10-K 1 c09734e10vk.htm FORM 10-K Form 10-K
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
FORM 10-K
(Mark One)
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
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   Registrants; State of Incorporation;   IRS Employer
File Number   Addresses; and Telephone Number   Identification No.
1-8962
  PINNACLE WEST CAPITAL CORPORATION   86-0512431
 
  (An Arizona corporation)    
 
  400 North Fifth Street, P.O. Box 53999     
 
  Phoenix, Arizona 85072-3999    
 
  (602) 250-1000     
1-4473
  ARIZONA PUBLIC SERVICE COMPANY   86-0011170
 
  (An Arizona corporation)    
 
  400 North Fifth Street, P.O. Box 53999     
 
  Phoenix, Arizona 85072-3999    
 
  (602) 250-1000     
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 þ   No o
ARIZONA PUBLIC SERVICE COMPANY
  Yes þ   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 þ
ARIZONA PUBLIC SERVICE COMPANY
  Yes o   No þ
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 þ   No o
ARIZONA PUBLIC SERVICE COMPANY
  Yes þ   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 þ   No o
ARIZONA PUBLIC SERVICE COMPANY
  Yes o   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. þ
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 þ   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 þ   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 þ
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
  $3,935,855,234 as of June 30, 2010 
ARIZONA PUBLIC SERVICE COMPANY
  $0 as of June 30, 2010 
The number of shares outstanding of each registrant’s common stock as of February 15, 2011
     
PINNACLE WEST CAPITAL CORPORATION
  108,780,623 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 18, 2011 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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 Exhibit 10.6.5
 Exhibit 10.9.1C
 Exhibit 10.11.4
 Exhibit 12.1
 Exhibit 12.2
 Exhibit 12.3
 Exhibit 21.1
 Exhibit 23.1
 Exhibit 23.2
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 31.3
 Exhibit 31.4
 Exhibit 32.1
 Exhibit 32.2
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT
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
     
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
Base Fuel Rate
  The portion of APS’s retail base rates attributable to fuel and purchased power costs
Cholla
  Cholla Power Plant
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)
Pinnacle West Marketing & Trading
  Pinnacle West Marketing & Trading Co., LLC, a subsidiary of the Company
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
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 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 greenhouse gas emissions, renewable energy mandates and energy efficiency standards;
  our ability to meet renewable energy requirements 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 burdensome 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 substantially 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.
                         
    Year Ended December 31,  
Operating Revenues (in thousands):   2010     2009     2008  
APS
  $ 3,180,807     $ 3,149,500     $ 3,133,496  
Percentage of Pinnacle West Consolidated
    97 %     99 %     97 %
Pinnacle West’s other first-tier subsidiaries are SunCor, APSES 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. In 2009 our real-estate subsidiary, SunCor, began disposing of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to reduce its outstanding debt (see Note 23). All of SunCor’s operations are reflected as discontinued operations. As a result, the real estate segment is no longer a reportable segment. See Note 17 for financial information of our business segments.
BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY
APS currently provides electric service to approximately 1.1 million customers. We own or lease more than 6,290 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 2010, no single purchaser or user of energy accounted for more than 1.2% 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.
(MAP)

 

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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 2010 were as follows:
(PIE CHART)
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 Southern California Edison (“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 unless any of the other owners of interests in Units 4 and 5 exercise their rights of first refusal prior to March 8, 2011, in which case APS would not be able to purchase SCE’s entire share of the Units. 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 for a lease renewal period described below, expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and other typical closing conditions.

 

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APS, on behalf of the Four Corners participants, has negotiated amendments to an existing facility lease with the Navajo Nation which would extend the Four Corners leasehold interest 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 occurred on February 15, 2011 and is awaiting final signature by the Nation’s President. 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 will be conducted 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 will 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 2011, with options to extend 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 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 environmental and climate change developments and lease renewal negotiations with the Navajo Nation 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 interest in that Unit. APS has a total entitlement from Palo Verde of 1,146 MW.

 

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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. Prior to 2010, APS accounted for these arrangements as operating leases. Due to amended VIE accounting guidance, in 2010 APS began consolidating the lessor trust entities, and eliminated lease accounting for these transactions. The agreements have terms of 29.5 years 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 Licenses Operation of each of the three Palo Verde Units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987. 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. The current NRC schedule for the applications estimates that a final NRC decision will be issued in April 2011. APS is making preparations to secure resources necessary to operate the plant for the period of extended operation, including the execution in April 2010 of a Municipal Effluent Purchase and Sale Agreement that provides effluent water rights necessary for cooling purposes at Palo Verde through 2050.
Palo Verde Fuel Cycle — 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 are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The Palo Verde participants have contracted for all of Palo Verde’s requirements for uranium concentrates through 2011 and 95% of its requirements through 2017. A new contract is currently being negotiated that will cover Palo Verde’s remaining requirements for uranium concentrates through 2017. The participants have also contracted for all of Palo Verde’s conversion services through 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.

 

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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 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.
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 December 2047 (assuming the NRC approves APS’s request for renewed operating licenses, as discussed above). 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 Costs APS currently relies on an external sinking fund mechanism to meet the NRC financial assurance requirements for decommissioning its interests in Palo Verde Units 1, 2 and 3. The decommissioning costs of Palo Verde Units 1, 2 and 3 are currently included in APS’s ACC jurisdictional rates. Decommissioning costs are recoverable through a non-bypassable system benefits charge (one paid by all retail customers taking service from the APS system), which allows APS to maintain its external sinking fund mechanism. See Note 12 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.
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 combustion turbine unit and one 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.

 

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Solar Facilities
APS owns and operates more than sixty 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 less than 1 MW of 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, upon completion, 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.
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. APS does not expect to require new conventional generation sources sooner than 2017, due primarily to planned additions of renewable resources and energy efficiency initiatives.
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     223  
     
(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.

 

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(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 2010 peak one-hour demand on its electric system was recorded on July 15, 2010 at 6,936 MW, compared to the 2009 peak of 7,218 MW recorded on July 27, 2009. APS’s operable generating capacity, together with firm purchases totaling 2,974 MW, including short-term seasonal purchases and unit contingent purchases, resulted in an actual reserve margin, at the time of the 2010 peak demand, of 21.8%. 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.
Future Resources and Resource Plan
Under the ACC’s modified resource planning rule, APS will file by April 1st of each even year its resource plans for the next fifteen-year period. The ACC’s modified rule also requires APS to file its first resource plan within 120 days after the rule becomes effective. The modified rule became effective in January 2011 and APS will likely file a resource plan in the first quarter of 2011. The modified rule also 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.

 

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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% of retail electric sales in 2011 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. (See Note 3.) 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 25% of the overall RES requirement of 3% in 2011 and increases to 30% of the applicable RES requirement in 2012 and subsequent years. The following table summarizes these requirement standards and their timing:
                                 
    2011     2015     2020     2025  
 
RES as a % of retail electric sales
    3 %     5 %     10 %     15 %
Percent of RES to be supplied from distributed energy resources
    25 %     30 %     30 %     30 %
Renewable Energy Portfolio. APS has a diverse portfolio of existing and planned renewable resources totaling 875 MW, including wind, geothermal, solar, biomass and biogas. Of this portfolio, 288 MW are currently in operation and 587 MW are under contract for development or are under construction. Renewable resources in operation include 5 MW of facilities owned by APS, 223 MW of long-term purchased power agreements, and an estimated 60 MW of customer-sited, third-party owned distributed energy resources.
APS continues to actively consider opportunities to enhance its renewable energy portfolio, both to ensure its compliance with the RES and to meet the needs of its customer base. 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. One of the key programs under which APS will own solar resources is the “AZ Sun Program.” As approved by the ACC, the AZ Sun Program will allow APS to own 100 MW of solar photovoltaic power plants across Arizona by investing up to $500 million through 2014. 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 $377 million. See Note 3 for additional details about the AZ Sun Program, including the related cost recovery.
The following table summarizes APS’s renewable energy sources in operation and under development. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the projects to the electric grid.

 

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            Actual/             Net     Net Capacity  
            Target             Capacity     Planned/  
            Commercial             In     Under  
            Operation     Term     Operation     Development  
    Location     Date     (Years)     (MW)     (MW)  
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     2012/2013 (a)                     14  
 
                                     
Subtotal AZ Sun Program (b)
                                    83  
Multiple Facilities
  AZ       Various               5          
 
                                   
Total APS Owned
                            5       83  
 
                                   
 
                                       
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  
Wind:
                                       
Aragonne Mesa
  Santa Rosa, NM     2006       20       90          
High Lonesome
  Mountainair, NM     2009       30       100          
Perrin Ranch Wind
  Williams, AZ     2011       25               99  
Geothermal:
                                       
Salton Sea
  Imperial County, CA     2006       23       10          
Biomass:
                                       
Snowflake
  Snowflake, AZ     2008       15       10          
Snowflake
  Snowflake, AZ     2008       1       10          
Biogas:
                                       
Glendale Landfill
  Glendale, AZ     2010       20       3          
Landfill 1 (d)
  Surprise, AZ     2012       20               3  
 
                                   
Total Purchased Power Agreements
                            223       382  
 
                                   
 
                                       
Distributed Energy
                                       
Solar:
                                       
APS Owned (e)
  AZ   various                       1  
Third-party Owned (f)
  AZ   various               60       66  
Agreement 1
  Bagdad, AZ     2012       25               15  
Agreement 2 (g)
  AZ     2012-2014       20-25               40  
 
                                   
Total Distributed Energy
                            60       122  
 
                                   
Total Renewable Portfolio
                            288       587  
 
                                   
     
(a)   The timing is dependent on site preparation activities.
 
(b)   Under the AZ Sun Program, 17 MW remains to be fulfilled.
 
(c)   Represents contracted capacity.
 
(d)   Details of these agreements have not yet been publicly announced.
 
(e)   Reflects Community Power Project. See Note 3.
 
(f)   Achieved through incentive-based programs. Includes resources with production-based incentives that have terms of 10-20 years.
 
(g)   Agreement ramps up to 40 MW over 3 years.

 

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Demand Side Management
Arizona regulators are placing 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 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 APS’s 2009 retail rate case settlement.)
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.
In 2009, the DOE announced an ARRA commitment to fund the majority of a carbon dioxide emission reduction research and development project in the amount of $71 million, which was to be located at our Cholla power plant. Due to the increased resource and funding requirements for a project of that size, APS elected not to move forward with that award and is now in the process of closing out the project. However, APS is moving forward with work under the $3 million award from DOE for a high penetration photovoltaic generation study related to the Community Power Project in Flagstaff, Arizona. The funding under this DOE award will continue to be contingent upon meeting certain project milestones, including DOE-established budget parameters, over the next four years.
APS is also continuing its work as a sub-recipient under an ARRA award received through the State of Arizona’s Department of Commerce. This approximately $4 million award is for the implementation of various distributed energy and energy efficiency programs in Arizona. APS will be implementing certain solar water heater and photovoltaic-related community projects under this award.
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 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.

 

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APS is subject to varying degrees of competition from other investor-owned electric and gas utilities in Arizona (such as Southwest Gas Corporation), as well as cooperatives, municipalities, electrical districts and similar types of governmental or non-profit organizations. In addition, some customers, particularly industrial and large commercial customers, may own and operate generation facilities to meet some or all of their own energy requirements. This practice is becoming more popular with customers installing or having installed products such as 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.

 

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Wholesale
The FERC regulates rates for wholesale power sales and transmission services. (See Note 3 for information regarding APS’s transmission rates.) During 2010, approximately 5.8% 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 markets, hedges and trades in electricity and fuels.
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. In 2009, the House of Representatives passed a comprehensive energy and climate change bill, but the Senate did not consider it or a similar bill in the 111th Congress. With much focus on the economy, it is unclear when Congress will consider another global warming bill. The actual economic and operational impact of any legislation on APS depends on a variety of factors, none of which can be fully known until such legislation passes 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. At the present time, we cannot predict what form of legislation, if any, will ultimately pass.
In addition to federal legislative initiatives, state-specific initiatives may also impact our business. While Arizona has not yet enacted any state-specific legislation regarding greenhouse gas emissions, the California legislature enacted AB 32 and SB 1368 in 2006 to address greenhouse gas emissions. In December 2010, the California Air Resources Board approved regulations that will establish a cap-and-trade program for greenhouse gas emissions which is scheduled to be launched in 2012 as part of the state’s program implementing AB32. In addition, the New Mexico Environmental Improvement Board recently enacted a greenhouse gas cap-and-trade program and emissions cap, to become effective in 2012 and 2013, respectively.
We are monitoring these 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.)

 

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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 the 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.
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. At the present time, we cannot predict what other rules or regulations may ultimately result from the EPA’s endangerment finding, whether the parties challenging the endangerment finding or the tailoring rule will be successful, and what impact other potential rules or regulations will have on APS’s operations.
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 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.
The EPA also recently announced its intent to promulgate New Source Performance Standards (“NSPS”) for greenhouse gas emissions from certain industrial facilities, under the Clean Air Act. The EPA intends to propose the new standards by July 2011 and to finalize them by May 2012. The EPA has indicated that the rules will apply to coal-fired electric generating units (“EGUs”) and will establish NSPS for new and modified EGUs and emission guidelines for existing EGUs. The rules are expected to apply to the Four Corners, Cholla and the Navajo Plant. We cannot currently predict the impact of these rules 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.

 

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Regional Initiative. In 2007, six western states (Arizona, California, New Mexico, Oregon, Utah and Washington) and two Canadian provinces (British Columbia and Manitoba) entered into an accord, the Western Climate Initiative (“WCI”), to reduce greenhouse gas emissions from automobiles and certain industries, including utilities. Montana, Quebec and Ontario have also joined WCI. WCI participants set a goal of reducing greenhouse gas emissions 15% below 2005 levels by 2020. After soliciting public comment, in September 2008 WCI issued the design of a cap-and-trade program for greenhouse gas emissions. Due in part to the recent activity at the federal level discussed above, the initiative’s momentum and the movement toward detailed proposed rules has slowed. On February 2, 2010, Arizona’s Governor issued an executive order stating that Arizona will continue to be a member of WCI to monitor its advancements in this area, but it will not implement the WCI regional cap-and-trade program. As a result, while we continue to monitor the progress of WCI, at the present time we do not believe it will have a material impact on our operations.
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.
In January 2008, APS joined the Climate Registry as a Founding Reporter. Founding Reporters are companies that voluntarily joined the non-profit organization before May 2008 to measure and report greenhouse gas emissions in a common, accurate and transparent manner consistent across industry sectors and borders. Beginning in 2010, APS stopped participating in the Climate Registry because APS began reporting substantially the same information under the mandatory greenhouse gas reporting rule issued by the EPA on September 22, 2009. 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 Lawsuits. 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. 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. The court has not yet scheduled oral arguments on the plaintiffs’ appeal. We believe the action is without merit and intend to continue to defend against the claims.
A similar nuisance lawsuit, American Electric Power Co., Inc. v. Connecticut, is currently pending in the United States Supreme Court. Another such lawsuit was dismissed by the Fifth Circuit on procedural grounds. Both cases, as well as the Kivalina case, raise political and legal considerations, including whether the courts can or should be making climate change policy decisions. The outcome of the American Electric Power case is particularly significant because the issues being considered by the Supreme Court closely overlap with the main issues presented in the Kivalina appeal. We are not a party to either of these two lawsuits, but are monitoring these developments and their potential industry impacts.

 

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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.
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 has reviewed APS’s recommendations and is expected to submit to EPA Region 9 its proposed BART State Implementation Plan (“SIP”) for Cholla and other sources within the state in the near future. On January 19, 2011, a group of environmental organizations notified EPA of its intent to sue the agency as a result of EPA’s alleged failure to promulgate a Federal Implementation Plan for states that have not yet submitted all or part of the required BART SIPs, including Arizona.
Once APS receives a final determination as to what constitutes BART for Cholla, we will have five years to complete the installation of the equipment and to achieve the emission limits established by ADEQ. 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. EPA Region 9 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 anticipated mercury rules. (See “Environmental Matters — Mercury and Other Hazardous Air Pollutants” below for additional information on these anticipated 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.

 

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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.
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. The EPA extended the comment deadline for both the October 2010 proposal and the Supplemental Notice to May 2, 2011. We are currently evaluating both proposals and will be providing comments to the EPA on both.
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 five years after the EPA issues its final determinations to achieve compliance with their respective BART requirements.
In addition, on February 16, 2010, a group of environmental organizations filed a petition with the Departments of Interior and Agriculture requesting those agencies to certify to the EPA that visibility impairment in sixteen national park and wilderness areas is reasonably attributable to emissions from Four Corners, the Navajo Plant and other non-APS plants. If the agencies certify impairment, the EPA is required to evaluate and, if necessary, determine BART for Four Corners and the Navajo Plant under a different haze program known as “Reasonably Attributable Visibility Impairment.” On January 19, 2011, a similar group of environmental organizations filed a lawsuit against the Departments of Interior and Agriculture, alleging among other things that the agencies failed to act on the February 2010 petition “without unreasonable delay” and requesting the court to order the agencies to act on the petition within 30 days. We are currently evaluating the potential impact of this lawsuit on APS.
The Four Corners and Navajo Plant participants’ obligations to comply with the EPA’s final BART determinations, coupled with the financial impact of future climate change legislation, other environmental regulations, the result of the lawsuit mentioned above 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.
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).

 

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Mercury and other Hazardous Air Pollutants. In early 2008, the U.S. Court of Appeals for the D.C. Circuit vacated the Clean Air Mercury Rule (“CAMR”), which was adopted by the EPA to regulate mercury emissions from coal-fired power plants. As a result, the law in effect prior to the adoption of the CAMR became the applicable law, and the EPA is now required to adopt final maximum achievable control technology emissions (“MACT”) standards. Under a consent decree that was finalized on April 15, 2010, the EPA has agreed to issue final MACT standards for mercury and other hazardous air pollutants by November 2011. Under the terms of the consent decree, APS will have three years after the EPA issues its final rule to achieve compliance, which would likely 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 anticipated 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).
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 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. We do not know when the EPA will issue a final rule, including required compliance dates. 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 or NAAQS. In January 2010, the EPA proposed to adopt even more stringent eight-hour ozone NAAQS. 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 operations.

 

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New Source Review. On 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 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 May 7, 2010, APS received a Notice of Intent to Sue from Earthjustice, on behalf of several environmental organizations, related to alleged violations of the Clean Air Act at Four Corners (the “Notice”). The Notice alleges New Source Review-related violations and NSPS violations. Under the Clean Air Act, a citizens group is required to provide 60 days advance notice of its intent to file a lawsuit. Within that 60-day time period, the EPA may step in and file a lawsuit regarding the allegations. If the EPA does so, the citizens group is precluded from filing its own lawsuit, but it may still intervene in the EPA’s lawsuit, if it so desires. The 60-day period lapsed in early July 2010, and the EPA did not take any action. At this time, we cannot predict whether or when Earthjustice might file a lawsuit.
Endangered Species Act. On January 30, 2011, the Center for Biological Diversity, Dine Citizens Against Running Our Environment, and San Juan Citizens Alliance field a lawsuit against the Office of Surface Mining Reclamation and Enforcement (“OSM”) and the Department of the Interior, 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 are evaluating the lawsuit to determine its potential impact on plant operations.
Superfund. The Comprehensive Environmental Response, Compensation and Liability Act (“Superfund”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are 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, which is reserved as a liability on its financial statements. 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.
By letter dated April 25, 2008, the EPA informed APS that it may be a PRP in the Gila River Indian Reservation Superfund Site in Maricopa County, Arizona. APS, along with three other electric utility companies, owns a parcel of property on which a transmission pole and a portion of a transmission line are located. The property abuts the Gila River Indian Community boundary and, at one time, may have been part of an airfield where crop dusting took place. Currently, the EPA is only seeking payment from APS and four other PRPs for past cleanup-related costs involving contamination from the crop dusting. Based upon the total amount of cleanup costs reported by the EPA in its letter to APS, we do not expect that the resolution of this matter will have a material adverse impact on APS’s financial position, results of operations, or cash flows.
Manufactured Gas Plant Sites. Certain properties which APS now owns or which were previously owned by it or its corporate predecessors were at one time sites of, or sites associated with, manufactured gas plants. APS is taking action to voluntarily remediate these sites. APS does not expect these matters to have a material adverse effect on its financial position, results of operations, cash flows or liquidity.

 

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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.

 

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San Juan River Adjudication. Both groundwater and surface water in areas important to APS’s operations have been the subject of inquiries, claims and legal proceedings, which will require a number of years to resolve. APS is one of a number of parties in a proceeding, filed March 13, 1975, before the Eleventh Judicial District Court in New Mexico to adjudicate rights to a stream system from which water for Four 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. A number of parties are in the process of settlement negotiations with respect to certain claims in this matter. Other claims have been identified as ready for litigation in motions filed with the court. No trial date concerning APS’s water rights claims has been set in this matter.
Although the above matters remain subject to further evaluation, APS does not expect that the described litigation will have a material adverse impact on its financial position, results of operations, cash flows or liquidity.
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.

 

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APSES
APSES provides energy-related products and services (such as energy master planning, energy use consultation and facility audits, cogeneration analysis and installation, and project management) with a focus on energy efficiency and renewable energy to commercial and industrial retail customers in the western United States. On June 22, 2010, APSES sold its district cooling business consisting of operations in downtown Phoenix, Tucson, and on certain Arizona State University campuses. This sale resulted in an after-tax gain of approximately $25 million.
Financial Summary.
                         
    2010     2009     2008  
    (dollars in millions)  
Net income (loss)
  $ 30     $ (2 )   $ (1 )
Total assets at December 31
  $ 43     $ 74     $ 70  
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.
Financial Summary.
                         
    2010     2009     2008  
    (dollars in millions)  
Revenues (a)
  $ 102     $ 158     $ 242  
Net loss attributable to common shareholders (b)
  $ (9 )   $ (279 )   $ (26 )
Total assets at December 31 (c)
  $ 16     $ 166     $ 547  
     
(a)   All reported as discontinued operations on Pinnacle West’s Consolidated Statements of Income. (See Note 22).
 
(b)   These amounts include $266 million (pre-tax) and $53 million (pre-tax) real estate impairment charges for 2009 and 2008, respectively.
 
(c)   The reduction in assets in 2010 is primarily due to asset sales. The $16 million of assets at December 31, 2010 consists primarily of $8 million of intercompany receivables, $3 million of assets held for sale and $5 million of other assets.
In 2010 and 2009, income tax benefits related to SunCor operations were recorded by Pinnacle West in accordance with an intercompany tax sharing agreement. See “Liquidity and Capital Resources — Other Subsidiaries — SunCor” in Item 7 for a discussion of SunCor’s long-term debt, liquidity and capital requirements, and the SunCor-related risk factor in Item 1A for a discussion of risks facing SunCor.

 

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El Dorado
El Dorado owns minority interests in several energy-related investments and Arizona community-based ventures. El Dorado’s short-term goal is to prudently realize the value of its existing investments. On a long-term basis, Pinnacle West may use El Dorado, when appropriate, for investments that are strategic to the business of generating, distributing and marketing electricity.
Financial Summary.
                         
    2010     2009     2008  
    (dollars in millions)  
Net income (loss)
  $ 2     $ (7 )   $ (10 )
Total assets at December 31
  $ 19     $ 19     $ 28  
Income taxes related to El Dorado are recorded by Pinnacle West.
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:
                         
                    Approximate  
                    Number of  
    Principal Executive Office     Year of     Employees at  
    Address     Incorporation     December 31, 2010  
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       6,600  
 
                       
APSES
  60 E. Rio Salado Parkway
Suite 1001
Tempe, AZ 85281
    1998       50  
 
                       
SunCor
  80 East Rio Salado Parkway
Suite 410
Tempe, AZ 85281
    1965       10  
 
                       
El Dorado
  400 North Fifth Street Phoenix, AZ 85004     1983        
 
                     
Total
                    6,740  
 
                     
The APS number includes employees at jointly-owned generating facilities (approximately 3,100 employees) for which APS serves as the generating facility manager. Approximately 1,940 APS employees are union employees. The collective bargaining agreement with union employees in the fossil generation, energy delivery and customer service business areas expires in April 2011, and the parties began negotiating a successor agreement in February 2011. The agreement with union employees serving as Palo Verde security officers expires in 2013.

 

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WHERE TO FIND MORE INFORMATION
We use our website www.pinnaclewest.com as a channel of distribution for material Company information. The following filings are available free of charge on our website as soon as reasonably practicable after they are electronically filed with, or furnished to, the 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. Consequently, our financial condition and results of operations are dependent upon the satisfactory resolution of any APS retail 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 and 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 and regulations, 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 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, APS is required to have numerous permits, approvals and certificates from these agencies. APS believes the necessary permits, approvals and certificates have been obtained for its existing operations and that APS’s business is conducted in accordance with applicable laws in all material respects. However, changes in regulations or the imposition of new or revised laws or regulations could have an adverse impact on our results of operations. We are also unable to predict the impact on our business and operating results from pending or future regulatory activities of any of these agencies.
The operation of APS’s nuclear power plant exposes it to substantial regulatory oversight and potentially significant liabilities and capital expenditures.
The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, 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.

 

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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.
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 a final rulemaking from ADEQ 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 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.
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. A civilian organization notified the Four Corners participants that it intends to file a citizen suit against the participants for alleged violations of New Source Review and the NSPS program 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 citizen suit is filed and the citizens’ group prevails, significant capital investments could be required to install new pollution control technologies. The EPA could also seek civil penalties.
Mercury and other Hazardous Air Pollutants. The EPA is required to adopt maximum achievable control technology emissions standards for mercury and other hazardous air pollutants by November 2011. Compliance with the new standards will be required three years after the EPA issues its final rule. Depending on the compliance requirements contained in the final rule, APS may need to make significant capital investments to install additional pollution control equipment to meet these new standards.
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.

 

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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, which was dismissed but has been appealed.
Financial Risks — Potential Legislation and Regulation. In the past several years, the United States Congress has considered bills that would regulate domestic greenhouse gas emissions. It is possible that some form of legislation may occur in the future at the federal level with respect to greenhouse gas emissions.
If the United States Congress, or individual states or groups of states in which APS operates, ultimately pass legislation 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 expiration of the current lease term in 2016.
In addition, the EPA has 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 the 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. Several groups have filed lawsuits challenging the EPA’s endangerment finding. APS cannot predict what rules or regulations may ultimately result from the EPA’s endangerment finding, whether the parties challenging the endangerment finding will be successful, or what impact other potential rules or regulations will have on APS’s operations. Excessive costs to comply with future legislation or regulations could force APS and other similarly-situated electric power generators to retire or suspend operations at certain coal-fired facilities.
Physical and Operational Risks. Assuming that the primary physical and operational risks to APS from climate change are increased potential for drought or water shortage, and a mild to moderate increase in ambient temperatures, APS believes it is taking the appropriate steps to respond to these 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.

 

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If APS cannot meet or maintain the level of renewable energy required under Arizona’s increasing Renewable Energy Standards, APS may be subject to penalties or fines for non-compliance.
The RES requires APS to supply an increasing percentage of renewable energy each year, so that the amount of retail electricity sales from eligible renewable resources is at least 3% of total retail sales by 2011. This amount increases annually to 15% by 2025. In its 2009 retail rate case settlement agreement, APS agreed to exceed these standards and committed to an interim renewable energy target of 1,700 GWh of renewable resources to be 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. A portion of this 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 is 25% of the overall RES requirement of 3% in 2011 and increases to 30% of the applicable RES requirement in 2012 and subsequent years. If APS fails to implement any of its annual ACC-approved renewable implementation plans, it may be subject to penalties imposed by the ACC, including APS’s inability to recover certain costs. Compliance with the distributed resource requirement is contingent upon customer participation. The development of any renewable generation facilities resulting from the RES is subject to many other risks, including risks relating to financing, permitting, technology, fuel supply, and the construction of sufficient transmission capacity to support these facilities.
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.

 

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OPERATIONAL RISKS
APS’s results of operations can be adversely affected by various factors impacting demand for electricity.
Weather Conditions. Weather conditions directly influence the demand for electricity and affect the price of energy commodities. Electric power demand is generally a seasonal business. In Arizona, demand for power peaks during the hot summer months, with market prices also peaking at that time. As a result, APS’s overall operating results fluctuate substantially on a seasonal basis. In addition, APS has historically sold less power, and consequently earned less income, when weather conditions are milder. As a result, unusually mild weather could diminish APS’s results of operations.
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 results of operations.
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 ACC passed a policy statement on per customer revenue decoupling in December of 2010. The policy statement will have no effect on APS’s rates unless implemented in a rate case. The 2009 retail rate case settlement agreement also establishes energy efficiency goals for APS that begin in 2010 that extend through 2012, subjecting APS to energy efficiency requirements slightly greater for 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 is 25% of the overall RES requirement of 3% in 2011 and increases to 30% of the applicable RES requirement in 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, could have a material adverse impact on APS’s financial condition, results of operations and cash flows.
The operation of power generation facilities involves risks that could result in unscheduled power outages or reduced output, which could materially affect APS’s results of operations.
The operation of power generation 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. 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 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 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’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 discussions with the appropriate Indian tribes and approval by their respective 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 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.
The operation of Palo Verde requires licenses that need to be periodically renewed and/or extended. In December 2008, APS applied for renewed operating licenses for all three Palo Verde units for 20 years beyond the expirations of the current licenses. APS does not anticipate any problems renewing these licenses. However, as a result of potential terrorist threats and increased public scrutiny of utilities, the licensing process could result in increased licensing or compliance costs that are difficult to predict.

 

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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 yet to be developed, 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 could reduce the demand for power supply, which could adversely affect APS’s business.
APS is pursuing and implementing smart grid technologies, including advanced transmission and distribution system technologies, 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.

 

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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.
In the regular course of our business we handle a range of sensitive security and customer 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 information or system operating information could have a material adverse impact on our business and financial condition.
FINANCIAL RISKS
Financial market disruptions may increase our financing costs or limit our access to the credit and capital markets, which may adversely affect our liquidity and our ability to implement our financial strategy.
We rely on access to short-term money markets, longer-term capital markets and the bank market as a significant source of liquidity and for capital requirements not satisfied by the cash flow from our operations. We believe that we will maintain sufficient access to these financial markets. However, certain market disruptions may increase our cost of borrowing or adversely affect our ability to access one or more financial markets. Such disruptions could include:
    continuation of the current economic downturn;
    terrorist attacks or threatened attacks;
    mergers among financial institutions and the overall health of the banking industry; or
    the overall health of the utility industry.
In addition, the credit commitments of our lenders under our bank facilities may not be satisfied for a variety of reasons, including unexpected periods of financial distress affecting our lenders, which could materially adversely affect the adequacy of our liquidity sources.

 

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Changes in economic conditions 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:
    reducing 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 reduction in 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 in future financings, and our potential pool of investors and funding sources could decrease. In addition, borrowing costs under certain of 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 completely eliminate any possible future 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.
Market performance, changing interest rates and other economic factors could decrease the value of our benefit plan assets and nuclear decommissioning trust funds and increase our related obligations, resulting in significant additional funding that could negatively impact our business.
Disruptions in the capital markets and/or decline in market value may adversely affect the values of fixed income and equity investments held in our employee benefit plan trusts and nuclear decommissioning trusts. We have significant obligations in these areas and hold substantial assets in these trusts. A decline in the market value of the investments in these trusts may increase our funding requirements. Additionally, the pension plan and other postretirement benefit liabilities are impacted by the discount rate, which is the interest rate used to discount future pension and other postretirement benefit obligations. Declining interest rates impact the discount rate, 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 assumptions, may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans. A significant portion of the pension costs and other postretirement benefit costs and all of the nuclear decommissioning costs are recovered in regulated electricity prices. Our inability to fully recover these costs in a timely manner or any increased funding obligations could negatively impact our financial condition, results of operations or cash flows.

 

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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 in 2014. In the meantime, the FASB and the IASB are working on several accounting standards jointly to converge certain accounting differences before 2014. 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. Substantially all of our consolidated assets are held by APS. Accordingly, our cash flow 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.
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 assets and 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;

 

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    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;
    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 reduce its outstanding debt. As of December 31, 2010, SunCor had no existing bank debt and had total assets remaining on its books of $16 million, consisting of $8 million of intercompany receivables, $3 million of assets held for sale and $5 million of other assets. 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. As a result, SunCor may seek judicial protection to effectuate a resolution of any claims that cannot be successfully addressed by other means. In such event, Pinnacle West could be exposed to the uncertainties and complexities inherent for parent companies in such proceedings.

 

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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 2010 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:
                                         
                    Principal     Primary     Owned  
    No. of     %     Fuels     Dispatch     Capacity  
Name     Units     Owned (a)     Used     Type     (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:
                                       
Multiple facilities
                  Solar   As Available     5  
 
                                     
Total Solar
                                    5  
 
                                     
Total Capacity
                                    6,293  
 
                                     
     
(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%), Southern California Public Power Authority (5.91%), and Los Angeles Department of Water & Power (5.7%). The plant is operated by APS.

 

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(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 5,992 pole miles of overhead lines and approximately 49 miles of underground lines, 5,769 miles of which are located in Arizona. APS’s distribution facilities consist of approximately 11,098 miles of overhead lines and approximately 17,417 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, 2010:
         
    Percent Owned  
    (Weighted Average)  
North Valley System
    71.2 %
Palo Verde — Estrella 500KV System
    50.0 %
Round Valley System
    50.0 %
ANPP 500KV System
    34.0 %
Navajo Southern System
    26.1 %
Four Corners Switchyards
    47.5 %
Palo Verde — Yuma 500KV System
    43.5 %
Phoenix — Mead System
    17.5 %
Expansion. Each year APS prepares and files with the ACC a ten-year transmission plan. In APS’s 2011 plan, APS projects it will invest approximately $450 million in new transmission over the next ten years, which includes 258 miles of new lines. This investment will increase the import capability into metropolitan Phoenix by approximately 6% and will increase the import capability into the Yuma area by approximately 39%. One significant project presently nearing completion is the Morgan — Pinnacle Peak project, which consists of 26 miles of 500kV and 230kV lines.
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 2011 transmission plan, are the Delany 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.

 

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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. Each of the leases contains an option to extend for an additional 25-year period from the end of the existing lease term, for a rental amount tied to the original rent payment adjusted based on an index. The easements do not contain an express renewal option and it is unclear what conditions to renewal or extension of the easements may be imposed. APS is currently working with the Navajo Nation to extend the Four Corners leases and the transmission rights-of-way discussed below for an additional twenty-five years. (See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Generation Facilities — Coal Fueled Generating Facilities” in Item 1 for details of this extension and the related required approvals.) The ultimate cost of renewal of the Navajo Plant and Four Corners leases and easements is uncertain. The coal contracted for use in these plants is also located on Indian reservations.
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. The Four Corners and Navajo Plant leases provide Navajo Nation consent to certain of the rights-of-way for transmission lines related to those plants at a specified rental rate for the original term of the rights-of-way and for a like payment in any renewal period. In addition, a 1985 amendment to the leases provides a formula for calculating payments for certain new and renewal rights-of-way. However, some of our rights-of-way 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 is uncertain. We are monitoring these rights-of-way and easement issues and have had extensive discussions with the Navajo Nation regarding them. We are currently unable to predict the outcome of this matter.
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, liability associated with the Motorola 52nd Street Superfund Site and for information regarding the bankruptcy proceeding involving the landlord for our corporate headquarters building.

 

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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 18, 2011, current positions and principal occupations for the past five years are as follows:
             
Name   Age   Position   Period
   
 
       
Donald E. Brandt  
56
  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  
57
  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  
55
  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
   
 
       
Randall K. Edington  
57
  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  
57
  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

 

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Name   Age   Position   Period
   
 
       
James R. Hatfield  
53
  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 Hatfield  
45
  Vice President, Communications of APS   2010-Present
   
 
  Director, Corporate Communications of Southern California Edison   2004-2010
   
 
       
Lee R. Nickloy  
44
  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  
55
  Senior Vice President, Fossil Operations of APS   2009-Present
   
 
  Senior Vice President of Exelon Generation and President of Exelon Power   2004-2009
   
 
       
Lori S. Sundberg  
47
  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, 2011, Pinnacle West’s common stock was held of record by approximately 26,953 shareholders.
QUARTERLY STOCK PRICES AND DIVIDENDS PAID PER SHARE STOCK SYMBOL: PNW
                                 
                            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  
                                 
                            Dividends  
2009   High     Low     Close     Per Share  
 
                               
1st Quarter
  $ 35.13     $ 22.32     $ 26.56     $ 0.525  
2nd Quarter
    30.30       25.28       30.15       0.525  
3rd Quarter
    33.71       28.87       32.82       0.525  
4th Quarter
    37.96       31.08       36.58       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 2010 and 2009.
Common Stock Dividends
(Dollars in Thousands)
                 
Quarter   2010     2009  
1st Quarter
  $ 42,500     $ 42,500  
2nd Quarter
    56,900       42,500  
3rd Quarter
    56,900       42,500  
4th Quarter
    26,100       42,500  
The sole holder of APS’s common stock, Pinnacle West, is entitled to dividends when and as declared out of legally available funds. As of December 31, 2010, 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 2010.
                                 
                    Total Number of        
    Total             Shares Purchased     Maximum Number of  
    Number of     Average     as Part of Publicly     Shares that May Yet Be  
    Shares     Price Paid     Announced Plans     Purchased Under the  
Period   Purchased (1)     per Share     or Programs     Plans or Programs  
October 1 – October 31, 2010
                       
November 1 – November 30, 2010
                       
December 1 – December 31, 2010
    1,994     $ 41.39              
 
                       
 
                               
Total
    1,994     $ 41.39              
 
                       
     
(1)   Represents shares of common stock repurchased for rescission of director stock grant.

 

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ITEM 6. SELECTED FINANCIAL DATA
PINNACLE WEST CAPITAL CORPORATION — CONSOLIDATED
                                         
    2010     2009     2008     2007     2006  
    (dollars in thousands, except per share amounts)  
OPERATING RESULTS
                                       
Operating revenues:
                                       
Regulated electricity segment
  $ 3,180,678     $ 3,149,187     $ 3,127,383     $ 2,918,163     $ 2,635,036  
Marketing and trading
                66,897       138,247       136,748  
Other revenues
    82,967       26,723       25,407       34,375       24,282  
 
                             
Total operating revenues
  $ 3,263,645     $ 3,175,910     $ 3,219,687     $ 3,090,785     $ 2,796,066  
 
                             
Income from continuing operations
  $ 350,598     $ 252,558     $ 278,335     $ 299,218     $ 279,586  
Discontinued operations — net of income taxes (a)
    19,611       (179,794 )     (18,715 )     23,773       61,935  
 
                             
Net income
    370,209       72,764       259,620       322,991       341,521  
Less: Net income attributable to noncontrolling interests
    20,156       4,434       17,495       15,848       14,266  
 
                             
Net income attributable to common shareholders
  $ 350,053     $ 68,330     $ 242,125     $ 307,143     $ 327,255  
 
                             
 
                                       
COMMON STOCK DATA
                                       
Book value per share — year-end
  $ 33.93     $ 32.69     $ 34.16     $ 35.15     $ 34.48  
Earnings per weighted-average common share outstanding:
                                       
Continuing operations attributable to common shareholders — basic
  $ 3.10     $ 2.31     $ 2.59     $ 2.83     $ 2.67  
Net income attributable to common shareholders — basic
  $ 3.28     $ 0.68     $ 2.40     $ 3.06     $ 3.29  
Continuing operations attributable to common shareholders — diluted
  $ 3.08     $ 2.30     $ 2.58     $ 2.81     $ 2.65  
Net income attributable to common shareholders — diluted
  $ 3.27     $ 0.67     $ 2.40     $ 3.05     $ 3.27  
Dividends declared per share
  $ 2.10     $ 2.10     $ 2.10     $ 2.10     $ 2.025  
Weighted-average common shares outstanding — basic
    106,573,348       101,160,659       100,690,838       100,255,807       99,417,008  
Weighted-average common shares outstanding — diluted
    107,137,785       101,263,795       100,964,920       100,834,871       100,010,108  
 
                                       
BALANCE SHEET DATA
                                       
Total assets
  $ 12,362,703     $ 11,986,324     $ 11,805,967     $ 11,355,788     $ 11,019,185  
 
                             
Liabilities and equity:
                                       
Current liabilities
  $ 1,310,736     $ 1,108,943     $ 1,527,683     $ 1,365,192     $ 943,497  
Long-term debt less current maturities
    3,045,794       3,496,524       3,183,386       3,300,663       3,426,914  
Deferred credits and other
    4,230,947       3,952,853       3,523,929       3,029,866       3,131,901  
 
                             
Total liabilities
    8,587,477       8,558,320       8,234,998       7,695,721       7,502,312  
Total equity
    3,775,226       3,428,004       3,570,969       3,660,067       3,516,873  
 
                             
Total liabilities and equity
  $ 12,362,703     $ 11,986,324     $ 11,805,967     $ 11,355,788     $ 11,019,185  
 
                             
     
(a)   Amounts primarily related to SunCor’s real estate impairment charges (see Note 23) and APSES discontinued operations (see Note 22).

 

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SELECTED FINANCIAL DATA
ARIZONA PUBLIC SERVICE COMPANY — CONSOLIDATED
                                         
    2010     2009     2008     2007     2006  
    (dollars in thousands)  
OPERATING RESULTS
                                       
Electric operating revenues
  $ 3,180,807     $ 3,149,500     $ 3,133,496     $ 2,936,277     $ 2,658,513  
Fuel and purchased power costs
    1,046,815       1,178,620       1,289,883       1,151,392       969,767  
Other operating expenses
    1,584,955       1,501,081       1,376,257       1,326,934       1,258,848  
 
                             
Operating income
    549,037       469,799       467,356       457,951       429,898  
Other income (deductions)
    20,138       13,893       836       20,870       27,584  
Interest deductions — net of AFUDC
    213,349       213,258       188,353       179,033       173,486  
 
                             
Net income
    355,826       270,434       279,839       299,788       283,996  
Less: Net income attributable to noncontrolling interests
    20,163       19,209       17,495       15,848       14,266  
 
                             
Net income attributable to common shareholder
  $ 335,663     $ 251,225     $ 262,344     $ 283,940     $ 269,730  
 
                             
 
                                       
BALANCE SHEET DATA
                                       
Total assets
  $ 12,241,582     $ 11,681,571     $ 11,149,451     $ 10,514,981     $ 10,150,051  
 
                             
 
                                       
Liabilities and equity:
                                       
Total equity
  $ 3,916,037     $ 3,527,679     $ 3,416,751     $ 3,425,328     $ 3,278,230  
Long-term debt less current maturities
    2,948,991       3,180,406       2,850,242       2,876,881       2,877,502  
Palo Verde sale leaseback lessor notes less current maturities
    96,803       126,000       151,783       173,538       194,281  
 
                             
Total capitalization
    6,961,831       6,834,085       6,418,776       6,475,747       6,350,013  
Current liabilities
    1,095,897       900,625       1,289,523       1,076,449       826,715  
Deferred credits and other
    4,183,854       3,946,861       3,441,152       2,962,785       2,973,323  
 
                             
Total liabilities and equity
  $ 12,241,582     $ 11,681,571     $ 11,149,451     $ 10,514,981     $ 10,150,051  
 
                             

 

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion should be read in conjunction with Pinnacle West’s Consolidated Financial Statements and APS’s Consolidated Financial Statements and the related Notes that appear in Item 8 of this report. For information on the broad factors that may cause our actual future results to differ from those we currently seek or anticipate, see “Forward-Looking Statements” at the front of this report and “Risk Factors” in Item 1A.
OVERVIEW
Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS accounts for substantially all of our revenues and earnings, and is expected to continue to do so.
Areas of Business Focus
Operational Performance, Reliability and Recent Developments.
Nuclear. In 2010, Palo Verde achieved its best generation year ever, producing over 31 million megawatt-hours, with an overall station capacity factor of 90.5%. The generation from each Palo Verde operating unit directly reflects the station’s currently effective 18-month refueling cycle. In 2010, Palo Verde successfully refueled both Unit 1 and Unit 3. As part of the 2010 refueling outages, Palo Verde installed new reactor vessel closure heads and simplified head assembly modifications. These projects are designed to provide safety benefits, eliminate costly inspections and reduce the duration of future outages.
Coal and Related Environmental Matters. APS-operated coal plants, Four Corners and Cholla, achieved net capacity factors of 82% and 79%, respectively, in 2010. APS is focused on the impacts on its coal fleet that may result from potential legislation and increased regulation concerning greenhouse gas emissions. Recent concern over climate change and other emission-related issues could have a significant impact on our capital expenditures and operating costs in the form of taxes, emissions allowances or required equipment upgrades for these plants. APS is closely monitoring its long range capital management plans, understanding that any resulting legislation and regulation could impact the economic viability of certain plants, as well as the willingness or ability of power plant participants to fund any such equipment upgrades. In particular, on October 6, 2010, the EPA issued its proposed determination for “Best Available Retrofit Technology” (BART) requirements for Four Corners that, as proposed, would require installation of additional pollution control equipment on all five of the plant’s units. Based on APS’s current ownership share of Four Corners, APS currently estimates that its total costs for the proposed controls could be up to approximately $400 million for nitrogen oxide controls and about $220 million for particulate removal equipment. It is currently evaluating the impacts of the proposed determination and intends to submit comments during the EPA’s comment period. See “Business of Arizona Public Service Company — Environmental Matters” in Item 1 and environmental and climate change-related risks described in Item 1A for additional environmental and climate change developments and risks facing APS.

 

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In addition, SCE, a participant in Four Corners, has indicated that certain California legislation may prohibit it from making emission control expenditures at the plant. 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. The purchase price is $294 million, subject to certain adjustments. Completion of the purchase by APS, which is expected to occur in the second half of 2012, is subject to the receipt of approvals by the ACC, the California Public Utilities Commission and the FERC. APS and SCE filed applications with their respective commissions seeking requisite authority or approvals to complete the transaction. Closing is also conditioned on the execution of a new coal supply contract for the lease renewal period described below, 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 Four Corners leasehold interest 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 occurred on February 15, 2011 and is awaiting final signature by the Nation’s President. The effectiveness of the amendments also requires the approval of the DOI, as does a related Federal rights-of-way grant which the Four Corners participants will pursue. A Federal environmental review will be conducted as part of the DOI review process.
Pursuant to a Co-Tenancy Agreement among the Four Corners participants, the other participants have a right of first refusal to purchase shares of SCE’s interests proportional to their current ownership percentages. The exercise of this purchase right by any of the other participants must be exercised by March 8, 2011. If any of the purchase rights are exercised, the amount available for purchase by APS would be reduced. At this time APS does not know whether any of the other participants will exercise the right of first refusal.
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 will 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. When applying for approval to purchase Units 4 and 5, APS also requested from the ACC recovery of any unrecovered costs associated with the closure of Units 1, 2 and 3.
Transmission and Delivery. In the area of transmission and delivery to its customers, APS ranked favorably during 2010, with top quartile performance for average customer outage time and its best reliability year to date. During 2010, APS undertook several significant transmission projects, including the Morgan to Pinnacle Peak transmission line scheduled for completion in 2011. APS’s 2011 transmission plan projects that it will invest approximately $450 million in new transmission over the next ten years, which includes 258 miles of new lines. The first three years of these additions are included in the capital expenditures table presented in the “Liquidity” section below along with other transmission costs for upgrades and replacements. APS is working closely with regulators to identify and plan for transmission needs resulting from the current focus on renewable energy. APS is also working to establish and expand smart grid technology throughout its service territory designed to provide long-term benefits both to APS and its customers. APS is piloting and deploying a variety of technologies that are intended to allow customers to better monitor their energy use and needs, minimize system outage durations and the number of customers that experience outages, and facilitate cost savings to APS through improved reliability and the automation of certain distribution functions, including remote meter reading and remote connects and disconnects.

 

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Renewable Energy. The ACC approved the RES in 2006, recognizing the importance of renewable energy to our state. The renewable energy requirement is 3% of retail electric sales in 2011 and increases annually until it reaches 15% in 2025. In the 2009 retail rate case settlement agreement, APS agreed to exceed the RES standards, committing to 1,700 GWh of new renewable resources to be in service by year-end 2015 in addition to its 2008 renewable resource commitments. Taken together, APS’s commitment is estimated to be 3,400 GWh or approximately 10% of APS’s retail energy sales by year-end 2015, which is double the existing RES target of 5% for that year. See Note 3. 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).
APS has a diverse portfolio of existing and planned renewable resources totaling 875 MW, including solar, wind, geothermal, biomass and biogas. Of this portfolio, 288 MW are currently in operation and 587 MW are under contract for development or are under construction. Renewable resources in operation include 5 MW of utility-scale facilities owned by APS, 223 MW of long-term purchased power agreements, and an estimated 60 MW of customer-sited, third-party owned distributed energy resources.
To achieve our RES requirements, as mentioned above, to date APS has entered into contracts for 587 MW of renewable resources that are planned, in development or under construction. APS’s strategy to procure these resources includes new facilities to be owned by APS, purchased power contracts for new facilities and ongoing development of distributed energy resources. Through the AZ Sun Program, approved by the ACC on March 3, 2010, APS plans to own 100 MW of solar photovoltaic power plants across Arizona by investing up to $500 million through 2014. Under this program, APS has executed contracts for the development of 83 MW of new solar generation, representing an investment commitment of approximately $377 million. See Note 3 for additional details of the AZ Sun Program, including the related cost recovery. APS has also entered into long-term purchased power agreements for 382 MW from solar, wind and biogas facilities currently planned, in development or under construction, and 122 MW from distributed energy resources. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the project to the electric grid.
APS continues to actively consider opportunities to enhance its renewable energy portfolio, both to ensure its compliance with the Renewable Energy Standard and to meet the needs of its customer base.
Demand Side Management. Arizona regulators are placing 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 Energy Efficiency rulemaking, with a proposed Energy Efficiency Standard of 22% cumulative annual energy savings by 2020. The 22% figure represents the cumulative reduction in future energy usage through 2020 attributable to energy efficiency initiatives. On July 27, 2010, the proposed Energy Efficiency Standard was adopted by the ACC, approved by the Arizona Attorney General and became effective on January 1, 2011. This ambitious standard will likely impact Arizona’s future energy resource needs.

 

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Rate Matters. APS needs timely recovery through rates of its capital and operating expenditures to maintain adequate financial health. APS’s retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. At the end of 2009, the ACC approved a settlement agreement entered into by APS and twenty-one of the twenty-three other parties to APS’s general retail rate case, with modifications that did not materially affect the overall economic terms of the agreement. The rate case settlement authorizes and requires equity infusions into APS of at least $700 million prior to the end of 2014. The settlement demonstrated cooperation among APS, the ACC staff, the Residential Utility Consumer Office (RUCO) and other intervenors to the rate case, and establishes a future rate case filing plan that allows APS the opportunity to help shape Arizona’s energy future outside of continual rate cases. See Note 3 for a detailed discussion of the settlement agreement terms and information on APS’s FERC rates.
APS has several recovery mechanisms in place that provide more timely recovery to APS of its fuel and transmission costs, and costs associated with the promotion and implementation of its demand-side management and renewable energy efforts and customer programs. These mechanisms are described more fully in Note 3.
On October 18, 2010, the Chairman of the ACC issued a draft decoupling policy statement for consideration by the commission. On December 15, 2010 the ACC unanimously approved a slightly modified decoupling policy statement supportive of using a revenue-per-customer methodology, which is the mechanism APS and a number of other parties support. Decoupling refers to a ratemaking design which reduces or removes the linkage between sales and utility revenues and/or profits, reducing utility disincentives to the adoption of programs that benefit customers by saving energy. Mechanically, decoupling compares actual versus authorized revenues or revenue per customer over a period and either credits or collects any differences from customers in a subsequent period. The policy permits regulated utilities to file a decoupling proposal in their next general rate case. APS intends to include a decoupling model consistent with the policy statement for consideration in its upcoming general rate case, currently expected to be filed in June 2011.
Financial Strength and Flexibility. Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities and have been able to access these facilities, ensuring adequate liquidity for each company. In early February 2010, APS entered into a $500 million revolving credit facility, replacing its $377 million revolving credit facility that would have otherwise terminated in December 2010. At that same time, Pinnacle West entered into a $200 million revolving credit facility that replaced its $283 million facility that also would have otherwise terminated in December 2010. Since March 2010, Pinnacle West and APS have accessed the commercial paper market, which neither company had utilized since the third quarter of 2008 due to negative market conditions.
In April 2010, Pinnacle West issued 6,900,000 shares of common stock at an offering price of $38.00 per share, resulting in net proceeds of approximately $253 million. Pinnacle West contributed all of the net proceeds from this offering into APS in the form of equity infusions. APS has used these capital contributions to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes.
In early February 2011, APS entered into a $500 million revolving credit facility, replacing its $489 million revolving credit facility that would have otherwise terminated in September 2011.
SunCor Real Estate Operations. As a result of the continuing distressed conditions in the real estate markets, during 2009 SunCor undertook a program to dispose of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to reduce its outstanding debt. At December 31, 2010, SunCor had total remaining assets of about $16 million, which includes approximately $3 million of assets held for sale. See “Liquidity and Capital Resources — Other Subsidiaries — SunCor” below for information regarding 2010 asset sales and liquidity matters.

 

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District Cooling Business Sale. On June 22, 2010, APSES sold its district cooling business consisting of operations in downtown Phoenix, Tucson, and on certain Arizona State University campuses. The sale resulted in an after-tax gain of approximately $25 million. APSES is now focused on its core business of energy conservation and renewable energy contracting services.
Subsidiaries. The operations of APSES and our other first tier subsidiary, El Dorado, are not expected to have any material impact on our financial results, or to require any material amounts of capital, over the next three years.
Key Financial Drivers
In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below. We closely monitor these factors to plan for the Company’s current needs, and to adjust our expectations, financial budgets and forecasts appropriately.
Electric Operating Revenues. For the years 2008 through 2010, retail electric revenues comprised approximately 93% of our total electric operating revenues. Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms. Off-system sales of excess generation output, purchased power and natural gas are included in regulated electricity segment revenues and related fuel and purchased power because they are credited to APS’s retail customers through the PSA. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.
Customer and Sales Growth. Customer growth in APS’s service territory for the year ended December 31, 2010 was 0.6% compared with the prior year. For the three years 2008 through 2010, APS’s customer growth averaged 0.9% per year. We currently expect customer growth to average about 1.7% per year for 2011 through 2013 due to anticipated improving economic conditions both nationally and in Arizona. Retail sales in kilowatt-hours, adjusted to exclude the effects of weather variations, for 2010 declined 1.0% compared to the prior year, reflecting the poor economic conditions in 2010 and the effects of our energy efficiency programs. For the three years 2008 through 2010, APS’s actual retail electricity sales in kilowatt-hours, adjusted to exclude the effects of weather variations, declined at an average annual rate of 0.9%. We currently estimate that total retail electricity sales in kilowatt-hours will remain flat on average per year during 2011 through 2013, including the effects of APS’s energy efficiency programs, but excluding the effects of weather variations. A continuation of the economic downturn, or the failure of the Arizona economy to rebound in the near future, could further impact these estimates. The customer and sales growth referred to in this paragraph apply to Native Load customers.
Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns, impacts of energy efficiency programs and responses to retail price changes. Our experience indicates that a reasonable range of variation in our kilowatt-hour sales projection attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of up to $10 million.
Weather. In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data. Historical extreme weather variations have resulted in annual variations in net income in excess of $20 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.

 

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Fuel and Purchased Power Costs. Fuel and purchased power costs included on our Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, our hedging program for managing such costs and PSA deferrals and the related amortization.
Operations and Maintenance Expenses. Operations and maintenance expenses are impacted by growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, higher-trending pension and other postretirement benefit costs, renewable energy and demand side management related expenses (which are offset by the same amount of regulated electricity segment operating revenues) and other factors. In its 2009 retail rate case settlement, APS committed to operational expense reductions from 2010 through 2014 and received approval to defer certain pension and other postretirement benefit cost increases to be incurred in 2011 and 2012.
Depreciation and Amortization Expenses. Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates. See “Capital Expenditures” below for information regarding the planned additions to our facilities. We have also applied to the NRC for renewed operating licenses for each of the Palo Verde units. If the NRC grants the extension, we estimate that our annual pretax depreciation expense will decrease by approximately $34 million at the later of the license extension date or January 1, 2012.
Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate for APS, which currently owns the majority of our property, was 8.0% of the assessed value in 2010, 7.5% of the assessed value in 2009 and 7.8% of the assessed value in 2008. We expect property taxes to increase as we add new utility plants (including new generation, transmission and distribution facilities described below under “Capital Additions”) and as we improve our existing facilities.
Income Taxes. Income taxes are affected by the amount of pre-tax book income, income tax rates, and certain non-taxable items, such as the AFUDC. In addition, income taxes may also be affected by the settlement of issues with taxing authorities.
Interest Expense. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (see Note 6.) The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, equity issuances and internally generated cash flow. An allowance for borrowed funds offsets a portion of interest expense while capital projects are under construction. We stop accruing AFUDC on a project when it is placed in commercial operation.

 

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RESULTS OF OPERATIONS
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution.
Our reportable business segments reflect a change from previously reported information. As of December 31, 2010, our real estate activities are no longer considered a segment requiring separate reporting or disclosure. In 2009 our real estate subsidiary, SunCor, began disposing of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to reduce its outstanding debt (see Note 23). At December 31, 2010, SunCor had total remaining assets of about $16 million, which includes approximately $3 million of assets held for sale. Additionally, all of SunCor’s operations are reflected in discontinued operations.
Operating Results — 2010 compared with 2009
Our consolidated net income attributable to common shareholders for 2010 was $350 million, compared with $68 million for the comparable prior-year period. The improved results were primarily due to lower real estate impairment charges recorded in 2010 compared with the prior-year period by SunCor.

 

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In addition, regulated electricity segment net income increased approximately $82 million from the prior-year period due to increased revenues related to APS’s retail rate increases and other factors. Our consolidated results for 2010 also include a gain of $25 million after income taxes related to the sale of APSES’ district cooling business. The following table presents net income (loss) attributable to common shareholders by business segment compared with the prior-year period:
                         
    Year Ended        
    December 31,        
    2010     2009     Net Change  
    (dollars in millions)  
Regulated Electricity Segment:
                       
Operating revenues less fuel and purchased power expenses
  $ 2,134     $ 1,970     $ 164  
Operations and maintenance
    (870 )     (822 )     (48 )
Depreciation and amortization
    (415 )     (407 )     (8 )
Taxes other than income taxes
    (135 )     (123 )     (12 )
Other income (expenses), net
    (4 )     (2 )     (2 )
Interest charges, net of allowance for funds used during construction
    (204 )     (212 )     8  
Income taxes
    (161 )     (142 )     (19 )
Noncontrolling interests (Note 20)
    (20 )     (19 )     (1 )
 
                 
Regulated electricity segment net income
    325       243       82  
 
                 
 
                       
All other (a)
    5       (10 )     15  
 
                 
Income from Continuing Operations Attributable to Common Shareholders
    330       233       97  
 
                 
 
                       
Discontinued real estate activities, primarily impairment charges at SunCor (Note 23)
    (6 )     (167 )     161  
All other discontinued operations (b)
    26       2       24  
 
                 
Income (Loss) from Discontinued Operations Attributable to Common Shareholders
    20       (165 )     185  
 
                 
 
                       
Net Income Attributable to Common Shareholders
  $ 350     $ 68     $ 282  
 
                 
     
(a)   Includes activities related to APSES and El Dorado. None of the activities of either of these companies constitutes a reportable segment.
 
(b)   Income from discontinued operations for 2010 includes a gain of $25 million after income taxes related to the sale of APSES’ district cooling business.

 

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Regulated electricity segment
This section includes a discussion of major variances in income and expense amounts for the regulated electricity segment.
Operating revenues less fuel and purchased power expenses Regulated electricity segment operating revenues less fuel and purchased power expenses were $164 million higher for the year ended 2010 compared with the prior year. The following table describes the major components of this change:
                         
    Increase (Decrease)  
            Fuel and        
            purchased        
    Operating     power        
    revenues     expenses     Net change  
    (dollars in millions)  
 
Retail regulatory settlement effective January 1, 2010:
                       
Retail base rate increases, net of deferrals
  $ 269     $ 128     $ 141  
Line extension revenues (Note 3)
    19               19  
Transmission rate increases
    6               6  
Higher demand-side management and renewable energy surcharges (substantially offset in operations and maintenance expense)
    33       2       31  
Higher fuel and purchased power costs offset by the effects of higher off-system sales, net of related PSA deferrals
    28       26       2  
Lower retail revenues related to recovery of PSA deferrals, substantially offset by lower amortization of fuel and purchased power expense
    (270 )     (276 )     6  
Lower retail sales primarily due to lower usage per customer, including the effects of the Company’s energy efficiency programs, but excluding the effects of weather
    (28 )     (9 )     (19 )
Effects of weather on retail sales, primarily due to milder weather in the second quarter 2010
    (20 )     (6 )     (14 )
Miscellaneous items, net
    (5 )     3       (8 )
 
                 
Total
  $ 32     $ (132 )   $ 164  
 
                 
Operations and maintenance Operations and maintenance expenses increased $48 million for the year ended 2010 compared with the prior year primarily because of:
    An increase of $25 million related to demand-side management and renewable energy programs, which are primarily offset in operating revenues;
    An increase of $18 million related to employee benefits costs; and
    An increase of $5 million related to other miscellaneous factors.

 

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Depreciation and Amortization Depreciation and amortization expenses were $8 million higher for the year ended 2010 compared with the prior year primarily because of increased plant in service partially offset by lower depreciation rates.
Taxes other than income taxes Taxes other than income taxes increased $12 million for the year ended 2010 compared with the prior year primarily because of higher property tax rates in the current year.
Interest charges, net of allowance for funds used during construction Interest charges, net of allowance for funds used during construction, decreased $8 million for the year ended 2010 compared with the prior year primarily because of higher rates in the current year for the allowance for equity and borrowed funds used during construction, partially offset by higher interest charges due to higher debt balances. Interest charges, net of allowance for funds used during construction are comprised of the regulated electricity segment portions of the line items interest expense and allowance for equity and borrowed funds used during construction from the Consolidated Statements of Income.
Income taxes Income taxes were $19 million higher for the year ended 2010 compared with the prior year primarily because of higher pretax income in the current-year period, partially offset by $17 million of income tax benefits related to prior years that were resolved in the current year. See Note 4.
All other
All other revenues increased $56 million partially offset by increased other expenses of $41 million resulting primarily from improved margins from APSES’ products and services business. In addition, other income was higher due to investment losses at El Dorado in 2009.
Discontinued Operations
Real estate activities During the first quarter of 2009, SunCor’s Board of Directors authorized a series of strategic transactions to dispose of SunCor’s assets. This decision resulted in impairment charges of approximately $161 million after income taxes in 2009. As of December 31, 2010, all of SunCor’s operations have been reclassified to discontinued operations (see Note 22). The after-tax impacts of the $6 million loss from real estate activities for the year ended 2010 includes real estate impairment charges of approximately $10 million (see Note 23) and other costs of $6 million, partially offset by a gain from debt restructuring of approximately $10 million (see Note 6).
All other All other earnings from discontinued operations were $24 million higher for the year ended 2010 compared to the prior-year period primarily because of a gain of $25 million after income taxes related to the sale of APSES’ district cooling business in 2010.
Operating Results — 2009 Compared with 2008
Our consolidated net income attributable to common shareholders for 2009 was $68 million, compared with $242 million for the prior year period. The decrease in net income was primarily due to 2009 real estate impairment charges recorded by SunCor, the Company’s real estate subsidiary.

 

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In addition, regulated electricity segment net income decreased approximately $13 million from the prior year primarily due to lower retail sales resulting from lower usage per customer; higher interest charges, net of capitalized financing costs; higher depreciation and amortization expenses; and the absence of income tax benefits related to prior years recorded in 2008. These negative factors were partially offset by increased revenues due to an interim rate increase effective January 1, 2009 and transmission rate increases.
The following table presents net income attributable to common shareholders by business segment compared with the prior year:
                         
    Year Ended        
    December 31,        
    2009     2008     Net Change  
    (dollars in millions)  
Regulated Electricity Segment:
                       
Operating revenues less fuel and purchased power expenses
  $ 1,970     $ 1,843     $ 127  
Operations and maintenance
    (822 )     (756 )     (66 )
Depreciation and amortization
    (407 )     (391 )     (16 )
Taxes other than income taxes
    (123 )     (125 )     2  
Other income (expenses), net
    (2 )     (21 )     19  
Interest charges, net of allowance for funds used during construction
    (212 )     (185 )     (27 )
Income taxes
    (142 )     (92 )     (50 )
Noncontrolling interests (Note 20)
    (19 )     (17 )     (2 )
 
                 
Regulated electricity segment net income
    243       256       (13 )
 
                 
 
                       
All other (a)
    (10 )     5       (15 )
 
                 
Income from Continuing Operations Attributable to Common Shareholders
    233       261       (28 )
 
                 
 
                       
Discontinued real estate activities, primarily impairment charges at SunCor (Note 23)
    (167 )     (26 )     (141 )
All other discontinued operations (a)
    2       7       (5 )
 
                 
Loss from Discontinued Operations Attributable to Common Shareholders
    (165 )     (19 )     (146 )
 
                 
 
                       
Net Income Attributable to Common Shareholders
  $ 68     $ 242     $ (174 )
 
                 
     
(a)   Includes activities related to marketing and trading, APSES and El Dorado. Income for 2008 includes income from discontinued operations of $8 million related to the resolution of certain tax issues associated with the sale of Silverhawk Power Station (“Silverhawk”) in 2005. None of these segments is a reportable segment.
Regulated electricity segment
This section includes a discussion of major variances in income and expense amounts for the regulated electricity segment.

 

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Operating revenues less fuel and purchased power expenses Regulated electricity segment operating revenues less fuel and purchased power expenses were $127 million higher for the year ended 2009 compared with the prior year. The following table describes the major components of this change:
                         
    Increase (Decrease)  
            Fuel and        
            purchased        
    Operating     power        
    revenues     expenses     Net change  
    (dollars in millions)  
Higher renewable energy and demand-side management surcharges (substantially offset in operations and maintenance expense)
  $ 63     $       $ 63  
Interim retail rate increases effective January 1, 2009
    61               61  
Transmission rate increases
    21               21  
Increased mark-to-market valuations of fuel and purchased power contracts related to favorable changes in market prices, net of related PSA deferrals
            (18 )     18  
Effects of weather on retail sales, primarily due to hotter weather in the third quarter of 2009
    12       3       9  
Lower retail sales primarily due to lower usage per customer, including the effects of the Company’s energy efficiency programs, but excluding the effects of weather
    (58 )     (26 )     (32 )
Higher fuel and purchased power costs including the effects of lower off-system sales, net of related PSA deferrals
    (30 )     (19 )     (11 )
Lower retail revenues related to recovery of PSA deferrals, offset by lower amortization of the same amount recorded as fuel and purchased power expense (see Note 3)
    (36 )     (36 )      
Miscellaneous items, net
    (11 )     (9 )     (2 )
 
                 
Total
  $ 22     $ (105 )   $ 127  
 
                 
Operations and maintenance Operations and maintenance expenses increased $66 million for the year ended 2009 compared with the prior year primarily because of:
    An increase of $62 million related to renewable energy and demand-side management programs, which are offset in operating revenues;
    An increase of $29 million in generation costs, including more planned maintenance, partially offset by lower costs at Palo Verde due to cost efficiency measures; and
    A decrease of $25 million associated with cost saving measures and other factors, including the absence of employee severance costs in 2009.

 

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Depreciation and amortization Depreciation and amortization expenses increased $16 million for the year ended 2009 compared with the prior year primarily because of increases in utility plant in service. The increases in utility plant in service are the result of various improvements to APS’s existing fossil and nuclear generating plants and distribution and transmission infrastructure additions and upgrades.
Interest charges, net of allowance for funds used during construction Interest charges, net of allowance for funds used during construction increased $27 million for the year ended 2009 compared with the prior year primarily because of higher debt balances, partially offset by the effects of lower interest rates (see discussion related to APS’s debt issuances in “Pinnacle West Consolidated — Liquidity and Capital Resources” below). Interest charges, net of allowance for funds used during construction are comprised of the regulated electricity segment portions of the line items interest expense and allowance for equity and borrowed funds used during construction from the Consolidated Statements of Income.
Other income (expenses), net Other income (expenses), net improved $19 million for the year ended 2009 compared with the prior year primarily because of improved investment gains. Other income (expenses), net is comprised of the regulated electricity segment portions of the line items other income and other expense from the Consolidated Statements of Income.
Income taxes Income taxes were $50 million higher for the year ended 2009 compared with the prior year primarily because of $30 million of income tax benefits related to prior years recorded in 2008 and higher pretax income. See Note 4.
All other
All other earnings from continuing operations were $15 million lower for the year ended 2009 compared with the prior year primarily because of planned reductions of marketing and trading activities.
Discontinued operations
Real estate activities During the first quarter of 2009, we decided to sell substantially all of SunCor’s assets to reduce its outstanding debt. The loss from real estate activities attributable to common shareholders was $141 million higher for the year ended 2009 compared with the prior year primarily because of an increase in real estate impairment charges of $213 million before income taxes (see Note 23 for details of the impairment charges).
All other All other earnings from discontinued operations were $5 million lower for the year ended 2009 compared with the prior year primarily because of the absence of the 2008 resolution of certain tax issues associated with the sale of Silverhawk in 2005.

 

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LIQUIDITY AND CAPITAL RESOURCES
Cash Flows — Pinnacle West Consolidated
The following table presents net cash provided by (used for) operating, investing and financing activities for the years ended December 31, 2010, 2009 and 2008 (dollars in millions):
                         
    2010     2009     2008  
Net cash flow provided by operating activities
  $ 750     $ 1,067     $ 848  
Net cash flow used for investing activities
    (576 )     (705 )     (815 )
Net cash flow provided by (used for) financing activities
    (209 )     (322 )     16  
 
                 
Net increase (decrease) in cash and cash equivalents
  $ (35 )   $ 40     $ 49  
 
                 
2010 Compared with 2009
The decrease of approximately $317 million in net cash provided by operating activities is primarily due to voluntary pension contributions in 2010 of approximately $200 million, changes in collateral and margin cash provided as a result of changes in commodity prices and other changes in working capital.
The decrease of approximately $129 million in net cash used for investing activities is primarily due to approximately $100 million of proceeds from the sale of the district cooling business in June 2010 and the increase in proceeds from the sale of commercial real estate investments of approximately $29 million.
The decrease of approximately $113 million in net cash used for financing activities is primarily due to lower repayments of short-term borrowings in 2010 due to lower short-term debt balances partially offset by lower net sources of equity and long-term debt financing, including the proceeds of approximately $253 million from the issuance of equity in April 2010 and APS’s issuance of $500 million of unsecured senior notes in 2009.
2009 Compared with 2008
The increase of approximately $219 million in net cash provided by operating activities is primarily due to a reduction of collateral and margin cash required as a result of changes in commodity prices and a 2009 income tax refund (see Note 4).
The decrease of approximately $110 million in net cash used for investing activities is primarily due to lower levels of capital expenditures net of contributions (see table and discussion below), partially offset by lower real estate sales primarily due to a commercial property sale in 2008.
The increase of approximately $338 million in net cash used for financing activities is primarily due to repayments of short-term borrowings, partially offset by APS’s issuance of $500 million of unsecured senior notes.

 

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Cash Flows — Arizona Public Service Company
The following table presents APS’s net cash provided by (used for) operating, investing and financing activities for the years ended December 31, 2010, 2009 and 2008 (dollars in millions):
                         
    2010     2009     2008  
Net cash flow provided by operating activities
  $ 695     $ 995     $ 820  
Net cash flow used for investing activities
    (747 )     (738 )     (879 )
Net cash flow provided by (used for) financing activities
    31       (208 )     79  
 
                 
Net increase (decrease) in cash and cash equivalents
  $ (21 )   $ 49     $ 20  
 
                 
2010 Compared with 2009
The decrease of approximately $300 million in net cash provided by operating activities is primarily due to voluntary pension contributions in 2010 of approximately $200 million, increased collateral and margin cash provided as a result of changes in commodity prices, and the payment of income taxes in 2010. These were partially offset by other changes in working capital.
The increase of approximately $9 million in net cash used for investing activities is primarily due to lower contributions in aid of construction and other cash flows.
The decrease of approximately $239 million in net cash used for financing activities is primarily due to the repayment of short-term borrowings in 2009, partially offset by lower net sources of equity and long-term debt financing including the proceeds of approximately $253 million from the infusion of equity from Pinnacle West in 2010 and by APS’s issuance of $500 million of unsecured senior notes in 2009.
2009 Compared with 2008
The increase of approximately $175 million in net cash provided by operating activities is primarily due to a reduction of collateral and margin cash required as a result of changes in commodity prices.
The decrease of approximately $141 million in net cash used for investing activities is primarily due to lower levels of capital expenditures net of contributions.
The increase of approximately $287 million in net cash used for financing activities is primarily due to repayments of short-term borrowings, partially offset by APS’s issuance of $500 million of unsecured senior notes (see Note 6).

 

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Liquidity
Capital Expenditure Requirements
The following table summarizes the actual capital expenditures for 2008, 2009 and 2010 and estimated capital expenditures for the next three years:
CAPITAL EXPENDITURES
(dollars in millions)
                                                 
    Actual     Estimated  
    2008     2009     2010     2011     2012     2013  
APS
                                               
Generation:
                                               
Nuclear Fuel
  $ 47     $ 64     $ 63     $ 65     $ 68     $ 69  
Renewables
                6       236       179       90  
Environmental
    96       33       11       11       22       122  
Four Corners Units 4 and 5
                            294        
Other Generation
    167       144       172       144       152       107  
Distribution
    340       246       232       284       350       285  
Transmission
    163       193       120       143       220       248  
Other (a)
    43       52       62       78       49       41  
 
                                   
Total APS
    856       732       666       961       1,334       962  
Other
    48       13       4                    
 
                                   
Total
  $ 904     $ 745     $ 670     $ 961     $ 1,334     $ 962  
 
                                   
     
(a)   Primarily information systems and facilities projects.
Generation capital expenditures are comprised of various improvements to APS’s existing fossil and nuclear plants. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment, such as turbines, boilers and environmental equipment. Included under Renewables is the AZ Sun Program, which is a significant component of the increase in capital expenditures from 2010 to 2011. For purposes of this table, we have assumed 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, as discussed in the “Overview” section above. As a result, we included the $294 million purchase price under Generation and have not included environmental expenditures for Units 1-3. We are also monitoring the status of certain environmental matters, which, depending on their final outcome, could require modification to our environmental expenditures. (See “Business of Arizona Public Service Company — Environmental Matters — EPA Environmental Regulation — Regional Haze Rules, Mercury and Other Hazardous Air Pollutants and Coal Combustion Waste” in Item 1.)
Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, new customer construction, related information systems and facility costs. Examples of the types of projects included in the forecast include power lines, substations, line extensions to new residential and commercial developments and upgrades to customer information systems.
Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.

 

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Pinnacle West (Parent Company)
Our primary cash needs are for dividends to our shareholders and principal and interest payments on our short-term and long-term debt. The level of our common stock dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.
On January 19, 2011, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on March 1, 2011, to shareholders of record on February 1, 2011.
Our primary sources of cash are dividends from APS, external debt and equity financings. For the years 2008 through 2010, total distributions from APS were $522 million and there were no distributions from SunCor. For 2010, cash distributions from APS were $182 million.
An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At December 31, 2010, APS’s common equity ratio, as defined, was 53%. Its total shareholder equity was approximately $3.8 billion, and total capitalization was approximately $7.2 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $2.9 billion, assuming APS’s total capitalization remains the same. Based on the discussion above, this restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.
Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for the commercial paper programs. During the first quarter of 2010, Pinnacle West and APS refinanced existing credit facilities that would have otherwise matured in December 2010.
On February 12, 2010, Pinnacle West refinanced its $283 million revolving credit facility that would have matured in December 2010, and decreased the size of the facility to $200 million. The new facility matures in February 2013. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Pinnacle West will use the facility for general corporate purposes, commercial paper program support and for the issuance of letters of credit. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings. As a result of the downsized credit facility, the Company also reduced the size of its commercial paper program to $200 million from $250 million.
At December 31, 2010, the $200 million credit facility was available to support the issuance of up to $183 million in commercial paper or for bank borrowings, including issuances of letters of credit up to $183 million. At December 31, 2010, Pinnacle West had no outstanding borrowings under this credit facility, $17 million of commercial paper borrowings and no outstanding letters of credit.

 

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In April 2010, Pinnacle West issued 6,900,000 shares of common stock at an offering price of $38.00 per share, resulting in net proceeds of approximately $253 million. Pinnacle West contributed all of the net proceeds from this offering into APS in the form of equity infusions. APS has used these contributions to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes. Pinnacle West intends to issue equity to provide most of the funds for the equity infusions into APS required by the retail rate case settlement. Such equity issuances may occur at any time in the period through 2014, at Pinnacle West’s discretion. See Note 3.
In June 2010, Pinnacle West received approximately $100 million related to the sale of APSES’ district cooling business. The net proceeds were used to repay short-term indebtedness.
Pinnacle West expects to receive approximately $132 million of cash tax benefits related to SunCor’s strategic asset sales (see Note 23), a majority of which have been realized as of December 31, 2010. Approximately $7 million of these benefits were recorded in 2010 as reductions to income tax expense related to the current impairment charges. The additional $125 million of tax benefits were recorded as reductions to income tax expense related to SunCor impairment charges recorded on or before December 31, 2009.
The $68 million income tax receivables on the Consolidated Balance Sheets represent the anticipated refunds related to an APS tax accounting method change approved by the IRS in the third quarter of 2009 and the current year tax benefits related to the SunCor strategic asset sales that closed in 2010.
The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 includes provisions making qualified property placed into service after September 8, 2010 and before January 1, 2012 eligible for 100% bonus depreciation for federal income tax purposes. In addition, qualified property placed into service in 2012 is eligible for 50% bonus depreciation for federal income tax purposes. These provisions of the recent tax legislation are expected to generate approximately $450-500 million of cash tax benefits for APS through accelerated depreciation. It is anticipated that these cash benefits will be fully realized by APS by the end of 2013, with a majority of the benefit realized in 2012 and 2013. The cash generated is an acceleration of tax benefits that APS would have otherwise received over 20 years.
Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. IRS regulations require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension obligation. The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. During 2010, we made voluntary contributions of $200 million to our pension plan. The required minimum contribution to our pension plan is zero in 2011 and approximately $85 million in 2012. The contribution to our other postretirement benefit plans in 2010 was approximately $17 million. The contributions to our other postretirement benefit plans for 2011 and 2012 are expected to be approximately $20 million each year. APS and other subsidiaries fund their share of the contributions. APS’s share is approximately 98% of both plans.

 

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APS
APS’s capital requirements consist primarily of capital expenditures and maturities of long-term debt. APS funds its capital requirements with cash from operations and, to the extent necessary, external debt financing and equity infusions from Pinnacle West. See “Pinnacle West (Parent Company)” above for a discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle West.
On February 12, 2010, APS refinanced its $377 million credit facility that would have matured in December 2010, and increased the size of the facility to $500 million. The new credit facility terminates in February 2013. APS may increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use the facility for general corporate purposes, commercial paper program support and for the issuance of letters of credit. Interest rates are based on APS’s senior unsecured debt credit ratings.
On February 14, 2011, APS refinanced its $489 million credit facility that would have matured in September 2011, and increased the size of the facility to $500 million. The new credit facility terminates in February 2015. APS may increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use the facility for general corporate purposes, commercial paper program support and for the issuance of letters of credit. Interest rates are based on APS’s senior unsecured debt credit ratings.
At December 31, 2010, APS had two credit facilities totaling $989 million, consisting of the $500 million and $489 million credit facilities described above. These facilities were available either to support the issuance of up to $250 million in commercial paper, or for bank borrowings, including issuances of letters of credit up to $989 million. At December 31, 2010, APS had no borrowings outstanding under any of its credit facilities and no outstanding commercial paper. A $20 million letter of credit was issued under APS’s $489 million credit facility in the second quarter of 2010.
On July 13, 2010, APS changed the interest rate mode for the approximately $33 million of Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Bonds (Arizona Public Service Company Navajo Project) 1994 Series A, due 2029. The rate period for the bonds changed from a daily rate mode, supported by a letter of credit, to a three-year term rate mode that will bear interest at a rate of 3.625% per annum for three years. The letter of credit was terminated in connection with this change, and there is no bank or other third-party credit support for the bonds in the term rate mode.
On August 10, 2010, APS changed the letter of credit supporting the approximately $17 million of Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Bonds (Arizona Public Service Company Project) Series 1998, due 2033. The bonds were in a daily rate mode supported by a prior letter of credit and remain in a daily rate mode, supported by a new three-year letter of credit expiring in August 2013.

 

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On October 12, 2010, APS changed the interest rate mode for the approximately $147 million of City of Farmington, New Mexico Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Four Corners Project) 1994 Series A and 1994 Series B, due 2024 and City of Farmington, New Mexico Pollution Control Revenue Bonds (Arizona Public Service Company Four Corners Project) 1994 Series C, due 2024. The rate period for the 1994 Series A bonds and the 1994 Series B bonds changed from a daily rate mode, supported by letters of credit, to a term rate mode to maturity, subject to optional redemption after year ten, that will bear interest at a rate of 4.70% per annum until maturity in 2024 unless the optional redemption is exercised by APS. The rate period for the 1994 Series C bonds changed from a daily rate mode, supported by a letter of credit, to a three-year term rate mode that will bear interest at a rate of 2.875% per annum until October 2013. The letters of credit supporting each of these three series of bonds were terminated in connection with these changes, and there is no bank or other third-party credit support for any of these bonds.
On January 1, 2010, due to the adoption of amended accounting guidance relating to VIEs, APS began consolidating the Palo Verde Lessor Trusts (see Note 20) and, as a result of consolidation of these VIEs, APS has reported the Lessor Trusts’ long-term debt on its Consolidated Balance Sheets. Interest rates on these debt instruments are 8% and are fixed for the remaining life of the debt. As of December 31, 2010 approximately $29 million was classified as current maturities of long-term debt and $97 million was classified as long-term debt relating to these VIEs. These debt instruments mature on December 30, 2015 and have sinking fund features that are serviced by the lease payments. See Note 20 for additional discussion of the VIEs.
Other Financing Matters — See Note 3 for information regarding the PSA approved by the ACC. Although APS defers actual retail fuel and purchased power costs on a current basis, APS’s recovery of the deferrals from its ratepayers is subject to annual and, if necessary, periodic PSA adjustments.
See Note 3 for information regarding the retail rate case settlement, which includes ACC authorization and requirements of equity infusions into APS of at least $700 million by December 31, 2014.
See Note 18 for information related to the change in our margin accounts.
Other Subsidiaries
SunCor —In 2010, SunCor sold land parcels, commercial assets and master planned home-building communities for approximately $72 million, which approximated the carrying value of these assets, resulting in a net gain of zero. In connection with these sales, SunCor negotiated a restructuring of certain of its credit facilities. The debt restructuring resulted in an after-tax gain of approximately $10 million. At December 31, 2010, SunCor had total remaining assets of about $16 million, which includes approximately $3 million of assets held for sale. At December 31, 2010, SunCor had no debt outstanding.
El Dorado — El Dorado expects minimal capital requirements over the next three years and intends to focus on prudently realizing the value of its existing investments.
APSES —APSES expects minimal capital expenditures over the next three years.
Debt Provisions
Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant and each anticipates it will continue to meet this and other significant covenant requirements. For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2010, the ratio was approximately 49% for Pinnacle West and 46% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.

 

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Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.
All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’s bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for credit facilities borrowings.
See Notes 5 and 6 for further discussions of liquidity matters.
Credit Ratings
The ratings of securities of Pinnacle West and APS as of February 17, 2011 are shown below. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital. Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. At this time, we believe we have sufficient liquidity to cover a downward revision to our credit ratings.
             
    Moody’s   Standard & Poor’s   Fitch
Pinnacle West
           
Senior unsecured (a)
  Baa3 (P)   BB+ (prelim)   N/A
Commercial paper
  P-3   A-3   F3
Outlook
  Stable   Positive   Stable
 
           
APS
           
Senior unsecured
  Baa2   BBB-   BBB
Secured lease obligation bonds
  Baa2   BBB-   BBB
Commercial paper
  P-2   A-3   F3
Outlook
  Stable   Positive   Stable
     
(a)   Pinnacle West has a shelf registration under SEC Rule 415. Pinnacle West currently has no outstanding, rated senior unsecured securities. However, Moody’s assigned a provisional (P) rating and Standard & Poor’s assigned a preliminary (prelim) rating to the senior unsecured securities that can be issued under such shelf registration.

 

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Off-Balance Sheet Arrangements
On January 1, 2010 we adopted amended accounting guidance relating to VIEs and, as a result, we have consolidated certain entities which were previously not consolidated. The consolidation of these entities has impacted our consolidated financial statements. See Notes 1, 2 and 20 for a discussion of these impacts.
Guarantees and Surety Bonds
We have issued parental guarantees and obtained surety bonds on behalf of our subsidiaries including credit support instruments enabling APSES to offer energy-related products and surety bonds at APS, principally related to self-insured workers’ compensation. Non-performance or non-payment under the underlying contract by our subsidiaries would result in a payment liability on our part under the guarantee or surety bond. No liability is currently recorded on the Consolidated Balance Sheets related to such instruments. At December 31, 2010, we had no outstanding claims for payment under any of these instruments. Our guarantees and surety bonds have no recourse or collateral provisions to allow us to recover amounts paid under these instruments or surety bonds from our subsidiaries. We generally agree to indemnification provisions related to liabilities arising from or related to certain of our agreements, with limited exceptions depending on the particular agreement. See Note 21 for additional information regarding guarantees and letters of credit.

 

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Contractual Obligations
The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2010 (dollars in millions):
                                         
            2012-     2014-              
    2011     2013     2015     Thereafter     Total  
Long-term debt payments, including interest: (a)
                                       
APS
  $ 673     $ 949     $ 1,071     $ 2,587     $ 5,280  
Pinnacle West
    177                         177  
 
                             
Total long-term debt payments, including interest and capital lease obligations
    850       949       1,071       2,587       5,457  
 
                             
Short-term debt payments, including interest (b)
    17                         17  
Fuel and purchased power commitments (c)
    381       824       1,070       7,084       9,359  
Operating lease payments
    24       38       27       9       98  
Nuclear decommissioning funding requirements
    24       49       49       137       259  
Renewable energy credits (d)
    57       40       40       196       333  
Purchase obligations (e)
    214       125             117       456  
Noncontrolling interests
    10       28       55             93  
 
                             
Total contractual commitments
  $ 1,577     $ 2,053     $ 2,312     $ 10,130     $ 16,072  
 
                             
     
(a)   The long-term debt matures at various dates through 2038 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2010 (see Note 6).
 
(b)   The short-term debt represents commercial paper borrowings at Pinnacle West (see Note 5).
 
(c)   Our fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy and nuclear fuel (see Notes 3 and 11).
 
(d)   Contracts to purchase renewable energy credits in compliance with the Renewable Energy Standard.
 
(e)   These contractual obligations include commitments for capital expenditures and other obligations. These amounts do not include the purchase of SCE’s interest in Four Corners Units 4 and 5 due to additional approvals required. See discussion in “Overview.”
This table excludes $133 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain. This table also excludes $85 million in estimated minimum pension contributions in 2012 (see Note 8).
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.

 

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Regulatory Accounting
Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers. Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. We had $1.0 billion of regulatory assets and $753 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2010.
Included in the balance of regulatory assets at December 31, 2010 is a regulatory asset of $669 million for pension and other postretirement benefits. This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future earnings.
See Notes 1 and 3 for more information.
Pensions and Other Postretirement Benefit Accounting
Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit liability and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.

 

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The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2010 reported pension liability on the Consolidated Balance Sheets and our 2010 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):
                 
    Increase (Decrease)  
    Impact on     Impact on  
    Pension     Pension  
Actuarial Assumption (a)   Liability     Expense  
Discount rate:
               
Increase 1%
  $ (261 )   $ (8 )
Decrease 1%
    294       10  
Expected long-term rate of return on plan assets:
               
Increase 1%
          (7 )
Decrease 1%
          7  
     
(a)   Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2010 reported other postretirement benefit obligation on the Consolidated Balance Sheets and our 2010 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):
                 
    Increase (Decrease)  
    Impact on Other     Impact on Other  
    Postretirement Benefit     Postretirement  
Actuarial Assumption (a)   Obligation     Benefit Expense  
Discount rate:
               
Increase 1%
  $ (118 )   $ (5 )
Decrease 1%
    138       6  
Health care cost trend rate (b):
               
Increase 1%
    134       9  
Decrease 1%
    (107 )     (7 )
Expected long-term rate of return on plan assets — pretax:
               
Increase 1%
          (2 )
Decrease 1%
          2  
     
(a)   Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.
 
(b)   This assumes a 1% change in the initial and ultimate health care cost trend rate.
See Note 8 for further details about our pension and other postretirement benefit plans.

 

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Derivative Accounting
Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, determines whether we use accrual accounting (for contracts designated as normal) or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in the fair value are recognized periodically in income unless certain hedge criteria are met. For cash flow hedges, the effective portion of changes in the fair value of the derivative is recognized in common stock equity (as a component of other comprehensive income (loss)) and the ineffective portion is recognized in current earnings.
See “Market Risks — Commodity Price Risk” below for quantitative analysis. See “Fair Value Measurements” below for additional information on valuation. See Note 1 for discussion on accounting policies and Note 18 for a further discussion on derivative accounting.
Fair Value Measurements
We apply recurring fair value measurements to derivative instruments, nuclear decommissioning trusts, certain cash equivalents and plan assets held in our retirement and other benefit plans. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use inputs, or assumptions that market participants would use, to determine fair market value. The significance of a particular input determines how the instrument is classified in the fair value hierarchy. We utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The determination of fair value sometimes requires subjective and complex judgment. Our assessment of the inputs and the significance of a particular input to fair value measurement may affect the valuation of the instruments and their placement within the fair value hierarchy. Actual results could differ from our estimates of fair value. See Note 14 for further fair value measurement discussion, Note 1 for discussion on accounting policies and Note 18 for a further discussion on derivative accounting.
Our nuclear decommissioning trusts invest in fixed income securities and equity securities. The fair values of these securities are based on observable inputs for identical or similar assets. See Note 14 for further discussion of our nuclear decommissioning trusts.
Real Estate Investment Impairments
While we do not have any real estate investments or home inventory at December 31, 2010, we did have real estate investments of $120 million and $3 million of home inventory on our Consolidated Balance Sheets at December 31, 2009. For purposes of evaluating impairment, in accordance with guidance on the impairment and disposal of long-lived assets, we classified our real estate assets, such as land under development, land held for future development, and commercial property, as “held and used.” When events or changes in circumstances indicated that the carrying value of real estate assets considered held and used were not recoverable, we compared the undiscounted cash flows that we estimated would be generated by each asset to its carrying amount. If the carrying amount exceeded the undiscounted cash flows, we adjusted the asset to fair value and recognized an impairment charge. The adjusted value became the new book value (carrying amount) for held and used assets. We may have had real estate assets classified as held and used with fair values that were lower than their carrying amounts, but were not deemed to be impaired because the undiscounted cash flows exceeded the carrying amounts.

 

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Real estate home inventory was considered to be held for sale for the purposes of evaluating impairment. Home inventories were reported at the lower of carrying amount or fair value less cost to sell. Fair value less cost to sell was evaluated each period to determine if it had changed. Losses (and gains not to exceed any cumulative loss previously recognized) were reported as adjustments to the carrying amount.
We determined fair value for our real estate assets primarily based on the future cash flows that we estimated would be generated by each asset discounted for market risk. Our impairment assessments and fair value determinations required significant judgment regarding key assumptions such as future sales prices, future construction and land development costs, future sales timing, and discount rates. The assumptions were specific to each project and may have varied among projects. The discount rates we used to determine fair values at December 31, 2009 ranged from 11% to 29%. Due to the judgment and assumptions applied in the estimation process, with regard to impairments, it is possible that actual results could have differed from those estimates.
OTHER ACCOUNTING MATTERS
On January 1, 2010 we adopted amended accounting guidance relating to VIEs and, as a result, we have consolidated certain entities which were previously not consolidated. The consolidation of these entities has impacted our consolidated financial statements. See Notes 1, 2 and 20 for a discussion of these impacts.
The FASB is currently working on several significant projects with the desire to converge GAAP with IFRS. These projects include accounting for leases, revenue recognition, and financial instruments, among other items. Concurrently, the SEC is considering mandating IFRS for U.S. companies. See Note 2 for a discussion of these potential changes.
MARKET AND CREDIT RISKS
Market Risks
Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust fund.
Interest Rate and Equity Risk
We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust fund (see Note 14). The nuclear decommissioning trust fund also has risks associated with the changing market value of its investments. Nuclear decommissioning costs are recovered in regulated electricity prices.

 

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The tables below present contractual balances of our consolidated long-term and short-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2010 and 2009. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2010 and 2009 (dollars in thousands):
Pinnacle West — Consolidated
                                                 
                    Variable-Rate     Fixed-Rate  
    Short-Term Debt     Long-Term Debt     Long-Term Debt  
    Interest             Interest             Interest        
2010   Rates     Amount     Rates     Amount     Rates     Amount  
 
2011
    0.84 %   $ 16,600       0.32 %   $ 26,710       6.32 %   $ 605,169  
2012
                            6.41 %     477,435  
2013
                0.32 %     16,870       4.94 %     122,828  
2014
                            5.91 %     502,274  
2015
                            4.79 %     313,420  
Years thereafter
                            6.69 %     1,619,150  
 
                                         
Total
          $ 16,600             $ 43,580             $ 3,640,276  
 
                                         
Fair value
          $ 16,600             $ 43,580             $ 3,869,681  
 
                                         
Pinnacle West — Consolidated
                                                 
                    Variable-Rate     Fixed-Rate  
    Short-Term Debt     Long-Term Debt     Long-Term Debt  
    Interest             Interest             Interest        
2009   Rates     Amount     Rates     Amount     Rates     Amount  
 
2010
    1.09 %   $ 153,715       1.66 %   $ 276,636       7.90 %   $ 26,840  
2011
                2.00 %     39,967       6.32 %     605,425  
2012
                5.25 %     38       6.41 %     477,674  
2013
                5.25 %     1,774       6.77 %     58,912  
2014
                            5.91 %     502,499  
Years thereafter
                            6.46 %     1,817,420  
 
                                         
Total
          $ 153,715             $ 318,415             $ 3,488,770  
 
                                         
Fair value
          $ 153,715             $ 318,415             $ 3,631,585  
 
                                         

 

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The tables below present contractual balances of APS’s long-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2010 and 2009. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2010 and 2009 (dollars in thousands):
APS — Consolidated
                                 
    Variable-Rate     Fixed-Rate  
    Long-Term Debt     Long-Term Debt  
    Interest             Interest        
2010   Rates     Amount     Rates     Amount  
 
2011
    0.32 %   $ 26,710       6.48 %   $ 430,169  
2012
                6.41 %     477,435  
2013
    0.32 %     16,870       4.94 %     122,828  
2014
                5.91 %     502,274  
2015
                4.79 %     313,420  
Years thereafter
                6.69 %     1,619,150  
 
                           
Total
          $ 43,580             $ 3,465,276  
 
                           
Fair value
          $ 43,580             $ 3,693,276  
 
                           
APS — Consolidated
                                 
    Variable-Rate     Fixed-Rate  
    Long-Term Debt     Long-Term Debt  
    Interest             Interest        
2009   Rates     Amount     Rates     Amount  
 
2010
    0.25 %   $ 196,170       7.91 %   $ 26,789  
2011
    0.26 %     26,710       6.48 %     430,398  
2012
                6.41 %     477,654  
2013
                6.77 %     58,910  
2014
                5.91 %     502,499  
Years thereafter
                6.46 %     1,817,420  
 
                           
Total
          $ 222,880             $ 3,313,670  
 
                           
Fair value
          $ 222,880             $ 3,451,255  
 
                           
Commodity Price Risk
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. Our risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities to ensure compliance with our stated energy risk management policies. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity and fuels. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.

 

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The following table shows the net pretax changes in mark-to-market of our derivative positions in 2010 and 2009 (dollars in millions):
                 
    2010     2009  
Mark-to-market of net positions at beginning of year
  $ (169 )   $ (282 )
Recognized in earnings:
               
Change in mark-to-market losses for future period deliveries
    (7 )     (4 )
Mark-to-market losses realized including ineffectiveness during the period
    5       11  
Decrease (increase) in regulatory asset
    (36 )     76  
Recognized in OCI:
               
Change in mark-to-market losses for future period deliveries (a)
    (155 )     (155 )
Mark-to-market losses realized during the period
    123       185  
Change in valuation techniques
           
 
           
Mark-to-market of net positions at end of year
  $ (239 )   $ (169 )
 
           
     
(a)   The changes in mark-to-market recorded in OCI are due primarily to changes in forward natural gas prices.
The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at December 31, 2010 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting” and “Fair Value Measurements,” for more discussion of our valuation methods.
                                                         
                                                    Total  
                                            Years     fair  
Source of Fair Value   2011     2012     2013     2014     2015     thereafter     value  
Prices actively quoted
  $ (1 )   $     $     $     $     $     $ (1 )
Prices provided by other external sources
    (139 )     (47 )     (14 )                       (200 )
Prices based on models and other valuation methods
    (7 )     (4 )     (7 )     (6 )     (6 )     (8 )     (38 )
 
                                         
Total by maturity
  $ (147 )   $ (51 )   $ (21 )   $ (6 )   $ (6 )   $ (8 )   $ (239 )
 
                                         

 

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The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Consolidated Balance Sheets at December 31, 2010 and 2009 (dollars in millions):
                                 
    December 31, 2010     December 31, 2009  
    Gain (Loss)     Gain (Loss)  
    Price Up 10%     Price Down 10%     Price Up 10%     Price Down 10%  
Mark-to-market changes reported in:
                               
Earnings
                               
Electricity
  $     $     $ 1     $ (1 )
Natural gas
    1       (1 )     1       (1 )
Regulatory asset (liability) or OCI (a)
                               
Electricity
    13       (13 )     21       (21 )
Natural gas
    42       (42 )     59       (59 )
 
                       
Total
  $ 56     $ (56 )   $ 82     $ (82 )
 
                       
     
(a)   These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.
Credit Risk
We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 18 for a discussion of our credit valuation adjustment policy.
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
See “Market and Credit Risks” in Item 7 above for a discussion of quantitative and qualitative disclosures about market risk.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULES
         
    Page  
 
       
    80  
 
       
    81  
 
       
    83  
 
       
    84  
 
       
    86  
 
       
    87  
 
       
    88  
 
       
    153  
 
       
    154  
 
       
    156  
 
       
    157  
 
       
    159  
 
       
    160  
 
       
    162  
 
       
Financial Statement Schedules for 2010, 2009 and 2008
       
 
       
    168  
 
       
    169  
 
       
    170  
 
       
    171  
 
       
    172  
See Note 13 and S-2 for the selected quarterly financial data (unaudited) required to be presented in this Item.

 

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MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
(PINNACLE WEST CAPITAL CORPORATION)
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Pinnacle West Capital Corporation. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2010. The effectiveness of our internal control over financial reporting as of December 31, 2010 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s consolidated financial statements.
February 18, 2011

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Pinnacle West Capital Corporation
Phoenix, Arizona
We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the “Company”) as of December 31, 2010 and 2009 and the related consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedules listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

 

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Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
As disclosed in Note 2 to the consolidated financial statements, the Company adopted amended accounting guidance related to the consolidation of variable interest entities on January 1, 2010.
/s/ DELOITTE & TOUCHE LLP
Phoenix, Arizona
February 18, 2011

 

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PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(dollars and shares in thousands, except per share amounts)
                         
    Year Ended December 31,  
    2010     2009     2008  
OPERATING REVENUES
                       
Regulated electricity segment
  $ 3,180,678     $ 3,149,187     $ 3,127,383  
Marketing and trading
                66,897  
Other revenues
    82,967       26,723       25,407  
 
                 
Total
    3,263,645       3,175,910       3,219,687  
 
                 
OPERATING EXPENSES
                       
Regulated electricity segment fuel and purchased power
    1,046,815       1,178,620       1,284,116  
Marketing and trading fuel and purchased power
                45,572  
Operations and maintenance
    877,406       831,863       765,277  
Depreciation and amortization
    414,555       407,463       391,190  
Taxes other than income taxes
    135,334       123,277       124,853  
Other expenses
    65,651       24,534       26,032  
 
                 
Total
    2,539,761       2,565,757       2,637,040  
 
                 
OPERATING INCOME
    723,884       610,153       582,647  
 
                 
OTHER INCOME (DEDUCTIONS)
                       
Allowance for equity funds used during construction (Note 1)
    22,066       14,999       18,636  
Other income (Note 19)
    6,368       5,278       9,541  
Other expense (Note 19)
    (9,764 )     (14,269 )     (31,576 )
 
                 
Total
    18,670       6,008       (3,399 )
 
                 
INTEREST EXPENSE
                       
Interest charges
    244,174       237,527       219,916  
Allowance for borrowed funds used during construction (Note 1)
    (16,539 )     (10,430 )     (14,547 )
 
                 
Total
    227,635       227,097       205,369  
 
                 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
    514,919       389,064       373,879  
INCOME TAXES (Note 4)
    164,321       136,506       95,544  
 
                 
INCOME FROM CONTINUING OPERATIONS
    350,598       252,558       278,335  
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
                       
Net of income tax expense (benefit) of $12,808, $(107,596) and $(11,648) (Note 22)
    19,611       (179,794 )     (18,715 )
 
                 
NET INCOME
    370,209       72,764       259,620  
Less: Net income attributable to noncontrolling interests (Note 20)
    20,156       4,434       17,495  
 
                 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
  $ 350,053     $ 68,330     $ 242,125  
 
                 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC
    106,573       101,161       100,691  
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED
    107,138       101,264       100,965  
 
                       
EARNINGS PER WEIGHTED — AVERAGE COMMON SHARE OUTSTANDING
                       
Income from continuing operations attributable to common shareholders — basic
  $ 3.10     $ 2.31     $ 2.59  
Net income attributable to common shareholders — basic
    3.28       0.68       2.40  
Income from continuing operations attributable to common shareholders — diluted
    3.08       2.30       2.58  
Net income attributable to common shareholders — diluted
    3.27       0.67       2.40  
DIVIDENDS DECLARED PER SHARE
  $ 2.10     $ 2.10     $ 2.10  
 
                       
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
                       
Income from continuing operations, net of tax
  $ 330,435     $ 233,349     $ 260,840  
Discontinued operations, net of tax
    19,618       (165,019 )     (18,715 )
 
                 
Net income attributable to common shareholders
  $ 350,053     $ 68,330     $ 242,125  
 
                 
See Notes to Pinnacle West’s Consolidated Financial Statements.

 

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PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
                 
    December 31,  
    2010     2009  
ASSETS
               
 
               
CURRENT ASSETS
               
Cash and cash equivalents
  $ 110,188     $ 145,378  
Customer and other receivables
    324,207       301,915  
Accrued unbilled revenues
    103,292       110,971  
Allowance for doubtful accounts
    (7,981 )     (6,153 )
Materials and supplies (at average cost)
    181,414       176,020  
Fossil fuel (at average cost)
    21,575       39,245  
Deferred income taxes (Note 4)
    94,602       53,990  
Income tax receivable (Note 4)
    2,483       26,005  
Assets from risk management activities (Note 18)
    73,788       50,619  
Other current assets
    28,362       30,747  
 
           
Total current assets
    931,930       928,737  
 
           
 
               
INVESTMENTS AND OTHER ASSETS
               
Real estate investments — net (Notes 1, 6 and 23)
          119,989  
Assets from risk management activities (Note 18)
    39,032       28,855  
Nuclear decommissioning trust (Note 14)
    469,886       414,576  
Other assets
    116,216       110,091  
 
           
Total investments and other assets
    625,134       673,511  
 
           
 
               
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, 9 and 10)
               
Plant in service and held for future use
    13,201,960       12,848,138  
Accumulated depreciation and amortization
    (4,514,204 )     (4,340,645 )
 
           
Net
    8,687,756       8,507,493  
Construction work in progress
    459,361       467,700  
Palo Verde sale leaseback, net of accumulated depreciation of $213,094 and $204,328 (Note 20)
    137,956       146,722  
Intangible assets, net of accumulated amortization of $330,584 and $294,724
    184,952       164,380  
Nuclear fuel, net of accumulated amortization of $85,270 and $64,544
    108,794       118,243  
 
           
Total property, plant and equipment
    9,578,819       9,404,538  
 
           
 
               
DEFERRED DEBITS
               
Regulatory assets (Notes 1, 3 and 4)
    1,048,656       813,161  
Income tax receivable (Note 4)
    65,103       65,103  
Other
    113,061       101,274  
 
           
Total deferred debits
    1,226,820       979,538  
 
           
 
               
TOTAL ASSETS
  $ 12,362,703     $ 11,986,324  
 
           
See Notes to Pinnacle West’s Consolidated Financial Statements.

 

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PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS

(dollars in thousands)
                 
    December 31,  
    2010     2009  
LIABILITIES AND EQUITY
               
 
               
CURRENT LIABILITIES
               
Accounts payable
  $ 236,354     $ 240,637  
Accrued taxes (Note 4)
    104,711       104,011  
Accrued interest
    54,831       54,596  
Short-term borrowings (Note 5)
    16,600       153,715  
Current maturities of long-term debt (Note 6)
    631,879       303,476  
Customer deposits
    68,322       71,026  
Liabilities from risk management activities (Note 18)
    58,976       55,908  
Other current liabilities
    139,063       125,574  
 
           
Total current liabilities
    1,310,736       1,108,943  
 
           
 
               
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)
               
Long-term debt less current maturities
    2,948,991       3,370,524  
Palo Verde sale leaseback lessor notes less current maturities (Note 20)
    96,803       126,000  
 
           
Total long-term debt less current maturities
    3,045,794       3,496,524  
 
           
 
               
DEFERRED CREDITS AND OTHER
               
Deferred income taxes (Note 4)
    1,833,566       1,496,095  
Deferred fuel and purchased power regulatory liability (Note 3)
    58,442       87,291  
Other regulatory liabilities (Notes 1 and 3)
    694,589       679,072  
Liability for asset retirements (Note 12)
    328,571       301,783  
Liabilities for pension and other postretirement benefits (Note 8)
    813,121       811,338  
Liabilities from risk management activities (Note 18)
    65,390       62,443  
Customer advances
    121,645       136,595  
Coal mine reclamation
    117,243       92,060  
Unrecognized tax benefits (Note 4)
    66,349       142,099  
Other
    132,031       144,077  
 
           
Total deferred credits and other
    4,230,947       3,952,853  
 
           
 
               
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
               
 
               
EQUITY (Note 7)
               
Common stock, no par value; authorized 150,000,000 shares; issued 108,820,067 at end of 2010 and 101,527,937 at end of 2009
    2,421,372       2,153,295  
Treasury stock at cost; 50,410 shares at end of 2010 and 93,239 at end of 2009
    (2,239 )     (3,812 )
 
           
Total common stock
    2,419,133       2,149,483  
 
           
Retained earnings
    1,423,961       1,298,213  
 
           
Accumulated other comprehensive loss:
               
Pension and other postretirement benefits (Note 8)
    (59,420 )     (50,892 )
Derivative instruments
    (100,347 )     (80,695 )
 
           
Total accumulated other comprehensive loss
    (159,767 )     (131,587 )
 
           
Total shareholders’ equity
    3,683,327       3,316,109  
Noncontrolling interests (Note 20)
    91,899       111,895  
 
           
Total equity
    3,775,226       3,428,004  
 
           
 
               
TOTAL LIABILITIES AND EQUITY
  $ 12,362,703     $ 11,986,324  
 
           
See Notes to Pinnacle West’s Consolidated Financial Statements.

 

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PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
                         
    Year Ended December 31,  
    2010     2009     2008  
CASH FLOWS FROM OPERATING ACTIVITIES
                       
Net Income
  $ 370,209     $ 72,764     $ 259,620  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Gain on sale of district cooling business
    (41,973 )            
Depreciation and amortization including nuclear fuel
    472,807       450,864       431,672  
Deferred fuel and purchased power
    93,631       (51,742 )     (80,183 )
Deferred fuel and purchased power amortization
    (122,481 )     147,018       183,126  
Allowance for equity funds used during construction
    (22,066 )     (14,999 )     (18,636 )
Real estate impairment charge
    16,731       280,188       53,250  
Gain on real estate debt restructuring
    (16,755 )            
Deferred income taxes
    260,411       105,492       158,024  
Change in mark-to-market valuations
    2,688       (6,939 )     9,074  
Changes in current assets and liabilities:
                       
Customer and other receivables
    (67,943 )     12,292       73,446  
Accrued unbilled revenues
    7,679       (10,882 )     7,388  
Materials, supplies and fossil fuel
    12,276       (12,261 )     (25,453 )
Other current assets
    5,246       24,647       56,775  
Accounts payable
    9,125       (27,328 )     (69,439 )
Accrued taxes and income tax receivable — net
    24,222       (31,792 )     (13,149 )
Other current liabilities
    5,204       29,274       (5,130 )
Expenditures for real estate investments
    (622 )     (2,957 )     (21,168 )
Other changes in real estate assets
    4,068       (4,216 )     18,211  
Change in margin and collateral accounts — assets
    (9,937 )     (12,806 )     17,450  
Change in margin and collateral accounts — liabilities
    (88,315 )     35,654       (132,416 )
Change in long term income tax receivable
          (131,984 )      
Change in unrecognized tax benefits
    (73,621 )     137,898       (94,551 )
Change in other regulatory liabilities
    54,518       110,642       (12,129 )
Change in other long-term assets
    (43,189 )     (47,899 )     6,104  
Change in other long-term liabilities
    (101,456 )     16,377       46,207  
 
                 
Net cash flow provided by operating activities
    750,457       1,067,305       848,093  
 
                 
 
                       
CASH FLOWS FROM INVESTING ACTIVITIES
                       
Capital expenditures
    (748,374 )     (764,609 )     (935,577 )
Contributions in aid of construction
    32,754       53,525       60,292  
Allowance for borrowed funds used during construction
    (16,778 )     (10,745 )     (18,820 )
Proceeds from the sale of district cooling business
    100,300              
Proceeds from nuclear decommissioning trust sales
    560,469       441,242       317,619  
Investment in nuclear decommissioning trust
    (584,885 )     (463,033 )     (338,361 )
Proceeds from sale of commercial real estate investments
    72,038       43,370       94,171  
Other
    8,576       (4,667 )     5,517  
 
                 
Net cash flow used for investing activities
    (575,900 )     (704,917 )     (815,159 )
 
                 
 
                       
CASH FLOWS FROM FINANCING ACTIVITIES
                       
Issuance of long-term debt
          867,469       96,934  
Repayment of long-term debt
    (106,572 )     (456,882 )     (202,234 )
Short-term borrowings and payments — net
    (137,115 )     (516,754 )     331,741  
Dividends paid on common stock
    (216,979 )     (205,076 )     (204,247 )
Common stock equity issuance
    255,971       3,302       3,687  
Noncontrolling interests
    (11,403 )     (14,485 )     (13,782 )
Other
    6,351       171       3,891  
 
                 
Net cash flow provided by (used for) financing activities
    (209,747 )     (322,255 )     15,990  
 
                 
 
                       
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    (35,190 )     40,133       48,924  
 
                       
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
    145,378       105,245       56,321  
 
                 
 
                       
CASH AND CASH EQUIVALENTS AT END OF YEAR
  $ 110,188     $ 145,378     $ 105,245  
 
                 
Supplemental disclosure of cash flow information Cash paid during the period for:
                       
Income taxes, net of (refunds)
  $ (23,447 )   $ (52,776 )   $ 24,233  
Interest, net of amounts capitalized
  $ 221,728     $ 216,608     $ 205,546  
See Notes to Pinnacle West’s Consolidated Financial Statements.

 

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PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(dollars in thousands)
                         
    Year Ended December 31,  
    2010     2009     2008  
COMMON STOCK (Note 7)
                       
Balance at beginning of year
  $ 2,153,295     $ 2,151,323     $ 2,135,787  
Issuance of common stock
    263,297       10,620       10,845  
Other
    4,780       (8,648 )     4,691  
 
                 
Balance at end of year
    2,421,372       2,153,295       2,151,323  
 
                 
 
                       
TREASURY STOCK (Note 7)
                       
Balance at beginning of year
    (3,812 )     (2,854 )     (2,054 )
Purchase of treasury stock
    (82 )     (2,156 )     (1,387 )
Reissuance of treasury stock used for stock compensation
    1,655       1,198       587  
 
                 
Balance at end of year
    (2,239 )     (3,812 )     (2,854 )
 
                 
 
                       
RETAINED EARNINGS
                       
Balance at beginning of year
    1,298,213       1,444,208       1,413,741  
Net income attributable to common shareholders
    350,053       68,330       242,125  
Common stock dividends
    (224,305 )     (212,386 )     (211,405 )
Other
          (1,939 )     (253 )
 
                 
Balance at end of year
    1,423,961       1,298,213       1,444,208  
 
                 
 
                       
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
                       
Balance at beginning of year
    (131,587 )     (146,698 )     (15,863 )
Pension and other postretirement benefits (Note 8):
                       
Unrealized actuarial loss, net of tax benefit of $(7,738), $(4,223) and $(7,801)
    (11,795 )     (6,350 )     (11,053 )
Amortization to income:
                       
Actuarial loss, net of tax benefit of $1,870, $1,705 and $1,578
    2,868       2,615       2,437  
Prior service cost, net of tax benefit of $201, $215 and $222
    308       329       343  
Transition obligation, net of tax benefit of $59, $39 and $40
    91       61       62  
Derivative instruments:
                       
Net unrealized loss, net of tax benefit of $(61,348), $(61,329) and $(54,490)
    (93,939 )     (93,996 )     (83,093 )
Reclassification of net realized (gain) loss to income, net of tax (expense) benefit of $48,453, $72,877 and $(24,776)
    74,287       112,452       (39,531 )
 
                 
Balance at end of year
    (159,767 )     (131,587 )     (146,698 )
 
                 
 
                       
NONCONTROLLING INTERESTS
                       
Balance at beginning of year
    111,895       124,990       128,456  
Net income attributable to noncontrolling interests
    20,156       4,434       17,495  
Net capital activities by noncontrolling interests
    (40,152 )     (17,529 )     (20,961 )
 
                 
Balance at end of year
    91,899       111,895       124,990  
 
                 
 
                       
TOTAL EQUITY
  $ 3,775,226     $ 3,428,004     $ 3,570,969  
 
                 
 
                       
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
                       
Net income attributable to common shareholders
  $ 350,053     $ 68,330     $ 242,125  
Other comprehensive income (loss)
    (28,180 )     15,111       (130,835 )
 
                 
Comprehensive income attributable to common shareholders
  $ 321,873     $ 83,441     $ 111,290  
 
                 
See Notes to Pinnacle West’s Consolidated Financial Statements.

 

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Consolidation and Nature of Operations
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, SunCor, APSES, El Dorado and Pinnacle West Marketing & Trading. APS’s consolidated financial statements include the accounts of APS and the Palo Verde sale leaseback VIEs. Intercompany accounts and transactions between the consolidated companies have been eliminated.
APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS accounts for substantially all of our revenues and earnings, and is expected to continue to do so. SunCor was a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico, Idaho and Utah. All activities for SunCor are now reported as discontinued operations (see Note 22). APSES provides energy-related projects to commercial and industrial retail customers in competitive markets in the western United States. In 2008, APSES discontinued its commodity-related energy services (see Note 22). El Dorado is an investment firm. Pinnacle West Marketing & Trading began operations in early 2007. These operations were previously conducted by a division of Pinnacle West through the end of 2006. By the end of 2008, substantially all the contracts were transferred to APS or expired.
In preparing the consolidated financial statements, we have evaluated the events that have occurred after December 31, 2010 through the date the financial statements were issued.
Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. These consolidated financial statements and notes have been prepared consistently with the exception of the reclassification of certain prior year amounts on our Consolidated Statements of Income and Consolidated Balance Sheets in accordance with accounting requirements for reporting discontinued operations (see Note 22), and amended accounting guidance related to VIEs (see Note 2).
Certain line items are presented in more detail on the Consolidated Statements of Cash Flows than was presented in the prior years. Other line items are more condensed than the previous presentation. The prior year amounts were reclassified to conform to the current year presentation. These reclassifications had no impact on total net cash flow provided by operating activities.

 

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following tables show the impact of the reclassifications of prior years (previously reported) amounts (dollars in thousands):
                                 
                            Amount  
                            reported after  
            Reclassifications             adoption of  
            as a result of the             amended VIE  
            adoption of             accounting  
    As     new VIE     Reclassifications     guidance and  
Statement of Income for the Year   previously     accounting     for discontinued     discontinued  
Ended December 31, 2009   reported     guidance     operations     operations  
Operating Revenues
                               
Real estate segment
  $ 103,152     $     $ (103,152 )   $  
Other revenues
    44,762             (18,039 )     26,723  
Operating Expenses
                               
Real estate segment operations
    102,381             (102,381 )      
Real estate impairment charge
    258,453             (258,453 )      
Operations and maintenance
    875,357       (39,660 )     (3,834 )     831,863  
Depreciation and amortization
    404,331       7,704       (4,572 )     407,463  
Taxes other than income taxes
    123,663             (386 )     123,277  
Other expenses
    32,523             (7,989 )     24,534  
Other
                               
Other income
    5,669             (391 )     5,278  
Interest Expense
                               
Interest charges
    233,859       12,747       (9,079 )     237,527  
Allowance for borrowed funds used during construction
    (10,745 )           315       (10,430 )
Income Taxes
    37,827             98,679       136,506  
Income From Continuing Operations
    67,231       19,209       166,118       252,558  
Loss From Discontinued Operations
    (13,676 )           (166,118 )     (179,794 )
Net Income
    53,555       19,209             72,764  
Net Income (Loss) Attributable To Noncontrolling Interests
    (14,775 )     19,209             4,434  
 
                               
Statement of Income for the Year
Ended December 31, 2008
                               
Operating Revenues
                               
Real estate segment
  $ 74,549     $     $ (74,549 )   $  
Other revenues
    41,729             (16,322 )     25,407  
Operating Expenses
                               
Real estate segment operations
    100,102             (100,102 )      
Real estate impairment charge
    18,108             (18,108 )      
Operations and maintenance
    807,852       (39,660 )     (2,915 )     765,277  
Depreciation and amortization
    390,093       7,704       (6,607 )     391,190  
Taxes other than income taxes
    125,336             (483 )     124,853  
Other expenses
    34,171             (8,139 )     26,032  
Other
                               
Other income
    12,797             (3,256 )     9,541  
Interest Expense
                               
Interest charges
    215,684       14,461       (10,229 )     219,916  
Allowance for borrowed funds used during construction
    (18,820 )           4,273       (14,547 )
Income Taxes
    76,897             18,647       95,544  
Income From Continuing Operations
    231,304       17,495       29,536       278,335  
Income (Loss) From Discontinued Operations
    10,821             (29,536 )     (18,715 )
Net Income
    242,125       17,495             259,620  
Net Income Attributable To Noncontrolling Interests
          17,495             17,495  

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                         
            Reclassifications as a     Amounts reported  
            result of the adoption of     after adoption of  
    As previously     the new VIE accounting     amended VIE  
Balance Sheets – December 31, 2009   reported     guidance     accounting guidance  
Property, Plant and Equipment — Palo Verde sale leaseback, net of accumulated depreciation
  $     $ 146,722     $ 146,722  
Deferred Debits — Regulatory assets
    781,714       31,447       813,161  
Current Liabilities — Current maturities of long-term debt
    277,693       25,783       303,476  
Long-Term Debt Less Current Maturities Palo Verde sale leaseback lessor notes
          126,000       126,000  
Deferred Credits and Other — Other
    200,015       (55,938 )     144,077  
Equity — Noncontrolling interests
    29,571       82,324       111,895  
                         
                    Amounts reported  
            Reclassifications as a     after adoption of  
            result of the adoption of     amended VIE  
            the new VIE accounting     accounting  
            guidance and to     guidance and to  
Statement of Cash Flows for the   As previously     conform to current year     conform to current  
Year Ended December 31, 2009   reported     presentation     year presentation  
Cash Flows from Operating Activities
                       
Net income
  $ 53,555     $ 19,209     $ 72,764  
Depreciation and amortization including nuclear fuel
    443,160       7,704       450,864  
Other current assets
    (9,186 )     33,833       24,647  
Home inventory
    33,833       (33,833 )      
Other long-term liabilities
    7,050       9,327       16,377  
Cash Flows from Financing Activities
                       
Repayment of long-term debt
    (435,127 )     (21,755 )     (456,882 )
Noncontrolling interests
          (14,485 )     (14,485 )
Supplemental Disclosure of Cash Flow Information
                       
Cash paid for interest, net of amounts capitalized
    203,860       12,748       216,608  

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                         
                    Amounts reported  
            Reclassifications as a     after adoption of  
            result of the adoption of     amended VIE  
            the new VIE accounting     accounting  
            guidance and to     guidance and to  
Statement of Cash Flows for the   As previously     conform to current year     conform to current  
Year Ended December 31, 2008   reported     presentation     year presentation  
Cash Flows from Operating Activities
                       
Net income
  $ 242,125     $ 17,495     $ 259,620  
Depreciation and amortization including nuclear fuel
    423,969       7,703       431,672  
Other current assets
    8,734       48,041       56,775  
Home inventory
    48,041       (48,041 )      
Other long-term liabilities
    36,880       9,327       46,207  
Cash Flows from Financing Activities
                       
Repayment of long-term debt
    (181,491 )     (20,743 )     (202,234 )
Noncontrolling interests
          (13,782 )     (13,782 )
Supplemental Disclosure of Cash Flow Information
                       
Cash paid for interest, net of amounts capitalized
    191,085       14,461       205,546  
Accounting Records and Use of Estimates
Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Derivative Accounting
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity and fuels. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.
We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. See Note 18 for additional information about our derivative accounting policies.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fair Value Measurements
We determine and disclose the fair value of certain assets and liabilities in accordance with fair value guidance. Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between willing market participants on the measurement date. Inputs to fair value include observable and unobservable data. We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
We determine fair market value using actively-quoted prices for identical instruments when available. When actively quoted prices are not available for the identical instruments we use prices for similar instruments or other corroborative market information or prices provided by other external sources. For options, long-term contracts and other contracts for which price quotes are not available, we use unobservable inputs, such as models and other valuation methods, to determine fair market value.
The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our structured activities are hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. Our practice is to hedge within timeframes established by our executive risk committee.
See Note 14 for additional information about fair value measurements.
Regulatory Accounting
APS is regulated by the ACC and the FERC. The accompanying financial statements reflect the rate-making policies of these commissions. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers.
Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.
See Note 3 for additional information.
Utility Plant and Depreciation
Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes:
    material and labor;
    contractor costs;
    capitalized leases;
    construction overhead costs (where applicable); and
    capitalized interest or an allowance for funds used during construction.

 

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 12.
APS records a regulatory liability for the asset retirement obligations related to its regulated assets. This regulatory liability represents the difference between the amount that has been recovered in regulated rates and the amount calculated in accordance with guidance on accounting for asset retirement obligations. APS believes it can recover in regulated rates the costs capitalized in accordance with this accounting guidance.
We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2010 were as follows:
    Fossil plant — 18 years;
    Nuclear plant — 17 years;
    Other generation — 25 years;
    Transmission — 40 years;
    Distribution — 35 years; and
    Other — 7 years.
For the years 2008 through 2010, the depreciation rates ranged from a low of 1.30% to a high of 10.20%. The weighted-average rate was 2.98% for 2010, 3.06% for 2009 and 3.08% for 2008. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 34 years.
Investments
El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership).
Our investments in the nuclear decommissioning trust fund are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities. See Note 14 for more information on these investments.

 

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Allowance for Funds Used During Construction
AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant. Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statement of Income. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.
AFUDC was calculated by using a composite rate of 9.2% for 2010, 5.9% for 2009 and 7.0% for 2008. APS compounds AFUDC monthly and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
Electric Revenues
We derive electric revenues primarily from sales of electricity to our regulated Native Load customers. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.
Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called a “book-out” and usually occurs for contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and fuel and purchased power costs.
Effective January 1, 2010, electric revenues also include proceeds for line extension payments for new or upgraded service in accordance with the 2009 retail rate case settlement agreement (see Note 3). This revenue treatment continues through 2012, or until new rates are established in APS’s next general retail rate case, if that is before year end 2012. Certain proceeds received under previous versions of the line extension policy, or for activities not involving an extension or upgrade of service (e.g., service relocations at the request of governmental entities or undergrounding of overhead facilities) will continue to be treated as contributions in aid of construction and will not impact electric revenues.
Allowance for Doubtful Accounts
The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including accrued utility revenues. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment.

 

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Real Estate Investments
Real estate investments primarily included SunCor’s land, home inventory, commercial property and investments in joint ventures. Land included acquisition costs, infrastructure costs, capitalized interest and property taxes directly associated with the acquisition and development of each project. Home inventory consisted of construction costs, improved lot costs, capitalized interest and property taxes on homes and condos under construction. Homes under construction were classified as “real estate investments” on the Consolidated Balance Sheets; upon completion of construction they transferred to “home inventory” with the expectation that they would be sold in a timely manner.
For the purposes of evaluating impairment, in accordance with the provisions on accounting for the impairment or disposal of long-lived assets, we classified our real estate assets, such as land under development, land held for future development, and commercial property as “held and used.” When events or changes in circumstances indicated that the carrying values of real estate assets considered held and used would not be recoverable, we compared the undiscounted cash flows that we estimated would be generated by each asset to its carrying amount. If the carrying amount exceeded the undiscounted cash flows, we adjusted the asset to fair value and recognized an impairment charge. The adjusted value became the new book value (carrying amount) for held and used assets. Our internal models used inputs that we believe were consistent with those that would be used by market participants.
Real estate home inventory was considered to be held for sale for purposes of evaluating impairment in accordance with the provisions of accounting guidance for impairment or disposal of long-lived assets. Home inventories were reported at the lower of carrying amount or fair value less costs to sell. Fair value less costs to sell was evaluated each period to determine if it had changed. Losses (and gains not to exceed any cumulative loss previously recognized) were reported as adjustments to the carrying amount.
Investments in joint ventures for which SunCor did not have a controlling financial interest were not consolidated, but were accounted for using the equity method of accounting. In addition, see Note 22 and Note 23.
Cash and Cash Equivalents
We consider all highly liquid investments with a maturity of three months or less at acquisition to be cash equivalents.
Nuclear Fuel
APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production method is based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.
APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charges APS $0.001 per kWh of nuclear generation. See Note 11 for information on spent nuclear fuel disposal and Note 14 for information on nuclear decommissioning costs.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income Taxes
Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes. We file our federal income tax return on a consolidated basis and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. The income tax liability accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures. See Note 4.
Intangible Assets
We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’s software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives. Amortization expense was $45 million in 2010, $35 million in 2009 and $33 million in 2008. Estimated amortization expense on existing intangible assets over the next five years is $40 million in 2011, $36 million in 2012, $29 million in 2013, $23 million in 2014 and $15 million in 2015. At December 31, 2010, the weighted average remaining amortization period for intangible assets was 7 years.
2. New Accounting Standards
Variable Interest Entities
On January 1, 2010 we adopted amended accounting guidance relating to the consolidation of VIEs. This amended guidance significantly changed the consolidation model for VIEs. Under the prior guidance the consolidation model considered risk absorption using a quantitative approach when determining the primary beneficiary. The consolidation model under the new guidance requires a qualitative assessment and focuses on the power to direct activities of the VIE when determining the primary beneficiary. As a result of applying this qualitative assessment, we have determined that APS is the primary beneficiary of certain VIEs relating to the Palo Verde Unit 2 sale leaseback transactions, and is therefore required to consolidate these VIEs. Prior to adopting this new guidance, APS was not considered the primary beneficiary of these VIEs and did not consolidate these entities. We have adopted this guidance using retrospective application and have adjusted prior periods presented to reflect consolidation of the VIEs in those periods (see Note 1). See Note 20 for additional discussion and disclosures.
Future Accounting Changes
The FASB is currently working on several projects with the desire to converge GAAP with IFRS. These projects include accounting for leases, revenue recognition, and financial instruments, among other items. The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, we cannot determine the impact on our financial statements that may result from any such future changes.

 

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Concurrent with these convergence projects, the SEC is considering mandating IFRS for U.S. companies. At this time, the impacts and timing of potential conversion to IFRS are uncertain and cannot be determined until final conversion requirements are mandated. The potential preparation of our financial statements in accordance with IFRS could have a significant impact on our reported financial statement results.
3. Regulatory Matters
2008 General Retail Rate Case Impacts
On December 30, 2009, the ACC issued an order approving a settlement agreement entered into by APS and twenty-one other parties to its general retail rate case, which was originally filed in March 2008. The settlement agreement included a net retail rate increase of $207.5 million, which represented a base rate increase of $344.7 million less a reclassification of $137.2 million of fuel and purchased power revenues from the then-existing PSA to base rates. The new rates were effective January 1, 2010. The settlement agreement also contained on-going requirements, commitments and authorizations, including the following:
    Revenue accounting treatment for line extension payments received for new or upgraded service from January 1, 2010 through year end 2012 (or until new rates are established in APS’s next general rate case, if that is before the end of 2012);
    An authorized return on common equity of 11%;
    A capital structure comprised of 46.2% debt and 53.8% common equity;
    A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014;
    Authorization and requirements of equity infusions into APS of at least $700 million during the period beginning June 1, 2009 through December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in the second quarter of 2010); and
    Various modifications to the existing energy efficiency, demand-side management and renewable energy programs that require APS to, among other things, expand its conservation and demand-side management programs and its use of renewable energy, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand-side management costs and incentives.
The parties also agreed to a rate case filing plan in which APS is prohibited from filing its next two general rate cases until on or after June 1, 2011 and June 1, 2013, respectively, unless certain extraordinary events occur. Subject to the foregoing, APS may not request its next general retail rate increase to be effective prior to July 1, 2012. On February 1, 2011, APS filed a 120-day advanced notice of its intent to file its next rate case on June 1, 2011. The parties agreed to use good faith efforts to process these subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occur within 30 days after the filing of a rate case.

 

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Cost Recovery Mechanisms
APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.
Renewable Energy Standard. In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.
During 2009, APS filed its annual RES implementation plan, covering the 2010-2014 timeframe and requesting 2010 RES funding approval. The plan provided for the acquisition of renewable generation in compliance with requirements through 2014, and requested RES funding of $87 million for 2010, which was later approved by the ACC. APS also sought various other determinations in its plan, including approval of the AZ Sun Program and the Community Power Project in Flagstaff, Arizona described below.
On March 3, 2010, the ACC approved the AZ Sun Program, which contemplates the addition of 100 MW of APS-owned solar resources through 2014. Through this program, APS plans to invest up to $500 million in solar photovoltaic projects across Arizona, which APS will acquire through competitive procurement processes. The costs associated with the first 50 MW under this program will be recovered initially through the RES until such time as the costs are recovered in base rates or other mechanisms. The costs of the second 50 MW will be recovered through a mechanism to be determined in APS’s next retail rate case.
On April 1, 2010, the ACC approved the Community Power Project, a pilot program in which APS will own, operate and receive energy from approximately 1.5 MW of solar panels on the rooftops of up to 200 residential and business customers located within a certain test area in Flagstaff, Arizona. The capital carrying costs of the program will be recovered through the RES until such time as these costs are recovered in base rates.
On July 1, 2010, APS filed its annual RES implementation plan, covering the 2011-2015 timeframe and requesting 2011 RES funding of $96 million. The 2011 Plan addressed enhancements to the residential distributed energy incentive program based on high customer participation, among other things. On October 13, 2010, APS filed an adjusted RES implementation plan to reflect the following items, among others: 1) increased clarity relating to customer project in-service dates and related budget revisions; 2) AZ Sun Program updates; and 3) the addition of 10 MW of biomass capacity. On December 10, 2010, the ACC approved the 2011 Plan and associated funding request. In January 2011, the ACC voted to reconsider four aspects of the approved 2011 Plan, including: (a) approval to proceed with a feed-in tariff filing; (b) approval for APS to participate in the ownership of distributed energy facilities in the Schools and Government program; (c) denial of a Rapid Reservation program that allows customers to receive priority in the incentive reservation process in exchange for receipt of a reduced incentive amount; and (d) allocation of the budget among various programs and studies. Hearings were held on January 24, 2011 and January 28, 2011. The ACC amended its original decision that approved the 2011 Plan as follows: the ACC (a) reversed its approval of a feed-in tariff program; (b) restricted APS’s ownership of facilities to only economically challenged, rural schools and only after a school has received a bid from a third-party solar installer; (c) approved the Rapid Reservation program; and (d) maintained the original approved budget with some timing modifications.

 

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Demand-Side Management Adjustor Charge (“DSMAC”). The 2009 retail rate case settlement agreement requires APS to submit an annual Energy Efficiency Implementation Plan for review by and approval of the ACC. On July 15, 2009, APS filed its initial Energy Efficiency Implementation Plan, requesting approval by the ACC of programs and program elements for which APS had estimated a budget in the amount of $50 million for 2010. APS received ACC approval of all of its proposed programs and implemented the new DSMAC on March 1, 2010. A surcharge was added to customer bills in order to recover these estimated amounts for use on certain demand-side management programs. The surcharge allows for the recovery of energy efficiency expenses and any earned incentives.
The ACC approved recovery of all 2009 program costs plus incentives. The change from program cost recovery on a historical basis to recovery on a concurrent basis, as authorized in the settlement agreement, resulted in this one-time need to address two years (2009 and 2010) of cost recovery. As requested by APS, 2009 program cost recovery is to be spread over a three-year period.
On June 1, 2010, APS filed its 2011 Energy Efficiency Implementation Plan. In order to meet the energy efficiency goal for 2011 established by the settlement agreement of annual energy savings of 1.25%, expressed as a percent of total energy resources to meet retail load, APS proposed a total budget for 2011 of $79 million. On February 17, 2011, a total budget for 2011 of $80 million was approved and when added to the amortization of 2009 costs discussed above less the $10 million already being recovered in general rates, the DSMAC would recover approximately $75 million over a twelve month period beginning March 1, 2011. These amounts do not include approximately $1 million for an electric vehicle charging station program submitted to the ACC for approval on September 30, 2010.
PSA Mechanism and Balance. The PSA, which the ACC initially approved in 2005 as a part of APS’s 2003 rate case, and which was modified by the ACC in 2007, provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:
    APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;
    under a 90/10 sharing arrangement, APS defers 90% of the difference between retail fuel and purchased power costs (excluding certain costs, such as renewable energy resources and the capacity components of long-term purchased power agreements acquired through competitive procurement) and the Base Fuel Rate; APS absorbs 10% of the retail fuel and purchased power costs above the Base Fuel Rate and retains 10% of the benefit from the retail fuel and purchased power costs that are below the Base Fuel Rate;

 

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    an adjustment to the PSA rate is made annually each February 1st (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;
    the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);
    the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and
    the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.
The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2010 and 2009 (dollars in millions):
                 
    Year Ended  
    December 31,  
    2010     2009  
Beginning balance
  $ (87 )   $ 8  
Deferred fuel and purchased power costs-current period
    (93 )     52  
Amounts recovered through revenues
    122       (147 )
 
           
Ending balance
  $ (58 )   $ (87 )
 
           
The PSA rate for the PSA year beginning February 1, 2011 is ($0.0057) per kWh as compared to ($0.0045) per kWh for the prior year. The regulatory liability at December 31, 2010 reflects lower average prices, primarily for natural gas and gas-based generation. Any uncollected (overcollected) deferrals during the 2011 PSA year will be included in the historical component of the PSA rate for the PSA year beginning February 1, 2012.
Transmission Rates and Transmission Cost Adjustor. In July 2008, the FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS must file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.

 

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The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and have a significant effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may be calculated to account for previously over-collected amounts.
Effective June 1, 2010, APS’s annual wholesale transmission rates for all users of its transmission system were reduced by approximately $12 million in accordance with the FERC-approved formula as a result of lower costs reflected in the formula. Approximately $10 million of this revenue reduction relates to transmission services used for APS’s retail customers. On May 20, 2010, APS filed with the ACC an application for the related reduction of its TCA rate. The ACC approved the TCA reduction on July 27, 2010.
Regulatory Assets and Liabilities
The detail of regulatory assets is as follows (dollars in millions):
                 
    December 31,  
    2010     2009  
Pension and other postretirement benefits (Note 8)
  $ 669     $ 532  
Deferred fuel and purchased power — mark-to-market (Note 18)
    77       41  
Deferred income taxes (Note 4)
    72       59  
Transmission vegetation management
    46       34  
Coal reclamation
    38       16  
Palo Verde VIE (Note 20)
    33       31  
Deferred compensation
    32       31  
Tax expense of Medicare subsidy (Note 8)
    23        
Loss on reacquired debt
    22       23  
Demand side management (a)
    18       18  
Other
    19       28  
 
           
Total regulatory assets (b)
  $ 1,049     $ 813  
 
           
     
(a)   See Cost Recovery Mechanisms discussion above.
 
(b)   There are no regulatory assets for which regulators have allowed recovery of costs but not allowed a return by exclusion from rate base.
Included in the balance of regulatory assets at December 31, 2010 and 2009 is a regulatory asset for pension and other postretirement benefits. This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future earnings.

 

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The detail of regulatory liabilities is as follows (dollars in millions):
                 
    December 31,  
    2010     2009  
Removal costs (Note 1) (a)
  $ 379     $ 385  
Asset retirement obligations (Note 12)
    184       156  
Deferred fuel and purchased power (b)(c)
    58       87  
Renewable energy standard (b)
    50       51  
Spent nuclear fuel (Note 11)
    45       34  
Deferred gains on utility property
    18       20  
Tax benefit of Medicare subsidy (Note 8)
          17  
Other
    19       16  
 
           
Total regulatory liabilities
  $ 753     $ 766  
 
           
     
(a)   In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.
 
(b)   See Cost Recovery Mechanisms discussion above.
 
(c)   Subject to a carrying charge.
4. Income Taxes
Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates.
APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations. The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction and pension and other postretirement benefits. The regulatory liabilities relate to deferred taxes resulting primarily from investment tax credits. APS amortizes these amounts as the differences reverse.
Pinnacle West expects to recognize approximately $132 million of cash tax benefits related to SunCor’s strategic asset sales (see Note 23), a majority of which have been realized as of December 31, 2010. Approximately $7 million of these benefits were recorded in 2010 as reductions to income tax expense related to the current impairment charges. The additional $125 million of tax benefits were recorded as reductions to income tax expense related to SunCor impairment charges recorded on or before December 31, 2009.
The $68 million income tax receivables on the Consolidated Balance Sheets represent the anticipated refunds related to an APS tax accounting method change approved by the IRS in the third quarter of 2009 and the current year tax benefits related to the SunCor strategic asset sales that closed in 2010. A majority of this amount is classified as long-term, as cash refunds are not expected to be received in the next twelve months.

 

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The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):
                         
    2010     2009     2008  
Total unrecognized tax benefits, January 1
  $ 201,216     $ 63,318     $ 157,869  
Additions for tax positions of the current year
    7,551       44,094       12,923  
Additions for tax positions of prior years
          98,942       32,510  
Reductions for tax positions of prior years for:
                       
Changes in judgment
    (11,017 )           (4,454 )
Settlements with taxing authorities
    (62,199 )     (4,089 )     (35,812 )
Lapses of applicable statute of limitations
    (7,956 )     (1,049 )     (99,718 )
 
                 
Total unrecognized tax benefits, December 31
  $ 127,595     $ 201,216     $ 63,318  
 
                 
During the first quarter of 2010, the Company reached a settlement with the IRS with regard to the examination of tax returns for the years ended December 31, 2005 through 2007. As a result of this settlement, net uncertain tax positions decreased $62 million, including approximately $3 million which decreased our effective tax rate. Additionally, the settlement resulted in the recognition of net interest benefits of approximately $4 million through the effective tax rate.
Included in the balances of unrecognized tax benefits at December 31, 2010, 2009 and 2008 were approximately $7 million, $16 million and $16 million, respectively, of tax positions that, if recognized, would decrease our effective tax rate.
As of the balance sheet date, the tax year ended December 31, 2008 and all subsequent tax years remain subject to examination by the IRS. With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 1999. We do not anticipate that there will be any significant increases or decreases in our unrecognized tax benefits within the next twelve months.
We reflect interest and penalties, if any, on unrecognized tax benefits in the Consolidated Statements of Income as income tax expense. The amount of interest recognized in the Consolidated Statement of Income related to unrecognized tax benefits was a pre-tax benefit of $2 million for 2010, a pre-tax expense of $2 million for 2009 and a pre-tax benefit of $51 million for 2008.
The total amount of accrued liabilities for interest recognized in the consolidated Balance Sheets related to unrecognized tax benefits was $6 million as of December 31, 2010, $8 million as of December 31, 2009 and $6 million as of December 31, 2008. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, as of December 31, 2010, we have recognized $5 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

 

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The components of income tax expense are as follows (dollars in thousands):
                         
    Year Ended December 31,  
    2010     2009     2008  
Current:
                       
Federal
  $ (108,827 )   $ (38,502 )   $ (85,866 )
State
    25,545       (38,080 )     11,738  
 
                 
Total current
    (83,282 )     (76,582 )     (74,128 )
 
                 
Deferred:
                       
Income from continuing operations
    271,147       105,492       158,024  
Discontinued operations
    (10,736 )            
 
                 
Total deferred
    260,411       105,492       158,024  
 
                 
Total income tax expense
    177,129       28,910       83,896  
Less: income tax expense (benefit) on discontinued operations
    12,808       (107,596 )     (11,648 )
 
                 
Income tax expense — continuing operations
  $ 164,321     $ 136,506     $ 95,544  
 
                 
The following chart compares pretax income from continuing operations at the 35% federal income tax rate to income tax expense — continuing operations (dollars in thousands):
                         
    Year Ended December 31,  
    2010     2009     2008  
 
Federal income tax expense at 35% statutory rate
  $ 180,222     $ 136,172     $ 130,858  
Increases (reductions) in tax expense resulting from:
                       
State income tax net of federal income tax benefit
    17,878       14,837       12,640  
Credits and favorable adjustments related to prior years resolved in current year
    (17,300 )           (28,873 )
Medicare Subsidy Part-D (see Note 8)
    1,311       (2,095 )     (1,993 )
Allowance for equity funds used during construction (see Note 1)
    (6,563 )     (4,265 )     (5,755 )
Palo Verde VIE noncontrolling interest (see Note 20)
    (7,057 )     (6,723 )     (6,123 )
Other
    (4,170 )     (1,420 )     (5,210 )
 
                 
Income tax expense — continuing operations
  $ 164,321     $ 136,506     $ 95,544  
 
                 

 

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The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):
                 
    December 31,  
    2010     2009  
Current asset
  $ 94,602     $ 53,990  
Long-term liability
    (1,833,566 )     (1,496,095 )
 
           
Deferred income taxes — net
  $ (1,738,964 )   $ (1,442,105 )
 
           
The components of the net deferred income tax liability were as follows (dollars in thousands):
                 
    December 31,  
    2010     2009  
DEFERRED TAX ASSETS
               
Risk management activities
  $ 124,731     $ 87,404  
Regulatory liabilities:
               
Asset retirement obligation and removal costs
    222,448       213,814  
Deferred fuel and purchased power
    23,089       34,463  
Renewable energy standard
    18,749        
Other
    28,360       21,613  
Pension and other postretirement liabilities
    321,182       306,515  
Real estate investments and assets held for sale
    19,855       113,082  
Renewable energy incentives
    37,327        
Credit and loss carryforwards
    42,971       3,423  
Other
    68,684       57,015  
 
           
Total deferred tax assets
    907,396       837,329  
 
           
DEFERRED TAX LIABILITIES
               
Plant-related
    (2,210,976 )     (1,951,262 )
Risk management activities
    (30,125 )     (20,863 )
Regulatory assets:
               
Allowance for equity funds used during construction
    (28,276 )     (23,285 )
Deferred fuel and purchased power — mark-to-market
    (30,276 )     (16,167 )
Pension and other postretirement benefits
    (264,313 )     (210,080 )
Other
    (77,078 )     (57,210 )
Other
    (5,316 )     (567 )
 
           
Total deferred tax liabilities
    (2,646,360 )     (2,279,434 )
 
           
Deferred income taxes — net
  $ (1,738,964 )   $ (1,442,105 )
 
           
A majority of the deferred tax assets for credit and loss carryforwards relate to federal general business credits and federal net operating losses. These federal credits and losses first begin to expire in 2029.

 

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. Lines of Credit and Short-Term Borrowings
Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for the commercial paper programs. During the first quarter of 2010, Pinnacle West and APS refinanced revolving credit facilities existing at the time that would have otherwise matured in December 2010. Since March 2010, Pinnacle West and APS have accessed the commercial paper markets, which neither company had utilized since the third quarter of 2008 due to negative market conditions.
The table below presents these credit facilities and amounts available and outstanding and other short-term borrowings as of December 31, 2010 (dollars in millions):
                                                     
                Letters                     Weighted        
                of                     Average        
Credit       Amount     Credit     Short-Term     Unused     Interest     Commitment  
Facility   Expiration   Committed     Used     Borrowings     Amount     Rate     Fees  
PNW Revolving Credit Facility
  February 2013   $ 200     $     $     $ 183             0.625 %
 
                                                   
PNW Commercial Paper
  January 2011                 17             0.840 %      
 
                                                   
APS Revolving Credit Facility
  February 2013     500                   500             0.500 %
 
                                                   
APS Revolving Credit Facility
  September 2011     489       20             469             0.100 %
 
                                           
Total
      $ 1,189     $ 20     $ 17     $ 1,152                  
 
                                           
Pinnacle West
On February 12, 2010, Pinnacle West refinanced its $283 million revolving credit facility that would have matured in December 2010, and decreased the size of the facility to $200 million. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Pinnacle West will use the facility for general corporate purposes, commercial paper program support of up to $200 million, or for the issuance of letters of credit. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings.
APS
On February 12, 2010, APS refinanced its $377 million credit facility that would have matured in December 2010, and increased the size of the facility to $500 million. APS may increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use the facility for general corporate purposes, commercial paper program support and for the issuance of letters of credit. Interest rates are based on APS’s senior unsecured debt credit ratings.

 

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On February 14, 2011, APS refinanced its $489 million revolving credit facility that would have matured in September 2011, and increased the size of the facility to $500 million. The new revolving credit facility terminates in February 2015. APS may increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use the facility for general corporate purposes, commercial paper program support and for the issuance of letters of credit. Interest rates are based on APS’s senior unsecured debt credit ratings.
At December 31, 2010, APS had two credit facilities totaling $989 million, consisting of the $500 million and $489 million credit facilities described above. These facilities were available either to support the issuance of up to $250 million in commercial paper, or for bank borrowings, including issuances of letters of credit. See Note 21 for discussion of APS’s letters of credit.
SunCor
SunCor had no short-term borrowings at December 31, 2010 and approximately $5 million at December 31, 2009.
The table below presents the consolidated credit facilities and amounts available and outstanding and other short-term borrowings as of December 31, 2009 (dollars in millions):
                                             
                                Weighted        
Credit       Amount     Short-Term     Unused     Average     Commitment  
Facility   Expiration   Committed     Borrowings     Amount     Interest Rate     Fees  
PNW Revolving Credit Facility
  December 2010   $ 283     $ 149     $ 134       0.982 %     0.15 %
 
                                           
APS Revolving Credit Facility
  December 2010     377             377             0.11 %
 
                                           
APS Revolving Credit Facility
  September 2011     489             489             0.10 %
 
                                           
SunCor Short-term Borrowings
  January 2010           5             LIBOR plus 2.50 %      
 
                                     
Total
      $ 1,149     $ 154     $ 1,000                  
 
                                     
Pinnacle West
At December 31, 2009, the Pinnacle West credit facility was available to support the issuance of up to $250 million in commercial paper or bank borrowings, including issuances of letters of credit, up to $94 million. At December 31, 2009, Pinnacle West had borrowings of approximately $149 million under its credit facility, no letters of credit and no other short-term borrowings.

 

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
APS
At December 31, 2009, the APS credit facilities were available either to support the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including issuances of letters of credit, up to $583 million. At December 31, 2009, APS had no borrowings or letters of credit under its revolving credit facilities or other short-term borrowings.
Debt Provisions
Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On October 30, 2007, the ACC issued a financing order in which it approved APS’s request, subject to specified parameters and procedures, to increase (a) APS’s short-term debt authorization from 7% of APS’s capitalization to (i) 7% of APS’s capitalization plus (ii) $500 million (which is required to be used for purchases of natural gas and power) and (b) APS’s long-term debt authorization from approximately $3.2 billion to $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs. This financing order expires December 31, 2012; however, all debt previously authorized and outstanding on December 31, 2012 will remain authorized and valid obligations of APS.

 

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. Long-Term Debt and Liquidity Matters
Substantially all of Pinnacle West’s and APS’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2010 and 2009 (dollars in thousands):
                                 
    Maturity     Interest     December 31,  
    Dates (a)     Rates     2010     2009  
APS
                               
Pollution control bonds — Variable
    2024-2038       (b )   $ 43,580     $ 222,880  
Pollution control bonds — Fixed
    2029-2034       (c )     522,275       342,975  
Pollution control bonds with senior notes
    2029       5.05 %     90,000       90,000  
Unsecured notes
    2011       6.375 %     400,000       400,000  
Unsecured notes
    2012       6.50 %     375,000       375,000  
Unsecured notes
    2014       5.80 %     300,000       300,000  
Unsecured notes
    2015       4.650 %     300,000       300,000  
Unsecured notes
    2016       6.25 %     250,000       250,000  
Unsecured notes
    2019       8.75 %     500,000       500,000  
Unsecured notes
    2033       5.625 %     200,000       200,000  
Unsecured notes
    2035       5.50 %     250,000       250,000  
Unsecured notes
    2036       6.875 %     150,000       150,000  
Secured note
    2014       6.00 %           1,075  
Palo Verde sale leaseback lessor notes
    2015       8.00 %     126,000       151,783  
Unamortized discount
                    (6,183 )     (7,185 )
Capitalized lease obligations
    2011-2012       (d )     2,001       2,837  
 
                           
Subtotal (e)
                    3,502,673       3,529,365  
 
                           
SUNCOR
                               
Notes payable
    2011       (f )           95,535  
Capitalized lease obligations
    2011-2012       (g )           100  
 
                           
Subtotal
                          95,635  
 
                           
PINNACLE WEST
                               
Senior notes
    2011       5.91 %     175,000       175,000  
 
                           
Total long-term debt
                    3,677,673       3,800,000  
Less current maturities:
                               
APS
                    456,879       222,959  
SunCor
                          80,517  
Pinnacle West
                    175,000        
 
                           
Total
                    631,879       303,476  
 
      &n