UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2009

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

For the transition period from                      to                     

Commission File		Registrants; State of Incorporation;		IRS Employer
Number		Addresses; and Telephone Number		Identification No.
1-8962		PINNACLE WEST CAPITAL CORPORATION		86-0512431
		(An Arizona corporation)
		400 North Fifth Street, P.O. Box 53999
		Phoenix, Arizona 85072-3999
		(602) 250-1000
1-4473		ARIZONA PUBLIC SERVICE COMPANY		86-0011170
		(An Arizona corporation)
		400 North Fifth Street, P.O. Box 53999
		Phoenix, Arizona 85072-3999
		(602) 250-1000

Securities registered pursuant to Section 12(b) of the Act:

 

		Title Of Each Class		Name Of Each Exchange On Which Registered
PINNACLE WEST CAPITAL CORPORATION		Common Stock, No Par Value		New York Stock Exchange
ARIZONA PUBLIC SERVICE COMPANY		None		None

 

Securities registered pursuant to Section 12(g) of the Act:

ARIZONA PUBLIC SERVICE COMPANY Common Stock, Par Value $2.50 per share

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

PINNACLE WEST CAPITAL CORPORATION

Yes þ

No o

ARIZONA PUBLIC SERVICE COMPANY

Yes þ

No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

PINNACLE WEST CAPITAL CORPORATION

Yes o

No þ

ARIZONA PUBLIC SERVICE COMPANY

Yes o

No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

PINNACLE WEST CAPITAL CORPORATION

Yes þ

No o

ARIZONA PUBLIC SERVICE COMPANY

Yes þ

No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

PINNACLE WEST CAPITAL CORPORATION

Yes o

No o

ARIZONA PUBLIC SERVICE COMPANY

Yes o

No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or in any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

PINNACLE WEST CAPITAL CORPORATION

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o
				(Do not check if a smaller reporting company)

ARIZONA PUBLIC SERVICE COMPANY

Large accelerated filer o		Accelerated filer o		Non-accelerated filer þ		Smaller reporting company o
				(Do not check if a smaller reporting company)

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ

State the aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of each registrant’s most recently completed second fiscal quarter:

PINNACLE WEST CAPITAL CORPORATION		$3,035,693,863 as of June 30, 2009
ARIZONA PUBLIC SERVICE COMPANY		$0 as of June 30, 2009

The number of shares outstanding of each registrant’s common stock as of February 15, 2010

PINNACLE WEST CAPITAL CORPORATION		101,445,202 shares
ARIZONA PUBLIC SERVICE COMPANY		Common Stock, $2.50 par value, 71,264,947 shares. Pinnacle West Capital Corporation is the sole holder of Arizona Public Service Company’s Common Stock.

 

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Pinnacle West Capital Corporation’s definitive Proxy Statement relating to its Annual Meeting of Shareholders to be held on May 19, 2010 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			22
Item 1B. Unresolved Staff Comments			33
Item 2. Properties			34
Item 3. Legal Proceedings			37
Item 4. Submission of Matters to a Vote of Security Holders			37
Executive Officers of Pinnacle West			38
PART II			40
Item 5. Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			40
Item 6. Selected Financial Data			42
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			44
Item 7A. Quantitative and Qualitative Disclosures about Market Risk			79
Item 8. Financial Statements and Supplementary Data			80
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			169
Item 9A. Controls and Procedures			169
Item 9B. Other Information			170
PART III			170
Item 10. Directors, Executive Officers and Corporate Governance of Pinnacle West			170
Item 11. Executive Compensation			170
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			170
Item 13. Certain Relationships and Related Transactions, and Director Independence			172
Item 14. Principal Accountant Fees and Services			172
PART IV			173
Item 15. Exhibits and Financial Statement Schedules			173
SIGNATURES			213

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 7 of this report is divided into two sections — Pinnacle West Consolidated and APS. The Pinnacle West Consolidated section describes Pinnacle West and its subsidiaries on a consolidated basis, including discussions of Pinnacle West’s regulated utility and non-utility operations. Item 8 of this report includes Consolidated Financial Statements of Pinnacle West and 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’ 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’ 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
kV		Kilovolt, one thousand volts
kWh		Kilowatt-hour, one thousand watts per hour
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
Salt River Project		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 you 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. These factors include:

•

regulatory and judicial decisions, developments and proceedings;

•

our ability to achieve timely and adequate rate recovery of our costs;

•

our ability to reduce 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;

•

power plant performance and outages;

•

volatile fuel and purchased power costs;

•

fuel and water supply availability;

•

new legislation or regulation 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 credit, financial and real estate market conditions;

•

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

•

restrictions on dividends or other burdensome provisions in our credit agreements and ACC orders;

•

our ability, or the ability of our subsidiaries, to meet debt service obligations;

•

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;

•

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;

•

transmission and distribution 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 ability of our counterparties and power plant participants to meet contractual or other obligations;

•

technological developments in the electric industry; and

•

economic and other conditions affecting the real estate market in SunCor’s market areas.

These and other factors are discussed in Risk Factors described in Item 1A of this report, which you should review carefully before placing any reliance on our financial statements or disclosures. Neither Pinnacle West nor APS assumes any obligation to update any forward-looking statements, even if our internal estimates change, except as may be required by applicable law.

PART I

ITEM 1. BUSINESS

Pinnacle West

Pinnacle West is a holding company that conducts business through its subsidiaries. We derive the majority of our revenues and earnings from our wholly-owned subsidiary, APS. APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the State of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.

Operating Revenues (in thousands):

		Year Ended December 31,
		2009				2008				2007
APS		$	3,149,500			$	3,133,496			$	2,936,277
Percentage of Pinnacle West Consolidated		96%				95%				89%

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

Our reportable business segments are the regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities, and includes electricity generation, transmission and distribution, and the real estate segment, which consists of real estate development and investment activities in the western United States.

Due to the continuing distressed conditions in the real estate markets, in 2009 our real-estate subsidiary, SunCor, undertook a program to dispose of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to eliminate its outstanding debt. As a part of this plan to sell substantially all of SunCor’s assets, the real estate segment may no longer be a reporting segment in the future. See Note 17 for financial information of our business segments.

BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY

APS currently provides electric service to approximately 1.1 million customers. We own or lease more than 6,280 MW of regulated generation capacity and we hold a mix of both long-term and short-term power purchase agreements for additional capacity, including a variety of agreements for the purchase of renewable energy. During 2009, no single purchaser or user of energy accounted for more than 1.1% of our electric revenues.

The following map shows APS’ 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 power purchase agreements. Resource planning is an important function necessary to meet Arizona’s future energy needs. APS’ sources of energy by fuel type during 2009 were: coal — 36.3%; nuclear — 25.9%; purchased power — 20.6%; and gas, oil and other — 17.2%.

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 785 MW. The Four Corners plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. See “Plant and Transmission Line Leases and Easements on Indian Lands” in Item 2 for additional information. 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.

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. See “Plant and Transmission Line Leases and Easements on Indian Lands” in Item 2 for additional information.

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 — Capital Expenditures” in Item 7 for environmental and climate change developments impacting these coal facilities. See Note 11 for information regarding APS’ 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 sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. APS accounts for these leases as operating leases. The leases, which have terms of 29.5 years, 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 lessors 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 Notes 9 and 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 at full power. 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 a final decision in the fall of 2011. APS is making preparations to secure resources necessary to operate the plant for the period of extended operation.

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. New contracts are currently being negotiated that would meet the plant’s conversion services needs through 2011, taking into account available inventory. The participants have also contracted for all of Palo Verde’s enrichment services through 2013 and all of Palo Verde’s fuel assembly fabrication services until at least 2015.

Spent Nuclear Fuel and Waste Disposal — 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, through 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. If uncertainties regarding the United States government’s obligation to accept and store used 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. See “Palo Verde Nuclear Generating Station” in Note 11 for a discussion of spent nuclear fuel and waste disposal.

NRC Inspection —On February 22, 2007, the NRC issued a “white” finding (low to moderate safety significance) due to electrical output issues with the Unit 3 emergency diesel generator that occurred in 2006. Under the NRC’s Action Matrix, this finding, coupled with a previous NRC “yellow” finding relating to a 2004 matter involving Palo Verde’s safety injection systems, resulted in Palo Verde Unit 3 being placed in the “multiple/repetitive degraded cornerstone” column of the NRC’s Action Matrix (“Column 4”), subjecting it to an enhanced NRC inspection regime. Although only Palo Verde Unit 3 was in NRC’s Column 4, in order to adequately assess the need for improvements, APS’ management conducted site-wide assessments of equipment and operations.

On March 24, 2009, the NRC informed APS that it was removing Palo Verde Unit 3 from Column 4, removing Units 1 and 2 from the “one degraded cornerstone” column (“Column 3”) of the NRC’s Action Matrix, and returning all three units of the plant to “Column 1” routine inspection and oversight by the NRC. This notification followed the NRC’s completion of its inspections of the corrective actions taken by Palo Verde to address the performance deficiencies that caused the NRC to place Unit 3 into Column 4 and Units 1 and 2 into Column 3.

Nuclear Decommissioning Costs — APS currently relies on an external sinking fund mechanism to meet the NRC financial assurance requirements for 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’ ACC jurisdictional rates. Decommissioning costs are recoverable through a non-bypassable system benefits charge, which allows APS to maintain its external sinking fund mechanism. See Note 12 for additional information about APS’ 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 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’ hedging program. APS has long-term gas transportation agreements with three different companies, which provide APS with fuel delivery through 2024. Fuel oil is acquired under short-term purchases delivered primarily to West Phoenix, where it is distributed to APS’ other oil power plants by truck.

Solar Facilities

APS owns and operates more than thirty on-grid and off-grid small solar systems around the state. Together they have the capacity to produce about 6 MW of renewable energy. This fleet of solar systems is anchored by a 3 MW facility located at the Prescott Airport and a 1 MW facility located at APS’ Saguaro power plant.

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’ 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 to planned additions of renewable resources and energy efficiency initiatives.

Purchased Power Capacity — APS’ 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.

CONVENTIONAL AGREEMENTS:

Type		Dates Available		Capacity (MW)
Purchase Agreement (a)		Year-round through December 2014		Up to 90
Purchase Agreement (b)		Year-round through June 15, 2010		238
Exchange Agreement (c)		May 15 to September 15 annually through 2020		480
Tolling Agreement		June 2007 through May 2017		500
Tolling Agreement		June 2010 through October 2019		560
Day-Ahead Call Option Agreement		June 2007 through September 2015 (summer seasons)		500
Day-Ahead Call Option Agreement		June 2007 through summer 2016		150
Demand Response Agreement (d)		2010 through 2024 (summer seasons)		100

RENEWABLE AGREEMENTS:

Type and Name		Location		Contract End Date		Capacity (MW)
Operating Facilities:
Wind
Aragonne Mesa		Santa Rosa, NM		2026		90
High Lonesome		Mountainair, NM		2039		100
Geothermal
Salton Sea		Imperial County, CA		2029		10
Biomass
White Mountain Power		Snowflake, AZ		2023		10
Biogas
Glendale Landfill		Glendale, AZ		2030		3
Signed Agreements for Other Facilities:
Solar
Solana (a)		Gila Bend, AZ		2043		250
Solar 1 (b)		Ajo, AZ		2036		5
Solar 2 (b)		Buckeye, AZ		2035		6
Solar 3 (b)		Prescott, AZ		2041		10

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’ 2009 peak one-hour demand on its electric system was recorded on July 27, 2009 at 7,218 MW, compared to the 2008 peak of 7,026 MW recorded on August 1, 2008. APS’ operable generating capacity, together with firm purchases totaling 2,657 MW, including short-term seasonal purchases and unit contingent purchases, resulted in an actual reserve margin, at the time of the 2009 peak demand, of 15.6%. 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 and technical problems.

Future Resources and Resource Plan

On January 29, 2009, APS submitted a Resource Plan Report to the ACC proposing a diverse portfolio of generation resources to address the projected 60% increase in customer peak demand by 2025, which equates to approximately 6,500 MW of new capacity resources and accounts for both new resources needed to meet growing customer loads as well as resources that will be needed to replace expiring long-term purchases.

On December 15, 2009, the ACC approved a modified resource planning rule that requires APS to 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. APS believes the modified rule will likely become effective by mid-2010, requiring APS to file a revised resource plan by the Fall of 2010, which will supercede the January 2009 filing. The modified rule also requires the ACC to issue an order with its acknowledgment of APS’ resource plan within approximately nine months following its submittal.

Renewable Energy Standard

In connection with its ongoing resource planning efforts, APS continues to focus on increasing the percentage of its energy that is produced by renewable resources. In 2006, the ACC adopted the Arizona Renewable Energy Standard and Tariff (the “Renewable Energy Standard” or “RES”). Under the Renewable Energy Standard, 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 2.5% of retail electric sales in 2010 and increases annually until it reaches 15% in 2025. In APS’ recent retail rate case settlement agreement, APS committed to, among other things, an interim renewable energy target of 10% by year-end 2015, which is double the existing RES target of 5% for that year. (See Note 3.) A component of the original 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 original RES, an increasing percentage of that requirement must be supplied from distributed energy resources. This distributed energy requirement is 20% of the overall RES requirement of 2.5% in 2010 and increases to 30% of the applicable RES requirement in 2012 and subsequent years. The following table summarizes these requirement standards and their timing:

		2010				2015				2020				2025
RES as a % of retail electric sales			2.5	%			5.0	%			10.0	%			15.0	%
Percent of RES to be supplied from distributed energy resources			20.0	%			30.0	%			30.0	%			30.0	%
APS’ RES commitment as a % of retail electric sales per the retail rate case settlement agreement							10.0	%

APS has a diverse portfolio of renewable resources including wind, geothermal, solar and biomass, which currently collectively generates over 210 MW of renewable energy for its customers via owned or contracted renewable generation facilities and an additional installed capacity of 21 MW equivalent of customer-sited distribution energy systems in operation. These current renewable generation projects are either APS-owned solar facilities, as described under “Generation Facilities — Solar Facilities” above, are acquired through long-term purchased power agreements, as described under “Purchased Power Contracts” above, or are partially funded by renewable incentives we offer to our customers. APS continues to actively consider opportunities to enhance its renewable energy portfolio, both to ensure its compliance with the Renewable Energy Standard and to meet the needs of its customer base.

Demand Side Management and Energy Efficiency

Arizona regulators are placing an increased focus on energy efficiency and 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% annual energy savings by 2020. An ambitious standard, such as that proposed, will likely increase participation by APS customers in these conservation and energy efficiency programs, which in turn will likely impact Arizona’s future energy resource needs. Energy Efficiency Rules are expected to be formally adopted in 2010. (See Note 3 for demand side management and energy efficiency obligations resulting from APS’ recent retail rate case settlement.)

Economic Stimulus Projects

Through the American Recovery and Reinvestment Act of 2009 (“ARRA”), the Federal government is making a number of programs available for utilities to develop renewable resources, improve reliability and create jobs from the availability of 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 $70.5 million, which will be located at our Cholla power plant. It also announced a commitment to fund, subject to final negotiations, a $3.3 million high penetration photovoltaic generation study related to a proposed APS community power project in Flagstaff, Arizona. These funding amounts are contingent upon meeting certain project milestones, including DOE-established budget parameters, over the next four years.

APS has also been selected by the State of Arizona’s Department of Commerce as a sub-recipient under the State’s ARRA award for the implementation of various distributed energy and energy efficiency programs in Arizona. The State is in final negotiations to provide APS with approximately $3.7 million from the State’s ARRA grant so that APS can implement certain solar water heater, photovoltaic and/or wind energy related community projects.

APS intends to continue to evaluate additional funding opportunities under the ARRA programs that may be of benefit to APS’ business, operations or community activities.

Competitive Environment and Regulatory Oversight

Retail

The ACC regulates APS’ retail electric rates and its issuance of securities. The ACC must also approve any transfer or encumbrance of APS’ 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’ 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’ customers. In 2000, an 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. However, as a result of a new request for authorization to provide competitive retail electric service by Sempra Energy Solutions, LLC, 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 is due to be filed with the ACC on April 1, 2010. At present, only limited electric retail competition exists in Arizona and only with certain entities not regulated by the ACC.

Currently, there are two matters pending with the ACC that involve a business model where customers pay solar vendors for the installation and operation of solar facilities based on the amount of energy produced. The ACC must make a determination whether these entities would be considered “public service corporations” under the Arizona Constitution, causing them to be regulated by the ACC. Use of such products by customers within our territory would result in some level of competition; however, at this time we do not feel this would materially impact our financial results. APS cannot predict when, and the extent to which, additional electric service providers will enter or re-enter APS’ service territory.

Wholesale

The FERC regulates rates for wholesale power sales and transmission services. (See Note 3 for information regarding APS’ transmission rates.) During 2009, approximately 4.8% of APS’ electric operating revenues resulted from such sales and services. APS’ wholesale activity primarily consists of managing fuel and purchased power risks in connection with the costs of serving retail customer energy requirements. APS also sells, in the wholesale market, its generation output that is not needed for APS’ 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 and Regulatory Initiatives. In the past several years, the United States Congress has considered bills that would regulate domestic greenhouse gas emissions. On June 26, 2009, the House of Representatives approved the American Clean Energy and Security Act of 2009, H.R. 2454. In addition to establishing clean energy programs, H.R. 2454 would establish a greenhouse gas emission cap-and-trade system starting in 2012 applicable to about 85% of all emission sources in the nation. A similar bill (Kerry-Boxer Bill, S. 1733) is pending before the Senate. Both of these bills would allocate a certain number of allowances to local distribution companies (such as APS) through 2030.

To the extent APS’ emissions exceed the allowances allocated to it under these proposed bills, APS would have an “allowance gap.” APS would have to purchase enough allowances from the market to fill these gaps. The table below illustrates the estimated cost impacts to APS in 2012 to acquire allowances to fill its allowance gap, and the associated retail rate impacts to customers under H.R. 2454 and S. 1733. For purposes of this illustration, the table provides three assumed allowance prices of $20, $50 and $75 per metric ton.

				H.R. 2454								S. 1733
Allowance Cost				Annual Cost								Annual Cost
($ per metric ton)				($ in millions)				Rate Impact				($ in millions)				Rate Impact
$	20			$	68				2%			$	101				3%
$	50			$	170				5%			$	252				8%
$	75			$	255				8%			$	379				12%

The actual economic and operational impact of this or any similar legislation on the Company 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 the 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.

The EPA recently 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. The recent endangerment finding could result in the EPA issuing new regulatory requirements under the Clean Air Act for new and modified major greenhouse gas emitting sources, including power plants. On September 30, 2009, the EPA announced a proposed rule under the Clean Air Act requiring certain new and modified stationary sources, including power plants, to use the best available control technology to minimize greenhouse gas emissions. Several groups have filed lawsuits challenging the EPA’s endangerment finding. At the present time we cannot predict whether the proposed stationary source rule will be adopted in its current or a revised form, what other rules or regulations may ultimately result from the EPA’s finding, whether the parties challenging the endangerment finding will be successful, and what impact the proposed rule and potential other rules or regulations will have on APS’ operations.

In anticipation of potential future regulation of greenhouse gases under the Clean Air Act as described above, on September 22, 2009, the EPA issued a mandatory greenhouse gas reporting rule. The rule applies to direct greenhouse gas emissions from facilities such as APS’ power plants. We expect that our incremental costs to comply with this rule will be immaterial since APS already routinely reports CO₂ and other greenhouse gas emissions from its plants.

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 and New Mexico is currently considering proposed legislation to address these issues. 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.

If any emission reduction legislation or 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, and implementation of an active technology innovation effort to evaluate potential emerging new technologies. 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.

On May 18, 2009, we submitted a comprehensive Climate Change Management Plan to the ACC to comply with an ACC order that directed APS to undertake a climate management plan, carbon emission reduction study and commitment and action plan with public input and ACC review. The Climate Change Management Plan details scientific, legislative and policy issues, potential physical and financial risks to APS, greenhouse gas emission inventory, APS technology innovation and greenhouse gas reduction efforts, and our companies’ strategic approach to climate change management.

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. APS will not participate in the Climate Registry after 2009 because we will be reporting substantially the same information under the new EPA reporting rule. Pinnacle West has also reported, and will continue to report, greenhouse gas emissions in its annual Corporate Responsibility Report, which is available on our website (www.pinnaclewest.com). In addition to emissions data, the report provides information related to the Company, its approach to sustainability and its workplace and environmental performance, as well as a copy of our Climate Change Management Plan discussed above. 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 court in November 2009. We believe the action is without merit and intend to continue to defend against the claims.

Similar nuisance lawsuits are currently pending in the 2nd and 5th Circuits. In the fall of 2009, the U.S. Courts of Appeals for each of these Circuits reversed lower court decisions and ruled that the plaintiffs in both cases could bring common law nuisance lawsuits against coal-burning utilities allegedly contributing to global warming. 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. We are not a party to either of these two lawsuits, but will monitor 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.

ADEQ is currently undertaking a rulemaking process to address the Clean Air Visibility Rule requirements. ADEQ’s rules were due to EPA Region 9 in December 2007, but are expected to be submitted in 2010. As part of the rulemaking process, ADEQ required APS to perform a BART analysis for Cholla. APS completed a 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. Once APS receives ADEQ’s 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).

EPA Region 9 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.

The EPA recently issued an Advanced Notice of Proposed Rulemaking (ANPR) seeking public comments on what constitutes BART for each plant. The public comment period expired in October, 2009, but the EPA has extended the comment period until March 20, 2010 for the Navajo and Hopi Tribes. We expect that the EPA will issue proposed and final BART determinations for Four Corners and the Navajo Plant in 2010. The participant owners of Four Corners and the Navajo Plant will have five years after the EPA issues its final determination 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. If the agencies certify impairment, the EPA is required to evaluate and, if necessary, determine BART for Four Corners.

APS’ recommended plan for Four Corners includes the installation of combustion control equipment, with an estimated cost to APS, based on preliminary engineering estimates and APS’ Four Corners ownership interest, of approximately $50 million. If the EPA determines that post-combustion controls are required, APS’ total costs could be up to approximately $422 million for Four Corners. 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’ Navajo ownership interest. If the EPA determines that post-combustion controls are required, APS’ total costs could be up to approximately $93 million for Navajo. 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 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’ 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 proposed consent decree, the EPA has agreed to issue final MACT standards for mercury and other hazardous air pollutants by November 2011. If the consent decree is finalized in its current form, 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. The estimated costs expected to be incurred over the next three years for such equipment 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).

Federal Implementation Plan (“FIP”). In September 1999, the EPA proposed FIPs to set air quality standards at certain power plants, including Four Corners and the Navajo Plant, which it later revised in 2006. The FIP for Four Corners was finalized in 2009, and we do not believe compliance with its required limits will have a material adverse impact on our financial position, results of operations or cash flows. The proposed FIP for the Navajo Plant is still pending. APS cannot currently predict the effect of this proposed FIP on its financial position, results of operations or cash flows, or whether the proposed FIP will be adopted in its current form.

Coal Combustion Waste. The EPA is expected to issue proposed regulations governing the handling and disposal of coal combustion byproducts (“CCBs”), such as fly ash and bottom ash. APS currently disposes of CCBs 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 is evaluating options that include regulation of CCBs under non-hazardous waste standards, hazardous waste standards, or a combination of both, and a potential phase out of the disposal of CCBs through the use of ash ponds. A proposed rule is expected during the first quarter of 2010. We do not know when the EPA will issue a final rule, including required compliance dates. While APS continues to advocate for the regulation of CCBs as non-hazardous waste, we cannot currently predict the outcome of the EPA’s actions and whether such actions will have a material adverse impact on our financial position, results of operations or cash flows.

Section 114 Request. 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 (“NSR”). 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 has responded to the EPA’s request and is currently unable to predict the timing or content of EPA’s response, if any, or any resulting actions.

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 $1.2 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’ 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 Planning — Generation — 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 Tribal 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’ generating plants. At the present time, APS has adequate water to meet its needs. However, conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions.

Both groundwater and surface water in areas important to APS’ 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.

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’ 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’ other power plants are also located within the geographic area subject to the summons. APS’ 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’ water rights claims has been set in this matter.

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’ groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and, therefore, is potentially at issue in the case. APS’ 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’ 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.

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.

BUSINESS OF OTHER SUBSIDIARIES

SunCor

SunCor has been a developer of residential, commercial and industrial real estate projects in Arizona, Idaho, New Mexico and Utah. Due to the continuing distressed conditions in the real estate markets, in 2009 SunCor undertook a program to dispose of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to eliminate its outstanding debt.

At December 31, 2009, SunCor had total assets of about $166 million. At December 31, 2008, SunCor had total assets of about $547 million. The reduction in SunCor’s assets is primarily due to 2009 real estate impairment charges of $266 million and 2009 asset sales. SunCor’s remaining assets consist primarily of land with improvements, commercial buildings, golf courses and other real estate investments. SunCor’s remaining projects include master-planned communities and commercial and residential projects. Four of the master-planned communities and the commercial and residential projects are in Arizona. Other master-planned communities are located in Idaho, New Mexico and Utah.

SunCor’s operating revenues were approximately $103 million in 2009, $75 million in 2008, and $190 million in 2007. SunCor’s net loss attributable to common shareholders was approximately $279 million in 2009, which includes $266 million (pre-tax) in real estate impairment charges. In 2009, income tax benefits related to SunCor operations were recorded by Pinnacle West in accordance with an intercompany tax sharing agreement. SunCor’s net loss attributable to common shareholders in 2008 was $26 million, which included a $53 million (pre-tax) real estate impairment charge. SunCor’s net income was approximately $24 million in 2007. Certain components of SunCor’s real estate sales activities, which are included in the real estate segment, are required to be reported as discontinued operations on Pinnacle West’s Consolidated Statements of Income. (See Notes 22 and 23.)

See “Liquidity — 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.

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. APSES also owns and operates district cooling systems.

APSES had a net loss of $2 million in 2009, a net loss of $1 million in 2008 and a net loss of $4 million in 2007. At December 31, 2009, APSES had total assets of $74 million.

El Dorado

El Dorado owns minority interests in several energy-related investments and Arizona community-based ventures. El Dorado’s short-term goal is to prudently realize the value of its existing investments. On a long-term basis, Pinnacle West may use El Dorado, when appropriate, for investments that are strategic to the business of generating, distributing and marketing electricity.

El Dorado had a net loss of $7 million in 2009, a net loss of $10 million in 2008 and a net loss of $6 million in 2007. Income taxes related to El Dorado are recorded by Pinnacle West. At December 31, 2009, El Dorado had total assets of $19 million.

OTHER INFORMATION

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

								Approximate
								Number of
		Principal Executive Office		Year of				Employees at
		Address		Incorporation				December 31, 2009
Pinnacle West		400 North Fifth Street			1985				7,200	(a)
		Phoenix, AZ 85004
APS		400 North Fifth Street			1920				6,800	(b)
		P.O. Box 53999 Phoenix, AZ 85072-3999
SunCor		80 East Rio Salado Parkway			1965				260
		Suite 410 Tempe, AZ 85281
APSES		60 E. Rio Salado Parkway			1998				70
		Suite 1001 Tempe, AZ 85281
El Dorado		400 North Fifth Street			1983				—
		Phoenix, AZ 85004

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 and other corporate governance information is also available on the Pinnacle West website. Pinnacle West will post any amendments to the Code of Ethics 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 connection with 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’ 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’ retail electric rates and the FERC regulates rates for wholesale power sales and transmission services. While approved electric rates are intended to permit APS to recover its costs of service and earn a reasonable rate of return, 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. In connection with its recent rate case settlement agreement, APS agreed not to request its next general retail rate increase to be effective prior to July 1, 2012. The ACC must also approve APS’ 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’ 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’ business, including the FERC, the NRC, the EPA and state and local governmental agencies. These agencies regulate many aspects of APS’ 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. APS underwent its first mandatory regularly-scheduled triennial audit for compliance with these standards in early 2010 and expects to receive its results by mid-2010. 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’ 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’ 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. APS was subject to this heightened scrutiny until March 2009, when it exited the NRC’s enhanced inspection regime. 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’ 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’ 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 final rulemaking from the EPA that could impose new requirements on Four Corners and the Navajo Plant. APS is also awaiting 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. Recently Congress directed the EPA to propose new federal regulations governing the disposal of CCBs, which are generated as a result of burning coal and consist of, among other things, fly ash and bottom ash. APS currently disposes of CCBs 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 CCBs as a hazardous solid waste or phases out APS’ ability to dispose of CCBs through the use of ash ponds, APS could incur significant costs for CCB 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 NSR 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 NSR. APS received and responded to a request from the EPA regarding projects and operations of Four Corners. If the EPA seeks to impose NSR requirements at Four Corners or any other APS plant, either through a lawsuit or a Notice of Violation, 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. 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 be sure 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’ customers, could have a material adverse effect on its financial condition, results of operations or cash flows.

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

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

Physical and Operational Risks. Projections for the Southwest United States from climate change models include an increase in the number of extreme hot days in the summer, less precipitation in the form of snow and the earlier runoff of snowmelt, increased wildfire potential, and the potential for water shortages. 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 at this time 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 risk factors that APS considers in the normal course of business in the engineering and construction of its electric system. Large increases in ambient temperature due to climate change could require evaluation of certain materials used within its system and represents a greater challenge.

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. The House of Representatives approved a bill that would establish a greenhouse gas emission cap-and-trade system, and the Senate is currently considering proposed legislation. There is growing consensus that some form of regulation or legislation is likely to occur in the near 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 generation facility CO₂ and other greenhouse gas emissions could result in the creation of substantial additional capital expenditures and operating costs in the form of taxes, emissions allowances or required equipment upgrades and could have a material adverse impact on all fossil fuel fired generation facilities (particularly coal-fired facilities, which constitute approximately 28% of APS’ generation capacity). A cap-and-trade program may also result in counterparty credit risk and financial liquidity risk since collateral is typically exchanged between counterparties as a means of mitigating risk in the event of a counterparty default.

At the state level, the California legislature enacted legislation to address greenhouse gas emissions. This legislation and other state-specific initiatives may affect APS’ 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 recently 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. The recent endangerment finding could result in the EPA issuing new regulatory requirements under the Clean Air Act, beyond those related to motor vehicle emissions, which could impact APS’ power plants and result in substantial additional costs. 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.

If APS cannot meet or maintain the level of renewable energy required under Arizona’s increasing Renewable Energy Standards or the higher commitment levels established in the settlement agreement, APS may be subject to penalties or fines for non-compliance.

The Renewable Energy Standard and Tariff (“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 2.5% of total retail sales by 2010. This amount increases annually to 15% by 2025. In its recent retail rate case settlement agreement, APS agreed to exceed these standards and committed to an interim renewable energy target of 10% 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 20% of the overall RES requirement of 2.5% in 2010 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 resource plans, it may be subject to penalties imposed by the ACC, including APS’ 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’ 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’ service area in 1999 and 2000, there are currently no active retail competitors offering unbundled energy or other utility services to APS’ customers. As a result, APS cannot predict if, when, and the extent to which, additional competitors may re-enter APS’ service territory.

Currently, there are two matters pending with the ACC that involve a business model where customers pay solar vendors for the installation and operation of solar facilities based on the amount of energy produced. The ACC must make a determination whether these entities would be considered “public service corporations” under the Arizona Constitution, causing them to be regulated by the ACC. Use of such products by customers within APS’ territory would result in some level of competition.

As a result of changes in federal law and regulatory policy, competition in the wholesale electricity market has greatly increased due to a greater participation by traditional electricity suppliers, non-utility generators, independent power producers, and wholesale power marketers and brokers. This increased competition could affect APS’ load forecasts, plans for power supply and wholesale energy sales and related revenues. As a result of the changing regulatory environment and the relatively low barriers to entry, we expect wholesale competition to increase, which could adversely affect our business.

OPERATIONAL RISKS

APS’ 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’ 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’ results of operations and harm its financial condition.

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’ communities and electric transmission lines. Any damage caused as a result of forest fires could negatively impact APS’ results of operations.

Effects of Energy Conservation Measures and Distributed Energy. The ACC has initiated a rulemaking regarding energy efficiency, which includes a proposed 22% annual energy savings requirement by 2020. If adopted, this will likely increase participation by APS customers in energy efficiency and conservation programs and demand-side management efforts, which in turn would impact the demand for electricity. The proposed 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. The retail rate case settlement agreement establishes energy efficiency goals for APS that begin in 2010, subjecting APS to energy efficiency requirements in advance of the proposed rules described above.

APS must also meet certain distributed energy requirements. A portion of APS’ 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 20% of the overall RES requirement of 2.5% in 2010 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 regulatory mechanisms, could have a material adverse impact on APS’ financial condition, results of operations or 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’ 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’ business. If APS’ 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’ business and results of operations.

Assured supplies of water are important for APS’ 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’ generating plants have been 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’ 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 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 easements or other rights-of-way that are effective for specified periods. APS is currently unable to predict the outcome of discussions with the appropriate Indian tribes with respect to future renewal of these 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 owners, 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 $103 million (but not more than $15 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 or impossible 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’ 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.

Congress is considering legislation to impose restrictions on the use of over-the-counter derivatives, including energy derivatives, which could subject APS to governmental regulation relating to these hedging transactions. If such legislation becomes law, APS could potentially face higher costs to hedge its risks, fewer potential counterparties still active in the newly-regulated marketplace and increased liquidity requirements.

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 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 may adversely affect APS’ business.

Research and development activities are ongoing to improve alternative technologies to produce power, including fuel cells, micro turbines, clean coal and coal gasification, photovoltaic (solar) cells 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’ generating facilities less competitive. In addition, advances in technology could reduce the demand for power supply, which could adversely affect APS’ business.

APS is pursuing and implementing advanced technologies, including smart grid transmission and distribution systems and advanced meters for use in 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’ existing technologies and equipment. Uncertainties and unknowns related to these and other advancements in technology and equipment could adversely affect APS’ business if national standards develop that do not embrace the current technologies or if the technologies and equipment fail to perform as expected.

FINANCIAL RISKS

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

We rely on access to short-term money markets, longer-term capital markets and the bank markets as a significant source of liquidity and for capital requirements not satisfied by the cash flow from our operations. We believe that we will maintain sufficient access to these financial markets. However, certain market disruptions may increase our cost of borrowing or adversely affect our ability to access one or more financial markets. Such disruptions could include:

•

continuation of the current economic downturn;

•

terrorist attacks or threatened attacks on our facilities or those of unrelated energy companies;

•

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

•

the overall health of the utility industry.

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

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:

•

increasing the cost of future debt financing;

•

reducing our credit ratings;

•

increasing our vulnerability to adverse economic and industry conditions; and

•

requiring us to dedicate a substantial 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 “Pinnacle West Consolidated — 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’ 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 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 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 International Financial Reporting Standards (“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 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. 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 our subsidiaries.

We conduct our operations primarily through subsidiaries. Substantially all of our consolidated assets are held by such subsidiaries. Accordingly, our cash flow is dependent upon the earnings and cash flows of these subsidiaries and their distributions to us. The subsidiaries are separate and distinct legal entities and have no obligation to make distributions to us.

The debt agreements of some of our subsidiaries may restrict their ability to pay dividends, make distributions or otherwise transfer funds to us. 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 common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt.

Our ability to meet our debt service obligations could be adversely affected because our debt securities are structurally subordinated to the debt securities and other obligations of our subsidiaries.

Because we are 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. None of the indentures under which we or our subsidiaries may issue debt securities limits our ability or the ability of our subsidiaries to incur additional debt in the future. 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:

•

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

•

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

•

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

•

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

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

At December 31, 2009, SunCor had borrowings of approximately $57 million under its principal loan facility (the "Secured Revolver"). The Secured Revolver matured on January 30, 2010 and SunCor and the agent bank for the Secured Revolver are discussing an extension of the maturity date to allow time for SunCor to continue discussions concerning the potential sale of additional properties. In addition to the Secured Revolver, at December 31, 2009, SunCor had approximately $43 million of outstanding debt under other credit facilities ($9 million of which has matured since December 31, 2009 and remains outstanding).

If SunCor is unable to obtain an extension or renewal of the Secured Revolver or its other matured debt, or if it is unable to comply with the mandatory repayment and other provisions of any new or modified credit agreements, SunCor could be required to immediately repay its outstanding indebtedness under all of its credit facilities as a result of cross-default provisions. Such an immediate repayment obligation would have a material adverse impact on SunCor's business and financial position and impair its ongoing viability.

SunCor intends to apply the proceeds of its planned asset sales to the repayment of its outstanding debt. If it is unable to locate suitable buyers and close certain asset sales or obtain sufficient proceeds from these sales to maintain or pay off its existing debt, it may be unable to satisfy obligations under its credit facilities, resulting in the immediate repayment obligations described above.

SunCor cannot predict the outcome of negotiations with its lenders or its ability to sell assets for sufficient proceeds to repay its outstanding debt. SunCor's ability to generate sufficient cash from operations while it pursues lender negotiations and further asset sales is uncertain.

The Company has not guaranteed any SunCor indebtedness. As a result, we do not believe that SunCor's inability to meet its financial covenants under the Secured Revolver or its other outstanding credit facilities would have a material adverse impact on Pinnacle West's cash flows or liquidity. Any resulting SunCor losses would be reflected in Pinnacle West's consolidated financial statements. If SunCor were required to seek protection under federal bankruptcy laws, Pinnacle West could be exposed to the uncertainties and complexities inherent for parent companies in such proceedings.

During 2008 and 2009 the real estate market weakened significantly resulting in lower land and home sales and depressed real estate prices. As a result, in 2008 and 2009 SunCor recognized certain impairment charges. SunCor may be required to record additional impairments.

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 2009 fiscal year and that remain unresolved.

ITEM 2. PROPERTIES

Generation Facilities

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

Principal

Primary

Owned

No. of

%

Fuels

Dispatch

Capacity

Name

Units

Owned (a)

Used

Type

(MW)

Nuclear:

Palo Verde (b)

3

29.1

%

Uranium

Base Load

1,146

Total Nuclear

1,146

Steam:

Four Corners 1, 2, 3

3

Coal

Base Load

560

Four Corners 4, 5 (c)

2

15

%

Coal

Base Load

225

Cholla

3

Coal

Base Load

647

Navajo (d)

3

14

%

Coal

Base Load

315

Ocotillo

2

Gas

Peaking

220

Saguaro

2

Gas/Oil

Peaking

210

Total Steam

2,177

Combined Cycle:

Redhawk

2

Gas

Load Following

984

West Phoenix

5

Gas

Load Following

887

Total Combined Cycle

1,871

Combustion Turbine:

Ocotillo

2

Gas

Peaking

110

Saguaro 1, 2

2

Gas/Oil

Peaking

110

Saguaro 3

1

Gas

Peaking

79

Douglas

1

Oil

Peaking

16

Sundance

10

Gas

Peaking

420

West Phoenix

2

Gas

Peaking

110

Yucca 1, 2, 3

3

Gas/Oil

Peaking

93

Yucca 4

1

Oil

Peaking

54

Yucca 5, 6

2

Gas

Peaking

96

Total Combustion Turbine

1,088

Solar:

Multiple state-wide solar facilities

Solar

Peaking

6

Total Solar

6

Total Capacity

6,288

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’ generating facilities.

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

Transmission and Distribution Facilities

Current Facilities. APS’ transmission facilities consist of approximately 5,946 pole miles of overhead lines and approximately 49 miles of underground lines, 5,723 miles of which are located in Arizona. APS’ distribution facilities consist of approximately 11,362 miles of overhead lines and approximately 17,308 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’ jointly-owned interests in those transmission facilities recorded on the Consolidated Balance Sheets at December 31, 2009:

		Percent Owned
		(Weighted Average)
North Valley System			65.9	%
Palo Verde — Estrella 500KV System			55.5	%
Round Valley System			50.0	%
ANPP 500KV System			35.8	%
Navajo Southern System			31.4	%
Four Corners Switchyards			27.5	%
Palo Verde — Yuma 500KV System			23.9	%
Phoenix — Mead System			17.1	%

Expansion. Each year APS prepares and files with the ACC a ten-year transmission plan. In APS’ 2010 plan, APS projects it will invest approximately $520 million in new transmission over the next ten years, which includes 270 miles of new lines. This investment will increase the import capability into metropolitan Phoenix by approximately 26% and will increase the import capability into the Yuma area by approximately 38%. One significant project presently under construction is the Morgan - Pinnacle Peak project, which consists of 26 miles of 500kV and 230kV lines. APS completed two major substation projects in 2009. The Dugas substation (500/69kV) will provide system voltage support and capacity for the Verde Valley area and the Sugarloaf substation (500/69kV) will provide system voltage support and capacity for the Show Low and Snowflake areas, and will also support renewable energy development in that area.

APS continues to work with regulators to identify transmission projects necessary to support renewable energy facilities. Two such projects, which are included in APS’ 2010 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. 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 initiated discussions with the Navajo Nation regarding them. We are currently unable to predict the outcome of this matter.

Real Estate Segment Properties

See “Business of Other Subsidiaries — SunCor ” in Item 1 for information regarding SunCor’s remaining properties. Substantially all of SunCor’s debt is collateralized by interests in its real property.

ITEM 3. LEGAL PROCEEDINGS

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

See Note 3 for the resolution of APS’ general retail rate case and other matters before the ACC.

See Note 11 with regard to a lawsuit brought by APS on behalf of itself and the other Palo Verde owners against the DOE, for information relating to the FERC proceedings on California and Pacific Northwest energy market issues and for information regarding the bankruptcy proceeding involving the landlord for our corporate headquarters building.

ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS

Not applicable.

EXECUTIVE OFFICERS OF PINNACLE WEST

Pinnacle West’s executive officers are elected no less often than annually and may be removed by the Board of Directors at any time. The executive officers, their ages at February 19, 2010, current positions and principal occupations for the past five years are as follows:

Name		Age		Position		Period
Donald E. Brandt		55		Chairman of the Board and Chief Executive Officer of Pinnacle West; Chairman of the Board of APS		2009-Present
				Chief Executive Officer of APS		2008-Present
				President and Chief Operating Officer of Pinnacle West		2008-2009
				President of APS		2006-2009
				Executive Vice President of Pinnacle West; Chief Financial Officer of APS		2003-2008
				Chief Financial Officer of Pinnacle West		2002-2008
				Executive Vice President of APS		2003-2006
Donald G. Robinson		56		President and Chief Operating Officer of APS		2009-Present
				Senior Vice President, Planning and Administration of APS		2007-2009
				Vice President, Planning of APS		2003-2007
James R. Hatfield		52		Treasurer of Pinnacle West and APS		2009-Present
				Senior Vice President and Chief Financial Officer of Pinnacle West and APS		2008-Present
				Senior Vice President and Chief Financial Officer of OGE Energy Corp.		1999-2008
Denise R. Danner		54		Vice President, Controller and Chief Accounting Officer of Pinnacle West; Chief Accounting Officer of APS		2010-Present
				Vice President and Controller of APS		2009-Present
				Senior Vice President, Controller and Chief Accounting Officer of Allied Waste Industries, Inc.		2007-2008
				Vice President, Controller and Chief Accounting Officer of Phelps Dodge Corporation		2004-2007
Randall K. Edington		56		Executive Vice President and Chief Nuclear Officer of APS		2007-Present
				Senior Vice President and Chief Nuclear Officer of APS		2007
				Site Vice President and Chief Nuclear Officer of Cooper Generating Station with Entergy Corporation		2003-2007

Name		Age		Position		Period
David P. Falck		56		Executive Vice President, General Counsel and Secretary of Pinnacle West and APS		2009-Present
				Senior Vice President — Law of Public Service Enterprise Group Inc.		2007-2009
				Partner — Pillsbury Winthrop Shaw Pittman LLP		1987-2007
Mark A. Schiavoni		54		Senior Vice President, Fossil Operations of APS		2009-Present
				Senior Vice President of Exelon Generation and President of Exelon Power		2004-2009
Lori S. Sundberg		46		Vice President, Human Resources of APS		2007-Present
				Vice President, Employee Relations, Safety, Compliance & Embrace of American Express Company		2007
				Vice President, HR Relationship Leader, Global Corporate Travel Division of American Express Company		2003-2007
Steven M. Wheeler		61		Executive Vice President, Customer Service and Regulation of APS		2003-Present

PART II

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

Pinnacle West’s common stock is publicly held and is traded on the New York Stock Exchange. At the close of business on February 15, 2010, Pinnacle West’s common stock was held of record by approximately 28,216 shareholders.

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

														Dividends
2009		High				Low				Close				Per Share
1st Quarter		$	35.13			$	22.32			$	26.56			$	0.525
2nd Quarter			30.30				25.28				30.15				0.525
3rd Quarter			33.71				28.87				32.82				0.525
4th Quarter			37.96				31.08				36.58				0.525

														Dividends
2008		High				Low				Close				Per Share
1st Quarter		$	42.92			$	34.08			$	35.08			$	0.525
2nd Quarter			37.39				30.26				30.77				0.525
3rd Quarter			37.88				30.34				34.41				0.525
4th Quarter			35.83				26.27				32.13				0.525

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

The chart below sets forth the dividends paid on APS’ common stock for each of the four quarters for 2009 and 2008.

Common Stock Dividends
(Dollars in Thousands)

Quarter		2009		2008
1st Quarter		$42,500		$42,500
2nd Quarter		42,500		42,500
3rd Quarter		42,500		42,500
4th Quarter		42,500		42,500

The sole holder of APS’ common stock, Pinnacle West, is entitled to dividends when and as declared out of legally available funds. As of December 31, 2009, APS did not have any outstanding preferred stock.

Issuer Purchases of Equity Securities

The following table contains information about our purchases of our common stock during the fourth quarter of 2009.

		Total								Total Number of
		Number of								Shares Purchased				Maximum Number of
		Shares				Average				as Part of Publicly				Shares that May Yet Be
		Purchased				Price Paid				Announced Plans				Purchased Under the
Period		(1)				per Share				or Programs				Plans or Programs
October 1 - October 31, 2009			—				—				—				—
November 1 - November 30, 2009			35			$	33.46				—				—
December 1 - December 31, 2009			—				—				—				—
Total			35			$	33.46				—				—

ITEM 6. SELECTED FINANCIAL DATA
PINNACLE WEST CAPITAL CORPORATION — CONSOLIDATED

		2009				2008				2007				2006				2005
		(dollars in thousands, except per share amounts)
OPERATING RESULTS
Operating revenues:
Regulated electricity segment		$	3,149,187			$	3,127,383			$	2,918,163			$	2,635,036			$	2,237,145
Real estate segment			103,152				74,549				189,726				306,938				280,204
Marketing and trading			—				66,897				138,247				136,748				179,895
Other revenues			44,762				41,729				48,018				36,172				61,221
Total operating revenues		$	3,297,101			$	3,310,558			$	3,294,154			$	3,114,894			$	2,758,465
Income from continuing operations (a)		$	67,231			$	231,304			$	300,436			$	308,972			$	223,933
Discontinued operations — net of income taxes (b)			(13,676	)			10,821				6,707				18,283				(47,666	)
Net Income			53,555				242,125				307,143				327,255				176,267
Less: Net loss attributable to noncontrolling interests			(14,775	)			—				—				—				—
Net income attributable to common shareholders		$	68,330			$	242,125			$	307,143			$	327,255			$	176,267
COMMON STOCK DATA
Book value per share — year-end		$	32.69			$	34.16			$	35.15			$	34.48			$	34.58
Earnings per weighted-average common share outstanding:
Continuing operations attributable to common shareholders — basic		$	0.81			$	2.30			$	3.00			$	3.11			$	2.32
Net income attributable to common shareholders — basic		$	0.68			$	2.40			$	3.06			$	3.29			$	1.83
Continuing operations attributable to common shareholders — diluted		$	0.81			$	2.29			$	2.98			$	3.09			$	2.32
Net income attributable to common shareholders — diluted		$	0.67			$	2.40			$	3.05			$	3.27			$	1.82
Dividends declared per share		$	2.10			$	2.10			$	2.10			$	2.025			$	1.925
Weighted-average common shares outstanding — basic			101,160,659				100,690,838				100,255,807				99,417,008				96,483,781
Weighted-average common shares outstanding — diluted			101,263,795				100,964,920				100,834,871				100,010,108				96,589,949
BALANCE SHEET DATA
Total assets		$	11,808,155			$	11,620,093			$	11,162,209			$	10,817,900			$	10,588,485
Liabilities and equity:
Current liabilities		$	1,083,160			$	1,505,928			$	1,344,449			$	923,338			$	1,608,863
Long-term debt less current maturities			3,370,524				3,031,603				3,127,125				3,232,633				2,608,455
Deferred credits and other			4,008,791				3,589,194				3,159,024				3,215,813				2,946,203
Total liabilities			8,462,475				8,126,725				7,630,598				7,371,784				7,163,521
Total equity			3,345,680				3,493,368				3,531,611				3,446,116				3,424,964
Total liabilities and equity		$	11,808,155			$	11,620,093			$	11,162,209			$	10,817,900			$	10,588,485

SELECTED FINANCIAL DATA
ARIZONA PUBLIC SERVICE COMPANY

		2009				2008				2007				2006				2005
		(dollars in thousands)
OPERATING RESULTS
Electric operating revenues		$	3,149,500			$	3,133,496			$	2,936,277			$	2,658,513			$	2,270,793
Fuel and purchased power costs			1,178,620				1,289,883				1,151,392				969,767				688,982
Other operating expenses			1,533,037				1,408,213				1,358,890				1,290,804				1,200,198
Operating income			437,843				435,400				425,995				397,942				381,613
Other income (deductions)			13,893				836				20,870				27,584				(69,171	)
Interest deductions — net of AFUDC			200,511				173,892				162,925				155,796				141,963
Net income		$	251,225			$	262,344			$	283,940			$	269,730			$	170,479
BALANCE SHEET DATA
Total assets		$	11,503,402			$	10,963,577			$	10,321,402			$	9,948,766			$	9,143,643
Liabilities and equity:
Common stock equity		$	3,445,355			$	3,339,150			$	3,351,441			$	3,207,473			$	2,985,225
Long-term debt less current maturities			3,180,406				2,850,242				2,876,881				2,877,502				2,479,703
Total capitalization			6,625,761				6,189,392				6,228,322				6,084,975				5,464,928
Current liabilities			874,842				1,267,768				1,055,706				806,556				1,021,084
Deferred credits and other			4,002,799				3,506,417				3,037,374				3,057,235				2,657,631
Total liabilities and equity		$	11,503,402			$	10,963,577			$	10,321,402			$	9,948,766			$	9,143,643

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

INTRODUCTION

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

OVERVIEW

Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides retail and wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS accounts for substantially all of our revenues and earnings, and is expected to continue to do so.

Areas of Business Focus

Operational Performance and Reliability.

Nuclear. Palo Verde experienced strong performance during 2009, with its three units achieving a combined year-end capacity factor of 89%. With a focus on safely and efficiently generating electricity for the long-term, APS applied for twenty-year renewals of its operating licenses for each of the three Palo Verde units, and is making preparations to secure necessary resources to operate the plant during this extended period of time. Palo Verde’s 2009 accomplishments also included the installation of a new reactor vessel head, upgraded equipment and processes designed to substantially reduce the time required to defuel and refuel the reactor during refueling outages, and the successful implementation of a comprehensive improvement plan, which allowed Palo Verde Unit 3 to exit the NRC’s enhanced inspection regime (“Column 4”) earlier than anticipated, in March of 2009.

Coal and Related Environmental Matters. APS’ coal plants, Four Corners and Cholla, achieved net capacity factors of 88% and 77%, respectively, in 2009. APS is focused on developing legislation and increased regulation concerning greenhouse gas emissions, and the potential impacts on our coal fleet. Recent concern over climate change and other emission-related issues could have a significant impact on our capital expenditures and operating costs in the form of taxes, emissions allowances or required equipment upgrades for these plants. APS is closely monitoring our long range capital management plans, understanding that the resulting legislation and regulation could impact the economic viability of certain plants, as well as the willingness or ability of power plant participants to fund any such equipment upgrades. See “Business of Arizona Public Service Company — Environmental Matters — Climate Change” in Item 1 and climate change-related risks described in Item 1A for additional climate change developments and risks facing APS.

Transmission and Delivery. In the area of transmission and delivery to its customers, APS also ranked favorably during 2009, with top quartile performance for average customer outage time. During 2009, APS undertook several significant transmission projects, including the Morgan to Pinnacle Peak transmission line scheduled for completion at the end of 2010, and the completion of two switchyards, one of which will support capacity for renewable energy projects. APS is working closely with regulators to identify and plan for transmission needs resulting from the current focus on renewable energy. APS is also working to establish and expand smart grid technology throughout its service territory designed to provide a variety of benefits both to APS and its customers. This technology should allow customers to better monitor their energy use and needs, minimize system outage durations and the number of customers that experience outages, and facilitate cost savings to APS through improved reliability and the automation of certain distribution functions, including remote meter reading and remote connects and disconnects.

Renewable Energy. APS is committed to increasing the amount of energy produced by renewable energy resources, which was a significant focus in APS’ recent rate case settlement described below. APS and the other parties to the rate case worked with the ACC Commissioners to address a wide range of customer needs and to secure a clean, sustainable energy future for Arizona. The ACC adopted a renewable energy standard several years ago, recognizing the importance of renewable energy to our state. In the rate case settlement agreement, APS agreed to exceed these standards, committing that 10% of APS’ resources will come from renewable energy by the year 2015. A variety of other provisions in the settlement agreement reinforce APS’ dedication to renewable energy through initiatives to build a photovoltaic solar plant, install solar rooftop panels on schools and seek an Arizona wind generation project.

During 2009, APS filed its annual RES implementation plan that included a request for ACC approval of the “AZ Sun Program.” As proposed in its plan, APS would invest an estimated $500 million to develop at least 100 MW of photovoltaic solar plants. It currently anticipates that this solar capacity would be placed into service in the 2011 to 2014 timeframe. The ultimate timing depends on the outcome of current and future procurement processes. See Note 3 for additional details regarding this program, including the estimated timing of the ACC’s determination on the matter and the related cost recovery. APS also issued two requests for proposal (“RFP”) for renewable resources in early 2010. These RFP’s are part of the process for procuring the additional renewable resources required under the rate case settlement. The first RFP is for utility-scale solar photovoltaic projects between 15 and 50 MW. Assuming ACC approval of the AZ Sun Program as proposed, this RFP will serve as the first procurement step for implementing that program. The second RFP is for wind projects between 15 and 100 MW to be located within Arizona.

Rate Matters. APS needs timely recovery through rates of its capital and operating expenditures to maintain adequate financial health. APS’ retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. At the end of 2009, the ACC approved a settlement agreement entered into by APS and twenty-one of the twenty-three other parties to APS’ general retail rate case, with modifications that did not materially affect the overall economic terms of the agreement. The rate case settlement should strengthen APS’ financial condition by allowing for rate stability and a greater level of cost recovery and return on investment. It also authorizes and requires equity infusions into APS of at least $700 million prior to the end of 2014. The settlement demonstrates cooperation among APS, the ACC staff, the Residential Utility Consumer Office (RUCO) and other intervenors to the rate case, and establishes a future rate case filing plan that allows APS the opportunity to help shape Arizona’s energy future outside of continual rate cases. See Note 3 for a detailed discussion of the settlement agreement terms and information on APS’ FERC rates.

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

Financial Strength and Flexibility. Despite the volatility and disruption of the credit markets, Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities and have been able to access these facilities, ensuring adequate liquidity for each company. In early February 2010, APS entered into a $500 million revolving credit facility, replacing its $377 million revolving credit facility that would have otherwise terminated in December 2010. At that same time, Pinnacle West entered into a $200 million revolving credit facility that replaces its $283 million facility that also would have otherwise terminated in December 2010.

SunCor Real Estate Operations. As a result of the continuing distressed conditions in the real estate markets, during 2009 SunCor undertook a program to dispose of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to eliminate its outstanding debt. This resulted in impairment charges of approximately $266 million, or $161 million after income taxes, for 2009. See “Pinnacle West Consolidated — Liquidity and Capital Resources — Other Subsidiaries — SunCor” below for a discussion of SunCor’s outstanding debt and related matters, Note 23 for a further discussion of impairment charges and the SunCor-related risk factor in Item 1A.

Subsidiaries. Our other first tier subsidiaries, El Dorado and APSES, are not expected to have any material impact on our financial results, or to require any material amounts of capital, over the next three years.

Key Financial Drivers

In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below. We closely monitor these factors to plan for the Company’s current needs, and to adjust our expectations, financial budgets and forecasts appropriately.

Electric Operating Revenues. For the years 2007 through 2009, retail electric revenues comprised approximately 94% of our total electric operating revenues. Our electric operating revenues are affected by customer growth, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms. Off-system sales of excess generation output, purchased power and natural gas are included in regulated electricity segment revenues and related fuel and purchased power because they are credited to APS’ retail customers through the PSA. These revenue transactions are affected by the availability of excess economic generation or other energy resources and wholesale market conditions, including competition, demand and prices.

Customer and Sales Growth. Customer growth in APS’ service territory for the year ended December 31, 2009 was 0.6% compared with the prior year. For the three years 2007 through 2009, APS’ customer growth averaged 1.8% per year. We currently expect customer growth to average about 1% per year for 2010 through 2012 due to economic conditions both nationally and in Arizona. Retail sales in kilowatt-hours, adjusted to exclude the effects of weather variations, for 2009 declined 2.4% compared to the prior year, reflecting the poor economic conditions in 2009 and the effects of our energy efficiency programs. For the three years 2007 through 2009, APS’ actual retail electricity sales in kilowatt-hours, adjusted to exclude the effects of weather variations, grew at an average annual rate of 0.3%. We currently estimate that total retail electricity sales in kilowatt-hours will remain flat on average per year during 2010 through 2012, including the effects of APS’ energy efficiency programs, but excluding the effects of weather variations. A continuation of the economic downturn, or the failure of the Arizona economy to rebound in the near future, could further impact these estimates. The customer and sales growth referred to in this paragraph apply to Native Load customers.

Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns, impacts of energy efficiency programs and responses to retail price changes. Our experience indicates that a reasonable range of variation in our kilowatt-hour sales projection attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of up to $10 million.

Weather. In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data. Historical extreme weather variations have resulted in annual variations in net income in excess of $20 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.

Fuel and Purchased Power Costs. Fuel and purchased power costs included on our Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, our hedging program for managing such costs and PSA deferrals and the amortization thereof.

Operations and Maintenance Expenses. Operations and maintenance expenses are impacted by growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, higher-trending pension and other postretirement benefit costs, renewable energy and demand side management related expenses (which are offset by the same amount of regulated electricity segment operating revenues) and other factors. In its recent retail rate case settlement, APS committed to operational expense reductions from 2010 through 2014 and received approval to defer certain pension and other postretirement benefit cost increases to be incurred in 2011 and 2012.

Depreciation and Amortization Expenses. Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates. The “Capital Expenditures” section below provides information regarding the planned additions to our facilities. We have also applied to the NRC for renewed operating licenses for each of the Palo Verde units. If the NRC grants the extension, we estimate that our annual pretax depreciation expense will decrease by approximately $34 million at the later of the license extension date or January 1, 2012.

Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate for APS, which currently owns the majority of our property, was 7.5% of the assessed value for 2009, 7.8% of the assessed value for 2008 and 8.3% of the assessed value for 2007. We expect property taxes to increase as we add new utility plant (including new generation, transmission and distribution facilities described below under “Capital Additions”) and as we improve our existing facilities.

Income Taxes. Income taxes are affected by the amount of pre-tax book income, income tax rates, and certain non-taxable items, such as the allowance for equity funds used during construction. In addition, income taxes may also be affected by the settlement of issues with taxing authorities.

Interest Expense. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (see Note 6.) The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, and internally generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop accruing capitalized interest on a project when it is placed in commercial operation.

PINNACLE WEST CONSOLIDATED — RESULTS OF OPERATIONS

Our results of operations, provided below, are based upon our two reportable business segments:

•

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

•

our real estate segment, which consists of SunCor’s real estate development and investment activities.

Operating Results — 2009 Compared with 2008

Our consolidated net income attributable to common shareholders for 2009 was $68 million, compared with net income of $242 million for the prior year. The decrease in net income was primarily due to 2009 real estate impairment charges recorded by SunCor, the Company’s real estate subsidiary.

In addition, regulated electricity segment net income decreased approximately $13 million from the prior year primarily due to lower retail sales resulting from lower usage per customer; higher interest charges, net of capitalized financing costs; higher depreciation and amortization expenses; and the absence of income tax benefits related to prior years recorded in 2008. These negative factors were partially offset by increased revenues due to the interim rate increase effective January 1, 2009 and transmission rate increases.

The following table presents net income attributable to common shareholders by business segment compared with the prior year:

										Increase
										(Decrease)
										in Net
										Income
		Year Ended								Attributable
		December 31,								to Common
		2009				2008				Shareholders
		(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses		$	1,970			$	1,843			$	127
Operations and maintenance			(862	)			(796	)			(66	)
Depreciation and amortization			(400	)			(383	)			(17	)
Taxes other than income taxes			(123	)			(125	)			2
Other income (expenses), net			(1	)			(20	)			19
Interest charges, net of capitalized financing costs			(199	)			(171	)			(28	)
Income taxes			(142	)			(92	)			(50	)
Regulated electricity segment net income			243				256				(13	)
Real Estate Segment:
Real estate impairment charges (a)			(266	)			(53	)			(213	)
Other real estate operations			(10	)			10				(20	)
Income taxes			109				17				92
Real estate segment net loss			(167	)			(26	)			(141	)
All Other (b)			(8	)			12				(20	)
Net Income Attributable to Common Shareholders		$	68			$	242			$	(174	)

Regulated electricity segment

This section includes a discussion of major variances in income and expense amounts for the regulated electricity segment.

Operating revenues less fuel and purchased power expenses

Regulated electricity segment operating revenues less fuel and purchased power expenses were $127 million higher for the year ended 2009 compared with the prior year. The following table describes the major components of this change:

		Increase (Decrease)
						Purchased
		Operating				power and fuel
		revenues				expenses				Net change
		(dollars in millions)
Higher renewable energy and demand-side management surcharges (substantially offset in operations and maintenance expense)		$	63			$				$	63
Interim retail rate increases effective January 1, 2009			61								61
Transmission rate increases			21								21
Increased mark-to-market valuations of fuel and purchased power contracts related to favorable changes in market prices, net of related PSA deferrals							(18	)			18
Effects of weather on retail sales, primarily due to hotter weather in the third quarter of 2009			12				3				9
Lower retail sales primarily due to lower usage per customer, including the effects of the Company’s energy efficiency programs, but excluding the effects of weather			(58	)			(26	)			(32	)
Higher fuel and purchased power costs including the effects of lower off-system sales, net of related PSA deferrals			(30	)			(19	)			(11	)
Lower retail revenues related to recovery of PSA deferrals, offset by lower amortization of the same amount recorded as fuel and purchased power expense (see Note 3)			(36	)			(36	)			—
Miscellaneous items, net			(11	)			(9	)			(2	)
Total		$	22			$	(105	)		$	127

Operations and maintenance Operations and maintenance expenses increased $66 million for the year ended 2009 compared with the prior year primarily because of:

•

An increase of $62 million related to renewable energy and demand-side management programs, which are offset in operating revenues;

•

An increase of $29 million in generation costs, including more planned maintenance, partially offset by lower costs at Palo Verde due to cost efficiency measures; and

•

A decrease of $25 million associated with cost saving measures and other factors, including the absence of employee severance costs in 2009.

Depreciation and amortization Depreciation and amortization expenses increased $17 million for the year ended 2009 compared with the prior year primarily because of increases in utility plant in service. The increases in utility plant in service are the result of various improvements to APS’ existing fossil and nuclear generating plants and distribution and transmission infrastructure additions and upgrades.

Interest charges, net of capitalized financing costs Interest charges, net of capitalized financing costs increased $28 million for the year ended 2009 compared with the prior year primarily because of higher debt balances, partially offset by the effects of lower interest rates (see discussion related to APS’ debt issuances in “Pinnacle West Consolidated — Liquidity and Capital Resources” below). Interest charges, net of capitalized financing costs are comprised of the regulated electricity segment portions of the line items interest expense, capitalized interest and allowance for equity funds used during construction from the Consolidated Statements of Income.

Other income (expenses), net Other income (expenses), net improved $19 million for the year ended 2009 compared with the prior year primarily because of improved investment gains. Other income (expenses), net is comprised of the regulated electricity segment portions of the line items other income and other expense from the Consolidated Statements of Income.

Income taxes Income taxes were $50 million higher for the year ended 2009 compared with the prior year primarily because of $30 million of income tax benefits related to prior years recorded in 2008 and higher pretax income. See Note 4.

Real estate segment

During the first quarter of 2009, we decided to restructure SunCor through the sale of substantially all of its assets. The real estate segment net loss attributable to common shareholders was $141 million higher for the year ended 2009 compared with the prior year primarily because of:

•

An increase in real estate impairment charges of $213 million (see Note 23 for details of the impairment charges);

•

A decrease of $20 million in income from other real estate operations primarily due to 2008 income from a commercial property sale; and

•

An increase in income tax benefits of $92 million primarily because of a higher net loss.

All Other

All other earnings were $20 million lower for the year ended 2009 compared with the prior year primarily because of planned reductions of marketing and trading activities and the absence of the 2008 resolution of certain tax issues associated with the sale of Silverhawk in 2005.

Operating Results — 2008 Compared with 2007

Our consolidated net income attributable to common shareholders for 2008 was $242 million, compared with net income of $307 million for the prior year. The decrease in net income was primarily due to lower results recorded by SunCor, the Company’s real estate subsidiary.

In addition, regulated electricity segment net income decreased approximately $18 million from the prior year primarily due to higher operations and maintenance expenses; lower retail sales due to the effects of weather; higher depreciation and amortization expenses; and higher interest charges, net of capitalized financing costs. These negative factors were partially offset by increased revenues due to the rate increase effective July 1, 2007; transmission rate increases; and income tax benefits related to prior years recorded in 2008.

The following table presents net income attributable to common shareholders by business segment compared with the prior year:

										Increase
										(Decrease)
										in Net
										Income
		Year Ended								Attributable
		December 31,								to Common
		2008				2007				Shareholders
		(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses		$	1,843			$	1,777			$	66
Operations and maintenance			(796	)			(709	)			(87	)
Depreciation and amortization			(383	)			(365	)			(18	)
Taxes other than income taxes			(125	)			(128	)			3
Other income (expenses), net			(20	)			(6	)			(14	)
Interest charges, net of capitalized financing costs			(171	)			(156	)			(15	)
Income taxes			(92	)			(139	)			47
Regulated electricity segment net income			256				274				(18	)
Real Estate Segment:
Real estate impairment charges (a)			(53	)			—				(53	)
Other real estate operations			10				37				(27	)
Income taxes			17				(14	)			31
Real estate segment net income (loss)			(26	)			23				(49	)
All Other (b)			12				10				2
Net Income Attributable to Common Shareholders		$	242			$	307			$	(65	)