Exhibit 99.8

Pinnacle West Capital Corporation
Earnings Variance Explanations
For Periods Ended June 30, 2003 and 2002

     This discussion explains the changes in our consolidated earnings for the three, six and twelve month periods ended June 30, 2003 and 2002. Condensed Consolidated Statements of Income for the three, six and twelve months ended June 30, 2003 and 2002 follow this discussion. We will file our Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2003 on or before August 14, 2003. We suggest this section be read in connection with the Pinnacle West Capital Corporation Annual Report on Form 10-K for the fiscal year ended December 31, 2002 and the Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2003. We have reclassified certain prior period amounts to conform to our current period presentation. Additional operating and financial statistics and a glossary of terms are available on our website (www.pinnaclewest.com).

Earnings Contributions By Subsidiary And Business Segment

     We have three principal business segments (determined by products, services and the regulatory environment):

• our regulated electricity segment, which consists of regulated traditional retail and wholesale electricity businesses and related activities and includes electricity generation, transmission and distribution;

• our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services’ commodity-related energy services; and

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

     The following tables summarize net income and segment details for the three, six and twelve months ended June 30, 2003 and the comparable prior periods for Pinnacle West and each of our subsidiaries (dollars in millions):

											Marketing and
	Total					Regulated Electricity					Trading					Real Estate (a)				Other
Three months ended
June 30,	2003		2002			2003		2002			2003		2002			2003		2002		2003			2002
Arizona Public Service (b)	$	43	$	64		$	41	$	64		$	2	$	—		$	—	$	—	$	—		$	—
Pinnacle West Energy (b)		2		1			2		1			—		—			—		—		—			—
APS Energy Services (c)		5		11			—		—			4		10			—		—		1			1
SunCor		2		2			—		—			—		—			2		2		—			—
El Dorado (c)		2		(3	)		—		—			—		—			—		—		2			(3	)
Parent company (c)		1		(6	)		—		(4	)		2		(1	)		—		—		(1	)		(1	)
Income (loss) from continuing operations		55		69			43		61			8		9			2		2		2			(3	)
Income from discontinued operations – net of tax		1		6			—		—			—		—			1		6		—			—
Net income (loss)	$	56	$	75		$	43	$	61		$	8	$	9		$	3	$	8	$	2		$	(3	)

													Marketing and
	Total						Regulated Electricity						Trading				Real Estate (a)				Other
Six months ended
June 30,	2003			2002			2003			2002			2003		2002		2003		2002		2003			2002
Arizona Public Service (b)	$	59		$	96		$	53		$	96		$	6	$	—	$	—	$	—	$	—		$	—
Pinnacle West Energy (b)		8			2			8			2			—		—		—		—		—			—
APS Energy Services (c)		13			13			—			—			10		11		—		—		3			2
SunCor		4			3			—			—			—		—		4		3		—			—
El Dorado (c)		5			(3	)		—			—			—		—		—		—		5			(3	)
Parent company (c)		(14	)		11			(12	)		(5	)		1		18		—		—		(3	)		(2	)
Income (loss) from continuing operations		75			122			49			93			17		29		4		3		5			(3	)
Income from discontinued operations – net of tax		6			7			—			—			—		—		6		7		—			—
Net income (loss)	$	81		$	129		$	49		$	93		$	17	$	29	$	10	$	10	$	5		$	(3	)

													Marketing and
	Total						Regulated Electricity						Trading						Real Estate (a)				Other (d)
Twelve months ended
June 30,	2003			2002			2003			2002			2003			2002			2003		2002		2003			2002
Arizona Public Service (b)	$	162		$	243		$	156		$	218		$	6		$	25		$	—	$	—	$	—		$	—
Pinnacle West Energy (b) (e)		(13	)		19			(15	)		19			2			—			—		—		—			—
APS Energy Services (c)		28			11			—			—			23			9			—		—		5			2
SunCor		10			6			—			—			—			—			10		6		—			—
El Dorado (c)		(47	)		(3	)		—			—			—			—			—		—		(47	)		(3	)
Parent company (c)		20			44			(15	)		(6	)		17			52			—		—		18			(2	)
Income (loss) from continuing operations		160			320			126			231			48			86			10		6		(24	)		(3	)
Income from discontinued operations – net of tax		8			7			—			—			—			—			8		7		—			—
Cumulative effect of change in accounting - net of tax (f) (g)		(66	)		(12	)		—			—			(66	)		(12	)		—		—		—			—
Net income (loss)	$	102		$	315		$	126		$	231		$	(18	)	$	74		$	18	$	13	$	(24	)	$	(3	)

(a)	See “Real Estate Activities” discussion below.
(b)	Consistent with APS’ October 2001 ACC filing, APS entered into contracts with its affiliates to buy power through June 2003. The contracts reflect a price based on the fully-dispatchable dedication of the Pinnacle West Energy generating assets to APS’ Native Load customers (customers receiving power under traditional cost-based rate regulation). Under the ACC Track B order, APS was required to solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. Pinnacle West Energy bid on and entered into a contract to supply most of these purchase power requirements in summer months through September 2006.
(c)	APS Energy Services’ net income prior to 2003 and El Dorado’s net income are primarily reported before income taxes. The income tax expense or benefit for these subsidiaries was recorded at the parent company.
(d)	Primarily includes activities related to El Dorado in the twelve months ended June 30, 2003, principally El Dorado’s investment in NAC Holding Inc. (NAC). For the twelve months ended June 30, 2003, we recorded a pretax loss of $47 million related to NAC contracts with two customers.
(e)	In the fourth quarter of 2002, Pinnacle West Energy recorded a charge related to the cancellation of Redhawk Units 3 and 4 of approximately $30 million after income taxes ($49 million pretax).
(f)	We recorded a $66 million after tax charge as of October 1, 2002 for the cumulative effect of a change in accounting for trading activities, for the early adoption of EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.”
(g)	APS recorded a $12 million after tax charge in July 2001 for the cumulative effect of a change in accounting for derivatives related to the adoption of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.”

2

Results of Operations

     General

     Throughout the following explanations of our results of operations, we refer to “gross margin.” With respect to our regulated electricity segment and our marketing and trading segment, gross margin refers to electric operating revenues less purchased power and fuel costs. Our real estate segment gross margin refers to real estate revenues less real estate operations costs of SunCor. Other gross margin refers to other operating revenues less other operating expenses, which includes El Dorado’s investment in NAC, which we began consolidating in our financial statements in July 2002. Other gross margin also includes amounts related to APS Energy Services’ energy consulting services.

     Operating Results – Three-month period ended June 30, 2003 compared with three-month period ended June 30, 2002

     Our consolidated net income for the three months ended June 30, 2003 was $56 million compared with $75 million for the prior year. The period-to-period decrease of $19 million was primarily due to (amounts after tax):

• $13 million of higher purchased power and fuel costs primarily due to higher hedged gas and power prices;

• $5 million of higher depreciation, operations and maintenance and net interest expense, net of decreased purchased power costs and increased generation sales other than Native Load, related to new power plants in service;

• $5 million of lower SunCor earnings contributions primarily due to the sale of a retail center in the prior year period which was reported as discontinued operations on the Condensed Consolidated Statements of Income, see “Real Estate Activities” below for further discussion;

• a $4 million earnings decrease due to a retail electricity price reduction;

• $4 million of higher operating costs primarily related to higher pension and other benefit costs;

• $3 million of higher depreciation expense primarily related to increased plant assets in service; and

• $1 million of miscellaneous factors, net.

     The above decreases were partially offset by (amounts after tax):

• $8 million of higher retail sales primarily due to customer growth, excluding weather effects;

• $4 million of lower regulatory asset amortization; and

• $4 million of higher income as a result of the absence of NAC losses in 2003.

3

     For additional details, see the following discussion.

     The major factors that increased (decreased) net income were as follows
(dollars in millions):

			Increase
			(Decrease)
Regulated electricity segment gross margin:
	Increased purchased power and fuel costs primarily due to higher hedged gas and power prices		$	(22	)
	Retail electricity price reduction effective July 1, 2002			(7	)
	Effects of weather on retail sales			(1	)
	Higher retail sales primarily due to customer growth, excluding weather effects			14
	Decreased purchased power costs due to new power plants in service			6
		Net decrease in regulated electricity segment gross margin		(10	)
Marketing and trading segment gross margin:
	Lower realized wholesale margins primarily due to lower unit margins, partially offset by higher volumes			(6	)
	Lower mark-to-market gains for future delivery due to lower market liquidity			(4	)
	Higher revenues related to the adoption of EITF 02-3			8
	Increased competitive retail sales in California by APS Energy Services			2
	Increase in generation sales other than Native Load due to higher sales volumes			1
		Net increase in marketing and trading segment gross margin		1
Net decrease in regulated electricity and marketing and trading segments’ gross margins				(9	)
Higher operations and maintenance expense related to increased pension and other benefit costs, new power plants in service and prior period reversal of APS Energy Services’ California reserve				(13	)
Higher interest expense and lower capitalized interest related to new power plants in service				(7	)
Higher depreciation and amortization primarily related to new power plants and increased plant assets, partially offset by lower regulatory asset amortization				(5	)
Higher income primarily related to the absence of NAC losses in 2003				7
Miscellaneous items, net				3
	Net decrease in income from continuing operations before income taxes			(24	)
Lower income taxes primarily due to lower income				10
	Net decrease in income from continuing operations			(14	)
Decrease in income from discontinued operations related to SunCor – net of income tax (see “Real Estate Activities” below)				(5	)
	Net decrease in net income		$	(19	)

4

Regulated Electricity Segment Gross Margin

     Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $10 million higher in the three months ended June 30, 2003, compared with the same period in the prior year as a result of:

• a $7 million decrease in retail revenues related to a reduction in retail electricity prices;

• a $20 million increase in retail revenues related to customer growth, excluding weather effects;

• a $2 million decrease in retail revenues related to weather; and

• a $1 million net decrease due to other miscellaneous factors.

     Regulated electricity segment purchased power and fuel costs were $20 million higher in the three months ended June 30, 2003, compared with the same period in the prior year as a result of:

• a $22 million increase in purchased power and fuel costs primarily due to higher hedged gas and power prices;

• a $6 million increase related to customer growth, excluding weather effects;

• a $1 million decrease related to the effects of weather on retail sales;

• a $6 million decrease in purchased power costs due to new power plants in service; and

• a $1 million decrease due to other miscellaneous factors.

Marketing and Trading Segment Gross Margin

     Marketing and trading segment revenues were $118 million higher in the three months ended June 30, 2003, compared with the same period in the prior year as a result of:

• $77 million of higher realized wholesale revenues primarily due to higher volumes and higher prices;

• $2 million in lower mark-to-market gains for future delivery primarily as a result of lower market liquidity;

• $8 million of higher revenues related to the adoption of EITF 02-3;

• a $17 million increase from higher competitive retail sales in California by APS Energy Services; and

• an $18 million increase from generation sales other than Native Load primarily due to higher sales volumes and higher prices.

     Marketing and trading segment purchased power and fuel costs were $117 million higher in the three months ended June 30, 2003, compared to the same period in the prior year as a result of:

• an $83 million increase in purchased power costs related to other realized marketing activities in the current period primarily due to higher volumes and higher prices;

• a $2 million increase in mark-to-market fuel costs for future delivery;

• a $15 million increase in purchased power costs related to higher competitive retail sales in California by APS Energy Services; and

• a $17 million increase in fuel costs related to generation sales other than Native Load primarily because of higher natural gas prices and higher sales volumes.

5

Other Income Statement Items

     The increase in operations and maintenance expense of $13 million was due to increased pension and other benefit costs, new power plants in service, a prior period reversal of APS Energy Services’ California reserve and other costs.

     Net interest expense increased $7 million primarily because of higher debt balances and lower capitalized interest related to our generation construction program, including completion of Redhawk Units 1 and 2 in mid-2002.

     The increase in depreciation and amortization expense of $5 million primarily related to increased plant assets and new power plants, partially offset by lower regulatory asset amortization.

     The increase in other gross margin of $2 million was primarily due to increased NAC gross margins.

     The decrease in other expense of $8 million primarily related to the absence of NAC losses of $6 million in 2003 and lower other expenses.

     The increase in real estate segment gross margin of $2 million was primarily due to higher home sales. In addition, in the 2003 period, discontinued operations of $1 million after tax primarily related to SunCor’s sale of its water utility company. In the 2002 period, discontinued operations of $6 million after tax primarily related to SunCor’s sale of a retail center (see “Real Estate Activities” below).

     Operating Results – Six-month period ended June 30, 2003 compared with six-month period ended June 30, 2002

     Our consolidated net income for the six months ended June 30, 2003 was $81 million compared with $129 million for the prior year. Both periods include income from discontinued operations related to our real estate segment. The period-to-period decrease of $48 million was primarily due to (amounts after tax):

• $20 million of lower earnings contributions from our marketing and trading activities, reflecting lower liquidity and higher price volatility in the wholesale power markets in the western United States, partially offset by higher revenues related to the adoption of EITF 02-3;

• $16 million of higher depreciation, operations and maintenance and net interest expense, net of decreased purchased power costs and increased generation sales other than Native Load, related to new power plants in service;

• $14 million of higher purchased power and fuel costs primarily due to higher hedged gas and power prices;

• $8 million of higher operating costs primarily related to higher pension and other benefit costs;

6

• a $7 million earnings decrease due to a retail electricity price reduction;

• $7 million of higher depreciation expense related to increased plant assets in service;

• $4 million from the effects of weather on retail sales; and

• $6 million of miscellaneous factors, net.

     The above decreases were partially offset by (amounts after tax):

• $13 million of higher retail sales primarily due to customer growth, excluding weather effects;

• $8 million of lower regulatory asset amortization;

• $7 million related to the absence of NAC losses in 2003 and the current period settlement of an NAC contract dispute; and

• $6 million in higher competitive retail sales in California by APS Energy Services.

     For additional details, see the following discussion.

7

     The major factors that increased (decreased) net income were as follows
(dollars in millions):

			Increase
			(Decrease)
Regulated electricity segment gross margin:
	Increased purchased power and fuel costs primarily due to higher hedged gas and power prices		$	(23	)
	Retail electricity price reduction effective July 1, 2002			(12	)
	Effects of milder weather on retail sales			(7	)
	Higher retail sales volumes due to customer growth, excluding weather effects			21
	Decreased purchased power costs due to new power plants in service			3
		Net decrease in regulated electricity segment gross margin		(18	)
Marketing and trading segment gross margin:
	Lower realized wholesale margins primarily due to lower unit margins, partially offset by higher volumes			(30	)
	Lower mark-to-market gains for future delivery due to lower market liquidity and higher price volatility			(18	)
	Higher revenues related to the adoption of EITF 02-3			16
	Increased competitive retail sales in California by APS Energy Services			10
	Increase in generation sales other than Native Load due to higher sales volumes			2
		Net decrease in marketing and trading segment gross margin		(20	)
Net decrease in regulated electricity and marketing and trading segments’ gross margins				(38	)
Higher operations and maintenance expense related to increased pension and other benefit costs, new power plants in service and increased customer service costs				(28	)
Higher interest expense and lower capitalized interest primarily related to new power plants in service				(14	)
Higher depreciation and amortization primarily related to new power plants and increased plant assets, partially offset by lower regulatory asset amortization				(11	)
Higher income primarily related to the absence of NAC losses in 2003 and NAC’s settlement of a contract dispute recorded in the first quarter of 2003				11
	Miscellaneous factors, net			1
	Net decrease in income from continuing operations before income taxes			(79	)
Lower income taxes primarily due to lower income				32
	Net decrease in income from continuing operations			(47	)
Decrease in income from discontinued operations related to SunCor – net of income tax (see “Real Estate Activities” below)				(1	)
	Net decrease in net income		$	(48	)

8

Regulated Electricity Segment Gross Margin

     Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $15 million higher in the six months ended June 30, 2003, compared with the same period in the prior year as a result of:

• a $4 million increase related to traditional wholesale sales as a result of higher sales volumes and higher prices;

• a $12 million decrease in retail revenues related to a reduction in retail electricity prices;

• a $13 million decrease in retail revenues related to milder weather;

• a $34 million increase in retail revenues related to customer growth, excluding weather effects; and

• a $2 million net increase due to other miscellaneous factors.

     Regulated electricity segment purchased power and fuel costs were $33 million higher in the six months ended June 30, 2003, compared with the same period in the prior year as a result of:

• a $4 million increase related to traditional wholesale sales as a result of higher sales volumes and higher prices;

• a $23 million increase in purchased power and fuel costs primarily due to higher hedged gas and power prices;

• a $6 million decrease related to the effects of milder weather on retail sales;

• a $13 million increase related to customer growth, excluding weather effects;

• a $3 million decrease in purchased power costs due to new power plants in service; and

• a $2 million net increase due to other miscellaneous factors.

Marketing and Trading Segment Gross Margin

     Marketing and trading segment revenues were $205 million higher in the six months ended June 30, 2003, compared with the same period in the prior year as a result of:

• $19 million in lower mark-to-market gains for future delivery primarily as a result of lower market liquidity and higher price volatility;

• $106 million of higher realized wholesale revenues primarily due to higher volumes;

• $16 million of higher revenues related to the adoption of EITF 02-3;

• a $48 million increase from higher competitive retail sales in California by APS Energy Services; and

• a $54 million increase from generation sales other than Native Load primarily due to higher prices and higher sales volumes.

     Marketing and trading segment purchased power and fuel costs were $225 million higher in the six months ended June 30, 2003, compared to the same period in the prior year as a result of:

• a $1 million decrease in mark-to-market fuel costs for future delivery;

• a $136 million increase in purchased power costs related to other realized marketing activities in the current period primarily due to higher volumes and higher prices;

9

• a $38 million increase in purchased power costs related to higher competitive retail sales in California by APS Energy Services; and

• a $52 million increase in fuel costs related to generation sales other than Native Load primarily because of higher natural gas prices and higher sales volumes.

Other Income Statement Items

     The increase in operations and maintenance expense of $28 million was due to increased pension and other benefit costs, new power plants in service and increased customer service costs.

     Net interest expense increased $14 million primarily because of higher debt balances and lower capitalized interest related to our generation construction program, including completion of Redhawk Units 1 and 2 in mid-2002.

     The increase in depreciation and amortization expense of $11 million primarily related to new power plants and increased plant assets, partially offset by lower regulatory asset amortization.

     The increase in other gross margin of $8 million was primarily due to NAC’s $5 million reversal of loss reserves related to the settlement of a contract.

     The decrease in other expense of $7 million primarily related to prior period NAC losses.

     Operating Results – Twelve-month period ended June 30, 2003 compared with twelve-month period ended June 30, 2002

     Our consolidated net income for the twelve months ended June 30, 2003 was $102 million compared with $315 million for the prior year. The period-to-period decrease of $213 million was primarily due to (amounts after tax):

• a $66 million charge for the cumulative effect of a change in accounting for trading activities for the early adoption of EITF 02-3 on October 1, 2002;

• $61 million of lower earnings contributions from our marketing and trading activities, reflecting lower liquidity and lower price volatility in the wholesale power markets in the western United States, partially offset by higher revenues related to the adoption of EITF 02-3;

• $37 million of higher purchased power and fuel prices primarily due to higher hedged gas and power prices;

• $34 million of higher operations and maintenance expenses related to the Redhawk Units 3 and 4 cancellation charge and 2002 severance costs, partially offset by lower generation reliability costs;

• $25 million in losses related to our investment in NAC;

• $19 million of higher depreciation, operations and maintenance and net interest expense, net of decreased purchased power costs and increased generation sales other than Native Load, related to new power plants in service;

10

• a $16 million earnings decrease due to two retail electricity price reductions;

• $14 million from the effects of milder weather on retail sales;

• $12 million of depreciation expense related to increased plant assets in service;

• $11 million of higher pension and other benefit costs; and

• $3 million of miscellaneous factors, net.

     The above decreases were partially offset by (amounts after tax):

• $26 million of higher retail sales primarily due to customer growth, excluding weather effects;

• $17 million in higher competitive retail sales in California by APS Energy Services;

• $17 million of lower regulatory asset amortization;

• $13 million of 2001 charges related to Enron and its affiliates; and

• a $12 million charge for the cumulative effect of a change in accounting for derivatives, as required by SFAS No. 133, recorded in the twelve months ended June 30, 2002.

     For additional details, see the following discussion.

11

     The major factors that increased (decreased) net income were as follows (dollars in millions):

			Increase
			(Decrease)
Regulated electricity segment gross margin:
	Increased purchased power and fuel costs primarily due to higher hedged gas and power prices		$	(61	)
	Retail electricity price reductions effective July 1, 2001 and July 1, 2002			(27	)
	Effects of milder weather on retail sales			(23	)
	Higher retail sales volumes due to customer growth, excluding weather effects			44
	Decreased purchased power due to new power plants in service			20
	2001 charges related to purchase power contracts with Enron			13
	Miscellaneous factors, net			5
		Net decrease in regulated electricity segment gross margin		(29	)
Marketing and trading segment gross margin:
	Lower mark-to-market gains for future delivery due to lower market liquidity and lower price volatility			(98	)
	Lower realized wholesale margins due to lower unit margins, partially offset by higher volumes			(30	)
	Increased competitive retail sales in California by APS Energy Services			28
	Higher revenues related to the adoption of EITF 02-3			25
	Increase in generation sales other than Native Load primarily due to higher sales volumes			8
	Change in prior period mark-to-market value related to trading with Enron			8
		Net decrease in marketing and trading segment gross margin		(59	)
Net decrease in regulated electricity and marketing and trading segments’ gross margins				(88	)
Higher operations and maintenance expense related primarily to a $47 million write-off of Redhawk Units 3 and 4, 2002 severance costs of approximately $36 million, increased pension and other benefit costs and new power plants in service, partially offset by lower generation reliability costs				(94	)
Lower income primarily related to NAC losses				(41	)
Higher interest expense and lower capitalized interest primarily related to new power plants in service				(30	)
Higher depreciation and amortization primarily related to new power plants and increased plant assets, partially offset by lower regulatory asset amortization				(17	)
Higher taxes other than income taxes due to increased property taxes on higher property balances				(6	)
Lower real estate segment gross margin primarily due to lower commercial and property management sales, partially offset by higher home sales				(4	)
Lower other expense primarily related to prior period non-operating costs				11
	Net decrease in income from continuing operations before income taxes			(269	)
Lower income taxes primarily due to lower income				109
	Net decrease in income from continuing operations			(160	)
Increase in income from discontinued operations related to SunCor – net of income tax (see “Real Estate Activities” below)				1
Increase due to cumulative effect of a change in accounting for derivatives – net of income tax				12
Decrease due to cumulative effect of a change in accounting for trading activities – net of income tax				(66	)
	Net decrease in net income		$	(213	)

12

Regulated Electricity Segment Gross Margin

     Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $259 million lower in the twelve months ended June 30, 2003, compared with the same period in the prior year as a result of:

• an $18 million increase related to traditional wholesale sales as a result of higher prices and higher sales volumes;

• a $281 million decrease related to retail load hedge management wholesale sales primarily as a result of lower prices and lower sales volumes;

• a $27 million decrease in retail revenues related to reductions in retail electricity prices;

• a $37 million decrease in retail revenues related to milder weather;

• a $63 million increase in retail revenues related to customer growth and higher average usage, excluding weather effects; and

• a $5 million net increase due to other miscellaneous factors.

     Regulated electricity segment purchased power and fuel costs were $230 million lower in the twelve months ended June 30, 2003, compared with the same period in the prior year as a result of:

• an $18 million increase related to traditional wholesale sales as a result of higher prices and higher sales volumes;

• a $257 million decrease related to retail load hedge management wholesale sales primarily as a result of lower prices and lower sales volumes;

• a $37 million increase in purchased power and fuel costs due to higher hedged gas and power prices;

• a $14 million decrease related to the effects of milder weather on retail sales;

• a $19 million increase related to customer growth, excluding weather effects;

• a $13 million net decrease for charges in 2001 related to purchased power contracts with Enron and its affiliates; and

• a $20 million decrease in purchased power costs due to new power plants in service.

Marketing and Trading Segment Gross Margin

     Marketing and trading segment revenues were $247 million higher in the twelve months ended June 30, 2003, compared with the same period in the prior year as a result of:

• $98 million in lower mark-to-market gains for future delivery primarily as a result of lower market liquidity and lower price volatility;

• $117 million of higher realized wholesale revenues primarily due to higher volumes, partially offset by lower prices;

• a $111 million increase from higher competitive retail sales in California by APS Energy Services;

• $25 million of higher revenues related to the adoption of EITF 02-3;

• an $84 million increase from generation sales other than Native Load primarily due to higher sales volumes and higher prices; and

• an $8 million increase due to the 2001 write-off of prior period mark-to-market value related to trading with Enron and its affiliates.

13

     Marketing and trading segment purchased power and fuel costs were $306 million higher in the twelve months ended June 30, 2003, compared to the same period in the prior year as a result of:

• a $147 million increase in purchased power costs related to other realized marketing activities in the current period primarily due to higher volumes and higher prices;

• an $83 million increase in purchased power costs related to higher competitive retail sales in California by APS Energy Services; and

• a $76 million increase in fuel costs related to generation sales other than Native Load primarily because of higher sales volumes and higher natural gas prices.

Other Income Statement Items

     The increase in operations and maintenance expense of $94 million was due to a $47 million write-off related to the cancellation of Redhawk Units 3 and 4, severance costs of $36 million related to a 2002 voluntary workforce reduction, increased pension and other benefit costs of $17 million, new power plants in service of $17 million and other costs of $1 million, partially offset by lower costs related to generation reliability of $25 million.

     The decrease in other gross margin of $37 million was primarily due to losses on El Dorado’s investment in NAC, partially offset by increased margin on APS Energy Services’ non-commodity sales. Total NAC losses for the twelve month period ended June 30, 2003 totaled approximately $47 million on a pretax basis and were primarily related to contracts with two customers. We reversed $5 million of loss reserves in the first quarter of 2003 related to NAC’s settlement of one of those contracts. We believe we have reserved our exposure with respect to these contracts in all material respects and, as a result, we consider these charges to be non-recurring.

     The decrease in other expense of $7 million is primarily related to the absence of NAC losses of $4 million in 2003 recorded as other expense and prior period non-operating costs.

     Net interest expense increased $30 million primarily because of higher debt balances related to our generation construction program and lower capitalized interest on our generation construction program due to completion of Redhawk Units 1 and 2 in mid-2002.

     The increase in depreciation and amortization expense of $17 million primarily related to new power plants and increased plant assets, partially offset by lower regulatory amortization.

     The increase in taxes other than income taxes of $6 million is primarily due to increased property taxes on higher property balances.

     The decrease in real estate segment gross margin of $4 million was primarily due to lower commercial and property management sales, partially offset by higher home sales activities. In addition, as discussed in “Real Estate Activities” below, SunCor had a $14 million ($8 million after tax) gain on the sale of its water utility company included in discontinued operations for the twelve months ended June 30, 2003 and a $12 million ($7 million after tax) gain related primarily to the sale of a retail center included in discontinued operations in the twelve months ended June 30, 2002.

14

Real Estate Activities

     As discussed in our 2002 10-K, we have undertaken an aggressive effort to accelerate asset sales activities to approximately double SunCor’s annual earnings in 2003 to 2005 compared with the $19 million in earnings recorded in 2002.

     Certain components of SunCor’s real estate sales activities, which are included in the real estate segment, may be required to be reported as discontinued operations on our Condensed Consolidated Statements of Income in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Among other things, SFAS No. 144 prescribes accounting for discontinued operations and defines certain real estate activities as discontinued operations. We adopted SFAS No. 144 effective January 1, 2002 and determined that activities that would have required discontinued operations reporting in 2002, 2001 and 2000 were immaterial. We currently estimate that 15% to 30% of SunCor’s net income in 2003 will be reported in discontinued operations; however, this ultimately depends on the specific properties sold.

     In the first quarter of 2003, SunCor sold its water utility company, which resulted in an after tax gain of $5 million ($8 million pretax). The gain on the sale and operating income in the current and prior periods are classified as discontinued operations on our Condensed Consolidated Statements of Income.

     In the second quarter of 2002, SunCor sold a retail center, but maintained a significant continuing involvement through a management contract. In the first quarter of 2003, this management contract was canceled. As a result, the gain on the 2002 sale and the operating income related to this property have been reclassified as discontinued operations. The income from discontinued operations in the three, six and twelve months ended June 30, 2002 primarily reflects this sale.

     The following chart provides a summary of SunCor’s earnings (after income taxes) for the three, six and twelve months ended June 30, 2003 and the comparable prior periods (dollars in millions):

	Three Months				Six Months				Twelve Months
	Ended				Ended				Ended
	June 30,				June 30,				June 30,
	2003		2002		2003		2002		2003		2002
Income from continuing operations	$	2	$	2	$	4	$	3	$	10	$	6
Income from discontinued operations		1		6		6		7		8		7
Net income	$	3	$	8	$	10	$	10	$	18	$	13

Forward-Looking Statements

     This document contains forward-looking statements based on current expectations and we assume no obligation to update these statements or make any further statements on any of these issues, except as required by applicable law. These forward-looking statements are often identified by words such as “hope,” “may,” “believe,” “anticipate,” “plan,” “expect,” “require,” “intend,”

15

“assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by us. These factors include, but are not limited to, the ongoing restructuring of the electric industry, including the introduction of retail electric competition in Arizona and decisions impacting wholesale competition; the outcome of regulatory and legislative proceedings relating to the restructuring; state and federal regulatory and legislative decisions and actions, including the outcome of the rate case we filed with the ACC on June 27, 2003 and the wholesale electric price mitigation plan adopted by the FERC; regional economic and market conditions, including the results of litigation and other proceedings resulting from the California energy situation, volatile purchased power and fuel costs and the completion of generation and transmission construction in the region, which could affect customer growth and the cost of power supplies; the cost of debt and equity capital and access to capital markets; weather variations affecting local and regional customer energy usage; conservation programs; power plant performance; the successful completion of our generation construction program; regulatory issues associated with generation construction, such as permitting and licensing; our ability to compete successfully outside traditional regulated markets (including the wholesale market); our ability to manage our marketing and trading activities and the use of derivative contracts in our business; technological developments in the electric industry; the performance of the stock market, which affects the amount of our required contributions to our pension plan and nuclear decommissioning trust funds; the strength of the real estate market in SunCor’s market areas, which include Arizona, New Mexico and Utah; and other uncertainties, all of which are difficult to predict and many of which are beyond our control.

16

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(in thousands, except per share amounts)

			THREE MONTHS ENDED
			June 30,						Increase (Decrease)
			2003			2002			Amount			Percent
Operating Revenues
	Regulated electricity segment		$	506,632		$	496,838		$	9,794			2.0	%	B
	Marketing and trading segment			167,475			49,503			117,972			238.3	%	B
	Real estate segment			57,189			44,294			12,895			29.1	%	B
	Other revenues			26,187			2,881			23,306			809.0	%	B
		Total		757,483			593,516			163,967			27.6	%	B
Operating Expenses
	Regulated electricity segment purchased power and fuel			124,108			104,591			19,517			18.7	%	W
	Marketing and trading segment purchased power and fuel			147,698			30,479			117,219			384.6	%	W
	Operations and maintenance			141,519			128,996			12,523			9.7	%	W
	Real estate operations segment			53,942			42,532			11,410			26.8	%	W
	Depreciation and amortization			107,076			101,786			5,290			5.2	%	W
	Taxes other than income taxes			28,149			27,632			517			1.9	%	W
	Other expenses			22,509			1,668			20,841			1249.5	%	W
		Total		625,001			437,684			187,317			42.8	%	W
Operating Income				132,482			155,832			(23,350	)		15.0	%	W
Other
	Other income			2,698			3,987			(1,289	)		32.3	%	W
	Other expense			(5,157	)		(13,020	)		7,863			60.4	%	B
		Total		(2,459	)		(9,033	)		6,574			72.8	%	B
Interest Expense
	Interest charges			51,117			46,764			4,353			9.3	%	W
	Capitalized interest			(11,231	)		(13,908	)		2,677			19.2	%	W
		Total		39,886			32,856			7,030			21.4	%	W
Income From Continuing Operations Before Income Taxes				90,137			113,943			(23,806	)		20.9	%	W
Income Taxes				35,248			45,140			(9,892	)		21.9	%	B
Income From Continuing Operations				54,889			68,803			(13,914	)		20.2	%	W
Income From Discontinued Operations - Net of Income Tax Expense				1,253			6,562			(5,309	)		80.9	%	W
Net Income			$	56,142		$	75,365		$	(19,223	)		25.5	%	W
Weighted-Average Common Shares Outstanding - Basic				91,258			84,794			6,464			7.6	%
Weighted-Average Common Shares Outstanding - Diluted				91,450			84,926			6,524			7.7	%
Earnings Per Weighted-Average Common Share Outstanding
	Income From Continuing Operations - Basic		$	0.60		$	0.81		$	(0.21	)		25.9	%	W
	Net Income - Basic		$	0.62		$	0.89		$	(0.27	)		30.3	%	W
	Income From Continuing Operations - Diluted		$	0.60		$	0.81		$	(0.21	)		25.9	%	W
	Net Income - Diluted		$	0.61		$	0.89		$	(0.28	)		31.5	%	W

Certain prior year amounts have been restated to conform to the 2003 presentation.

          B — Better

          W — Worse

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(in thousands, except per share amounts)

		SIX MONTHS ENDED
		June 30,						Increase (Decrease)
		2003			2002			Amount			Percent
Operating Revenues
	Regulated electricity segment	$	891,592		$	877,079		$	14,513			1.7	%	B
	Marketing and trading segment		330,218			125,318			204,900			163.5	%	B
	Real estate segment		97,877			83,805			14,072			16.8	%	B
	Other revenues		41,758			7,158			34,600			483.4	%	B
	Total		1,361,445			1,093,360			268,085			24.5	%	B
Operating Expenses
	Regulated electricity segment purchased power and fuel		198,779			166,122			32,657			19.7	%	W
	Marketing and trading segment purchased power and fuel		291,343			66,264			225,079			339.7	%	W
	Operations and maintenance		274,636			246,426			28,210			11.4	%	W
	Real estate operations segment		94,101			79,178			14,923			18.8	%	W
	Depreciation and amortization		212,474			201,442			11,032			5.5	%	W
	Taxes other than income taxes		56,645			54,390			2,255			4.1	%	W
	Other expenses		31,730			4,970			26,760			538.4	%	W
	Total		1,159,708			818,792			340,916			41.6	%	W
Operating Income			201,737			274,568			(72,831	)		26.5	%	W
Other
	Other income		8,353			7,113			1,240			17.4	%	B
	Other expense		(9,288	)		(16,074	)		6,786			42.2	%	B
	Total		(935	)		(8,961	)		8,026			89.6	%	B
Interest Expense
	Interest charges		98,968			91,283			7,685			8.4	%	W
	Capitalized interest		(21,210	)		(27,767	)		6,557			23.6	%	W
	Total		77,758			63,516			14,242			22.4	%	W
Income From Continuing Operations Before Income Taxes			123,044			202,091			(79,047	)		39.1	%	W
Income Taxes			48,002			80,037			(32,035	)		40.0	%	B
Income From Continuing Operations			75,042			122,054			(47,012	)		38.5	%	W
Income From Discontinued Operations - Net of Income Tax Expense			6,398			7,068			(670	)		9.5	%	W
Net Income		$	81,440		$	129,122		$	(47,682	)		36.9	%	W
Weighted-Average Common Shares Outstanding - Basic			91,257			84,769			6,488			7.7	%
Weighted-Average Common Shares Outstanding - Diluted			91,402			84,910			6,492			7.6	%
Earnings Per Weighted-Average Common Share Outstanding
	Income From Continuing Operations - Basic	$	0.82		$	1.44		$	(0.62	)		43.1	%	W
	Net Income - Basic	$	0.89		$	1.52		$	(0.63	)		41.4	%	W
	Income From Continuing Operations - Diluted	$	0.82		$	1.44		$	(0.62	)		43.1	%	W
	Net Income - Diluted	$	0.89		$	1.52		$	(0.63	)		41.4	%	W

Certain prior year amounts have been restated to conform to the 2003 presentation.

          B — Better

          W — Worse

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(in thousands, except per share amounts)

		TWELVE MONTHS ENDED
		June 30,						Increase (Decrease)
		2003			2002			Amount			Percent
Operating Revenues
	Regulated electricity segment	$	2,027,536		$	2,287,043		$	(259,507	)		11.3	%	W
	Marketing and trading segment		530,831			284,412			246,419			86.6	%	B
	Real estate segment		215,153			187,924			27,229			14.5	%	B
	Other revenues		96,537			15,733			80,804			513.6	%	B
	Total		2,870,057			2,775,112			94,945			3.4	%	B
Operating Expenses
	Regulated electricity segment purchased power and fuel		532,200			762,536			(230,336	)		30.2	%	B
	Marketing and trading segment purchased power and fuel		419,118			113,332			305,786			269.8	%	W
	Operations and maintenance		612,748			519,132			93,616			18.0	%	W
	Real estate operations segment		200,848			169,195			31,653			18.7	%	W
	Depreciation and amortization		435,114			418,435			16,679			4.0	%	W
	Taxes other than income taxes		110,207			104,693			5,514			5.3	%	W
	Other expenses		131,719			13,854			117,865			850.8	%	W
	Total		2,441,954			2,101,177			340,777			16.2	%	W
Operating Income			428,103			673,935			(245,832	)		36.5	%	W
Other
	Other income		14,937			16,230			(1,293	)		8.0	%	W
	Other expense		(25,656	)		(33,146	)		7,490			22.6	%	B
	Total		(10,719	)		(16,916	)		6,197			36.6	%	B
Interest Expense
	Interest charges		195,197			180,533			14,664			8.1	%	W
	Capitalized interest		(37,192	)		(52,675	)		15,483			29.4	%	W
	Total		158,005			127,858			30,147			23.6	%	W
Income Before Continuing Operations Before Income Taxes			259,379			529,161			(269,782	)		51.0	%	W
Income Taxes			100,193			208,802			(108,609	)		52.0	%	B
Income From Continuing Operations			159,186			320,359			(161,173	)		50.3	%	W
Income From Discontinued Operations - Net of Income Tax Expense			8,285			7,068			1,217			17.2	%	B
Cumulative Effect of a Change in Accounting for Derivatives - Net of Income Tax Benefit			—			(12,446	)		12,446			100.0	%	B
Cumulative Effect of a Change in Accounting for Trading Activities - Net of Income Tax Benefit			(65,745	)		—			(65,745	)		100.0	%	W
Net Income		$	101,726		$	314,981		$	(213,255	)		67.7	%	W
Weighted-Average Common Shares Outstanding - Basic			88,121			84,734			3,387			4.0	%
Weighted-Average Common Shares Outstanding - Diluted			88,276			84,888			3,388			4.0	%
Earnings Per Weighted-Average Common Share Outstanding
	Income From Continuing Operations - Basic	$	1.81		$	3.78		$	(1.97	)		52.1	%	W
	Net Income - Basic	$	1.15		$	3.72		$	(2.57	)		69.1	%	W
	Income From Continuing Operations - Diluted	$	1.80		$	3.77		$	(1.97	)		52.3	%	W
	Net Income - Diluted	$	1.15		$	3.71		$	(2.56	)		69.0	%	W

Certain prior year amounts have been restated to conform to the 2003 presentation.
	B — Better
	W — Worse