1. Summary of Significant Accounting Policies

Consolidation and Nature of Operations

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, SunCor, APSES, El Dorado and Pinnacle West Marketing & Trading. APS’s consolidated financial statements include the accounts of APS and the Palo Verde sale leaseback VIEs. Intercompany accounts and transactions between the consolidated companies have been eliminated.

APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS accounts for substantially all of our revenues and earnings, and is expected to continue to do so. SunCor was a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico, Idaho and Utah. All activities for SunCor are now reported as discontinued operations (see Note 22). APSES provides energy-related projects to commercial and industrial retail customers in competitive markets in the western United States. In 2008, APSES discontinued its commodity-related energy services (see Note 22). El Dorado is an investment firm. Pinnacle West Marketing & Trading began operations in early 2007. These operations were previously conducted by a division of Pinnacle West through the end of 2006. By the end of 2008, substantially all the contracts were transferred to APS or expired.

In preparing the consolidated financial statements, we have evaluated the events that have occurred after December 31, 2010 through the date the financial statements were issued.

Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. These consolidated financial statements and notes have been prepared consistently with the exception of the reclassification of certain prior year amounts on our Consolidated Statements of Income and Consolidated Balance Sheets in accordance with accounting requirements for reporting discontinued operations (see Note 22), and amended accounting guidance related to VIEs (see Note 2).

Certain line items are presented in more detail on the Consolidated Statements of Cash Flows than was presented in the prior years. Other line items are more condensed than the previous presentation. The prior year amounts were reclassified to conform to the current year presentation. These reclassifications had no impact on total net cash flow provided by operating activities.

The following tables show the impact of the reclassifications of prior years (previously reported) amounts (dollars in thousands):

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

						Reclassifications as a				Amounts reported
						result of the adoption of				after adoption of
		As previously				the new VIE accounting				amended VIE
Balance Sheets – December 31, 2009		reported				guidance				accounting guidance
Property, Plant and Equipment — Palo Verde sale leaseback, net of accumulated depreciation		$	—			$	146,722			$	146,722
Deferred Debits — Regulatory assets			781,714				31,447				813,161
Current Liabilities — Current maturities of long-term debt			277,693				25,783				303,476
Long-Term Debt Less Current Maturities Palo Verde sale leaseback lessor notes			—				126,000				126,000
Deferred Credits and Other — Other			200,015				(55,938	)			144,077
Equity — Noncontrolling interests			29,571				82,324				111,895

										Amounts reported
						Reclassifications as a				after adoption of
						result of the adoption of				amended VIE
						the new VIE accounting				accounting
						guidance and to				guidance and to
Statement of Cash Flows for the		As previously				conform to current year				conform to current
Year Ended December 31, 2009		reported				presentation				year presentation
Cash Flows from Operating Activities
Net income		$	53,555			$	19,209			$	72,764
Depreciation and amortization including nuclear fuel			443,160				7,704				450,864
Other current assets			(9,186	)			33,833				24,647
Home inventory			33,833				(33,833	)			—
Other long-term liabilities			7,050				9,327				16,377
Cash Flows from Financing Activities
Repayment of long-term debt			(435,127	)			(21,755	)			(456,882	)
Noncontrolling interests			—				(14,485	)			(14,485	)
Supplemental Disclosure of Cash Flow Information
Cash paid for interest, net of amounts capitalized			203,860				12,748				216,608

										Amounts reported
						Reclassifications as a				after adoption of
						result of the adoption of				amended VIE
						the new VIE accounting				accounting
						guidance and to				guidance and to
Statement of Cash Flows for the		As previously				conform to current year				conform to current
Year Ended December 31, 2008		reported				presentation				year presentation
Cash Flows from Operating Activities
Net income		$	242,125			$	17,495			$	259,620
Depreciation and amortization including nuclear fuel			423,969				7,703				431,672
Other current assets			8,734				48,041				56,775
Home inventory			48,041				(48,041	)			—
Other long-term liabilities			36,880				9,327				46,207
Cash Flows from Financing Activities
Repayment of long-term debt			(181,491	)			(20,743	)			(202,234	)
Noncontrolling interests			—				(13,782	)			(13,782	)
Supplemental Disclosure of Cash Flow Information
Cash paid for interest, net of amounts capitalized			191,085				14,461				205,546

Accounting Records and Use of Estimates

Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Derivative Accounting

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity and fuels. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.

We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. See Note 18 for additional information about our derivative accounting policies.

Fair Value Measurements

We determine and disclose the fair value of certain assets and liabilities in accordance with fair value guidance. Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between willing market participants on the measurement date. Inputs to fair value include observable and unobservable data. We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

We determine fair market value using actively-quoted prices for identical instruments when available. When actively quoted prices are not available for the identical instruments we use prices for similar instruments or other corroborative market information or prices provided by other external sources. For options, long-term contracts and other contracts for which price quotes are not available, we use unobservable inputs, such as models and other valuation methods, to determine fair market value.

The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our structured activities are hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. Our practice is to hedge within timeframes established by our executive risk committee.

See Note 14 for additional information about fair value measurements.

Regulatory Accounting

APS is regulated by the ACC and the FERC. The accompanying financial statements reflect the rate-making policies of these commissions. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers.

Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.

See Note 3 for additional information.

Utility Plant and Depreciation

Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes:

•

material and labor;

•

contractor costs;

•

capitalized leases;

•

construction overhead costs (where applicable); and

•

capitalized interest or an allowance for funds used during construction.

We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 12.

APS records a regulatory liability for the asset retirement obligations related to its regulated assets. This regulatory liability represents the difference between the amount that has been recovered in regulated rates and the amount calculated in accordance with guidance on accounting for asset retirement obligations. APS believes it can recover in regulated rates the costs capitalized in accordance with this accounting guidance.

We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2010 were as follows:

•

Fossil plant — 18 years;

•

Nuclear plant — 17 years;

•

Other generation — 25 years;

•

Transmission — 40 years;

•

Distribution — 35 years; and

•

Other — 7 years.

For the years 2008 through 2010, the depreciation rates ranged from a low of 1.30% to a high of 10.20%. The weighted-average rate was 2.98% for 2010, 3.06% for 2009 and 3.08% for 2008. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 34 years.

Investments

El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership).

Our investments in the nuclear decommissioning trust fund are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities. See Note 14 for more information on these investments.

Allowance for Funds Used During Construction

AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant. Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statement of Income. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.

AFUDC was calculated by using a composite rate of 9.2% for 2010, 5.9% for 2009 and 7.0% for 2008. APS compounds AFUDC monthly and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

Electric Revenues

We derive electric revenues primarily from sales of electricity to our regulated Native Load customers. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.

Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called a “book-out” and usually occurs for contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and fuel and purchased power costs.

Effective January 1, 2010, electric revenues also include proceeds for line extension payments for new or upgraded service in accordance with the 2009 retail rate case settlement agreement (see Note 3). This revenue treatment continues through 2012, or until new rates are established in APS’s next general retail rate case, if that is before year end 2012. Certain proceeds received under previous versions of the line extension policy, or for activities not involving an extension or upgrade of service (e.g., service relocations at the request of governmental entities or undergrounding of overhead facilities) will continue to be treated as contributions in aid of construction and will not impact electric revenues.

Allowance for Doubtful Accounts

The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including accrued utility revenues. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment.

Real Estate Investments

Real estate investments primarily included SunCor’s land, home inventory, commercial property and investments in joint ventures. Land included acquisition costs, infrastructure costs, capitalized interest and property taxes directly associated with the acquisition and development of each project. Home inventory consisted of construction costs, improved lot costs, capitalized interest and property taxes on homes and condos under construction. Homes under construction were classified as “real estate investments” on the Consolidated Balance Sheets; upon completion of construction they transferred to “home inventory” with the expectation that they would be sold in a timely manner.

For the purposes of evaluating impairment, in accordance with the provisions on accounting for the impairment or disposal of long-lived assets, we classified our real estate assets, such as land under development, land held for future development, and commercial property as “held and used.” When events or changes in circumstances indicated that the carrying values of real estate assets considered held and used would not be recoverable, we compared the undiscounted cash flows that we estimated would be generated by each asset to its carrying amount. If the carrying amount exceeded the undiscounted cash flows, we adjusted the asset to fair value and recognized an impairment charge. The adjusted value became the new book value (carrying amount) for held and used assets. Our internal models used inputs that we believe were consistent with those that would be used by market participants.

Real estate home inventory was considered to be held for sale for purposes of evaluating impairment in accordance with the provisions of accounting guidance for impairment or disposal of long-lived assets. Home inventories were reported at the lower of carrying amount or fair value less costs to sell. Fair value less costs to sell was evaluated each period to determine if it had changed. Losses (and gains not to exceed any cumulative loss previously recognized) were reported as adjustments to the carrying amount.

Investments in joint ventures for which SunCor did not have a controlling financial interest were not consolidated, but were accounted for using the equity method of accounting. In addition, see Note 22 and Note 23.

Cash and Cash Equivalents

We consider all highly liquid investments with a maturity of three months or less at acquisition to be cash equivalents.

Nuclear Fuel

APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production method is based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.

APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charges APS $0.001 per kWh of nuclear generation. See Note 11 for information on spent nuclear fuel disposal and Note 14 for information on nuclear decommissioning costs.

Income Taxes

Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes. We file our federal income tax return on a consolidated basis and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. The income tax liability accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures. See Note 4.

Intangible Assets

We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’s software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives. Amortization expense was $45 million in 2010, $35 million in 2009 and $33 million in 2008. Estimated amortization expense on existing intangible assets over the next five years is $40 million in 2011, $36 million in 2012, $29 million in 2013, $23 million in 2014 and $15 million in 2015. At December 31, 2010, the weighted average remaining amortization period for intangible assets was 7 years.

2. New Accounting Standards

Variable Interest Entities

On January 1, 2010 we adopted amended accounting guidance relating to the consolidation of VIEs. This amended guidance significantly changed the consolidation model for VIEs. Under the prior guidance the consolidation model considered risk absorption using a quantitative approach when determining the primary beneficiary. The consolidation model under the new guidance requires a qualitative assessment and focuses on the power to direct activities of the VIE when determining the primary beneficiary. As a result of applying this qualitative assessment, we have determined that APS is the primary beneficiary of certain VIEs relating to the Palo Verde Unit 2 sale leaseback transactions, and is therefore required to consolidate these VIEs. Prior to adopting this new guidance, APS was not considered the primary beneficiary of these VIEs and did not consolidate these entities. We have adopted this guidance using retrospective application and have adjusted prior periods presented to reflect consolidation of the VIEs in those periods (see Note 1). See Note 20 for additional discussion and disclosures.

Future Accounting Changes

The FASB is currently working on several projects with the desire to converge GAAP with IFRS. These projects include accounting for leases, revenue recognition, and financial instruments, among other items. The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, we cannot determine the impact on our financial statements that may result from any such future changes.

Concurrent with these convergence projects, the SEC is considering mandating IFRS for U.S. companies. At this time, the impacts and timing of potential conversion to IFRS are uncertain and cannot be determined until final conversion requirements are mandated. The potential preparation of our financial statements in accordance with IFRS could have a significant impact on our reported financial statement results.

3. Regulatory Matters

2008 General Retail Rate Case Impacts

On December 30, 2009, the ACC issued an order approving a settlement agreement entered into by APS and twenty-one other parties to its general retail rate case, which was originally filed in March 2008. The settlement agreement included a net retail rate increase of $207.5 million, which represented a base rate increase of $344.7 million less a reclassification of $137.2 million of fuel and purchased power revenues from the then-existing PSA to base rates. The new rates were effective January 1, 2010. The settlement agreement also contained on-going requirements, commitments and authorizations, including the following:

•

Revenue accounting treatment for line extension payments received for new or upgraded service from January 1, 2010 through year end 2012 (or until new rates are established in APS’s next general rate case, if that is before the end of 2012);

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An authorized return on common equity of 11%;

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A capital structure comprised of 46.2% debt and 53.8% common equity;

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A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014;

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Authorization and requirements of equity infusions into APS of at least $700 million during the period beginning June 1, 2009 through December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in the second quarter of 2010); and

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Various modifications to the existing energy efficiency, demand-side management and renewable energy programs that require APS to, among other things, expand its conservation and demand-side management programs and its use of renewable energy, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand-side management costs and incentives.

The parties also agreed to a rate case filing plan in which APS is prohibited from filing its next two general rate cases until on or after June 1, 2011 and June 1, 2013, respectively, unless certain extraordinary events occur. Subject to the foregoing, APS may not request its next general retail rate increase to be effective prior to July 1, 2012. On February 1, 2011, APS filed a 120-day advanced notice of its intent to file its next rate case on June 1, 2011. The parties agreed to use good faith efforts to process these subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occur within 30 days after the filing of a rate case.

Cost Recovery Mechanisms

APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.

Renewable Energy Standard. In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.

During 2009, APS filed its annual RES implementation plan, covering the 2010-2014 timeframe and requesting 2010 RES funding approval. The plan provided for the acquisition of renewable generation in compliance with requirements through 2014, and requested RES funding of $87 million for 2010, which was later approved by the ACC. APS also sought various other determinations in its plan, including approval of the AZ Sun Program and the Community Power Project in Flagstaff, Arizona described below.

On March 3, 2010, the ACC approved the AZ Sun Program, which contemplates the addition of 100 MW of APS-owned solar resources through 2014. Through this program, APS plans to invest up to $500 million in solar photovoltaic projects across Arizona, which APS will acquire through competitive procurement processes. The costs associated with the first 50 MW under this program will be recovered initially through the RES until such time as the costs are recovered in base rates or other mechanisms. The costs of the second 50 MW will be recovered through a mechanism to be determined in APS’s next retail rate case.

On April 1, 2010, the ACC approved the Community Power Project, a pilot program in which APS will own, operate and receive energy from approximately 1.5 MW of solar panels on the rooftops of up to 200 residential and business customers located within a certain test area in Flagstaff, Arizona. The capital carrying costs of the program will be recovered through the RES until such time as these costs are recovered in base rates.

On July 1, 2010, APS filed its annual RES implementation plan, covering the 2011-2015 timeframe and requesting 2011 RES funding of $96 million. The 2011 Plan addressed enhancements to the residential distributed energy incentive program based on high customer participation, among other things. On October 13, 2010, APS filed an adjusted RES implementation plan to reflect the following items, among others: 1) increased clarity relating to customer project in-service dates and related budget revisions; 2) AZ Sun Program updates; and 3) the addition of 10 MW of biomass capacity. On December 10, 2010, the ACC approved the 2011 Plan and associated funding request. In January 2011, the ACC voted to reconsider four aspects of the approved 2011 Plan, including: (a) approval to proceed with a feed-in tariff filing; (b) approval for APS to participate in the ownership of distributed energy facilities in the Schools and Government program; (c) denial of a Rapid Reservation program that allows customers to receive priority in the incentive reservation process in exchange for receipt of a reduced incentive amount; and (d) allocation of the budget among various programs and studies. Hearings were held on January 24, 2011 and January 28, 2011. The ACC amended its original decision that approved the 2011 Plan as follows: the ACC (a) reversed its approval of a feed-in tariff program; (b) restricted APS’s ownership of facilities to only economically challenged, rural schools and only after a school has received a bid from a third-party solar installer; (c) approved the Rapid Reservation program; and (d) maintained the original approved budget with some timing modifications.

Demand-Side Management Adjustor Charge (“DSMAC”). The 2009 retail rate case settlement agreement requires APS to submit an annual Energy Efficiency Implementation Plan for review by and approval of the ACC. On July 15, 2009, APS filed its initial Energy Efficiency Implementation Plan, requesting approval by the ACC of programs and program elements for which APS had estimated a budget in the amount of $50 million for 2010. APS received ACC approval of all of its proposed programs and implemented the new DSMAC on March 1, 2010. A surcharge was added to customer bills in order to recover these estimated amounts for use on certain demand-side management programs. The surcharge allows for the recovery of energy efficiency expenses and any earned incentives.

The ACC approved recovery of all 2009 program costs plus incentives. The change from program cost recovery on a historical basis to recovery on a concurrent basis, as authorized in the settlement agreement, resulted in this one-time need to address two years (2009 and 2010) of cost recovery. As requested by APS, 2009 program cost recovery is to be spread over a three-year period.

On June 1, 2010, APS filed its 2011 Energy Efficiency Implementation Plan. In order to meet the energy efficiency goal for 2011 established by the settlement agreement of annual energy savings of 1.25%, expressed as a percent of total energy resources to meet retail load, APS proposed a total budget for 2011 of $79 million. On February 17, 2011, a total budget for 2011 of $80 million was approved and when added to the amortization of 2009 costs discussed above less the $10 million already being recovered in general rates, the DSMAC would recover approximately $75 million over a twelve month period beginning March 1, 2011. These amounts do not include approximately $1 million for an electric vehicle charging station program submitted to the ACC for approval on September 30, 2010.

PSA Mechanism and Balance. The PSA, which the ACC initially approved in 2005 as a part of APS’s 2003 rate case, and which was modified by the ACC in 2007, provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:

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APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;

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under a 90/10 sharing arrangement, APS defers 90% of the difference between retail fuel and purchased power costs (excluding certain costs, such as renewable energy resources and the capacity components of long-term purchased power agreements acquired through competitive procurement) and the Base Fuel Rate; APS absorbs 10% of the retail fuel and purchased power costs above the Base Fuel Rate and retains 10% of the benefit from the retail fuel and purchased power costs that are below the Base Fuel Rate;

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an adjustment to the PSA rate is made annually each February 1st (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;

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the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);

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the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and

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the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2010 and 2009 (dollars in millions):

		Year Ended
		December 31,
		2010				2009
Beginning balance		$	(87	)		$	8
Deferred fuel and purchased power costs-current period			(93	)			52
Amounts recovered through revenues			122				(147	)
Ending balance		$	(58	)		$	(87	)

The PSA rate for the PSA year beginning February 1, 2011 is ($0.0057) per kWh as compared to ($0.0045) per kWh for the prior year. The regulatory liability at December 31, 2010 reflects lower average prices, primarily for natural gas and gas-based generation. Any uncollected (overcollected) deferrals during the 2011 PSA year will be included in the historical component of the PSA rate for the PSA year beginning February 1, 2012.

Transmission Rates and Transmission Cost Adjustor. In July 2008, the FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS must file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.

The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and have a significant effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may be calculated to account for previously over-collected amounts.

Effective June 1, 2010, APS’s annual wholesale transmission rates for all users of its transmission system were reduced by approximately $12 million in accordance with the FERC-approved formula as a result of lower costs reflected in the formula. Approximately $10 million of this revenue reduction relates to transmission services used for APS’s retail customers. On May 20, 2010, APS filed with the ACC an application for the related reduction of its TCA rate. The ACC approved the TCA reduction on July 27, 2010.

Regulatory Assets and Liabilities

The detail of regulatory assets is as follows (dollars in millions):

		December 31,
		2010				2009
Pension and other postretirement benefits (Note 8)		$	669			$	532
Deferred fuel and purchased power — mark-to-market (Note 18)			77				41
Deferred income taxes (Note 4)			72				59
Transmission vegetation management			46				34
Coal reclamation			38				16
Palo Verde VIE (Note 20)			33				31
Deferred compensation			32				31
Tax expense of Medicare subsidy (Note 8)			23				—
Loss on reacquired debt			22				23
Demand side management (a)			18				18
Other			19				28
Total regulatory assets (b)		$	1,049			$	813

Included in the balance of regulatory assets at December 31, 2010 and 2009 is a regulatory asset for pension and other postretirement benefits. This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future earnings.

The detail of regulatory liabilities is as follows (dollars in millions):

		December 31,
		2010				2009
Removal costs (Note 1) (a)		$	379			$	385
Asset retirement obligations (Note 12)			184				156
Deferred fuel and purchased power (b)(c)			58				87
Renewable energy standard (b)			50				51
Spent nuclear fuel (Note 11)			45				34
Deferred gains on utility property			18				20
Tax benefit of Medicare subsidy (Note 8)			—				17
Other			19				16
Total regulatory liabilities		$	753			$	766

4. Income Taxes

Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates.

APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations. The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction and pension and other postretirement benefits. The regulatory liabilities relate to deferred taxes resulting primarily from investment tax credits. APS amortizes these amounts as the differences reverse.

Pinnacle West expects to recognize approximately $132 million of cash tax benefits related to SunCor’s strategic asset sales (see Note 23), a majority of which have been realized as of December 31, 2010. Approximately $7 million of these benefits were recorded in 2010 as reductions to income tax expense related to the current impairment charges. The additional $125 million of tax benefits were recorded as reductions to income tax expense related to SunCor impairment charges recorded on or before December 31, 2009.

The $68 million income tax receivables on the Consolidated Balance Sheets represent the anticipated refunds related to an APS tax accounting method change approved by the IRS in the third quarter of 2009 and the current year tax benefits related to the SunCor strategic asset sales that closed in 2010. A majority of this amount is classified as long-term, as cash refunds are not expected to be received in the next twelve months.

The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):

		2010				2009				2008
Total unrecognized tax benefits, January 1		$	201,216			$	63,318			$	157,869
Additions for tax positions of the current year			7,551				44,094				12,923
Additions for tax positions of prior years			—				98,942				32,510
Reductions for tax positions of prior years for:
Changes in judgment			(11,017	)			—				(4,454	)
Settlements with taxing authorities			(62,199	)			(4,089	)			(35,812	)
Lapses of applicable statute of limitations			(7,956	)			(1,049	)			(99,718	)
Total unrecognized tax benefits, December 31		$	127,595			$	201,216			$	63,318

During the first quarter of 2010, the Company reached a settlement with the IRS with regard to the examination of tax returns for the years ended December 31, 2005 through 2007. As a result of this settlement, net uncertain tax positions decreased $62 million, including approximately $3 million which decreased our effective tax rate. Additionally, the settlement resulted in the recognition of net interest benefits of approximately $4 million through the effective tax rate.

Included in the balances of unrecognized tax benefits at December 31, 2010, 2009 and 2008 were approximately $7 million, $16 million and $16 million, respectively, of tax positions that, if recognized, would decrease our effective tax rate.

As of the balance sheet date, the tax year ended December 31, 2008 and all subsequent tax years remain subject to examination by the IRS. With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 1999. We do not anticipate that there will be any significant increases or decreases in our unrecognized tax benefits within the next twelve months.

We reflect interest and penalties, if any, on unrecognized tax benefits in the Consolidated Statements of Income as income tax expense. The amount of interest recognized in the Consolidated Statement of Income related to unrecognized tax benefits was a pre-tax benefit of $2 million for 2010, a pre-tax expense of $2 million for 2009 and a pre-tax benefit of $51 million for 2008.

The total amount of accrued liabilities for interest recognized in the consolidated Balance Sheets related to unrecognized tax benefits was $6 million as of December 31, 2010, $8 million as of December 31, 2009 and $6 million as of December 31, 2008. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, as of December 31, 2010, we have recognized $5 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

The components of income tax expense are as follows (dollars in thousands):

		Year Ended December 31,
		2010				2009				2008
Current:
Federal		$	(108,827	)		$	(38,502	)		$	(85,866	)
State			25,545				(38,080	)			11,738
Total current			(83,282	)			(76,582	)			(74,128	)
Deferred:
Income from continuing operations			271,147				105,492				158,024
Discontinued operations			(10,736	)			—				—
Total deferred			260,411				105,492				158,024
Total income tax expense			177,129				28,910				83,896
Less: income tax expense (benefit) on discontinued operations			12,808				(107,596	)			(11,648	)
Income tax expense — continuing operations		$	164,321			$	136,506			$	95,544

The following chart compares pretax income from continuing operations at the 35% federal income tax rate to income tax expense — continuing operations (dollars in thousands):

		Year Ended December 31,
		2010				2009				2008
Federal income tax expense at 35% statutory rate		$	180,222			$	136,172			$	130,858
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit			17,878				14,837				12,640
Credits and favorable adjustments related to prior years resolved in current year			(17,300	)			—				(28,873	)
Medicare Subsidy Part-D (see Note 8)			1,311				(2,095	)			(1,993	)
Allowance for equity funds used during construction (see Note 1)			(6,563	)			(4,265	)			(5,755	)
Palo Verde VIE noncontrolling interest (see Note 20)			(7,057	)			(6,723	)			(6,123	)
Other			(4,170	)			(1,420	)			(5,210	)
Income tax expense — continuing operations		$	164,321			$	136,506			$	95,544

The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):

		December 31,
		2010				2009
Current asset		$	94,602			$	53,990
Long-term liability			(1,833,566	)			(1,496,095	)
Deferred income taxes — net		$	(1,738,964	)		$	(1,442,105	)