

$

2,936,277

 

Fuel and purchased power costs

 

1,009,464

 

1,046,815

 

1,178,620

 

1,289,883

 

1,151,392

 

Other operating expenses

 

1,673,394

 

1,584,955

 

1,501,081

 

1,376,257

 

1,326,934

 

Operating income

 

554,383

 

549,037

 

469,799

 

467,356

 

457,951

 

Other income

 

24,974

 

20,138

 

13,893

 

836

 

20,870

 

Interest expense — net of allowance for borrowed funds

 

215,584

 

213,349

 

213,258

 

188,353

 

179,033

 

Net income

 

363,773

 

355,826

 

270,434

 

279,839

 

299,788

 

Less: Net income attributable to noncontrolling interests

 

27,524

 

20,163

 

19,209

 

17,495

 

15,848

 

Net income attributable to common shareholder

 

$

336,249

 

$

335,663

 

$

251,225

 

$

262,344

 

$

283,940

 

 

 

 

 

 

 

 

 

 

 

 

 

BALANCE SHEET DATA

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

13,032,237

 

$

12,271,877

 

$

11,730,500

 

$

11,124,360

 

$

10,476,274

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities and equity:

 

 

 

 

 

 

 

 

 

 

 

Total equity

 

$

4,051,406

 

$

3,916,037

 

$

3,527,679

 

$

3,416,751

 

$

3,425,328

 

Long-term debt less current maturities

 

2,828,507

 

2,948,991

 

3,180,406

 

2,850,242

 

2,876,881

 

Palo Verde sale leaseback lessor notes less current maturities

 

65,547

 

96,803

 

126,000

 

151,783

 

173,538

 

Total capitalization

 

6,945,460

 

6,961,831

 

6,834,085

 

6,418,776

 

6,475,747

 

Current liabilities

 

1,322,714

 

1,234,865

 

1,070,970

 

1,344,501

 

1,112,489

 

Deferred credits and other

 

4,764,063

 

4,075,181

 

3,825,445

 

3,361,083

 

2,888,038

 

Total liabilities and equity

 

$

13,032,237