1. Consolidation and Nature of Operations

The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, 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 (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 December 31, 2009 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. The December 31, 2009 condensed consolidated balance sheet data was derived from audited financial statements, but does not include disclosures required by GAAP for audited annual statements. This quarterly report should be reviewed in conjunction with the audited financial statements included in the 2009 Form 10-K. These condensed consolidated financial statements and notes have been prepared consistently with the 2009 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 amended accounting guidance on consolidation of variable interest entities (“VIEs”) (see Note 7). The following tables show the impacts of the reclassifications to prior year (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
		previously				accounting				for discontinued				discontinued
		reported				guidance				operations				operations
Statement of Income for the Three Months Ended June 30, 2009
Operating Revenues
Real estate segment		$	12,680			$	—			$	(12,680	)		$	—
Other revenues			10,782				—				(4,704	)			6,078
Operating Expenses
Real estate segment operations			19,429				—				(19,429	)			—
Real estate impairment charge			(4,062	)			—				4,062				—
Operations and maintenance			226,245				(9,914	)			(786	)			215,545
Depreciation and amortization			100,034				1,925				(979	)			100,980
Taxes other than income taxes			32,887				—				(121	)			32,766
Other expenses			7,733				—				(2,029	)			5,704
Other
Other income			6,608				—				(356	)			6,252
Interest Expense
Interest charges			58,863				3,338				(2,317	)			59,884
Allowance for borrowed funds used under construction			(3,311	)			—				86				(3,225	)
Income Taxes			39,579				—				1,421				41,000
Income From Continuing Operations			74,027				4,651				2,352				81,030
Loss From Discontinued Operations			(5,832	)			—				(2,352	)			(8,184	)
Net Income			68,195				4,651				—				72,846
Net Income (Loss) Attributable To Noncontrolling Interests			(152	)			4,651				—				4,499
Statement of Income for the Six Months Ended June 30, 2009
Operating Revenues
Real estate segment		$	27,520			$	—			$	(27,520	)		$	—
Other revenues			19,231				—				(8,353	)			10,878
Operating Expenses
Real estate segment operations			46,339				—				(46,339	)			—
Real estate impairment charge			204,418				—				(204,418	)			—
Operations and maintenance			433,776				(19,829	)			(1,576	)			412,371
Depreciation and amortization			199,920				3,851				(2,713	)			201,058
Taxes other than income taxes			67,015				—				(242	)			66,773
Other expenses			14,200				—				(3,371	)			10,829
Other
Other income			3,746				—				(454	)			3,292
Interest Expense
Interest charges			114,559				6,677				(4,088	)			117,148
Allowance for borrowed funds used under construction			(7,145	)			—				176				(6,969	)
Income Taxes			(55,425	)			—				83,241				27,816
Income (Loss) From Continuing Operations			(91,966	)			9,301				143,003				60,338
Loss From Discontinued Operations			(10,559	)			—				(143,003	)			(153,562	)
Net Loss			(102,525	)			9,301				—				(93,224	)
Net Loss Attributable To Noncontrolling Interests			(14,362	)			9,301				—				(5,061	)

						Reclassifications as a				Amount reported
						result of the adoption of				after adoption of
		As previously				new VIE accounting				amended VIE
		reported				guidance				accounting guidance
Balance Sheets — December 31, 2009
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

						Reclassifications as a				Amounts reported
						result of the adoption of				after adoption of
		As previously				the new VIE accounting				amended VIE
		reported				guidance				accounting guidance
Statement of Cash Flows for the Six Months Ended June 30, 2009
Cash Flows from Operating Activities
Net loss		$	(102,525	)		$	9,301			$	(93,224	)
Depreciation and amortization including nuclear fuel			218,939				3,851				222,790
Other current liabilities			(7,977	)			(7,818	)			(15,795	)
Other long-term assets			(8,025	)			2				(8,023	)
Other long-term liabilities			46,898				4,662				51,560
Cash Flows from Financing Activities
Repayment and acquisition of long-term debt			(195,767	)			(6,605	)			(202,372	)
Noncontrolling interests			—				(3,393	)			(3,393	)
Supplemental Disclosure of Cash Flow Information
Cash paid for Interest, Net of Amounts Capitalized			90,847				6,677				97,524

2. Long-term Debt and Liquidity Matters

The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements as of June 30, 2010 (dollars in millions):

		Consolidated				Consolidated
Year		Pinnacle West				APS
2010		$	271			$	181
2011			632				457
2012			478				478
2013			92				92
2014			503				503
Thereafter			1,816				1,816
Total		$	3,792			$	3,527

Credit Facilities, Debt and Equity 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 2010, Pinnacle West and APS refinanced existing revolving credit facilities that would have otherwise matured in December 2010. Since March 2010, Pinnacle West and APS have accessed the commercial paper markets, which neither company had utilized since the third quarter of 2008 due to negative market conditions.

Pinnacle West

On February 12, 2010, Pinnacle West refinanced its $283 million revolving credit facility that would have matured in December 2010, and decreased the size of the facility to $200 million. The new facility matures in February 2013. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Pinnacle West will use the facility for general corporate purposes, commercial paper support and for the issuance of letters of credit. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings. As a result of the downsized credit facility, the Company also reduced the size of its commercial paper program to $200 million from $250 million.

At June 30, 2010, the $200 million credit facility was available to support the issuance of up to $200 million in commercial paper or for bank borrowings, including issuances of letters of credit up to $100 million. At June 30, 2010, Pinnacle West had no outstanding borrowings under this credit facility, no commercial paper borrowings and no outstanding letters of credit.

In April 2010, Pinnacle West issued 6,900,000 shares of common stock at an offering price of $38.00 per share, resulting in net proceeds of approximately $253 million. Pinnacle West contributed all of the net proceeds from this offering into APS in the form of equity infusions. APS has used these contributions to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes.

In June 2010, Pinnacle West received approximately $100 million related to the sale of APSES’ district cooling business. The net proceeds were used to repay short-term indebtedness.

APS

On February 12, 2010, APS refinanced its $377 million credit facility that would have matured in December 2010, and increased the size of the facility to $500 million. The new credit facility terminates in February 2013. APS has the option to 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 support and for the issuance of letters of credit. Interest rates are based on APS’ senior unsecured debt credit ratings.

At June 30, 2010, APS had two credit facilities totaling $989 million, including the $500 million credit facility described above and a $489 million facility that terminates in September 2011. These facilities are available either to support the issuance of up to $250 million in commercial paper or for bank borrowings, including issuances of letters of credit up to $739 million. At June 30, 2010, APS had no borrowings outstanding under any of its credit facilities and no outstanding commercial paper. A $20 million letter of credit was issued under APS’ $489 million credit facility in the second quarter of 2010.

On July 13, 2010, APS changed the interest rate mode for the approximately $33 million of Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Bonds (Arizona Public Service Company Navajo Project) 1994 Series A, due 2029. The rate period for the bonds changed from a daily rate mode, supported by a letter of credit, to a three-year term rate mode that will bear interest at a rate of 3.625% per annum for three years. The letter of credit was terminated in connection with this change, and there is no bank or other third-party credit support for the bonds in the term rate mode.

On January 1, 2010, due to the adoption of amended accounting guidance relating to VIEs, APS began consolidating the Palo Verde Lessor Trusts (see Note 7) and, as a result of consolidation of these VIEs, APS has reported the Lessor Trusts’ long-term debt on its Condensed Consolidated Balance Sheets. Interest rates on these debt instruments are 8% and are fixed for the remaining life of the debt. As of June 30, 2010, approximately $30 million was classified as current maturities of long-term debt and $113 million was classified as long-term debt relating to these VIEs. These debt instruments mature on December 30, 2015 and have sinking fund features that are serviced by the lease payments. See Note 7 for additional discussion of the VIEs.

SunCor

In July, SunCor sold land parcels, commercial assets and a master planned home-building community for approximately $70 million, which approximated the carrying value of these assets, resulting in a net gain of zero. In connection with this sale, SunCor negotiated a restructuring of certain of its credit facilities, including its principal loan facility. The debt restructuring resulted in an after-tax gain of approximately $9 million, which will be recognized in the third quarter of 2010.

At June 30, 2010, SunCor had approximately $103 million of assets on its balance sheet classified as assets held for sale. These assets consisted of the $70 million of assets sold in July as discussed above, $25 million of consolidated VIEs (see Note 7), master planned home-building communities and golf courses. Because it is expected that SunCor will dispose of these assets within the next 12 months, they are classified as assets held for sale on the balance sheet.

At June 30, 2010, SunCor had $94 million of debt outstanding under various credit facilities, all of which was in default. After the sale and debt restructuring discussed above, $6 million remains outstanding. Neither Pinnacle West nor any of its other subsidiaries has guaranteed any SunCor indebtedness. A SunCor debt default would not result in a cross-default of any of the debt of Pinnacle West or any of its other subsidiaries. While there can be no assurances as to the ultimate outcome of this matter, Pinnacle West does not believe that SunCor’s inability to repay remaining debt outstanding would have a material adverse impact on Pinnacle West’s cash flows or liquidity.

As of June 30, 2010, SunCor could not transfer any cash dividends to Pinnacle West. This restriction does not affect Pinnacle West’s ability to meet its ongoing capital requirements.

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 common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At June 30, 2010, APS’ common equity ratio, as defined, was 52%. Its total shareholder equity was approximately $3.6 billion, and total capitalization was approximately $7.0 billion. APS would be prohibited from paying dividends if the payment would reduce its common equity below approximately $2.8 billion, assuming APS’ 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 (“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 contains 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’ next general rate case, if that is before the end of 2012), which resulted in projected estimates of increased revenues of $23 million, $25 million and $49 million, respectively;
	•		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 (see Note 2)); 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. APS currently expects it will file its next rate case in June 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 on 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 the upcoming year’s RES funding amount.

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 $86.7 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. The costs of the second 50 MW will be recovered through a mechanism to be determined in APS’ 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. Third party developers may also own systems that participate in the pilot. Costs of the program will be recovered through the RES until such time as the 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 $96.4 million. The 2011 Plan includes two components to address issues that have arisen in the past year: 1) enhancements to the residential distributed energy incentive program based on high customer participation; and 2) two programs offered in response to ACC workshops on “feed-in tariffs,” which provide opportunities for streamlined development of certain renewable projects. APS expects the ACC to vote on the 2011 Plan in the fourth quarter of 2010.

Demand-Side Management Adjustor Charge (“DSMAC”). The 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 $49.9 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 $78.9 million. If this plan is approved by the ACC as proposed, 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 $74.5 million over a twelve month period beginning March 1, 2011.

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 from the “Base Fuel Rate,” which is currently $0.0376 per kilowatt-hour (“kWh”). The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for the six-month periods ended June 30, 2010 and 2009 (dollars in millions):

		Six Months Ended
		June 30,
		2010				2009
Beginning balance		$	(87	)		$	8
Deferred fuel and purchased power costs-current period			(65	)			(13	)
Amounts refunded (recovered)			55				(66	)
Ending balance		$	(97	)		$	(71	)

The PSA rate for the current PSA Year is ($0.0045) per kWh. Since the 2010 PSA adjustment was a reduction of the PSA rate, the ACC accelerated the 2010 adjustment from the standard PSA year start date of February 1^st to January 1^st to coincide with the increase in retail rates resulting from the ACC’s decision in the general retail rate case, causing a minimal net impact on residential bills. This accelerated 2010 adjustment will remain in effect until February 1, 2011. The regulatory liability at June 30, 2010 reflects lower average prices and the seasonal nature of fuel and purchased power costs. Any uncollected (overcollected) deferrals during the 2010 PSA Year will be included in the historical component of the PSA rate for the PSA Year beginning February 1, 2011.

The PSA rate for the PSA Year that began February 1, 2009 was $0.0053 per kWh. The PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.

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’ 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 under the transmission cost adjustor (“TCA”) mechanism, by which changes in Retail Transmission Charges can be reflected in APS’ retail rates.

The formula rate is updated each year effective June 1 on the basis of APS’ actual cost of service, as disclosed in APS’ 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’ 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’ 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.

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.

On March 23, 2010, the President signed into law comprehensive health care reform legislation under the Patient Protection and Affordable Care Act (the “Act”). One feature of the Act is the elimination of the tax deduction for prescription drug costs that are reimbursed as part of the Medicare Part D subsidy. Although this tax increase does not take effect until 2013, we are required to recognize the full accounting impact in our financial statements in the period in which the Act is signed. In accordance with accounting for regulated companies, the loss of this deduction is substantially offset by a regulatory asset that will be recovered through future electric revenues. In the first quarter of 2010, Pinnacle West charged regulatory assets and liabilities for a total of $42 million, with a corresponding increase in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

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 or billed to electric plant participants) (dollars in millions):

		Pension Benefits																Other Benefits
		Three Months								Six Months								Three Months								Six Months
		Ended June 30,								Ended June 30,								Ended June 30,								Ended June 30,
		2010				2009				2010				2009				2010				2009				2010				2009
Service cost — benefits earned during the period		$	13			$	13			$	28			$	27			$	5			$	4			$	10			$	9
Interest cost on benefit obligation			30				30				61				59				10				9				21				19
Expected return on plan assets			(31	)			(29	)			(62	)			(58	)			(10	)			(8	)			(20	)			(17	)
Amortization of:
Transition obligation			—				—				—				—				(1	)			1				—				2
Prior service cost			—				—				1				1				—				—				—				—
Net actuarial loss			4				4				10				7				2				2				5				5
Net periodic benefit cost		$	16			$	18			$	38			$	36			$	6			$	8			$	16			$	18
Portion of cost charged to expense		$	8			$	9			$	19			$	17			$	3			$	4			$	8			$	9
APS’ share of cost charged to expense		$	8			$	8			$	19			$	16			$	3			$	4			$	8			$	8

Contributions

The required minimum contribution to our pension plan is zero in 2010. During the first quarter of 2010, we made a voluntary contribution of $100 million to our pension plan. The contribution to our other postretirement benefit plans in 2010 is estimated to be approximately $15 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 98% of both plans.

5. Business Segments

Pinnacle West’s two reportable business segments are:

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

In July, SunCor sold land parcels, commercial assets and a master planned home-building community. It is expected that SunCor will dispose of its remaining assets within the next 12 months. As a result, they are classified as assets held for sale on the balance sheet at June 30, 2010 and all of SunCor’s operations have been reclassified to discontinued operations. While segment reporting is not required for discontinued operations, Pinnacle West continues to provide the information below, due to the significant impacts of real estate impairments in 2009. See Note 14 — Discontinued Operations.

Financial data for the three and six months ended June 30, 2010 and 2009 and at June 30, 2010 and December 31, 2009 is provided as follows (dollars in millions):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2010				2009				2010				2009
Operating revenues:
Regulated electricity segment		$	800			$	813			$	1,411			$	1,415
All other (a)			21				6				30				11
Total		$	821			$	819			$	1,441			$	1,426
Net income (loss) attributable to common shareholders:
Regulated electricity segment		$	88			$	78			$	95			$	58
Real estate segment			(1	)			(9	)			(15	)			(140	)
All other (a)			28				(1	)			29				(6	)
Total		$	115			$	68			$	109			$	(88	)

		As of				As of
		June 30, 2010				December 31, 2009
Assets:
Regulated electricity segment		$	11,974			$	11,691
Real estate segment			115				161
All other (a)			69				134
Total		$	12,158			$	11,986

6. Income Taxes

Pinnacle West expects to receive approximately $132 million of cash tax benefits related to SunCor’s strategic asset sales (see Note 16), which will not be fully realized until all of the asset sales are completed. Approximately $7 million of these benefits were recorded in the six months ended June 30, 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 $65 million long-term income tax receivable on the Condensed Consolidated Balance Sheets represents the anticipated refunds related to an APS tax accounting method change approved by the Internal Revenue Service (“IRS”) in the third quarter of 2009.

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 $3.5 million which decreased our effective tax rate. Additionally, the settlement resulted in the recognition of net interest benefits of approximately $3 million through the effective tax rate.

As of June 30, 2010, 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.

7. Variable Interest Entities

On January 1, 2010 we adopted amended accounting guidance relating to 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, 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. Further discussion follows regarding the impact of the consolidation.

APS VIEs

In 1986, APS entered into agreements with three separate 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 2010 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 we are the operating agent for Palo Verde, are obligated to decommission the leased assets and have fair value purchase options.

Under the previous quantitative VIE consolidation model, APS was not considered the primary beneficiary of the lessor trusts, as APS did not absorb the majority of the entities’ expected losses or did not receive a majority of the residual returns. The arrangements were previously accounted for as operating leases.

Consolidation of these VIEs eliminates the lease accounting we previously reported 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. The creditors of the VIEs have no recourse to the assets of APS or Pinnacle West. As a result of consolidation we have eliminated rent expense, and have recognized depreciation and interest expense, resulting in an increase in net income for the three and six months ended June 30, 2010 of $5 million and of $10 million, respectively, 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 June 30, 2010 include the following amounts relating to the VIEs (in millions):

		June 30,
		2010
Property plant and equipment, net of accumulated depreciation		$	142
Long-term debt including current maturities			143
Equity- Noncontrolling interests			89

For regulatory ratemaking purposes the leases continue to be treated as operating leases, and as a result we have recorded a regulatory asset of $32 million as of June 30, 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 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 June 30, 2010, APS would have been required to pay the noncontrolling equity participants approximately $152 million and assume $143 million of debt. Since APS now consolidates the VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.

We also have certain long-term purchased power agreements to purchase substantially all of an entity’s output from a specified facility for a specified period. We have evaluated these arrangements under the VIE accounting guidance and have determined that these agreements do not represent variable interests. If these agreements had been deemed variable interests, we would not be considered the primary beneficiary, as we do not have the power to direct the entities’ activities in a manner that would significantly impact their economic performance and, therefore, would not consolidate the entities. The adoption of the amended accounting guidance has not changed how we account for these arrangements.

SunCor VIEs

SunCor is the primary beneficiary of certain land development trust arrangements and, accordingly, consolidates these VIEs. We have determined that SunCor is the primary beneficiary of these VIEs because SunCor controls the activities related to the development of the land held in the trusts. Our adoption of amended VIE accounting guidance has not changed our accounting treatment of the SunCor VIEs. Our Condensed Consolidated Balance Sheets reflect $25 million of assets and $25 million of noncontrolling equity interests relating to these arrangements at June 30, 2010. Our Condensed Consolidated Balance Sheets reflect $29 million of assets and $29 million of noncontrolling equity interests related to these arrangements at December 31, 2009. The assets relating to these VIEs consist strictly of land, all of which is restricted and may only be used for payment to the noncontrolling interests. We have not provided, and are not required to provide, financing or other financial support to these entities.

8. Derivative and Energy Trading 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.

Our derivative instruments are accounted for at fair value and are presented on the Condensed Consolidated Balance Sheets as “Assets/Liabilities from Risk Management Activities” (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 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 between 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 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 June 30, 2010, 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’ retail base rates attributable to fuel and purchased power costs (“Base Fuel Rate”), which is currently $0.0376 per kWh (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 June 30, 2010, we had the following outstanding gross notional amount of derivatives, which represent both purchases and sales (does not reflect net position):

Commodity		Quantity
Power			16,004,799			megawatt hours
Gas			166,950,111			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 and six months ended June 30, 2010 and 2009 (dollars in thousands):

				Three Months Ended								Six Months Ended
		Financial Statement		June 30,								June 30,
Commodity Contracts		Location		2010				2009				2010				2009
Amount of Gain (Loss) Recognized in AOCI on Derivative Instruments (Effective Portion)		Accumulated other comprehensive loss-derivative instruments		$	(8,588	)		$	5,554			$	(100,255	)		$	(132,994	)
Amount of Loss Reclassified from AOCI into Income (Effective Portion Realized)		Regulated electricity segment fuel and purchased power			(29,143	)			(47,964	)			(42,329	)			(73,330	)
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			11,899				(4,900	)			1,432				(3,908	)

During the next twelve months, we estimate that a net loss of $101 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 and six months ended June 30, 2010 and 2009 (dollars in thousands):

				Three Months Ended								Six Months Ended
		Financial Statement		June 30,								June 30,
Commodity Contracts		Location		2010				2009				2010				2009
Amount of Net Gain Recognized in Income from Derivative Instruments		Regulated electricity segment revenue		$	426			$	766			$	595			$	337
Amount of Net Gain (Loss) Recognized in Income from Derivative Instruments		Regulated electricity segment fuel and purchased power expense			(29,260	)			22,242				(64,228	)			(41,722	)
Total				$	(28,834	)		$	23,008			$	(63,633	)		$	(41,385	)

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 balance sheet. These amounts are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets. Amounts are as of June 30, 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		$	10			$	—			$	14			$	70			$	94
Liabilities			(188	)			(1,285	)			(115,010	)			(98,430	)			(214,913	)
Total hedging instruments			(178	)			(1,285	)			(114,996	)			(98,360	)			(214,819	)
Derivatives not designated as accounting hedging instruments:
Assets			36,271				45,490				38,470				33,213				153,444
Liabilities			(1,955	)			—				(101,349	)			(100,856	)			(204,160	)
Total non-hedging instruments			34,316				45,490				(62,879	)			(67,643	)			(50,716	)
Total derivatives			34,138				44,205				(177,875	)			(166,003	)			(265,535	)
Margin account			20,344				—				1,458				—				21,802
Collateral provided to counterparties			10,235				—				112,727				79,423				202,385
Collateral provided from counterparties			(4,500	)			—				(1,250	)			—				(5,750	)
Prepaid option premiums			(106	)			—				1,373				—				1,267
Balance Sheet Total		$	60,111			$	44,205			$	(63,567	)		$	(86,580	)		$	(45,831	)

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, 2009 (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		$	329			$	—			$	3,242			$	75			$	3,646
Liabilities			(3,436	)			(256	)			(72,899	)			(77,953	)			(154,544	)
Total hedging instruments			(3,107	)			(256	)			(69,657	)			(77,878	)			(150,898	)
Derivatives not designated as accounting hedging instruments:
Assets			31,220				29,807				34,645				44,631				140,303
Liabilities			(4,123	)			(696	)			(81,722	)			(71,408	)			(157,949	)
Total non-hedging instruments			27,097				29,111				(47,077	)			(26,777	)			(17,646	)
Total derivatives			23,990				28,855				(116,734	)			(104,655	)			(168,544	)
Margin account			8,643				—				12,464				104				21,211
Collateral provided to counterparties			17,986				—				49,412				42,108				109,506
Collateral provided from counterparties			—				—				(1,050	)			—				(1,050	)
Balance Sheet Total		$	50,619			$	28,855			$	(55,908	)		$	(62,443	)		$	(38,877	)

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 one counterparty for which our exposure represents approximately 34% of Pinnacle West’s $104 million of risk management assets as of June 30, 2010. This exposure relates to a long-term traditional wholesale contract with a counterparty that has 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 our 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 June 30, 2010 was $390 million, for which we had posted collateral of $192 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 rating were to fall below investment grade (below BBB- for Standard & Poor’s Ratings Services (“Standard & Poor’s”) or Fitch, Inc. (“Fitch”) or Baa3 for Moody’s Investors Service, Inc. (“Moody’s”)), which would be a violation of the credit rating provisions. If the investment grade contingent features underlying these agreements had been triggered on June 30, 2010, after off-setting asset positions under master netting arrangements we would have been required to post approximately an additional $90 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 $200 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 and six months ended June 30, 2010 and 2009 (dollars in thousands):

		Three Months Ended June 30, 2010												Three Months Ended June 30, 2009
		Common				Noncontrolling								Common				Noncontrolling
		Shareholders				Interests				Total				Shareholders				Interests				Total
Beginning balance, April 1		$	3,213,933			$	116,067			$	3,330,000			$	3,162,902			$	116,617			$	3,279,519
Net income			114,797				4,769				119,566				68,347				4,499				72,846
Other comprehensive income (loss):
Net unrealized gains (losses) on derivative instruments (a)			(8,588	)			—				(8,588	)			5,554				—				5,554
Net reclassification of realized losses to income (b)			29,143				—				29,143				47,964				—				47,964
Reclassification of pension and other postretirement benefits to income			1,362				—				1,362				1,253				—				1,253
Net unrealized losses related to pension and other postretirement benefits			(6,933	)			—				(6,933	)			(4,204	)			—				(4,204	)
Net income tax expense related to items of other comprehensive income (loss)			(5,914	)			—				(5,914	)			(19,844	)			—				(19,844	)
Total other comprehensive income			9,070				—				9,070				30,723				—				30,723
Total comprehensive income			123,867				4,769				128,636				99,070				4,499				103,569
Issuance of capital stock			255,480				—				255,480				2,717				—				2,717
Purchase of treasury stock, net of reissuances			—				—				—				5				—				5
Other (primarily stock compensation)			140				—				140				(4,820	)			—				(4,820	)
Dividends on common stock			(113,872	)			—				(113,872	)			(53,069	)			—				(53,069	)
Net capital activities by noncontrolling interests			—				(7,381	)			(7,381	)			—				(8,439	)			(8,439	)
Ending balance, June 30		$	3,479,548			$	113,455			$	3,593,003			$	3,206,805			$	112,677			$	3,319,482

		Six Months Ended June 30, 2010												Six Months Ended June 30, 2009
		Common				Noncontrolling								Common				Noncontrolling
		Shareholders				Interests				Total				Shareholders				Interests				Total
Beginning balance, January 1		$	3,316,109			$	111,895			$	3,428,004			$	3,445,979			$	124,990			$	3,570,969
Net income (loss)			108,783				9,886				118,669				(88,163	)			(5,061	)			(93,224	)
Other comprehensive income (loss):
Net unrealized losses on derivative instruments (a)			(100,255	)			—				(100,255	)			(132,994	)			—				(132,994	)
Net reclassification of realized losses to income (b)			42,329				—				42,329				73,330				—				73,330
Reclassification of pension and other postretirement benefits to income			2,755				—				2,755				2,506				—				2,506
Net unrealized losses related to pension and other postretirement benefits			(6,933	)			—				(6,933	)			(4,204	)			—				(4,204	)
Net income tax benefit related to items of other comprehensive income (loss)			24,511				—				24,511				24,157				—				24,157
Total other comprehensive loss			(37,593	)			—				(37,593	)			(37,205	)			—				(37,205	)
Total comprehensive income (loss)			71,190				9,886				81,076				(125,368	)			(5,061	)			(130,429	)
Issuance of capital stock			258,160				—				258,160				5,346				—				5,346
Purchase of treasury stock, net of reissuances			1,078				—				1,078				(1,546	)			—				(1,546	)
Other (primarily stock compensation)			142				—				142				(11,527	)			—				(11,527	)
Dividends on common stock			(167,131	)			—				(167,131	)			(106,079	)			—				(106,079	)
Net capital activities by noncontrolling interests			—				(8,326	)			(8,326	)			—				(7,252	)			(7,252	)
Ending balance, June 30		$	3,479,548			$	113,455			$	3,593,003			$	3,206,805			$	112,677			$	3,319,482