1. Consolidation and Nature of Operations

The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, SunCor Development Company (“SunCor”), APS Energy Services Company, Inc. (“APSES”), and El Dorado Investment Company (“El Dorado”). Intercompany accounts and transactions between the consolidated companies have been eliminated. The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde sale leaseback variable interest entities (“VIEs”) (see Note 7 for further discussion). 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.

Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.

In preparing the condensed consolidated financial statements, we have evaluated the events that have occurred after March 31, 2011 through the date the financial statements were issued.

Our condensed 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 condensed consolidated financial statements and notes have been prepared consistently with the 2010 Form 10-K with the exception of the reclassification of certain prior year amounts on our Condensed Consolidated Statements of Income, Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows in accordance with accounting requirements for reporting discontinued operations (see Note 14), and the impacts related to the reclassification of regulatory assets and liabilities for the current portion (see Note 3).

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

										Amount
										reported after
		As				Reclassifications				reclassification
Statement of Income for the Three		previously				for discontinued				for discontinued
Months Ended March 31, 2010		reported				operations				operations
Operating Revenues
Real estate segment		$	9,416			$	(9,416	)		$	—
Other revenues			12,750				(3,820	)			8,930
Operating Expenses
Real estate segment operations			13,890				(13,890	)			—
Real estate impairment charge			15,112				(15,112	)			—
Operations and maintenance			209,991				(2,149	)			207,842
Depreciation and amortization			101,536				(883	)			100,653
Taxes other than income taxes			31,827				(103	)			31,724
Other expenses			8,061				(1,133	)			6,928
Other
Other income			2,395				(287	)			2,108
Interest Expense
Interest charges			62,054				(1,349	)			60,705
Allowance for borrowed funds used during construction			(3,080	)			33				(3,047	)
Income Taxes			(15,480	)			8,308				(7,172	)
Income (Loss) From Continuing Operations			(772	)			12,755				11,983
Loss From Discontinued Operations			(125	)			(12,755	)			(12,880	)

										Amount
										reported after
						Reclassifications				reclassification
		As				for regulatory				for regulatory
		previously				assets and				assets and
Balance Sheets — December 31, 2010		reported				liabilities				liabilities
Current Assets — Regulatory assets		$	—			$	62,286			$	62,286
Current Assets — Deferred income taxes			94,602				30,295				124,897
Deferred Debits — Regulatory assets			1,048,656				(62,286	)			986,370
Current Liabilities — Deferred fuel and purchased power regulatory liability			—				58,442				58,442
Current Liabilities — Other regulatory liabilities			—				80,526				80,526
Deferred Credits and Other — Deferred income taxes			1,833,566				30,295				1,863,861
Deferred Credits and Other — Deferred fuel and purchased power regulatory liability			58,442				(58,442	)			—
Deferred Credits and Other — Regulatory liabilities			694,589				(80,526	)			614,063

										Amount
										reported after
						Reclassifications				reclassification
		As				for regulatory				for regulatory
Statement of Cash Flows for the		previously				assets and				assets and
Three Months Ended March 31, 2010		reported				liabilities				liabilities
Cash Flows from Operating Activities
Other current assets		$	(8,836	)		$	688			$	(8,148	)
Other current liabilities			(36,582	)			(2,990	)			(39,572	)
Change in other long-term assets			(25,903	)			(690	)			(26,593	)
Change in other long-term liabilities			(39,550	)			2,992				(36,558	)

2. Long-term Debt and Liquidity Matters

The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt and capitalized lease requirements as of March 31, 2011 (dollars in millions):

		Consolidated				Consolidated
Year		Pinnacle West				APS
2011		$	457			$	457
2012			477				477
2013			140				140
2014			502				502
2015			488				313
Thereafter			1,620				1,620
Total		$	3,684			$	3,509

Credit Facilities and Debt Issuances

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs. During the first quarter of 2011, APS refinanced an existing revolving credit facility (as discussed below) that would have otherwise matured in September 2011.

Pinnacle West

On February 23, 2011, Pinnacle West entered into a $175 million term loan facility that matures February 20, 2015. Pinnacle West used the proceeds of the loan to repay its 5.91% $175 million Senior Notes. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings, or if unavailable, its long-term issuer ratings.

At March 31, 2011, Pinnacle West’s $200 million credit facility, which matures in 2013, was available for general corporate purposes, support of its $200 million commercial paper program, or for issuances of letters of credit. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At March 31, 2011, Pinnacle West had no outstanding borrowings under this credit facility, no outstanding letters of credit and commercial paper borrowings of $17 million.

APS

On February 14, 2011, APS refinanced its $489 million revolving credit facility that would have matured in September 2011, with a new $500 million facility. The new revolving credit facility terminates in February 2015. APS may increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use the facility for general corporate purposes, commercial paper program support and for the issuance of letters of credit. Interest rates are based on APS’s senior unsecured debt credit ratings.

At March 31, 2011, APS had two credit facilities totaling $1 billion, including the $500 million credit facility described above and a $500 million facility that matures in February 2013. These facilities are available to support its $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. See Note 12 for discussion of APS’s letters of credit. At March 31, 2011, APS had no borrowings outstanding under any of its credit facilities and no outstanding commercial paper. A $20 million letter of credit was outstanding under APS’s 2011 $500 million credit facility described above.

Debt Provisions

An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At March 31, 2011, APS was in compliance with the common equity ratio requirements established by the ACC. Its total shareholder equity was approximately $3.8 billion, and total capitalization was approximately $7.1 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $2.9 billion, assuming APS’s total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

3. Regulatory Matters

2008 General Retail Rate Case Impacts

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

•

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

•

An authorized return on common equity of 11%;

•

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

•

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

•

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

•

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

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

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 Arizona Renewable Energy Standard and Tariff (“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 megawatts (“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 settlement agreement related to the 2008 retail rate case 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 power supply adjustor (“PSA”) provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.

The following table shows the changes in the deferred fuel and purchased power regulatory liability for 2011 and 2010 (dollars in millions):

		Three Months Ended
		March 31,
		2011				2010
Beginning balance		$	(58	)		$	(87	)
Deferred fuel and purchased power costs-current period			(50	)			(44	)
Amounts refunded through revenues			31				26
Ending balance		$	(77	)		$	(105	)

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 March 31, 2011 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 calculation of the PSA rate for the PSA year beginning February 1, 2012.

Transmission Rates and Transmission Cost Adjustor. In July 2008, the United States Federal Energy Regulatory Commission (“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 transmission cost adjustor (“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 could 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, 2011, APS’s annual wholesale transmission rates for all users of its transmission system will increase by approximately $44.3 million for the twelve-month period beginning June 1, 2011 in accordance with the FERC-approved formula as a result of higher costs and lower revenues reflected in the formula. Approximately $38.2 million of this revenue increase relates to transmission services used for APS’s retail customers. On April 22, 2011, APS filed with the ACC an application for the related increase of its TCA rate.

Regulatory Assets and Liabilities

As discussed in Note 1, as of March 31, 2011, the Company revised its presentation of regulatory assets and liabilities to separately reflect current and non-current amounts on the Condensed Consolidated Balance Sheets. This presentation is reflected in the tables below.

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

		March 31, 2011								December 31, 2010
		Current				Non-Current				Current				Non-Current
Pension and other postretirement benefits		$	—			$	663			$	—			$	669
Deferred fuel and purchased power — mark-to-market (Note 8)			38				38				42				35
Deferred income taxes			3				68				3				69
Transmission vegetation management			—				45				—				46
Coal reclamation			2				36				2				36
Palo Verde VIE (Note 7)			—				33				—				33
Deferred compensation			—				33				—				32
Tax expense of Medicare subsidy			2				22				2				21
Loss on reacquired debt			1				20				1				21
Demand side management (a)			9				5				12				6
Other			1				17				—				18
Total regulatory assets (b)		$	56			$	980			$	62			$	986

Included in the balance of regulatory assets at March 31, 2011 and December 31, 2010 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):

		March 31, 2011								December 31, 2010
		Current				Non-Current				Current				Non-Current
Removal costs (a)		$	20			$	359			$	22			$	357
Asset retirement obligations (Note 16)			—				206				—				184
Deferred fuel and purchased power (b)(c)			77				—				58				—
Renewable energy standard (b)			50				—				50				—
Income taxes — change in rates			—				50				—				—
Spent nuclear fuel			5				41				4				41
Deferred gains on utility property			2				16				2				16
Other			1				18				3				16
Total regulatory liabilities		$	155			$	690			$	139			$	614

4. Retirement Plans and Other Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and other postretirement benefit plans for the employees of Pinnacle West and our subsidiaries. Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date.

The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged to a regulatory asset) (dollars in millions):

		Pension Benefits								Other Benefits
		Three Months Ended								Three Months Ended
		March 31,								March 31,
		2011				2010				2011				2010
Service cost — benefits earned during the period		$	16			$	15			$	6			$	5
Interest cost on benefit obligation			31				31				12				11
Expected return on plan assets			(33	)			(31	)			(10	)			(10	)
Amortization of:
Transition obligation			—				—				—				1
Prior service cost			—				1				—				—
Net actuarial loss			6				6				3				3
Net periodic benefit cost		$	20			$	22			$	11			$	10
Portion of cost charged to expense		$	8			$	11			$	4			$	5
APS’s share of cost charged to expense		$	8			$	10			$	4			$	5

Contributions

The required minimum contribution to our pension plan is zero in 2011 and approximately $85 million in 2012. The contributions to our other postretirement benefit plans for 2011 and 2012 are expected to be approximately $20 million each year. APS and other subsidiaries fund their share of the contributions. APS’s share is approximately 99% of both plans.

5. Business Segments

Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily retail and wholesale sales supplied to traditional cost-based rate regulation (“Native Load”) customers) and related activities and includes electricity generation, transmission and distribution.

Financial data for the three months ended March 31, 2011 and 2010 and at March 31, 2011 and December 31, 2010 is provided as follows (dollars in millions):

		Three Months Ended
		March 31,
		2011				2010
Operating revenues:
Regulated electricity segment		$	648			$	611
All other (a)			12				9
Total		$	660			$	620
Net income (loss) attributable to common shareholders:
Regulated electricity segment		$	(15	)		$	7
All other (b)			—				(13	)
Total		$	(15	)		$	(6	)

		As of				As of
		March 31, 2011				December 31, 2010
Assets:
Regulated electricity segment		$	12,237			$	12,285
All other (b)			66				108
Total		$	12,303			$	12,393

6. Income Taxes

The $68 million income tax receivable on the Condensed Consolidated Balance Sheets represents the anticipated refunds related to an APS tax accounting method change approved by the IRS in the third quarter of 2009. This amount is classified as long-term, as cash refunds are not expected to be received in the next twelve months.

On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four year phase-in of corporate income tax rate reductions beginning in 2014. As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in Arizona. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. In the first quarter of 2011, Pinnacle West increased regulatory liabilities by a total of $53 million, with a corresponding decrease in accumulated deferred income tax liabilities to reflect the impact of this change in tax law.

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 2006. We do not anticipate that there will be any significant increases or decreases in our unrecognized tax benefits within the next twelve months.

7. Variable-Interest Entities

Palo Verde Sale Leaseback Trusts

In 1986, APS entered into agreements with three separate variable-interest entity (“VIE”) lessor trusts in order to sell and lease back interests in Palo Verde Nuclear Generating Station (“Palo Verde”) Unit 2 and related common facilities. The VIE lessor trusts are single-asset leasing entities. APS will pay approximately $49 million per year for the years 2011 to 2015 related to these leases. The leases do not contain fixed price purchase options or residual value guarantees. However, the lease agreements include fixed rate renewal periods which may have a significant impact on the VIEs’ economic performance. We have concluded that these fixed rate renewal periods may give APS the ability to utilize the asset for a significant portion of the asset’s economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance. In addition to the fixed rate renewal periods, our primary beneficiary analysis also considered that APS is the operating agent for Palo Verde, is obligated to decommission the leased assets and has fair value purchase options.

For the reasons discussed above, APS consolidates these VIEs. Consolidation of these VIEs eliminates the lease accounting and results in changes in our consolidated assets, debt, equity, and net income. Assets of the VIEs are restricted and may only be used to settle the VIEs’ debt obligations and for payment to the noncontrolling interest holders. Other than the VIEs’ assets reported on our consolidated financial statements, the creditors of the VIEs have no other recourse to the assets of APS or Pinnacle West, except in certain circumstances such as a default by APS under the lease. As a result of consolidation we eliminate rent expense and recognize depreciation and interest expense, resulting in an increase in net income for the three months ended March 31, 2011 of $5 million entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders remains the same. Consolidation of these VIEs also results in changes to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows.

Our Condensed Consolidated Balance Sheets at March 31, 2011 and December 31, 2010 include the following amounts relating to the VIEs (in millions):

		March 31, 2011				December 31, 2010
Property plant and equipment, net of accumulated depreciation		$	136			$	138
Long-term debt including current maturities			126				126
Equity- Noncontrolling interests			97				91

For regulatory ratemaking purposes the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset of $33 million as of March 31, 2011 and December 31, 2010.

APS is exposed to losses relating to these lessor trust VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the United States Nuclear Regulatory Commission (“NRC”) issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of March 31, 2011, APS would have been required to pay the noncontrolling equity participants approximately $146 million and assume $126 million of debt. Since APS consolidates the VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.

8. Derivative Accounting

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances, and in interest rates. We manage risks associated with these market fluctuations by utilizing various derivative instruments, including futures, forwards, options and swaps. As part of our overall risk management program, we may use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. Derivative instruments that are designated as cash flow hedges are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. We may also invest in derivative instruments for trading purposes; however, for the period ended March 31, 2011, there was no material trading activity.

Our derivative instruments are accounted for at fair value; see Note 15 for a discussion of fair value measurements. Derivative instruments for the physical delivery of purchase and sale quantities transacted in the normal course of business qualify for the normal purchase and sales scope exception and are accounted for under the accrual method of accounting. Due to the scope exception, these derivative instruments are excluded from our derivative instrument discussion and disclosures below.

We also enter into derivative instruments for economic hedging purposes. While we believe the economic hedges mitigate exposure to fluctuations in commodity prices, some of these instruments may not meet the specific hedge accounting requirements and are not designated as accounting hedges. Economic hedges not designated as accounting hedges are recorded at fair value on our balance sheet with changes in fair value recognized in the statement of income as incurred. These instruments are included in the “non-designated hedges” discussion and disclosure below.

Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value of the derivative instrument contract and the hedged item over time. We assess hedge effectiveness both at inception and on a continuing basis. These assessments exclude the time value of certain options. For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of accumulated other comprehensive income (“AOCI”) and reclassified into earnings in the same period during which the hedged transaction affects earnings. We recognize in current earnings, subject to the PSA, the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment. As of March 31, 2011, we hedged the majority of certain exposures to the price variability of commodities for a maximum of 39 months.

In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in 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 in our Condensed Consolidated Statements of Income, but this does not impact our financial condition, net income or cash flows.

For its regulated operations, APS defers for future rate treatment approximately 90% of unrealized gains and losses on certain derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the portion of APS’s base rates attributable to fuel and purchased power costs (see Note 3). Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

As of March 31, 2011, we had the following outstanding gross notional amount of derivatives, which represent both purchases and sales (does not reflect net position):

Commodity		Quantity
Power			13,715,268			megawatt hours
Gas			138,357,611			MMBTU (a)

Derivative Instruments in Designated Accounting Hedging Relationships

The following table provides information about gains and losses from derivative instruments in designated accounting hedging relationships and their impact on our Condensed Consolidated Statements of Income during the three months ended March 31, 2011 and 2010 (dollars in thousands):

				Three Months Ended
		Financial Statement		March 31,
Commodity Contracts		Location		2011				2010
Amount of Gain (Loss) Recognized in AOCI on Derivative Instruments (Effective Portion)		Accumulated other comprehensive loss-derivative instruments		$	988			$	(91,667	)
Amount of Loss Reclassified from AOCI into Income (Effective Portion Realized)		Regulated electricity segment fuel and purchased power			(14,846	)			(13,185	)
Amount of Gain (Loss) Recognized in Income from Derivative Instruments (Ineffective Portion and Amount Excluded from Effectiveness Testing) (a)		Regulated electricity segment fuel and purchased power			12				(10,467	)

During the next twelve months, we estimate that a net loss of $102 million before income taxes will be reclassified from AOCI as an offset to the effect of market price changes for the related hedged transactions. Approximately 90% of the amounts related to derivatives subject to the PSA will be recorded as either a regulatory asset or liability and have no effect on earnings.

Derivative Instruments Not Designated as Accounting Hedges

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments and their impact on our Condensed Consolidated Statements of Income during the three months ended March 31, 2011 and 2010 (dollars in thousands):

				Three Months Ended
		Financial Statement		March 31,
Commodity Contracts		Location		2011				2010
Amount of Net Gain Recognized in Income from Derivative Instruments		Regulated electricity segment revenue		$	1,507			$	170
Amount of Net Loss Recognized in Income from Derivative Instruments		Regulated electricity segment fuel and purchased power expense			(9,026	)			(34,969	)
Total				$	(7,519	)		$	(34,799	)

Fair Values of Derivative Instruments in the Condensed Consolidated Balance Sheets

The following table provides information about the fair value of our derivative instruments, margin account and cash collateral reported on a gross basis. Transactions with counterparties that have master netting arrangements are reported net on the Condensed Consolidated Balance Sheets. These amounts are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets. Amounts are as of March 31, 2011 (dollars in thousands):

						Investments				Current				Deferred Credits				Total Assets
Commodity Contracts		Current Assets				and Other Assets				Liabilities				and Other				(Liabilities)
Derivatives designated as accounting hedging instruments:
Assets		$	—			$	663			$	9,583			$	4,234			$	14,480
Liabilities			—				(245	)			(98,821	)			(54,802	)			(153,868	)
Total hedging instruments			—				418				(89,238	)			(50,568	)			(139,388	)
Derivatives not designated as accounting hedging instruments:
Assets			22,278				38,188				35,863				18,394				114,723
Liabilities			(44	)			(86	)			(107,359	)			(90,530	)			(198,019	)
Total non-hedging instruments			22,234				38,102				(71,496	)			(72,136	)			(83,296	)
Total derivatives			22,234				38,520				(160,734	)			(122,704	)			(222,684	)
Margin account			20,076				—				359				—				20,435
Collateral provided to counterparties			11,985				—				101,123				66,187				179,295
Collateral provided from counterparties			—				—				(11,795	)			—				(11,795	)
Prepaid option premiums and other			284				—				—				—				284
Balance Sheet Total		$	54,579			$	38,520			$	(71,047	)		$	(56,517	)		$	(34,465	)

The following table provides information about the fair value of our derivative instruments, margin account and cash collateral reported on a gross basis at December 31, 2010 (dollars in thousands):

						Investments				Current				Deferred Credits				Total Assets
Commodity Contracts		Current Assets				and Other Assets				Liabilities				and Other				(Liabilities)
Derivatives designated as accounting hedging instruments:
Assets		$	1,234			$	142			$	9,062			$	4,913			$	15,351
Liabilities			(602	)			(1,933	)			(107,784	)			(71,109	)			(181,428	)
Total hedging instruments			632				(1,791	)			(98,722	)			(66,196	)			(166,077	)
Derivatives not designated as accounting hedging instruments:
Assets			36,831				40,927				27,322				19,886				124,966
Liabilities			(312	)			(33	)			(112,535	)			(85,473	)			(198,353	)
Total non-hedging instruments			36,519				40,894				(85,213	)			(65,587	)			(73,387	)
Total derivatives			37,151				39,103				(183,935	)			(131,783	)			(239,464	)
Margin account			24,579				—				997				—				25,576
Collateral provided to counterparties			11,556				—				125,367				66,393				203,316
Collateral provided from counterparties			(1,750	)			—				(1,250	)			—				(3,000	)
Prepaid option premiums and other			2,252				(71	)			(155	)			—				2,026
Balance Sheet Total		$	73,788			$	39,032			$	(58,976	)		$	(65,390	)		$	(11,546	)

Credit Risk and Credit-Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management contracts with many counterparties, including two counterparties for which our exposure represents approximately 53% of Pinnacle West’s $93 million of risk management assets as of March 31, 2011. This exposure relates to long-term traditional wholesale contracts with counterparties that have very high credit quality. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position on March 31, 2011 was $328 million, for which we had posted collateral of $167 million in the normal course of business.

For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit ratings were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s), which would be a violation of the credit rating provisions. If the investment grade contingent features underlying these agreements had been fully triggered on March 31, 2011, after off-setting asset positions under master netting arrangements we would have been required to post approximately an additional $122 million of collateral to our counterparties; this amount includes those contracts which qualify for scope exceptions, which are excluded from the derivative details in the above footnote. We also have energy related non-derivative instrument contracts with investment grade credit-related contingent features which could also require us to post additional collateral of approximately $196 million if our debt credit ratings were to fall below investment grade.

9. Changes in Equity

The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three months ended March 31, 2011 and 2010 (dollars in thousands):

		Three Months Ended March 31, 2011												Three Months Ended March 31, 2010
		Common				Noncontrolling								Common				Noncontrolling
		Shareholders				Interests				Total				Shareholders				Interests				Total
Beginning balance, January 1		$	3,683,327			$	91,899			$	3,775,226			$	3,316,109			$	111,895			$	3,428,004
Net income (loss)			(15,135	)			5,461				(9,674	)			(6,014	)			5,117				(897	)
Other comprehensive income (loss):
Net unrealized gains (losses) on derivative instruments (a)			988				—				988				(91,667	)			—				(91,667	)
Net reclassification of realized losses to income (b)			14,846				—				14,846				13,185				—				13,185
Reclassification of pension and other postretirement benefits to income			1,433				—				1,433				1,393				—				1,393
Net income tax benefit (expense) related to items of other comprehensive income (loss)			(6,821	)			—				(6,821	)			30,426				—				30,426
Total other comprehensive income (loss)			10,446				—				10,446				(46,663	)			—				(46,663	)
Total comprehensive income (loss)			(4,689	)			5,461				772				(52,677	)			5,117				(47,560	)
Issuance of capital stock			13,560				—				13,560				2,680				—				2,680
Purchase of treasury stock, net of reissuances			(3,530	)			—				(3,530	)			1,078				—				1,078
Other (primarily stock compensation)			(148	)			—				(148	)			2				(22	)			(20	)
Dividends on common stock			(57,109	)			—				(57,109	)			(53,259	)			—				(53,259	)
Net capital activities by noncontrolling interests			—				—				—				—				(923	)			(923	)
Ending balance, March 31		$	3,631,411			$	97,360			$	3,728,771			$	3,213,933			$	116,067			$	3,330,000

10. Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

APS currently estimates it will incur $122 million (in 2011 dollars) over the current life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At March 31, 2011, APS had a regulatory liability of $46 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

Nuclear Insurance

The Palo Verde participants are insured against public liability for a nuclear incident up to $12.6 billion per occurrence. As required by the Price Anderson Nuclear Industries Indemnity Act, Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by commercial insurance carriers. The remaining balance of $12.2 billion is provided through a mandatory industry wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $118 million, subject to an annual limit of $18 million per incident, to be periodically adjusted for inflation. Based on APS’s interest in the three Palo Verde units, APS’s maximum potential assessment per incident for all three units is approximately $103 million, with an annual payment limitation of approximately $15 million.

The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $18 million for each retrospective assessment declared by NEIL’s Board of Directors due to losses. In addition, NEIL policies contain rating triggers that would result in APS providing approximately $46 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

Contractual Obligations

Our future contractual purchase obligations have increased from approximately $456 million at December 31, 2010 as disclosed in the 2010 Form 10-K to $699 million at March 31, 2011. This increase is primarily related to an amended agreement for certain transmission rights-of-way and a new contract for the construction of a solar facility. Total contractual purchase obligations are as follows (dollars in millions):

2011				2012				2013				2014				2015				Thereafter				Total
$	232			$	116			$	69			$	6			$	6			$	270			$	699

Payments for the transmission rights-of-way are subject to change based on changes in the Consumer Price Index.

FERC Market Issues

On July 25, 2001, the FERC ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest. The FERC affirmed the administrative law judge’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision was appealed to the U.S. Court of Appeals for the Ninth Circuit. On August 24, 2007, the Ninth Circuit issued an opinion that remanded the proceeding to the FERC for further consideration. Although the FERC has not yet determined whether any refunds will ultimately be required, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or cash flows.

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 potentially responsible parties (“PRPs”). PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, the United States Environmental Protection Agency (“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. We estimate that our costs related to this investigation and study will be approximately $1 million, which is reserved as a liability on our 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.

11. Other Income and Other Expense

The following table provides detail of other income and other expense for the three months ended March 31, 2011 and 2010 (dollars in thousands):

		Three Months Ended March 31,
		2011				2010
Other income:
Interest income		$	391			$	874
Investment gains — net			1,293				1,222
Miscellaneous			6				12
Total other income		$	1,690			$	2,108
Other expense:
Non-operating costs		$	(1,444	)		$	(1,794	)
Miscellaneous			(255	)			(902	)
Total other expense		$	(1,699	)		$	(2,696	)

12. Guarantees and Surety Bonds

We have issued parental guarantees and obtained surety bonds on behalf of our subsidiaries, including credit support instruments enabling APSES to offer energy-related products and surety bonds at APS, principally related to self-insured workers’ compensation. Non-performance or non-payment under the underlying contract by our subsidiaries would result in a payment liability on our part under the guarantee or surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets related to such instruments. At March 31, 2011, we had no outstanding claims for payment under any of these instruments. Our guarantees and surety bonds have no recourse or collateral provisions to allow us to recover amounts paid under these instruments. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at March 31, 2011 are as follows (dollars in millions):

		Guarantees								Surety Bonds
						Term								Term
		Amount				(in years)				Amount				(in years)
APSES		$	5				1			$	60				1
APS			4				1				9				1
Total		$	9							$	69

APS has entered into various agreements that require letters of credit for financial assurance purposes. At March 31, 2011, approximately $44 million of letters of credit were outstanding to support existing pollution control bonds of similar amount. The letters of credit are available to fund the payment of principal and interest of such debt obligations. These letters of credit expire in 2011 and 2013. APS has also entered into approximately $54 million of letters of credit to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 7 for further details on the Palo Verde sale leaseback transactions). These letters of credit were amended and extended in April 2010, and will expire in 2013.

We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements; most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.

13. Earnings Per Share

The following table presents earnings per weighted average common share outstanding for the three months ended March 31, 2011 and 2010:

		Three Months Ended
		March 31,
		2011				2010
Basic earnings per share:
Income (loss) from continuing operations attributable to common shareholders		$	(0.14	)		$	0.07
Loss from discontinued operations			—				(0.13	)
Earnings per share — basic		$	(0.14	)		$	(0.06	)
Diluted earnings per share:
Income (loss) from continuing operations attributable to common shareholders		$	(0.14	)		$	0.07
Loss from discontinued operations			—				(0.13	)
Earnings per share — diluted		$	(0.14	)		$	(0.06	)

For the three months ended March 31, 2011 and 2010, the weighted average common shares outstanding were the same for both basic and diluted shares. Options to purchase 45,500 shares of common stock for the three-month period ended March 31, 2011, and 387,800 shares for the three-month period ended March 31, 2010 were outstanding but were excluded from the computation of diluted earnings per share because the options’ exercise prices were greater than the average market price of the common shares.

14. Discontinued Operations

SunCor (real estate segment) — In 2009, our real estate subsidiary, SunCor, began disposing of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to reduce its outstanding debt. All activity for the income statement and prior comparative period income statement amounts are included in discontinued operations. In 2010, SunCor recorded real estate impairment charges of $15 million in the first quarter. SunCor’s asset sales resulted in no gain for 2010. SunCor has approximately $3 million of assets on its balance sheet classified as assets held for sale which are included in other current assets at March 31, 2011.

APSES (other) — In 2010, our subsidiary, APSES, sold its district cooling business consisting of operations in downtown Phoenix, Tucson, and on certain Arizona State University campuses. As a result of the sale, we recorded an after-tax gain from discontinued operations of approximately $25 million in June 2010. Prior period income statement amounts related to this sale and the associated revenues and costs are reflected in discontinued operations in 2010.

The following table provides revenue, income (loss) before income taxes and income (loss) after taxes classified as discontinued operations in Pinnacle West’s Condensed Consolidated Statements of Income for the three months ended March 31, 2011 and 2010 (dollars in millions):

		Three Months Ended
		March 31,
		2011				2010
Revenue:
SunCor		$	1			$	9
APSES			—				4
Total revenue		$	1			$	13
Loss before taxes:		$	(1	)		$	(21	)
Loss after taxes (a):		$	—				(13	)

15. Fair Value Measurements

We disclose the fair value of certain assets and liabilities according to a fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are:

Level 1 — Quoted prices in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis. This category includes derivative instruments that are exchange-traded such as futures, cash equivalents invested in exchange-traded money market funds, exchange-traded equities, and nuclear decommissioning trust investments in Treasury securities.

Level 2 — Quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable. This category includes nonexchange-traded contracts such as forwards, options, and swaps. This category also includes investments in common and commingled funds that are redeemable and valued based on the funds’ net asset values.

Level 3 — Model-derived valuations with significant unobservable inputs that are supported by little or no market activity. Instruments in this category include long-dated derivative transactions where models are required due to the length of the transaction, options, transactions in locations where observable market data does not exist, and common and collective trusts with significant restrictions on our ability to transact in the fund. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. The primary valuation technique we use to calculate the fair value of contracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We maximize the use of observable inputs and minimize the use of unobservable inputs. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market transactions, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market transactions, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

Recurring Fair Value Measurements

We apply recurring fair value measurements to derivative instruments, nuclear decommissioning trusts, certain cash equivalents and plan assets held in our retirement and other benefit plans (see Note 8).

Cash Equivalents