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 ______

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):

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:

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.

 

 

TABLE OF CONTENTS

		Page
GLOSSARY OF NAMES AND TECHNICAL TERMS			1
FORWARD-LOOKING STATEMENTS			2
PART I			3
Item 1. Business			3
Item 1A. Risk Factors			27
Item 1B. Unresolved Staff Comments			38
Item 2. Properties			39
Item 3. Legal Proceedings			41
Executive Officers of Pinnacle West			42
PART II			44
Item 5. Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			44
Item 6. Selected Financial Data			46
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			48
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.			78
Item 8. Financial Statements and Supplementary Data			79
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			173
Item 9A. Controls and Procedures			173
Item 9B. Other Information			174
PART III			174
Item 10. Directors, Executive Officers and Corporate Governance of Pinnacle West			174
Item 11. Executive Compensation			174
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			174
Item 13. Certain Relationships and Related Transactions, and Director Independence			176
Item 14. Principal Accountant Fees and Services			176
PART IV			177
Item 15. Exhibits and Financial Statement Schedules			177
SIGNATURES			219
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.

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

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.

PART I

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

Energy Sources and Resource Planning

To serve its customers, APS obtains power through its various generation stations and through purchased power agreements. Resource planning is an important function necessary to meet Arizona’s future energy needs. APS’s sources of energy by fuel type during 2010 were as follows:

Generation Facilities

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

Coal Fueled Generating Facilities

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

On November 8, 2010, APS and 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.

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.

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.

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.

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.

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 1 ^st 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.

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:

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.

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.

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.

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 111 ^th 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.)

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.

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.

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.

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).

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.

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 52 ^nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with 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.

Navajo Nation Environmental Issues

Four Corners and the Navajo Plant are located on the Navajo Reservation and are held under easements granted by the federal government as well as leases from the Navajo Nation. See “Energy Sources and Resource Planning — Generation Facilities — Coal Fueled Generating Facilities” above for additional information regarding these plants.

In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively, the “Navajo Acts”). The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water and pesticide activities, including those activities that occur at Four Corners and the Navajo Plant. On October 17, 1995, the Four Corners participants and the Navajo Plant participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, challenging the applicability of the Navajo Acts as to Four Corners and the Navajo Plant. The Court has stayed these proceedings pursuant to a request by the parties, and the parties are seeking to negotiate a settlement.

In April 2000, the Navajo Nation Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. APS believes the Navajo Nation exceeded its authority when it adopted the operating permit regulations. On July 12, 2000, the Four Corners participants and the Navajo Plant participants each filed a petition with the Navajo Supreme Court for review of these regulations. Those proceedings have been stayed, pending the settlement negotiations mentioned above. APS cannot currently predict the outcome of this matter.

On May 18, 2005, APS, Salt River Project, as the operating agent for the Navajo Plant, and the Navajo Nation executed a Voluntary Compliance Agreement to resolve their disputes regarding the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the courts granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the Clean Air Act. The agreement does not address or resolve any dispute relating to other Navajo Acts. APS cannot currently predict the outcome of this matter.

Water Supply

Assured supplies of water are important for APS’s generating plants. At the present time, APS has adequate water to meet its needs. However, the Four Corners region, in which Four Corners is located, has been experiencing drought conditions that may affect the water supply for the plants if adequate moisture is not received in the watershed that supplies the area. APS is continuing to work with area stakeholders to implement agreements to minimize the effect, if any, on future operations of the plant. The effect of the drought cannot be fully assessed at this time, and APS cannot predict the ultimate outcome, if any, of the drought or whether the drought will adversely affect the amount of power available, or the price thereof, from Four Corners.

Conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions, which, in addition to future supply conditions, have the potential to impact APS operations.

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

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 .

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.

Income taxes related to El Dorado are recorded by Pinnacle West.

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.

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).

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.

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.

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 CO ₂ , 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 CO ₂ 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.

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.

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.

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.

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.

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:

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continuation of the current economic downturn;

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terrorist attacks or threatened attacks;

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mergers among financial institutions and the overall health of the banking industry; or

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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.

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:

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reducing our credit ratings;

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increasing the cost of future debt financing and refinancing;

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increasing our vulnerability to adverse economic and industry conditions; and

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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.

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:

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variations in our quarterly operating results;

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

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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;

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

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

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favorable or adverse regulatory or legislative developments;

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our dividend policy;

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

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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:

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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;

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

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

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

While these provisions have the effect of encouraging persons seeking to acquire control of us to negotiate with our Board of Directors, they could enable the Board 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.

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 .

ITEM 2. PROPERTIES

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:

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.

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.

PART II

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				—				—

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