ML023100360

Part 8 of 10, Palo Verde, 2001 Annual Financial Report, Pinnacle West Capital Corporation Annual Report 2001

ML023100360
Person / Time
Site:	Palo Verde
Issue date:	10/30/2002
From:	Bauer S Arizona Public Service Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
102-04859-SAB/TNW/CJJ
Download: ML023100360 (64)

Text

dif*fer*en*ti*ate PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

PINNACLE WEST IS A PHOENIX-BASED COMPANY with consolidated assets of $8.0 billion and annual revenues of $4.6 billion.

Through our subsidiaries, we generate, sell and deliver electricity and energy related products and services to retail and wholesale customers in the western United States. We also develop residential, commercial and industrial real estate properties.

ABOUT THE COMPANY The logo at left is the mathematical symbol for differentiate.

Look for it throughout this report to learn what sets us apart.

DIFFERENTIATE: TO SET APART. THE THEME OF THIS YEARS ANNUAL REPORT.

CONTENTS 02 _ LETTER TO SHAREHOLDERS 06 _ COMPANY OVERVIEW 15 _ 2001 FINANCIAL STATEMENTS 60 _ BOARD OF DIRECTORS 61 _ OFFICERS 62 _ SHAREHOLDER INFORMATION INCOME HIGHLIGHTS Operating revenues

$ 4,551,373

$ 3,690,175

$ 2,423,353 23.3%

52.3%

Income from continuing operations 327,367 302,332 269,772 8.3%

12.1%

BALANCE SHEET HIGHLIGHTS Total assets year-end

$ 7,981,748

$ 7,162,985

$ 6,608,506 11.4%

8.4%

Common stock equity year-end

$ 2,499,323

$ 2,382,714

$ 2,205,733 4.9%

8.0%

PER SHARE HIGHLIGHTS Earnings per share from continuing operations - diluted 3.85 3.56 3.17 8.1%

12.3%

Dividends declared per share 1.525 1.425 1.325 7.0%

7.5%

Book value per share - year-end 29.46 28.09 26.00 4.9%

8.0%

STOCK PERFORMANCE Stock price per share - year-end 41.85 47.63 30.56 Stock price appreciation (12.1%)

55.8%

(27.9%)

Total return (9.0%)

61.8%

(25.1%)

Market capitalization - year-end

$ 3,549,924

$ 4,039,788

$ 2,592,462 (12.1%)

55.9%

FINANCIAL HIGHLIGHTS 2001 2000 1999 2001 2000 vs.

vs.

(dollars in thousands, except per share amounts) 2000 1999 Growth rate

p_1 FINANCIAL

• Our income from continuing operations of $327 million was the highest in our companys history.

• Earnings per share from continuing operations increased 8.1 percent in 2001 to $3.85 per diluted share of common stock.

• For the eighth consecutive year, we increased our annual dividend by 10 cents per share over the previous year.

• Our "ve-year annualized dividend growth rate for 1996 to 2001 was 9.8 percent - ranking in the top 20 percent of the electric utility industry.

• Our "ve-year annualized dividend growth rate for 1996 to 2001 was the second highest among U.S. utilities at 7.8 percent, compared with a negative growth rate for the rest of the industry.

OPERATIONAL

• APS retail service territory experienced customer growth of 3.7 percent - about three times the national average.

• APS lowered retail prices for the seventh time in eight years.

• For the 10th consecutive year, the Palo Verde Nuclear Generating Station was the nations number one power producer of any kind.

• Our Cholla, West Phoenix, Ocotillo and Saguaro fossil-fueled plants had their best years ever in terms of production.

• Pinnacle West Energy put Unit 4 of the West Phoenix Power Plant into operation, neared completion on Units 1 and 2 of the new Redhawk Power Plant, and broke ground on West Phoenix Unit 5.

OUR LONG-TERM STRATEGIES

• Deliver shareholders combined earnings and dividend growth that is above the industry average.

• Provide retail electricity customers reliable energy at stable prices.

• Capture retail electric growth opportunities and capitalize on opportunities in Western competitive markets as they develop.

• Build our generation portfolio consistent with our native load, cash "ow and market conditions.

• Manage purchases and sales of wholesale electricity and related commodities to limit risk and optimize usage of resources.

• Maintain the corporate discipline to focus on our long-term goals, while remaining agile enough to adapt to changing circumstances.

2001 HIGHLIGHTS MOVING FORWARD

p_2 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 Our direction going forward: Stay on plan.

Use what we have learned. Figure out answers to new questions - both known and unknown. Mix discipline with creativity. Stay agile.

As a company, we strive to remain "exible in the face of changing markets, yet unwavering in our commitments to increasing customer satis-faction and shareholder value. We stood like a rock on those commit-ments in 2001. Our cus-tomer satisfaction ratings have never been higher.

Our "nancial results have never been stronger.

Despite some hefty expenses last summer to ensure reliability, earnings from continuing oper-ations increased year-over-year by 8.1 percent.

Outstanding power marketing results and steady customer growth allowed us to improve earnings while providing customers with their seventh price decrease in eight years.

It may be hard to recall now - just 12 months later - how different the energy situation looked in 2001. In May 2001 the futures price for power delivered in August ended up ten times Augusts actual price. Our Power Marketing group steered through this volatility and produced outstanding results.

Our performance looks even better against the national and industry backdrop of a slowing economy and the missteps of some large compa-nies. We made different choices. We put our trust in real assets generating real electrons that travel over real wires into real homes and businesses.

Even as some of the fundamentals of our business change, this approach will not.

Our customer base continues to grow. Last year, APS experienced 3.7 percent customer growth - about three times the national average.

To meet this growing demand, we added a 120-megawatt unit at our West Phoenix plant - our "rst generation addition since 1988. This summer well add more than 1,000 megawatts at our new Redhawk facility, and next year well complete our West Phoenix expansion by "ring up another 530-megawatt unit. When these new gas-"red FROM WILLIAM J. POST, CHAIRMAN 2001...

Unprecedented electric price volatility...

Continued price decreases for our customers...

Bankruptcies of some of the industrys largest companies.

Our response:

We had one of the best "nancial years in our companys history.

To our shareholders:

p_3 units are completed, they will enhance our supply options by providing a balanced fuel mix of coal, nuclear and natural gas.

Equally important, weve recently received approval to build a new 500,000-volt transmis-sion line extending from the Palo Verde Switchyard to a new substation west of Phoenix.

This much-needed line will add to our system capacity, further strengthening our reliability.

With that, lets get right to the future. Looking ahead, I see opportunities in three signi"cant areas. First, although today we face tougher power markets and a slower economy, customer growth and wholesale market opportunities will prevail.

Second, weve taken on an important regulatory agenda. And third, evolutionary market develop-ments will determine the structure and substance of future electric competition.

THE POWER MARKET OPPORTUNITY For Pinnacle West, the key to mastering the power market challenge is risk management - one of our core strengths. Risk management is not just power marketing and trading, though that is key to our approach. We build in risk management from the bottom up by staying close to our core business, managing our exposure in new markets, growing generation in a disciplined manner, com-peting in regulatory arenas, adhering to tight "nancial guidelines and testing every action for impact on customers and shareholders.

Power Marketing is part of our parent compa-ny, which positions it uniquely to manage our enterprise-wide energy risk. Power Marketing supplements our existing resources with short-term purchases and reduces "nancial exposure with hedging techniques. By buying wholesale power to serve our retail customers, and selling available output from our generating facilities and other energy resources, this group optimizes results of energy markets and owned generation.

Weve been both calculating and aggressive with our power marketing. We calculate our risks in buying and selling power, striking a balance between moderate risk and the cost of hedging those risks. When opportunities arise, we move swiftly and aggressively to improve our positions.

Weve exceeded expectations in the past, and it is our intention to do so in the future.

Given the current depressed wholesale power prices, we expect lower gross margins from Power Marketing. On the other hand, we foresee lower expenditures for reliability and purchased power in 2002 - we wont have to spend the $140 million we spent in 2001 to ensure uninterrupted electric service for our customers.

While the Arizona economy is slowing some-what, it remains robust by comparison with the rest of the nation - and growth will continue. We expect to add customers at a rate of 3.2 percent in 2002, compared to the 3.7 to 4.2 percent of the last few years. Moving forward, this continued growth will drive our top-line revenues and strengthen our bottom-line results.

We also believe market volatility may increase in Western power markets later in the year. That could create trading opportunities, especially as we bring Redhawk Units 1 and 2 on line.

These new gas-"red units, with their greater ef"ciency in converting natural gas to electricity, will have a higher pro"t potential over the long run. Analysts refer to this margin as spark spread-the relationship between the price of natural gas and the price of wholesale power pro-duced from gas. While our generation capacity will remain close to the size of our native cus-tomer demand, these more ef"cient units will widen our power marketing options in the future.

Price caps - assuming they remain - present another challenge to power markets and to gener-ators and suppliers trying to negotiate those markets. At "rst, the soft price caps imposed last year had a dramatic effect on prices, treating the entire region as one pricing point, ignoring regional differences and transmission bottlenecks.

While price caps are benign in the current depressed market, over the long-term they will likely prevent price signals from attracting new capital and generation where they are needed.

Anticipating future regulatory impacts - from federal price caps to individual state actions - is the key to success in Western power markets.

THE REGULATORY OPPORTUNITY If our industry learned anything from California, it is that the public will not tolerate price volatility or low levels of reliability.

Regulators and politicians will act accordingly.

To avoid that situation in our state, last October we "led with the Arizona Corporation Commission (ACC) a plan designed to provide our APS customers with reliable electricity sup-plies at stable prices well into the future. This plan also permits a more deliberate approach to com-petitive markets in the Southwest.

Our plan doesnt change the substance of our 1999 Settlement Agreement, which provided rate decreases for customers through 2003, opened the door to competition for our retail customers and required that we transfer APS generation assets to a competitive subsidiary.

Our plan deals with current realities and pro-vides a sure path to meeting our states energy needs. The plan builds toward a robust wholesale market, supporting the move to competition rather than allowing the old rules to fail.

What were requesting is a modi"cation to one part of the ACC competition rules - a very important part that never measured up to expect-ed realities.

At the time the rules were put in place, the expectation was that the wholesale market would develop over the following years. As California has shown, the market hasnt developed as expect-ed and without change to the competition rules well be required in 2003 to obtain all APS customer power from the wholesale market.

Acquiring all of APS customer power needs in todays wholesale market is simply not possible.

Under our proposal, the competitive bidding would begin in 2003 with a 270-megawatt auc-tion. The same amount would be added each year through 2008. By that time, competitive bidding would supply at least 1,620 megawatts - nearly 25 percent - of APS customer needs. At that point, the market should be mature enough to supply that amount without distortion.

For our customers, this plan offers stable and predictable prices from a diversity of fuel sources, and reliability that cannot be obtained elsewhere in todays wholesale market. We have an obliga-tion to keep the lights on. Thats an obligation we accept and our customers expect us to keep. But without this or a similar plan, we think the cost of keeping the lights on will be more than our customers will want to pay.

For our shareholders, the plan provides a solid generation earnings platform plus the ability to sell extra capacity and energy in the wholesale market. The end result will be a generation com-ponent comprised of substantial owned assets, considerable earnings strength and opportunities for pro"t in the wholesale market.

For regulators, our reliability plan protects customers from price volatility and guarantees reliable power while preserving an orderly progression toward an increasingly competitive wholesale market in the Southwest.

During the Arizona restructuring debates, we were adamant about not divesting our power sta-tions and exposing APS customers to an untested wholesale market. It was clear, few customers

- and almost no residential and small business customers - had the technology or expertise to respond to real-time power prices, alter their usage and hedge their market risk. Dealing with market risk for our customers and shareholders is our job, and we expect to meet their demands.

As they consider our plan, the ACC - like many state commissions in the wake of the California experience - is taking another look at the existing competition rules. We cant say at this time how far this look will go. While the com-missioners have not indicated a need for sweeping change, they are prudently responding to the same environment and the same concerns that led us to propose our regulatory plan for reliability, price stability and competition.

THE MARKET STRUCTURE OPPORTUNITY The most signi"cant factor affecting future electric competition in the West is the sputtering development of the electric market structure.

This structure, both physical and "nancial, is beset by its complex composition - a collection of entities comprising state and federal regulators, federal agencies, public power, municipalities, industry associations and private companies all simultaneously operating to meet instantaneous customer demand.

This structure requires an extraordinary amount of coordination and distinguishes elec-tricity from any other commodity, making the development of a competitive electric wholesale market particularly dif"cult. Regulators - focused on the theme and promise of competition - did not fully consider the complexity of this process or the laws of physics and set up unworkable markets - or none at all.

This competitive theme camou"aged what, in substance, was increased and incomplete regula-tion. These regulatory efforts produced real world problems and reinforced movement toward even greater regulation. The dif"culties of many com-panies and the higher prices charged to California consumers can be traced to the imperfect market structures California created and regulators are now trying to correct through re-regulation.

p_4 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 We enjoyed solid customer growth and a growing economy.

p_5 This re-regulation goes beyond California to most of the Western states. When compounded with the signi"cant role public power plays in the West, the development of a robust competitive electric wholesale market will be slowed at best.

Public power owns approximately half of the generating and transmission resources in the Western grid. They are not regulated by the Federal Energy Regulatory Commission (FERC) and therefore arent required to comply with federal regulations concerning competitive market structures or operations. Although they currently participate in the interstate market, they can do so without regulatory interference, making the development of independent transmission organizations particularly challenging.

The FERC should support regional transmis-sion organizations (RTOs) such as our proposed WestConnect RTO. WestConnect, encompassing roughly the Southwest, recognizes regional differ-ences and state authority and complies with the FERCs requirements for RTOs. Public power is a part of it, and it is designed to interact effectively with other RTOs - addressing the so-called seams issue - while providing a "rm structure to enhance the competitive generation market.

As long as incomplete or unworkable themes continue to mark our industry and competitive power markets, the threat of re-regulation and potential loss of customer choice will loom over every regulatory proceeding.

HOW WE ARE DIFFERENT Last year was turbulent. There were challenges.

There were pitfalls. We set our company apart.

We were different. We prospered.

Were different because weve disregarded sim-ple assumptions and predictions about the future.

We realized deregulation didnt mean power prices had to drop or that markets would some-how satisfy hourly demands at reasonable prices.

We held on to our power plants. We established long-term power contracts. We kept control over costs. We protected customers by building power plants. We reduced our customers prices.

As we face challenges in 2002 and beyond, we enjoy some solid advantages. These include natu-ral advantages we recognize and build on. Our geographic location gives us seasonal diversity so that in typical years we have a favorable power exchange situation with the Northwest. We enjoy solid customer growth and a growing economy.

But these natural advantages are not as important as the ones weve created:

• an unwavering focus on customer satisfaction

• outstanding power plant operations

• an increasingly balanced fuel mix

• disciplined generation expansion roughly matching our native load growth

• a creative but risk-averse approach to power marketing These advantages support a strategy that is our de"nition of creating value: combined growth of earnings and dividends above the industry aver-age. Our advantages form a strategic mix we believe is unique and sustainable. Im con"dent the people of Pinnacle West will meet the com-plex challenges of the future. We have the skills, experience and intellectual capital to develop the answers and deliver shareholder value. We have, and we will.

William J. Post

p_6 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

$R,ES In 2001, we increased our annual dividend by 10 cents per share of common stock. Our "ve-year annualized dividend growth rate was about 8 percent, compared with a nega-tive growth rate for the industry as a whole.

We intend to grow our dividend by similar dollar amounts each year, steadily increasing the cash return to our shareholders and maintaining a pace ahead of our industry.

About half of the Companys earnings in 2001 came from power marketing and trad-ing activities. Our Power Marketing group managed a wholesale power market that peaked around $2 a kilowatt-hour; then, in just a few months, plummeted as low as two cents a kilowatt-hour.

A commitment to provide our customers reliable energy impacted 2001 earnings from APS, our electric utility. We spent more than

$140 million to ensure customers had reli-able power throughout the summer of 2001 and future summers. We dont foresee a need to repeat these expenses in 2002.

In its third year of operation, APS Energy Services (APSES), our competitive retail energy services af"liate, continued to carve a niche for itself by providing integrated solutions of commodity energy and energy-related products and services to commercial and industrial customers.

APSES is a relatively new company in an industry experiencing some stop-and-go reg-ulatory transitions, but was able to secure a number of pro"table multi-year contracts in the fourth quarter of 2001. These contracts allowed APSES to more than double its gross margin in 2001 while keeping operating expenses "at.

In early 2001, El Dorado, our investment subsidiary, sold a substantial portion of its holdings in a technology venture capital lim-ited partnership. By doing so, El Dorado is continuing a strategy of liquidating its exist-ing portfolio as quickly as prudent. Looking ahead, we expect El Dorado to make limited strategic investments in companies offering energy-related technologies and services.

In 2001, Pinnacle West produced near record earnings.

Our dividend growth over the last "ve years is number two industry-wide.

p_7 U,LTS

p_8 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001GrOw

p_9 Owth In 2001, APS experienced 3.7 percent cus-tomer growth - approximately three times the national average. Retail electricity sales increased 3.8 percent to 23.4 million megawatt-hours.

To keep pace with this growth, capital expendi-tures for our electricity delivery business rose to

$365 million in 2001.

In 2001, our Delivery group set records in con-struction activity. In just over a year, this group built eight distribution substations and three transmission substations. Before 1999, this group averaged two substations per year. In metropoli-tan Phoenix, Delivery installed 70 substation feeders. In a typical year, it adds 12 to 15.

This growing customer base also has increased energy demand. Pinnacle West Energy - our unregulated generation subsidiary - has built (and is currently building) new generation resources. In summer 2001, Pinnacle West Energy completed work on West Phoenix Unit 4, adding 120 megawatts to our capacity. The proj-ect came in ahead of schedule and under budget.

We also broke ground on West Phoenix Unit 5 -

a 530-megawatt addition - and Redhawk Units 1 and 2, which will add more than 1,000 megawatts when completed in mid-2002.

In 2001, SunCor, our real estate development subsidiary, broke ground on Hayden Ferry Lakeside, a mixed-use commercial project and the cornerstone of a high-pro"le development in Tempe, Ariz. When completed, the project will include business offices, restaurants, housing, entertainment and a hotel.

Moving forward, SunCor will continue efforts to geographically diversify itself by increasing home sales at its existing projects in Arizona, New Mexico and Utah, while initiating home sales at its new StoneRidge community in northern Arizona.

Last year, APS experienced 3.7 percent customer growth.

p_10 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 In the next "ve years, load growth is projected to increase nearly 30 percent. Considering these factors, it is clear that carefully planned genera-tion expansion which is consistent with our native load is a strategic investment. When completed, our new plants will provide us with a balanced fuel mix of nuclear, coal and natural gas. This bal-ance allows us "exibility in times of spiking wholesale prices or power shortages.

Initial electric competition rules for Arizona were adopted under the assumption that the market would provide enough energy to keep prices low and supply plentiful. This hasnt been the case. Weve seen deregulation fail - most notably in California.

In October 2001, we "led a plan with the Arizona Corporation Commission (ACC) requesting a variance from part of the ACCs elec-tric competition rules. Under existing ACC rules, beginning in early 2003, all of the generation load required to meet the demand of APS customers must come from the wholesale market, with 50 percent coming from a competitive bidding process. These rules were approved more than two years ago and wholesale market liquidity has not developed as was envisioned.

Our "ling supports a responsible transition to competition, while providing reliable power supplies to our customers at stable prices. It asks for a phase-in of competitive bidding of nearly 25 percent over a seven-year period, and approval of a long-term power purchase agreement between Pinnacle West and APS. This doesnt change our 1999 Settlement Agreement. We will continue to meet our commitments under that agreement, including lowering customer prices each year through 2003.

In October 2001, we "led a request with the Federal Energy Regulatory Commission (FERC) to form WestConnect, a for-pro"t regional trans-mission organization (RTO) made up of APS and other Southwestern transmission owners. If approved, WestConnect will be based on policies and procedures developed over the last four years by its predecessor - DesertSTAR, a previously proposed non-pro"t RTO.

The for-pro"t governance structure is designed to motivate innovation, ef"ciency and creativity in the operation of the Western transmission grid.

We believe its formation will preserve states rights but encourage regional cooperation, while allowing us to retain our transmission assets.

In the last two

years, our peak load demand has grown 15.3 percent.

In the next "ve years, load growth is projected to increase nearly 30 percent.

p_11 P N L I A N N G

p_12 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

p_13 Our region of the country continues to expand, and each year more customers count on us for reliable energy and fair prices. This responsibility is familiar - weve served this part of the country for more than 116 years.

While other Western utilities were raising customer prices, APS lowered retail rates for the seventh time since 1993. During that time, weve reduced electric prices by 13 percent and saved our customers more than $800 million - the largest cumulative rate decrease among all investor-owned electric companies in the nation.

Such price reductions are possible, in part, through the ef"cient performance of our power plants. Last year, the Palo Verde Nuclear Generating Station was the nations number one power producer for the 10th consecutive year -

generating nearly 29 billion kilowatt-hours of electricity at a cost of 1.30 cents per kilowatt-hour

- 30 percent below the estimated industry average of 1.86 cents per kilowatt-hour.

In 2001, our Cholla, West Phoenix, Ocotillo and Saguaro fossil-fueled plants each set records for total site generation - increasing production by a combined 7.2 percent.

This focus on performance resonates through-out all parts of our company and is re"ected in our recent customer satisfaction scores. In a 2001 survey, 85 percent of APS residential customers rated themselves as satis"ed or very satis"ed with their service from APS. In the same survey, 94 percent rated the reliability of our electricity as good, very good or excellent.

These numbers re"ect our ongoing efforts to take care of our customers. For example:

• The APS Call Center set a performance record in 2001 by handling 84 percent of customer calls within 20 seconds.

• Our focus on reliability was underlined when we restored power within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after a storm knocked out more than 100 trans-mission poles in Gila Bend, an Arizona town southwest of Phoenix.

• In 2001, we spent more than $140 million to ensure we could continue to meet the ener-gy needs of our customers.

The Better Business Bureau of Central and Northern Arizona recently presented us with its Business Ethics Award. Were proud of this honor.

It underscores our philosophy that areas such as financial integrity, business practices, safety, community involvement and environmental stewardship are not afterthoughts - theyre key ingredients in delivering value and de"ning who we are.

Customers count on us for reliable energy and fair prices.

PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 p_14 We have increased the type and extent of information we make available to investors to facilitate better understanding of our business performance and our "nancial results. The quality of our disclosure is a re"ection of who we are and our attitude about the need to be open and clear about our business operations and their effects on our "nancial results.

On our Web site - www.pinnaclewest.com - we provide con-siderable detail about our operating statistics and "nancial performance to complement our other reports.

All public companies will face tougher analysis and a demand for greater "nancial transparency to develop investor trust and con"dence. Changes in accounting standards, clos-RESULTS AND PERFORMANCE - A BETTER UNDERSTANDING er scrutiny by the SEC and rating agencies, and more rigor from investors and analysts seem inevitable. Such changes should result in more con"dence in numbers reported by cor-porate America. We welcome this trend.

Since our power marketing and trading activities have con-tributed signi"cantly to our bottom line in the last two years, we have expanded our disclosures to include more data on those operations. In addition to required disclosure in the "nancial statements and managements discussion of "nancial position and results of operations, some of the key data is explained below.

MARKETING AND TRADING GROSS MARGIN

SUMMARY

(a)

(millions of dollars, before income taxes) 2001 2000 REALIZED AND MARK-TO-MARKET COMPONENTS (b)

Current period effects Realized margin on delivered commodities Electricity Generation sales other than native load 79 54 Other electricity marketing and trading 119 69 Total electricity 198 123 Other commodities (14)

(9)

Total realized margin 184 114 Prior-period mark-to-market (gains) losses on contracts delivered during current period Electricity (15)

(2)

Other commodities 27 Charge related to trading activities with Enron and its af"liates (8)

Subtotal 6

(2)

Total current period effects 190 112 Change in mark-to-market gains (losses) for future period deliveries (c)

Electricity 146 7

Other commodities (19) 7 Total future period effects 127 14 Total gross margin before income taxes 317 126 BY COMMODITY SOLD OR TRADED Electricity 329 128 Other commodities (12)

(2)

Total gross margin before income taxes 317 126 ACCUMULATED MARK-TO-MARKET GAINS (LOSSES)

AT END OF YEAR (c) 138 11 (a) Gross margin equals electric operating revenues minus purchased power and fuel expenses, before income taxes.

(b) Generally accepted accounting principles (GAAP) require that the book value of certain contracts for sales or purchases of commodities be adjusted to re"ect changes in their fair value caused by changes in prevailing market prices. This process is called mark-to-market. Mark-to-market represents non-cash gains or losses.

(c) Essentially all of our marketing and trading activities are structured activities, meaning our portfolio of forward sales positions is hedged with a portfolio of forward purchases that protects the economic value of the sales transactions against market price changes.

Realized margins are cash gains or losses related to deliveries of commodity con-tracts in current period.

Due to high market prices in early 2001, sales of our generation to other utilities and power marketers con-tributed 43% of our realized marketing and trading margin.

Our mark-to-market value is substantially protected against future market price changes (c).

High and volatile market prices in 2001 enabled our marketing and trading activities to produce over 70%

higher contribution than in 2000.

58% of our marketing and trading margin was related to commodity contracts delivered during 2001.

When commodity contracts are delivered, gains or losses previously recorded through mark-to-market are reversed.

Accumulated gains at the end of 2001 are expected to be realized as follows: 31%

in 2002; 33% in 2003-2004; and the remainder thereafter.

p_15 2001 FINANCIAL STATEMENTS CONTENTS GLOSSARY 16 _ SELECTED CONSOLIDATED DATA 19 _ MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 32 _ REPORT OF MANAGEMENT AND INDEPENDENT AUDITORS REPORT 33 _ CONSOLIDATED STATEMENTS OF INCOME 34 _ CONSOLIDATED BALANCE SHEETS 36 _ CONSOLIDATED STATEMENTS OF CASH FLOWS 37 _ CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY 38 _ NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ACC - Arizona Corporation Commission ALJ - Administrative Law Judge CC&N - Certificate of Convenience and Necessity CHOLLA - Cholla Power Plant CITIZENS - Citizens Communications Company EITF - Emerging Issues Task Force FERC - United States Federal Energy Regulatory Commission FOUR CORNERS - Four Corners Power Plant ISO - California Independent System Operator ITC - Investment tax credit 1999 SETTLEMENT AGREEMENT - Settlement among APS and other parties related to the implementation of retail electric competition in Arizona NRC - United States Nuclear Regulatory Commission PALO VERDE - Palo Verde Nuclear Generating Station PPA - Purchase Power Agreement PX - California Power Exchange RULES - ACC retail electric competition rules SALT RIVER PROJECT - Salt River Project Agricultural Improvement and Power District

p_16 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 (a) Tax benefit stemming from the resolution of income tax matters related to a former subsidiary MeraBank, A Federal Savings Bank. See Note 4.

(b) Charges associated with a regulatory disallowance. See Note 3.

(c) Change in accounting standards related to derivatives. See Note 17.

SELECTED CONSOLIDATED DATA (dollars in thousands, except per share amounts) year ended December 31, 2001 2000 1999 1998 1997 OPERATING RESULTS Operating revenues Electric

$ 4,382,465

$ 3,531,810

$ 2,293,184

$ 2,006,398

$ 1,878,553 Real estate 168,908 158,365 130,169 124,188 116,473 Income from continuing operations 327,367 302,332 269,772 242,892 235,856 Discontinued operations (a) 38,000 Extraordinary charge -

net of income taxes (b)

(139,885)

Cumulative effect of change in accounting -

net of income taxes (c)

(15,201)

Net income 312,166 302,332 167,887 242,892 235,856 COMMON STOCK DATA Book value per share - year-end 29.46 28.09 26.00 25.50 23.90 Earnings (loss) per weighted average common share outstanding Continuing operations - basic 3.86 3.57 3.18 2.87 2.76 Discontinued operations 0.45 Extraordinary charge (1.65)

Cumulative effect of change in accounting (0.18)

Net income - basic 3.68 3.57 1.98 2.87 2.76 Continuing operations - diluted 3.85 3.56 3.17 2.85 2.74 Net income - diluted 3.68 3.56 1.97 2.85 2.74 Dividends declared per share 1.525 1.425 1.325 1.225 1.125 Indicated annual dividend rate per share -

year-end 1.60 1.50 1.40 1.30 1.20 Weighted-average common shares outstanding - basic 84,717,649 84,732,544 84,717,135 84,774,218 85,502,909 Weighted-average common shares outstanding - diluted 84,930,140 84,935,282 85,008,527 85,345,946 86,022,709 BALANCE SHEET DATA Total assets

$ 7,981,748

$ 7,162,985

$ 6,608,506

$ 6,824,546

$ 6,850,417 Liabilities and equity:

Long-term debt less current maturities

$ 2,673,078

$ 1,955,083

$ 2,206,052

$ 2,048,961

$ 2,244,248 Other liabilities 2,809,347 2,825,188 2,196,721 2,516,993 2,407,572 Total liabilities 5,482,425 4,780,271 4,402,773 4,565,954 4,651,820 Minority interests Non-redeemable preferred stock of APS 85,840 142,051 Redeemable preferred stock of APS 9,401 29,110 Common stock equity 2,499,323 2,382,714 2,205,733 2,163,351 2,027,436 Total liabilities and equity

$ 7,981,748

$ 7,162,985

$ 6,608,506

$ 6,824,546

$ 6,850,417

p_17 SELECTED CONSOLIDATED DATA (CONTINUED) (dollars in thousands, except per share amounts) year ended December 31, 2001 2000 1999 1998 1997 ELECTRIC OPERATING REVENUES Retail Residential 914,711 880,468 805,173 766,378 746,937 Business 952,627 935,214 911,449 889,244 873,232 Total retail 1,867,338 1,815,682 1,716,622 1,655,622 1,620,169 Wholesale revenue on delivered electricity:

Traditional contracts 73,305 120,618 60,486 58,184 63,027 Retail load hedge management 577,784 560,493 108,153 Marketing and trading - delivered:

Generation other than native load (a) 148,316 115,476 29,551 Other delivered electricity (a) 1,560,185 874,619 345,067 258,058 163,801 Total delivered marketing and trading 1,708,501 990,095 374,618 258,058 163,801 Total delivered wholesale electricity 2,359,590 1,671,206 543,257 316,242 226,828 Other marketing and trading:

Realized margins on delivered commodities other than electricity (13,646)

(8,789) 2,483 7,192 3,618 Prior period mark-to-market (gains) losses on contracts delivered during current period (1,059)

(2,079)

Change in mark-to-market for future period deliveries 126,580 13,831 975 Total other marketing and trading 111,875 2,963 3,458 7,192 3,618 Transmission for others 25,971 14,765 11,348 11,058 10,295 Other miscellaneous services 17,691 27,194 18,499 16,284 17,643 Total electric operating revenues

$ 4,382,465

$ 3,531,810

$ 2,293,184

$ 2,006,398

$ 1,878,553 (a) The break-out of generation other than native load is not available for 1997 through 1998.

p_18 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 DIVIDENDS DIVIDENDS PER PER 2001 HIGH LOW CLOSE SHARE 2000 HIGH LOW CLOSE SHARE 1st Quarter 47.96 39.06 45.87 0.375 1st Quarter 32.31 26.25 28.19 0.350 2nd Quarter 50.70 45.20 47.40 0.375 2nd Quarter 35.88 27.88 33.88 0.350 3rd Quarter 49.93 37.65 39.70 0.375 3rd Quarter 51.31 33.81 50.89 0.350 4th Quarter 43.50 38.00 41.85 0.400 4th Quarter 52.22 40.89 47.63 0.375 QUARTERLY STOCK PRICES AND DIVIDENDS PER SHARE Stock Symbol: PNW SELECTED CONSOLIDATED DATA (CONTINUED) (dollars in thousands, except per share amounts) year ended December 31, 2001 2000 1999 1998 1997 ELECTRIC SALES (MWh)

Retail:

Residential 10,334,860 9,780,680 8,774,822 8,310,689 7,970,309 Business 13,064,152 12,753,844 12,299,748 12,152,394 11,846,618 Total retail 23,399,012 22,534,524 21,074,570 20,463,083 19,816,927 Wholesale electricity delivered:

Traditional contracts 1,213,704 1,610,032 1,421,522 1,410,392 1,486,439 Retail load hedge management 3,039,905 6,673,658 630,945 Marketing and trading - delivered:

Generation other than native load (a) 1,387,860 1,494,299 1,267,349 Other delivered electricity (a) 14,612,997 12,219,368 12,374,018 8,906,999 7,747,134 Total delivered marketing and trading 16,000,857 13,713,667 13,641,367 8,906,999 7,747,134 Total delivered wholesale electricity 20,254,466 21,997,357 15,693,834 10,317,391 9,233,573 Total electric sales 43,653,478 44,531,881 36,768,404 30,780,474 29,050,500 ELECTRIC CUSTOMERS - AVERAGE Retail:

Residential 776,339 749,285 719,774 689,871 663,493 Business 98,198 94,128 90,496 87,831 84,576 Total retail 874,537 843,413 810,270 777,702 748,069 Wholesale 66 67 69 60 59 Total customers 874,603 843,480 810,339 777,762 748,128 (a) The break-out of generation other than native load is not available for 1997 through 1998.

See Managements Discussion and Analysis of Financial Condition and Results of Operations for a discussion of certain information in the tables above.

p_19 Affecting Our Financial Outlook, recent Arizona regulatory developments have raised uncertainty about the status and pace of retail electric competition in Arizona, including APS transfer of generation assets to Pinnacle West Energy.

BUSINESS SEGMENTS We have two principal business segments (determined by products, services and regulatory environment), which consist of regulated retail electricity business and related activities (retail business segment) and competitive business activities (marketing and trading segment). Our retail business segment currently includes activities related to electricity transmission and distribution, as well as electricity generation. Our marketing and trading segment currently includes activities related to wholesale marketing and trading, and APSES competitive energy services.

These reportable segments reflect a change in the reporting of our segment information. Before the fourth quarter of 2001, we had two segments (generation and delivery). The generation segment information combined our marketing and trading activities with our generation of electricity activities. The delivery segment included transmission and distribution activities.

In the fourth quarter, APS filed with the ACC a request for a proposed rule variance and approval of a purchase power agreement (see Note 3) that inherently views our business in the new reportable segments described as presented herein.

Internal management reporting has been changed to reflect this alignment. See Business Segments in Note 16 for more information about our business segments.

The following is a summary of net income by business segment for 2001, 2000, and 1999:

In this section, we explain the results of operations, general financial condition, and outlook for Pinnacle West Capital Corporation and our subsidiaries: Arizona Public Service Company (APS), Pinnacle West Energy Corporation (Pinnacle West Energy), APS Energy Services Company, Inc.

(APSES), SunCor Development Company (SunCor), and El Dorado Investment Company (El Dorado) including:

I the changes in our earnings from 2000 to 2001 and from 1999 to 2000; I our capital needs, liquidity and capital resources; I our marketing and trading activities; I our financial outlook; I our critical accounting policies I major factors that affect our financial outlook; and I our management of market risks.

OVERVIEW OF OUR BUSINESS Pinnacle West owns all of the outstanding common stock of APS. APS is Arizonas largest electric utility and provides either retail or wholesale electric service to substantially all of the state, with the major exceptions of the Tucson metro-politan area and about one-half of the Phoenix metropolitan area. APS also generates and, through our marketing and trading division, sells and delivers electricity to wholesale customers in the western United States.

Our other major subsidiaries are:

I Pinnacle West Energy, through which we conduct our unregulated electricity generation operations; I APSES, which provides commodity energy and energy-related products to key customers in competitive markets in the western United States; I SunCor, a developer of residential, commercial, and industrial real estate projects in Arizona, New Mexico, and Utah; and I El Dorado, an investment firm.

Pinnacle Wests marketing and trading division sells in the wholesale market APS and Pinnacle West Energy generation production output that is not needed for APS native load, which includes loads for retail customers and traditional cost-of-service wholesale customers. Subject to specified risk parameters established by our Board of Directors, the marketing and trading division also engages in activities to hedge purchases and sales of electricity, fuels, and emissions allowance and credits and to profit from market price movements. We explain in detail below the historical and prospective contribution of marketing and trading activities to our financial results.

APS is required to transfer its competitive electric assets and services to one or more corporate affiliates no later than December 31, 2002. Consistent with that requirement, APS has been addressing the legal and regulatory requirements necessary to complete the transfer of its generation assets to Pinnacle West Energy before that date. As we discuss in greater detail below under Business Outlook - Other Factors (dollars in millions) 2001 2000 1999 Retail 152 225 246 Marketing and trading 172 63 5

Other 3

14 19 Income from continuing operations 327 302 270 Income tax benefit from discontinued operations 38 Extraordinary charge -

net of income taxes (140)

Cumulative effect of change in accounting -

net of income taxes (15)

Net Income 312 302 168 MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Throughout this section, we refer to specific Notes in the Notes to Consolidated Financial Statements that begin on page 38. These Notes add further details to the discussion.

p_20 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 2001 Compared With 2000 Our consolidated net income for the year ended December 31, 2001 was $312 million compared with $302 million for the year ended December 31, 2000. In 2001, we recognized a $15 million after-tax loss in net income as a cumulative effect of a change in accounting for derivatives. See Note 17 for further discussion on accounting for derivatives.

Income from continuing operations for the year ended December 31, 2001 was $327 million compared with

$302 million for the year ended December 31, 2000.

The year-to-year comparison benefited from strong market-ing and trading results, including significant benefits in the 2001 third quarter from structured trading activities, and retail customer growth. These factors were partially offset by higher purchased power and fuel costs, due in part to increased power plant maintenance; generation reliability measures; continuing retail electricity price decreases; and a charge related to Enron and its affiliates.

RESULTS OF OPERATIONS The following is a summary of our net income by legal entity for 2001, 2000, and 1999:

INCREASE (dollars in millions)

(DECREASE)

Increases (decreases) in electric revenues, net of purchased power and fuel expense due to:

Marketing and trading activities:

Increase from generation sales other than native load due to higher market prices 25 Increase in other realized marketing and trading in current period primarily due to more transactions 45 Change in prior year period mark-to-market value for losses transferred to realized margin in current period 16 (a)

Change in prior period mark-to-market value related to trading with Enron and its affiliates (8)(b)

Increase in mark-to-market value related to future periods 113 (a)

Net increase in marketing and trading 191 Higher replacement power costs for plant outages related to higher market prices (70)

Retail price reductions (see Note 3)

(27)

Charges related to purchased power contracts with Enron and its affiliates (13)(b)

Higher retail sales primarily related to customer growth 35 Miscellaneous revenues 3

Total increase in revenues, net of purchased power and fuel expense 119 Decrease in real estate contributions (8)

Higher operations and maintenance expense related to 2001 generation reliability program (42)

Higher operations and maintenance expense related primarily to employee benefits, plant outage and maintenance; and other costs (38)

Lower net interest expense primarily due to higher capitalized interest 17 Higher other net expense (5)

Miscellaneous items, net 1

Net increase in income from continuing operations before income taxes 44 Higher income taxes primarily due to higher income (19)

Net increase in income from continuing operations 25 (a) Essentially all of our marketing and trading activities are structured activities. This means our portfolio of forward sales positions is hedged with a portfolio of forward purchases that protects the economic value of the sales transactions.

(b) We recorded charges totaling $21 million before income taxes for exposure to Enron and its affiliates in the fourth quarter of 2001.

(dollars in millions) 2001 2000 1999 APS 281 307 267 Pinnacle West Energy 18 (2)

APSES (10)

(13)

(9)

SunCor 3

11 6

El Dorado 2

11 Parent company (a) 35 (3)

(5)

Income from continuing operations 327 302 270 Income tax benefit from discontinued operations 38 Extraordinary charge -

net of income taxes (140)

Cumulative effect of change in accounting - net of income taxes (15)

Net income 312 302 168 (a) The 2001 amount primarily includes marketing and trading activities.

APS also includes some marketing and trading activities. (see Note 16 for further discussion of our business segments.)

The major factors that increased (decreased) income from continuing operations were as follows:

p_21 Electric operating revenues increased approximately $850 million because of:

I changes in marketing and trading revenues ($827 million, net increase):

I increased revenues related to generation sales other than native load as a result of higher average market prices ($32 million);

I increased realized revenues related to other marketing and trading in current period primarily due to more transactions ($681 million);

I decreased prior period mark-to-market value related to trading with Enron and its affiliates ($8 million);

I increased prior period mark-to-market value for losses transferred to realized margin in current period

($9 million);

I increased mark-to-market value for future periods primarily as a result of more forward sales volumes

($113 million);

I decreased revenues related to other wholesale sales and miscellaneous revenues as a result of sales volumes

($28 million);

I increased retail revenues primarily related to higher sales volumes primarily due to customer growth

($78 million); and I decreased retail revenues related to reductions in retail electricity prices ($27 million).

Purchased power and fuel expenses increased approximately

$731 million primarily because of:

I changes in marketing and trading purchased power and fuel costs ($636 million, net increase) due to:

I increased fuel costs related to generation sales other than native load as a result of higher fuel prices

($7 million);

I increased fuel and purchased power costs related to other realized marketing and trading in current period primarily due to more transactions ($636 million);

I decreased mark-to-market fuel costs related to accounting for derivatives ($7 million) (see Note 17)

I decreased costs related to other wholesale sales as a result of lower volumes ($31 million);

I higher replacement power costs primarily due to higher market prices and increased plant outages ($70 million),

including costs of $12 million related to a Palo Verde out-age extension to replace fuel control element assemblies; I higher costs related to retail sales volumes due to customer growth ($43 million); and I charges related to purchased power contracts with Enron and its affiliates ($13 million).

The decrease in real estate profits of $8 million resulted pri-marily from decreases in sales of land and homes by SunCor.

The increase in operations and maintenance expenses of $80 million primarily related to the 2001 generation summer reliability program (the addition of generating capability to enhance reliability for the summer of 2001 ($42 million)) and increased employee benefit costs, plant outage and mainte-nance, and other costs ($38 million). The comparison reflects Pinnacle Wests $10 million provision for our credit exposure related to the California energy situation, $5 million of which was recorded in the fourth quarter of 2000 and $5 million of which was recorded in the first quarter of 2001.

Net other expense increased $5 million primarily because of a change in the market value of El Dorados investment in a technology-related venture capital partnership in 2000 (see Note 1) and other non-operating costs partially offset by an insurance recovery of environmental remediation costs.

Interest expense decreased by $17 million primarily because of increased capitalized interest resulting from our generation expansion plan partially offset with higher interest expense due to higher debt balances.

2000 Compared With 1999 Our consolidated net income for the year ended December 31, 2000 was $302 million compared with $168 million for the year ended December 31, 1999. Our 2000 net income increased $134 million over 1999 primarily because of a

$140 million after-tax extraordinary charge that we recorded in 1999. This charge reflected a regulatory disallowance resulting from an ACC-approved Settlement Agreement related to the implementation of retail electric competition.

The resulting increase in our 2000 net income was partially offset by the absence of a $38 million income tax benefit from discontinued operations that we also recorded in 1999. See Regulatory Agreements below and Notes 1 and 3 for additional information about the 1999 Settlement Agreement and the resulting regulatory disallowance. See Note 4 for additional information about the income tax benefit from discontinued operations.

Income from continuing operations for the year ended December 31, 2000 was $302 million compared with $270 million for the year ended December 31, 1999. The year-to-year comparison benefited from strong wholesale and retail electric sales and real estate profits. These positive factors more than offset decreases resulting from the completion of ITC amortization in 1999, reductions in retail electricity prices, lower earnings from El Dorado, and miscellaneous factors. See Regulatory Agreements below and Note 3 for information on the price reductions. See Regulatory Agreements below and Note 4 for additional information about ITC amortization.

p_22 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 Electric operating revenues increased approximately $1.24 billion because of:

I changes in marketing and trading revenues ($616 million, net increase):

I increased revenues related to generation sales other than native load as a result of higher market prices

($86 million);

I increased realized revenues related to other marketing and trading in current period primarily due to more transactions and higher market prices ($519 million);

I decreased prior period mark-to-market value for gains transferred to realized margin in current period

($2 million);

I increased mark-to-market value for future periods primarily as a result of more forward sales volumes

($13 million);

I increased revenues related to increased volumes and higher market prices for other wholesale sales resulting from retail load hedging activities and miscellaneous revenues ($523 million);

I increased retail revenues primarily related to higher sales volumes due to customer growth ($127 million); and I decreased retail revenues related to reductions in retail electricity prices ($28 million).

Purchased power and fuel expenses increased approximately

$1.14 billion primarily due to:

I changes in marketing and trading purchased power and fuel costs ($507 million, increase) due to:

I increased fuel costs related to generation sales other than native load as a result of higher fuel prices

($39 million);

I increased fuel and purchased power costs related to other realized marketing and trading in current period primarily due to more transactions

($468 million);

I increased costs related to increased volumes and higher market prices for wholesale sales resulting from retail hedging activities ($513 million); and I higher costs related to retail sales volumes due to customer growth and increased fuel and purchased power prices

($118 million).

The increase in real estate profits of $13 million resulted pri-marily from increases in sales of land and homes by SunCor.

The increase in operations and maintenance expenses of $4 million primarily related to customer growth was substan-tially offset by $20 million of other items recorded in 1999.

The increase in depreciation and amortization of $11 million primarily related to higher plant in service balances offset by lower regulatory asset amortization.

Net other expense decreased $10 million primarily because of changes in 2000 in the market value of El Dorados investment in a technology-related venture capital partner-ship. See Note 1 for additional information about the valuation of El Dorados investments.

INCREASE (dollars in millions)

(DECREASE)

Increases (decreases) in electric revenues, net of purchased power and fuel expense due to:

Marketing and trading activities:

Increase from generation sales other than native load due to higher market prices 47 Increase in other realized marketing and trading in current period primarily due to more transactions 51 Change in prior year period mark-to-market value for gains transferred to realized margin in current period (2)(a)

Increase in mark-to-market value related to future periods 13 (a)

Net increase in marketing and trading 109 Retail price reductions (see Note 3)

(28)

Higher retail sales primarily related to customer growth 9

Miscellaneous revenues 10 Total increase in revenues, net of purchased power and fuel expense 100 Increase in real estate contributions 13 Higher operations and maintenance expense related primarily to customer growth substantially offset by $20 million of other items recorded in 1999 (4)

Higher other net expense primarily related to El Dorado (10)

Higher depreciation and amortization expense (11)

Miscellaneous items, net (3)

Net increase in income from continuing operations before income taxes 85 Higher income taxes due to higher income in 2000 and higher ITC amortization in 1999 (53)

Net increase in income from continuing operations 32 (a) Essentially all of our marketing and trading activities are structured activities. This means our portfolio of forward sales positions is hedged with a portfolio of forward purchases that protects the economic value of the sales transactions.

The major factors that increased (decreased) income from continuing operations were as follows:

p_23 Regulatory Agreements Regulatory agreements approved by the ACC affect the results of APS operations. The following discussion focuses on three agreements approved by the ACC, each of which included retail electricity price reductions:

I The 1999 Settlement Agreement to implement retail electric competition; I A 1996 agreement that accelerated the amortization of APS regulatory assets; and I A 1994 settlement that accelerated the amortization of APS deferred ITCs.

1999 Settlement Agreement As part of the 1999 Settlement Agreement, APS agreed to reduce retail electricity prices for standard-offer, full-service customers with loads less than three megawatts in a series of annual decreases of 1.5% on July 1, 1999 through July 1, 2003, for a total of 7.5%. The first reduction of approximately $24 million ($14 million after income taxes) included the July 1, 1999 retail price decrease required by the 1996 regulatory agreement (see below). For customers having loads three megawatts or greater, standard-offer rates will be reduced in annual increments that total 5% in the years 1999 through 2002.

The 1999 Settlement Agreement also removed, as a regulatory disallowance, $234 million before income taxes ($183 million net present value) from ongoing regulatory cash flows. APS recorded this regulatory disallowance as a net reduction of regulatory assets and reported it as a $140 million after-tax extraordinary charge on the 1999 income statement.

Under the 1996 regulatory agreement, APS was recovering substantially all of its regulatory assets through accelerated amortization over an eight-year period that would have ended June 30, 2004. For more details, see Note 1. The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions):

I $11 million annually ($7 million after income taxes),

or 0.7%, effective July 1, 1999 (as noted above, this reduction was included in the July 1, 1999 price reduction under the 1999 Settlement Agreement).

1994 Rate Settlement As part of a 1994 rate settlement, APS accelerated amortiza-tion of substantially all of its ITCs over a five-year period that ended on December 31, 1999. The amortization of ITCs decreased annual consolidated income tax expense by about $24 million. Beginning in 2000, no further benefits were reflected in income tax expense related to the accelera-tion of the ITCs (see Note 4).

LIQUIDITY AND CAPITAL RESOURCES Capital Needs and Resources Capital Expenditure Requirements The following table summarizes the actual capital expendi-tures for the year ended December 31, 2001 and estimated capital expenditures for the next three years.

1/1-6/30 1999 2000 2001 2002 2003 2004 TOTAL

$164

$158

$145

$115

$86

$18

$686 See Note 3 and Business Outlook - Electric Competition (Retail) below for additional information regarding the 1999 Settlement Agreement.

1996 Regulatory Agreement As part of the 1996 regulatory agreement, APS reduced its retail electricity prices by 3.4% effective July 1, 1996. This reduction decreased electric revenue by about $49 million annually ($29 million after income taxes). APS also agreed to share future cost savings with its customers during the term of this agreement, which resulted in the following additional retail price reductions:

I $18 million annually ($11 million after income taxes), or 1.2%, effective July 1, 1997; I $17 million annually ($10 million after income taxes), or 1.1%, effective July 1, 1998; and (ACTUAL)

(ESTIMATED)

(dollars in millions) 2001 2002 2003 2004 APS Delivery 354 $

349

$ 271

$ 280 Existing generation (a) 117 149 Subtotal 471 498 271 280 Pinnacle West Energy (b)

Generation expansion 533 411 255 113(e)

Existing generation(a) 107 99 Subtotal 533 411 362 212 SunCor (c) 80 79 48 52 Other (d) 45 35 15 16 Total

$1,129 $ 1,023

$ 696

$ 560 (a) Pursuant to the 1999 Settlement Agreement, APS is required to transfer its competitive electric assets and services no later than December 31, 2002.

(b)See Note 10 for further discussion of Pinnacle West Energys generation expansion program and Capital Resources and Cash Requirements - Pinnacle West Energy below.

(c)Consists primarily of capital expenditures for land development and retail and office building construction reflected in the Increase in real estate investments in the consolidated statements of cash flows.

(d)Primarily Pinnacle West and APSES.

(e)This amount does not include an expected reimbursement by Southern Nevada Water Authority (SNWA) of $100 million of these costs in 2004 in exchange for SNWAs purchase of a 25% interest in the Silverhawk project at that time.

APS and the other Palo Verde participants are currently con-sidering issues related to replacement of the steam generators in Units 1 and 3. Although a final determination of whether Units 1 and 3 will require steam generator replacement to operate over their current full licensed lives has not yet been made, APS and the other participants have approved an expenditure in 2002 to procure long lead-time materials for fabrication of a spare set of steam generators for either Unit 1 or 3. APS portion of this expenditure is approximately $7 million and is included in the estimated expenditures above.

p_24 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 This action will provide the Palo Verde participants an option to replace the steam generators at either Unit 1 or 3 as early as fall 2005 should they ultimately choose to do so.

If the participants decide to proceed with steam generator replacement at both Units 1 and 3, APS has estimated that its portion of the fabrication and installation costs and asso-ciated power uprate modifications would be approximately

$130 million over the next seven years, which will be funded with internally generated cash or external financings.

Existing generation capital expenditures are comprised of multiple improvements for our existing fossil and nuclear plants. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines, boilers, and environmental equipment. The increase in this category in 2002 is due primarily to Four Corners and various gas-fired units. The increased work on equipment is due to higher use of the units and also a stack replacement project for Four Corners Units 1 and 2. The existing generation also contains nuclear fuel expenditures of approximately $30 million annually in 2002, 2003 and 2004.

Delivery capital expenditures are comprised of transmission and distribution (T&D) infrastructure additions and upgrades, capital replacements, new customer construction, and related information systems and facility costs. Examples of the types of projects included in the forecast include T&D lines and substations, line extensions to new residential and commercial developments, and upgrades to customer information systems. In addition, we began several major transmission projects in 2001. These projects are periodic in nature and are driven by strong regional customer growth.

We expect to spend about $150 million on major transmis-sion projects during the 2002-2004 time frame.

Capital Resources and Cash Requirements The following table summarizes cash commitments for the year ended December 31, 2001 and estimated commit-ments for the next three years:

(ACTUAL)

(ESTIMATED)

(dollars in millions) 2001 2002 2003 2004 Long-term debt pay-ments (see Note 6)

APS 384 $

247

$ 205 Pinnacle West 213 276 216 SunCor 24 42 86 Total long-term debt payments 621 247 318 507 Operating leases pay-ments (see Note 8) 67 68 66 65 Fuel and purchase power commitments (see Note 10) 374 270 124 80 Total cash commitments

$ 1,062 $

585

$ 508

$ 652 Pinnacle West had available lines of credit in the amount of $250 million at December 31, 2001. APS had lines of credit available in the amount of $250 million at December 31, 2001. There was no outstanding balance on either the Pinnacle West or APS lines of credit at December 31, 2001.

Pinnacle West and APS project that these lines of credit will be available over the next three years. The lines of credit are anticipated to be renewed at their expiration dates. See Note 5 for further information on Pinnacle Wests and APS lines of credit.

SunCor had an available line of credit at December 31, 2001 in the amount of $140 million. This line of credit had an outstanding balance at December 31, 2001 of $128 million. SunCor projects that this line of credit will be available over the next three years. SunCor also anticipates renewing the line of credit at its expiration date. See Note 5 for further details on SunCors line of credit.

The parent company has issued parental guarantees and obtained surety bonds on behalf of its unregulated sub-sidiaries, primarily for Pinnacle West Energys expansion plans, which are reflected in the capital expenditure table above, and APSES retail and energy business.

APS has obtained approximately $500 million in letters of credit primarily to provide credit support for its variable rate tax-exempt bonds and its Palo Verde sale-leaseback transactions. Pinnacle West has obtained approximately

$40 million in letters of credit to provide credit support for Pinnacle West Energys generation expansion plans.

Pinnacle West and APS do not have ratings triggers in any of their debt agreements. Ratings triggers are provisions that would result in the acceleration of repayment obligations based upon a credit rating agency downgrade. Although those rating triggers appear in certain power marketing and trading agreements, their financial impacts are not expected to be significant.

APS first mortgage bondholders share a lien on substantially all utility plant assets (other than nuclear fuel, transportation equipment and other excluded assets). The mortgage bond indenture restricts the payment of common stock dividends under certain conditions. These conditions did not exist at December 31, 2001.

See the Companys consolidated debt structure in Note 6.

The parent company and our subsidiaries capital needs and resources are described as follows.

Pinnacle West (Parent Company)

During the past three years, our primary cash needs were for:

I dividends to our shareholders; I equity infusions into our subsidiaries; I interest payments; and I optional and mandatory repayment of principal on our long-term debt.

The equity infusions into our subsidiaries during the past three years included $50 million invested in APS in 1999.

p_25 This investment completed the funding of Pinnacle Wests commitment under the 1996 regulatory agreement (see Note 3) to infuse $50 million a year into APS ($200 million total) from 1996 through 1999. The investments into Pinnacle West Energy were $484 million in 2001 and $193 million in 2000 to fund portions of its capital expenditures for its generation expansion program.

Over the next three years, we anticipate that our cash needs will fall into these same categories. We expect our equity infusions into Pinnacle West Energy to continue as it invests in additional generating facilities (see Note 10) until it begins to finance its own construction needs.

Our primary sources of cash are dividends from APS, our marketing and trading operations, and external financing.

For the years 1999 through 2001, total dividends from APS were $510 million.

Our long-term debt at December 31, 2001 was $576 mil-lion compared with $238 million at December 31, 2000.

We had $235 million of borrowings outstanding on our commercial paper at December 31, 2001. Our debt repay-ment requirements for the parent company for the next three years are approximately: zero in 2002, $276 million in 2003, and $216 million in 2004.

On February 8, 2002, we issued $215 million of our 4.5%

Notes due 2004.

APS APS capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. APS pays for its capital requirements with cash from operations and, to the extent necessary, external financing. APS pays for its dividends to Pinnacle West with cash from operations.

During the period from 1999 through 2001, APS paid for substantially all of its capital expenditures with cash from operations. APS expects to do so in 2002 through 2004 with cash from operations and its own debt issuances.

See the capital expenditure table above for additional infor-mation regarding actual capital expenditures in 2001 and projected capital expenditures for the next three years.

During 2001, APS redeemed approximately $384 million of long-term debt, including premiums, with cash from operations and from the issuance of long-and short-term debt. APS long-term debt redemption requirements for the next three years are approximately: $247 million in 2002; zero in 2003; and $205 million in 2004. Based on market conditions and call provisions, APS may make optional redemptions of long-term debt from time to time.

As of December 31, 2001, APS had credit commitments from various banks totaling about $250 million, which were available either to support the issuance of commercial paper or to be used as bank borrowings. At the end of 2001, APS had about $171 million of commercial paper outstanding and no bank borrowings.

APS long-term debt was approximately $2.1 billion at December 31, 2001 and 2000 (see Note 6).

Although ACC financing orders establish maximum amounts of additional debt that APS may issue, APS does not expect these orders to limit its ability to meet its capital requirements.

On March 1, 2002, APS issued $375 million of 6.50%

Notes due 2012. On March 15, 2002, APS announced the redemption on April 15, 2002 of approximately $125 million of its First Mortgage Bonds, 8.75% series due 2024.

Pinnacle West Energy See Note 10 for a discussion of Pinnacle West Energys generation expansion plans. Pinnacle West Energy is currently funding its capital requirements through capital infusions from the parent. We finance those infusions through debt financing and internally generated cash, as Pinnacle West Energy develops and obtains additional generation assets. Pinnacle West Energy also expects to fund its capital requirements through internally generated cash and its own debt issuances. See the Capital Expenditures Table above for actual capital expenditures in 2001 and projected capital expenditures for the next three years.

Other Subsidiaries During the past three years, both SunCor and El Dorado funded all of their cash requirements with cash from operations and, in the case of SunCor, its own external financings. APSES funded its cash requirements with cash infusions from Pinnacle West.

SunCors capital needs consist primarily of capital expendi-tures for land development and retail and office building construction. See the Capital Expenditures Table above for actual capital expenditures in 2001 and projected capital expenditures for the next three years. SunCor expects to fund its capital requirements with cash from operations and external financings.

As of December 31, 2001, SunCor had a $140 million line of credit, under which $128 million of borrowings were outstanding. SunCors debt repayment obligations for the next three years are approximately: zero in 2002; $42 mil-lion in 2003; and $86 million in 2004.

El Dorado does not have any capital requirements over the next three years. El Dorado intends to focus on prudently realizing the value of its existing investments. El Dorados future investments are expected to be related to the energy sector.

APSES capital expenditures and other cash requirements are increasingly funded by operations, with some funding from cash infused by Pinnacle West. See the Capital Expendi-tures Table above regarding APSES capital expenditures.

See Notes 5 and 6 for additional information about outstanding lines of credit and long-term debt obligations.

p_26 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 CRITICAL ACCOUNTING POLICIES In preparing the financial statements in accordance with generally accepted accounting principles (GAAP), manage-ment must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosures at the date of the financial statements and during the reporting period. Some of those judgements can be subjective and complex, and actual results could differ from those estimates. Our most critical accounting policies include the determination of the appro-priate accounting for our derivative instruments, mark-to-market accounting and the impacts of regulatory accounting on our financial statements. See Note 1 for a discussion of these critical accounting policies.

OTHER ACCOUNTING MATTERS We prepare our financial statements in accordance with Statement of Financial Accounting Standards (SFAS) No.

71, Accounting for the Effects of Certain Types of Regulation. SFAS No. 71 requires a cost-based, rate-regu-lated enterprise to reflect the impact of regulatory decisions in its financial statements. As a result of the 1999 Settlement Agreement (see Regulatory Agreements above and Note 3), we discontinued the application of SFAS No.

71 for our generation operations. As a result, we tested the generation assets for impairment and determined that the generation assets were not impaired. Pursuant to the 1999 Settlement Agreement, we reported a regulatory disallowance ($140 million after income taxes) as an extra-ordinary charge on the 1999 consolidated income state-ment. See Note 1 for additional information on regulatory accounting and Note 3 for additional information on the 1999 Settlement Agreement.

Effective January 1, 2001, we adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheets and measure those instruments at fair value. Changes in the fair value of derivative financial instruments are either rec-ognized periodically in income or stockholders equity (as a component of other comprehensive income), depend-ing on whether or not the derivative meets specific hedge accounting criteria. Hedge effectiveness is measured based on the relative changes in fair value between the derivative contract and the hedged commodity over time. Any change in the fair value resulting from ineffectiveness is recognized immediately in net income. This new standard may result in additional volatility in our net income and other comprehensive income.

As a result of adopting SFAS No. 133 in 2001, we recorded a $15 million after-tax loss in consolidated net income and a $72 million after-tax gain in equity (as a component of other comprehensive income), both as a cumulative effect of a change in accounting principle. The loss primarily resulted from electricity options contracts. The gain resulted from unrealized gains on cash flow hedges. See Note 17 for further information on accounting for derivatives under SFAS No. 133, including discussion on new guidance effective on April 1, 2002.

In July 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. This Statement addresses financial accounting and reporting for acquired goodwill and other intangible assets and supersedes Accounting Principles Board Opinion No. 17, Intangible Assets.

This standard is effective for the year beginning January 1, 2002. We have no goodwill recorded in our consolidated balance sheets. The impacts of this new standard are not material to our consolidated financial statements.

The FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations in August 2001. The standard requires the estimated present value of the cost of decommis-sioning and certain other removal costs to be recorded as a liability, along with an offsetting plant asset when a decom-missioning or other removal obligation is incurred. We are currently evaluating the impacts of the new standard, which is effective for the year beginning January 1, 2003.

In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. This statement supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, and the accounting and reporting provisions for the disposal of a segment of a business. SFAS No. 144 is effective for the year beginning January 1, 2002. This standard does not impact our financial statements at adoption.

In 2001, the American Institute of Certified Public Accountants (AICPA) issued an exposure draft of a proposed Statement of Position (SOP), Accounting for Certain Costs Related to Property, Plant and Equipment (PP&E). This proposed SOP would create a project timeline framework for capitalizing costs related to PP&E construction, require that PP&E assets be accounted for at the component level and require administrative and general cost incurred in support of capital projects to be expensed in the current period. The AICPA plans to issue the final SOP in the fourth quarter of 2002. We are currently evaluating the impacts of the proposed SOP.

In 1986, APS entered into agreements with three separate special purpose entity (SPE) lessors in order to sell and lease back interests in Palo Verde Unit 2 (See Note 8). The leases are accounted for as operating leases in accordance with GAAP. In February 2002, the FASB discussed issues related to special purpose entities. It is expected that FASB will issue additional guidance on accounting for SPEs later this year. As a result of future FASB actions, we may be required to consolidate the Palo Verde SPEs in our financial state-ments. If consolidation is required, the assets and liabilities of the SPEs that relate to the sale-leaseback transactions would be reflected on our consolidated balance sheets. The SPE debt that is not reflected on our consolidated balance

p_27 sheets is approximately $300 million at December 31, 2001. Rating agencies have already considered this debt when evaluating our credit ratings.

BUSINESS OUTLOOK Financial Outlook We currently believe that it will be a challenge for us in 2002 to repeat our 2001 earnings. For 2001, our reported income from continuing operations was $327 million, or $3.85 per diluted share of common stock, and included charges totaling

$21 million before income taxes, or $0.15 per diluted share, that we do not expect to recur related to our exposure to Enron and its affiliates. Our earnings in 2002 are expected to be negatively affected by a significant decrease in the earnings contribution from our marketing and trading activities and retail electricity price decreases. These negative factors are expected to be substantially offset in 2002 by the absence of significant expenses for reliability and power plant outages that we incurred in 2001 that we do not expect to recur in 2002 and by retail customer growth, although the pace of growth is expected to be slower than in the past. These factors are described in more detail below.

In 2001, our marketing and trading activities contributed about one-half of our income from continuing operations before the Enron related charges. These activities are currently expected to provide about one-fourth of our earnings in 2002.

The drivers of such reduced earnings contributions from our marketing and trading activities in 2002 are significant reduc-tions in: wholesale market prices for electricity that occurred during 2001; wholesale market liquidity, which affects our ability to buy and resell electricity; and market volatility, which affects our ability to capture profitable structured trading activities. These reductions in regional market factors were due, in large part, to conservation measures in California and throughout the West; more generating plants in service in the West; lower natural gas prices; and the price mitigation plan that took effect in June 2001 as mandated by the FERC.

During 2001, in order to meet highest customer demand in APS history, we incurred significant expenses for our summer reliability program and for higher replacement power costs related to power plant outages. These efforts cost approxi-mately $140 million before income taxes, which is not expected to be repeated in 2002. See Results of Operations -

2001 Compared with 2000 above.

We estimate our retail customer growth in 2002 to be 3.2%,

which is slower than the pace of growth in recent years, although still about three times the national average. Our customer growth in 2001 was 3.7%. We expect the customer growth rate to be weak in the first two quarters of 2002, then begin a rebound. Our current estimate for customer growth in 2003 and 2004 is between 3.5% and 4.0% annually.

The retail price decreases are described above in Results of Operations - Regulatory Agreements.

As of December 31, 2001, the indicated annual dividend rate on our common stock was $1.60 per share. Since 1994, we have increased the dividend on our common stock ten cents per share per year. We currently plan to continue annual divi-dend increases of relatively consistent amounts, which would continue dividend growth at a pace above the industry average.

The foregoing discussion of future expectations is forward-looking information. Actual results may differ materially from expectations. See Forward-Looking Statements below.

Other Factors Affecting Our Financial Outlook Competition and Industry Restructuring Electric Competition (Wholesale)

The FERC regulates rates for wholesale power sales and trans-mission services. Our marketing and trading division sells in the wholesale market APS and Pinnacle West Energy genera-tion production output that is not needed for APS native load and, in doing so, competes with other utilities, power marketers, and independent power producers. Wholesale market prices significantly fell during 2001 and remain low for the reasons discussed under Financial Outlook above.

We cannot predict whether these lower prices will continue, or whether changes in various factors that affect demand and capacity, including regulatory actions, will cause the market prices to rise during 2002 or thereafter.

Electric Competition (Retail)

On September 21, 1999, the ACC approved Rules that provide a framework for the introduction of retail electric competition in Arizona. A Maricopa County, Arizona, Superior Court later found the Rules unlawful and uncon-stitutional; however, the Rules remain in effect pending the outcome of appeals. See Retail Electric Competition Rules in Note 3 for additional information about the Rules and the outstanding legal challenges to the Rules.

Although the Rules allow retail customers to have access to competitive providers of energy and energy services, APS is the provider of last resort for standard-offer, full-service customers under rates that have been approved by the ACC.

These rates are established until July 1, 2004. The 1999 Settlement Agreement allows APS to seek adjustment of these rates in the event of emergency conditions or circum-stances, such as the inability to secure financing on reason-able terms, or material changes in APS cost of service for ACC-regulated services resulting from federal, tribal, state or local laws, regulatory requirements, judicial decisions, actions or orders. Energy prices in the western U.S. whole-sale market vary and, during the course of the last two years, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount included in APS current retail rates. In the event of shortfalls due to unforeseen increases in load demand or generation outages, APS may need to purchase additional supplemental power in the wholesale spot market. Unless APS is able to obtain an adjustment of its rates under the 1999 Settlement Agreement, there can be no assurance that APS would be able to fully recover the costs of this power.

p_28 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 On September 23, 1999, the ACC approved a comprehen-sive 1999 Settlement Agreement among APS and various parties related to the implementation of retail electric competition in Arizona. See 1999 Settlement Agreement in Note 3 for additional information about the 1999 Settlement Agreement, including the recent resolution of legal challenges to the 1999 Settlement Agreement.

Under the Rules, as modified by the 1999 Settlement Agree-ment, APS is required to transfer all of its competitive electric assets and services either to an unaffiliated party or to a separate corporate affiliate no later than December 31, 2002.

Consistent with that requirement, APS has been addressing the legal and regulatory requirements necessary to complete the transfer of its generation assets to Pinnacle West Energy on or before that date. In anticipation of APS transfer of generation assets, Pinnacle West Energy has completed, and is in the process of developing and planning, various generation expansion projects so that APS can reliably meet the energy requirements of its Arizona customers.

Following APS transfer of its fossil-fueled generation assets and the receipt of certain regulatory approvals, Pinnacle West Energy expects to sell its power at wholesale to our marketing and trading division, which, in turn, is expected to sell power to APS and to non-affiliated power purchasers. In a filing with the ACC on October 18, 2001, APS requested the ACC to:

I grant APS a partial variance from an ACC Rule that would obligate APS to acquire all of its customers standard-offer generation requirements from the competitive market (with at least 50% of those requirements coming from a competitive bidding process) starting in 2003; and I approve as just and reasonable a long-term purchase power agreement between APS and Pinnacle West.

APS requested these ACC actions to ensure ongoing reliable service to APS standard-offer, full-service customers in a vola-tile generation market and to recognize Pinnacle West Ener-gys significant investment to serve APS load. See Proposed Rule Variance and Purchase Power Agreement in Note 3 for additional information about APS October 2001 ACC filing.

On February 8, 2002, the ACCs Chief ALJ issued a proce-dural order which consolidated the ACC docket relating to APS October, 2001 filing with several other pending ACC dockets, including a generic docket request by the ACC Chairman to determine if changed circumstances require the [ACC] to take another look at restructuring in Arizona.

Although the order consolidates several dockets, it states that a hearing on the APS matter will commence on April 29, 2002. The order went on to state that, contrary to APS position, the ALJ was construing the October, 2001 filing as a request by APS to amend the 1999 ACC order that approved the 1999 Settlement Agreement.

On March 22, 2002, the ACC Staff issued a report to the ACC recommending that the ACC address the following issues in the generic docket:

I The extent and manner of the ACCs involvement in moni-toring market conditions and/or mitigating the develop-ment of market power for generation and transmission; I The lack of guidance in the Rules regarding the mechanics of the competitive bidding process referenced above; I The consideration of alternatives to the transfer of genera-tion assets required by the Rules (the ACC Staff stated that such transfers would be unwise at the present time and recommended that all transfer and separation of utilities assets be stayed pending the completion of the generic docket);

I The consideration of transmission constraints that could impact the development of the wholesale power market; I The reassessment of adjustor mechanisms for standard-offer rates in light of problems with the development of a whole-sale power market; and I The adequacy of customer shopping credits in the context of the development of a competitive retail market (a shopping credit is the cost a customer does not pay to a utility distribution company if the customer obtains generation from another party).

Although not a specific ACC Staff recommendation, the report was also critical of certain aspects of the proposed purchase power agreement between APS and Pinnacle West.

A modification to the Rules or the 1999 Settlement Agreement as a result of the consolidated docket could, among other things, adversely affect APS ability to transfer its generation assets to Pinnacle West Energy by December 31, 2002. We cannot predict the outcome of the consolidated docket or its effect on the specific requests in APS October 2001 filing, the existing Arizona electric competition rules, or the 1999 Settlement Agreement.

As a result of the foregoing matters, as well as energy market developments, including those relating to Californias failed deregulation efforts and to Enrons recent bankruptcy filing, electric utility restructuring is in a state of flux in the western United States, including Arizona, and around the country.

Generation Expansion See Note 10 for information regarding our generation expan-sion plans. The planned additional generation is expected to increase revenues, fuel expenses, operating expenses, and financing costs.

California Energy Market Issues See Note 10 for information regarding California energy market issues.

Factors Affecting Operating Revenues Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona, and from competitive retail and wholesale bulk power markets in the western United States. These revenues are expected to be affected by electricity sales volumes related to customer mix, customer

p_29 growth and average usage per customer, as well as electricity prices and variations in weather from period to period.

In APS regulated retail market area, APS will provide electricity services to standard-offer, full-service customers and to energy delivery customers who have chosen another provider for their electricity commodity needs (unbundled customers). Customer growth in APS service territory averaged about 4% a year for the three years 1999 through 2001; we currently expect customer growth to be about 3.2% in 2002 and between 3.5% and 4.0% a year in 2003 and 2004. We currently estimate that retail electricity sales in kilowatt-hours will grow 3.5% to 5.5% a year in 2002 through 2004, before the retail effects of weather variations.

The customer growth and sales growth referred to in this paragraph apply to energy delivery customers. As industry restructuring evolves in the regulated market area, we cannot predict the number of APS standard-offer customers that will switch to unbundled service. As previously noted, under the 1999 Settlement Agreement, we have annual retail electricity price reductions of 1.5% through July 1, 2003 (see Note 3).

Competitive sales of energy and energy-related products and services are made by APSES in western states that have opened to competitive supply. Such activities currently are not material to our consolidated financial results.

Other Factors Affecting Future Financial Results Purchased power and fuel costs are impacted by our electric-ity sales volumes, existing contracts for generation fuel and purchased power, our power plant performance, prevailing market prices, new generating plants being placed in service and our hedging program for managing such costs.

Operations and maintenance expenses are expected to be affected by sales mix and volumes, power plant operations, inflation, outages and other factors.

Depreciation and amortization expenses are expected to be affected by net additions to existing utility plant and other property, changes in regulatory asset amortization, and our generation expansion program. See Note 1 for the regulato-ry asset amortization that is being recorded in 1999 through 2004 pursuant to the 1999 Settlement Agreement. Also, see Note 1 regarding current depreciation rates.

Taxes other than income taxes consist primarily of property taxes, which are affected by tax rates and the value of proper-ty in service and under construction. The average property tax rate for APS, which currently owns the majority of our property was 9.32% for 2001 and 9.16% for 2000. We expect property taxes to increase primarily due to our generation expansion program and our additions to existing facilities.

Interest expense is affected by the amount of debt outstand-ing and the interest rates on that debt. The primary factors affecting borrowing levels in the next several years are expected to be our generation expansion program and our internally-generated cash flow.

The annual earnings contribution from APSES is expected to be modest, yet positive, over the next several years due primarily to a number of retail electricity contracts in California. APSES pretax losses were $10 million in 2001 and $13 million in 2000.

The annual earnings contribution from SunCor is expected to remain modest over the next several years. SunCors earnings were $3 million in 2001, $11 million in 2000 and $6 million in 1999.

El Dorados historical results are not necessarily indicative of future performance for El Dorado. El Dorados strategies focus on prudently realizing the value of its existing invest-ments. Any future investments are expected to be related to the energy sector. See Note 1 for additional information regarding El Dorado.

We cannot accurately predict the impact of full retail competition on our financial position, cash flows, results of operations, or liquidity. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete effectively in a restructured industry.

Our financial results may be affected by the application of SFAS No. 133. See Critical Accounting Policies above and Note 17 for further information.

Our financial results may be affected by a number of broad factors. See Forward-Looking Statements below for further information on such factors, which may cause our actual future results to differ from those we currently seek or anticipate.

MARKET RISKS Our operations include managing market risks related to changes in interest rates, commodity prices, and investments held by the nuclear decommissioning trust fund.

Interest Rate and Equity Risk Our major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and interest earned by our nuclear decommissioning trust fund (see Note 11). Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. The nuclear decommis-sioning fund also has risks associated with changing market values of equity investments. Nuclear decommissioning costs are recovered in regulated electricity prices.

p_30 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 Commodity Price Risk We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal, and emissions allowances. We employ established proce-dures to manage risks associated with these market fluctua-tions by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options, and swaps. As part of our overall risk management program, we enter into derivative transactions to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodity.

In addition, subject to specified risk parameters established by the Board of Directors and monitored by the Energy Risk Management Committee, we engage in trading activities intended to profit from market price movements. In accor-dance with Emerging Issues Task Force (EITF) 98-10.

Accounting For Contracts Involved in Energy Trading and Risk Management Activities, such trading positions are marked-to-market. These trading activities are part of our marketing and trading activities and are reflected in the marketing and trading revenues and expenses.

Net gains at inception include a reasonable marketing margin and were approximately $3 million in 2001 and $2 million in 2000. See Note 17 for disclosure of risk management activities recorded on the consolidated balance sheets.

The table below shows the maturities of our trading positions as of December 31, 2001 in millions of dollars by the type of valuation that is performed to calculate the fair value of the contract. In addition, see Note 1 for more discussion on our valuation methods.

(dollars in millions) 2001 2000 Mark-to-market of net trading positions at beginning of year 12 Prior period marked-to-market gains realized during the year (1)

(2)

Change in marked-to-market gains for future period deliveries 127 14 Mark-to-market of net trading positions at end of year 138 12 The following schedule shows the changes in mark-to-market of our trading positions during the years ended December 31, 2001 and 2000:

EXPECTED MATURITY/PRINCIPAL REPAYMENT (dollars in thousands)

SHORT-TERM DEBT VARIABLE-RATE LONG-TERM DEBT FIXED-RATE LONG-TERM DEBT December 31, 2000 INTEREST RATES AMOUNT INTEREST RATES AMOUNT INTEREST RATES AMOUNT 2001 6.64%

82,775 7.23%

438,203 6.63%

25,266 2002 8.62%

36,890 8.13%

125,000 2003 8.61%

73,578 6.89%

25,443 2004 8.87%

268 6.17%

205,000 2005 8.89%

294 7.28%

400,000 Years thereafter 4.13%

483,790 7.47%

610,813 Total 82,775

$ 1,033,023

$ 1,391,522 Fair Value 82,775

$ 1,033,023

$ 1,422,014 EXPECTED MATURITY/PRINCIPAL REPAYMENT (dollars in thousands)

SHORT-TERM DEBT VARIABLE-RATE LONG-TERM DEBT FIXED-RATE LONG-TERM DEBT December 31, 2001 INTEREST RATES AMOUNT INTEREST RATES AMOUNT INTEREST RATES AMOUNT 2002 4.01%

405,762 7.76%

207 8.10%

125,933 2003 4.75%

292,912 6.87%

25,829 2004 5.32%

85,601 6.08%

205,677 2005 7.70%

294 7.59%

400,380 2006 7.30%

3,018 6.48%

384,085 Years thereafter 2.63%

480,740 6.73%

799,808 Total 405,762 862,772

$ 1,941,712 Fair Value 405,762 862,772

$ 1,963,389 The tables below present contractual balances of our long-term debt and commercial paper at the expected maturity dates as well as the fair value of those instruments on December 31, 2001 and 2000. The interest rates presented in the tables below represent the weighted average interest rates for the years ended December 31, 2001 and 2000.

p_31 DECEMBER 31, 2001 DECEMBER 31, 2000 (dollars in millions)

GAIN / (LOSS)

GAIN / (LOSS)

COMMODITY PRICE UP 10%

PRICE DOWN 10%

PRICE UP 10%

PRICE DOWN 10%

Trading (a):

Electric (3) 3 2

(2)

Natural gas (1) 1 (1) 1 Other 2

System (b):

Natural gas hedges 23 (23) 28 (28)

Total 19 (17) 29 (29)

(a) Essentially all of our marketing and trading activities are structured activities. This means our portfolio of forward sales positions is hedged with a portfolio of forward purchases that protects the economic value of the sales transactions.

(b)These contracts are hedges of our forecasted purchases of natural gas. The impact of these hypothetical price movements would substantially off-set the impact that these same price movements would have on the physical exposures being hedged.

YEARS TOTAL FAIR SOURCE OF FAIR VALUE 2002 2003-2004 2005-2006 THEREAFTER VALUE Prices actively quoted (13) 4 2

(7)

Prices provided by other external sources (12)

(8)

(4)

(24)

Prices based on models and other valuation methods 68 50 39 12 169 Total by maturity 43 46 37 12 138 The table below shows the impact that hypothetical price movements of 10% would have on the market value of our We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including one counterparty for which a worst case exposure represents approximately 50% of our $267 million of risk manage-ment and trading assets as of December 31, 2001. We use a risk management process to assess and monitor the financial exposure of this and all other counterparties. Despite the fact that the great majority of trading counterparties are rated as investment grade by the credit rating agencies, including the counterparty noted above, there is still a pos-sibility 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 princi-pally of 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 counter-parties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. In many contracts, we employ collateral requirements and stan-dardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.

Credit reserves are established representing our estimated credit losses on our overall exposure to counterparties. See Note 1 for a discussion of our credit reserve policy.

FORWARD-LOOKING STATEMENTS The above discussion contains forward-looking statements based on current expectations and we assume no obligation to update these statements. 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 the ongoing restructuring of the electric industry, including the introduction of retail electric competition in Arizona and APS October 2001 ACC filing; the outcome of regulatory and legislative proceedings relating to the restructuring; state and federal regulatory and legislative decisions and actions, including the price mitigation plan adopted by the FERC in June 2001; regional economic and market conditions, including the California energy situation and completion of generation construction in the region, which could affect customer growth and the cost of power supplies; the cost of debt and equity capital; weather varia-tions affecting local and regional customer energy usage; conservation programs; power plant performance; the successful completion of our generation expansion program; regulatory issues associated with generation expansion, such as permitting and licensing; our ability to compete success-fully outside traditional regulated markets (including the wholesale market); technological developments in the electric industry; and the strength of the real estate market in SunCors market areas, which include Arizona, New Mexico and Utah.

These factors and the other matters discussed above may cause future results to differ materially from historical results, or from results or outcomes we currently expect or seek.

risk management and trading assets and liabilities included on the consolidated balance sheets at December 31, 2001 and 2000.

p_32 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 INDEPENDENT AUDITORS REPORT To the Board of Directors and Stockholders of Pinnacle West Capital Corporation Phoenix, Arizona We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries as of December 31, 2001 and 2000, and the related consoli-dated statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2001. Our audits also included the financial statement schedule listed in the Index at Item 14.

These financial statements and the financial statement schedule are the responsibility of the Corporations manage-ment. Our responsibility is to express an opinion on the financial statements and the financial statement schedule based on our audits.

We conducted our audits in accordance with auditing stan-dards generally accepted in the United States of America.

Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and sig-nificant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements pre-sent fairly, in all material respects, the financial position of Pinnacle West Capital Corporation and subsidiaries at December 31, 2001 and 2000, and the results of their opera-tions and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consoli-dated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 17 to the financial statements, in 2001 Pinnacle West Capital Corporation changed its method of accounting for derivatives and hedging activities in order to comply with the provisions of Statement of Financial Accounting Standards No. 133.

DELOITTE & TOUCHE LLP Phoenix, Arizona February 8, 2002 (March 22, 2002, as to Note 18)

REPORT OF MANAGEMENT The responsibility for the integrity of our financial informa-tion rests with management, which has prepared the accom-panying financial statements and related information. This information was prepared in accordance with generally accepted accounting principles as appropriate in the circum-stances, and based on managements best estimates and judgments. These financial statements have been audited by independent auditors and their report is included.

Management maintains and relies upon systems of internal control. A limiting factor in all systems of internal control is that the cost of the system should not exceed the benefits to be derived. Management believes that our system provides the appropriate balance between such costs and benefits.

Periodically the internal control system is reviewed by both our internal auditors to test for compliance and our inde-pendent auditors in conjunction with their audit of our financial statements. Reports issued by the internal auditors are released to management, and such reports or summaries thereof are transmitted to the Audit Committee of the Board of Directors and the independent auditors on a timely basis.

By letter dated February 8, 2002, to the Audit Committee, our independent auditors confirmed that they are indepen-dent accountants with respect to us within the meaning of the Securities Act and the requirements of the Independence Standards Board.

The Audit Committee, composed solely of outside direc-tors, meets periodically with the internal auditors and inde-pendent auditors (as well as management) to review the work of each. The internal auditors and independent audi-tors have free access to the Audit Committee, without man-agement present, to discuss the results of their audit work.

Management believes that our systems, policies and proce-dures provide reasonable assurance that operations are con-ducted in conformity with the law and with managements commitment to a high standard of business conduct.

William J. Post Chris N. Froggatt Chairman and Vice President and Chief Executive Officer Controller REPORT OF MANAGEMENT AND INDEPENDENT AUDITORS REPORT

p_33 CONSOLIDATED STATEMENTS OF INCOME (dollars in thousands, except per share amounts) year ended December 31, 2001 2000 1999 OPERATING REVENUES Electric 4,382,465 3,531,810 2,293,184 Real estate 168,908 158,365 130,169 Total 4,551,373 3,690,175 2,423,353 OPERATING EXPENSES Purchased power and fuel 2,664,218 1,932,792 793,931 Operations and maintenance 530,095 450,205 446,173 Real estate operations 153,462 134,422 119,516 Depreciation and amortization 427,903 431,229 419,842 Taxes other than income taxes 101,068 99,780 96,606 Total 3,876,746 3,048,428 1,876,068 OPERATING INCOME 674,627 641,747 547,285 OTHER INCOME (EXPENSE)

Preferred stock dividend requirements of APS (1,016)

Net other income and expense (5,765)

(406) 10,573 Total (5,765)

(406) 9,557 INTEREST EXPENSE Interest charges 175,822 166,447 157,142 Capitalized interest (47,862)

(21,638)

(11,664)

Total 127,960 144,809 145,478 INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 540,902 496,532 411,364 INCOME TAXES 213,535 194,200 141,592 INCOME FROM CONTINUING OPERATIONS 327,367 302,332 269,772 Income tax benefit from discontinued operations 38,000 Extraordinary charge - net of income taxes of $94,115 (139,885)

Cumulative effect of a change in accounting for derivatives -

net of income taxes of $9,892 (15,201)

NET INCOME 312,166 302,332 167,887 WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC 84,718 84,733 84,717 WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED 84,930 84,935 85,009 EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING Continuing operations - basic 3.86 3.57 3.18 Net income - basic 3.68 3.57 1.98 Continuing operations - diluted 3.85 3.56 3.17 Net income - diluted 3.68 3.56 1.97 DIVIDENDS DECLARED PER SHARE 1.525 1.425 1.325 See Notes to Consolidated Financial Statements.

p_34 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 CONSOLIDATED BALANCE SHEETS (dollars in thousands)

December 31, 2001 2000 ASSETS CURRENT ASSETS Cash and cash equivalents 28,619 10,363 Customer and other receivables - net 367,241 513,822 Accrued utility revenues 76,131 74,566 Materials and supplies (at average cost) 81,215 71,966 Fossil fuel (at average cost) 27,023 19,405 Deferred income taxes (Note 4) 5,793 Assets from risk management and trading activities (Note 17) 66,973 17,506 Other current assets 80,203 80,492 Total current assets 727,405 793,913 INVESTMENTS AND OTHER ASSETS Real estate investments - net (Notes 1 and 6) 418,673 371,323 Assets from risk management and trading activities - long-term (Note 17) 200,351 32,955 Other assets 321,024 299,128 Total investments and other assets 940,048 703,406 PROPERTY, PLANT AND EQUIPMENT (NOTES 1, 6, 8 AND 9)

Plant in service and held for future use 8,203,888 7,809,566 Less accumulated depreciation and amortization 3,378,089 3,188,302 Total 4,825,799 4,621,264 Construction work in progress 1,032,234 464,540 Nuclear fuel, net of accumulated amortization of $56,836 and $61,256 49,282 47,389 Net property, plant and equipment 5,907,315 5,133,193 DEFERRED DEBITS Regulatory assets (Notes 1, 3 and 4) 342,383 469,867 Other deferred debits 64,597 62,606 Total deferred debits 406,980 532,473 TOTAL ASSETS 7,981,748 7,162,985 See Notes to Consolidated Financial Statements.

p_35 CONSOLIDATED BALANCE SHEETS (dollars in thousands)

December 31, 2001 2000 LIABILITIES AND EQUITY CURRENT LIABILITIES Accounts payable 269,124 375,805 Accrued taxes 96,729 89,246 Accrued interest 48,806 42,954 Short-term borrowings (Note 5) 405,762 82,775 Current maturities of long-term debt (Note 6) 126,140 463,469 Customer deposits 30,232 26,189 Deferred income taxes (Note 4) 3,244 Liabilities from risk management and trading activities (Note 17) 35,994 37,179 Other current liabilities 74,898 73,681 Total current liabilities 1,090,929 1,191,298 LONG-TERM DEBT LESS CURRENT MATURITIES (NOTE 6) 2,673,078 1,955,083 DEFERRED CREDITS AND OTHER Liabilities from risk management and trading activities - long-term (Note 17) 207,576 14,711 Deferred income taxes (Note 4) 1,064,993 1,143,040 Unamortized gain - sale of utility plant (Note 8) 64,060 68,636 Other 381,789 407,503 Total deferred credits and other 1,718,418 1,633,890 COMMITMENTS AND CONTINGENCIES (NOTES 3, 10 AND 11)

COMMON STOCK EQUITY Common stock, no par value; authorized 150,000,000 shares; issued and outstanding 84,824,947 at end of 2001 and 2000 1,531,038 1,532,831 Retained earnings 1,032,850 849,883 Accumulated other comprehensive loss (64,565)

Total common stock equity 2,499,323 2,382,714 TOTAL LIABILITIES AND EQUITY 7,981,748 7,162,985

p_36 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 CONSOLIDATED STATEMENTS OF CASH FLOWS (dollars in thousands) year ended December 31, 2001 2000 1999 CASH FLOWS FROM OPERATING ACTIVITIES Income from continuing operations 327,367 302,332 269,772 Items not requiring cash Depreciation and amortization 427,903 431,229 419,842 Nuclear fuel amortization 28,362 30,083 31,371 Deferred income taxes - net (16,939)

(38,625)

(43,886)

Deferred investment tax credit (264) 740 (23,514)

Mark-to-market gains - trading (125,521)

(11,752)

(975)

Mark-to-market gains - system (8,052)

Changes in current assets and liabilities Customer and other receivables - net 146,581 (269,223)

(10,723)

Accrued utility revenues (1,565)

(1,647)

(5,179)

Materials, supplies and fossil fuel (16,867) 475 (8,794)

Other current assets 289 (37,436)

(12,968)

Accounts payable (127,782) 193,502 28,193 Accrued taxes 7,483 18,736 12,591 Accrued interest 5,852 9,701 1,387 Other current liabilities 5,260 98,493 14,047 Change in El Dorado partnership investment 1,671 (3,773)

(25,786)

Increase in real estate investments (44,173)

(25,937)

(12,542)

Increase in regulatory assets (17,516)

(14,138)

(12,262)

Other - net (21,159) 30,634 15,026 Net Cash Flow Provided By Operating Activities 570,930 713,394 635,600 CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (1,040,585)

(658,608)

(343,448)

Capitalized interest (47,862)

(21,638)

(11,664)

Other - net (31,357)

(55,595)

(16,143)

Net Cash Flow Used For Investing Activities (1,119,804)

(735,841)

(371,255)

CASH FLOWS FROM FINANCING ACTIVITIES Issuance of long-term debt 995,447 651,000 607,791 Short-term borrowings - net 322,987 44,475 (140,530)

Dividends paid on common stock (129,199)

(120,733)

(112,311)

Repayment of long-term debt (621,057)

(558,019)

(510,693)

Redemption of preferred stock (96,499)

Other - net (1,048)

(4,618)

(11,936)

Net Cash Flow Provided By (Used For) Financing Activities 567,130 12,105 (264,178)

NET CASH FLOW 18,256 (10,342) 167 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 10,363 20,705 20,538 CASH AND CASH EQUIVALENTS AT END OF YEAR 28,619 10,363 20,705 Supplemental Disclosure of Cash Flow Information Cash paid during period for:

Income taxes 223,037 219,411 199,799 Interest paid, net of amounts capitalized 115,276 132,434 141,138 See Notes to Consolidated Financial Statements.

p_37 CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (dollars in thousands)

ACCUMULATED OTHER COMMON RETAINED COMPREHENSIVE years ended December 31, 2001, 2000, and 1999 STOCK EARNINGS INCOME (LOSS)

TOTAL Balance at December 31,1998

$ 1,550,643 612,708

$ 2,163,351 Net income 167,887 167,887 Dividends on common stock (112,311)

(112,311)

Common stock expense (13,194)

(13,194)

Balance at December 31, 1999 1,537,449 668,284 2,205,733 Net income 302,332 302,332 Dividends on common stock (120,733)

(120,733)

Common stock expense (4,618)

(4,618)

Balance at December 31, 2000 1,532,831 849,883 2,382,714 Net income 312,166 312,166 Minimum pension liability, net of $634 tax effect (966)

(966)

Cumulative effect of change in accounting for derivatives, net of $47,404 tax effect 72,274 72,274 Unrealized loss on derivative instruments, net of

$54,028 tax effect (82,373)

(82,373)

Reclassification of net realized gain to income, net of

$35,091 tax effect (53,500)

(53,500)

Comprehensive income (loss) 312,166 (64,565) 247,601 Dividends on common stock (129,199)

(129,199)

Common stock expense (1,793)

(1,793)

Balance at December 31, 2001

$ 1,531,038

$ 1,032,850 (64,565)

$ 2,499,323 See Notes to Consolidated Financial Statements.

p_38 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

1.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES Consolidation and Nature of Operations The consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, Pinnacle West Energy, APSES, SunCor, and El Dorado. Significant inter-company accounts and transactions between the consolidated companies have been eliminated.

APS, our major subsidiary and Arizonas largest electric utility, provides either retail or wholesale electric service to substantially all of the state, with the major exceptions of the Tucson metropolitan area and about one-half of the Phoenix metropolitan area. APS also generates and, directly or through our marketing and trading division, sells and delivers electricity to wholesale customers in the western United States. During 2001, APS transferred most of its marketing and trading activities to the parent company.

Pinnacle West Energy, which was formed in 1999, is the subsidiary through which we conduct our unregulated generation operations. APSES was formed in 1998 and provides commodity energy and energy-related products to key customers in competitive markets in the western United States. SunCor is a developer of residential, commercial, and industrial real estate projects in Arizona, New Mexico, and Utah. El Dorado is an investment firm.

Accounting Records and Use of Estimates Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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. We have reclassified certain prior year amounts to conform to current year presentation.

Derivative Instruments We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal, and emissions allowances. We employ established procedures to manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options, and swaps. As part of our overall risk management program, we enter into derivative transactions to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodity.

In addition, subject to specified risk parameters established by the Board of Directors and monitored by the ERMC, we engage in trading activities intended to profit from market price movements. If a contract was entered into for trading purposes, we account for it in accordance with EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. EITF 98-10 requires energy trading contracts to be measured at fair value as of the balance sheet date, with unrealized gains and losses included in earnings on a current basis (the mark-to-market method). See Mark-to-Market Method below and Note 17 for further information about our trading contracts.

We examine contracts at inception to determine the appro-priate accounting treatment. If a contract is not considered energy trading we must determine if it is a derivative as defined in SFAS No. 133 (see Note 17 for further infor-mation on SFAS No. 133). If a contract does not meet the derivative criteria or if it qualifies for a SFAS No. 133 scope exception, we account for the contract using accrual accounting (this means that costs and revenues are recorded when physical delivery occurs). For contracts that qualify as a derivative and do not meet a SFAS No. 133 scope exception, we further examine the contract to determine if it will qualify for hedge accounting. If a contract does not meet the hedging criteria in SFAS No. 133, we recognize the changes in the fair value of the derivative instrument in income each period (mark-to-market). If it does qualify for hedge accounting, changes in the fair value are recognized as either an asset or liability or in stockholders equity (as a component of accumulated other comprehensive income) depending on the nature of the hedge.

Gains and losses related to derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or fuel and purchased power expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings (deferral method). See Note 17 for further discussion on derivative accounting.

Mark-to-Market Method Under mark-to-market accounting the purchase or sale of energy commodities are reflected at fair market value, net of reserves, with resulting unrealized gains and losses recorded as assets and liabilities from risk management and trading activities in the consolidated balance sheets.

We determine fair market value using actively-quoted prices when available. We consider quotes for exchange-traded contracts and over-the-counter quotes obtained from independent brokers to be actively-quoted.

When actively-quoted prices are not available, we use prices provided by other external sources. This includes quarterly and calendar year quotes from independent brokers. We shape quarterly and calendar year quotes into monthly prices based on historical relationships.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

p_39 1/1-6/30 1999 2000 2001 2002 2003 2004 TOTAL

$164

$158

$145

$115

$86

$18

$686 For options, long-term contracts and other contracts where price quotes are not available, we use models and other valuation methods. For illiquid or unquoted market locations, we consider the historical relationship to readily-available market quotations. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.

For non-exchange traded contracts, we calculate fair market value based on the average of the bid and offer price, and we discount to reflect net present value. We maintain certain reserves for a number of risks associated with the valuation of future commitments. These include reserves for liquidity and credit risks based on the financial condi-tion of counterparties. The liquidity reserve represents the cost that would be incurred if all unmatched positions were closed-out or hedged. As we mark positions to a mid-market value this reserve adjusts the mid-market valuation to the bid or offer, after taking into consideration offsetting positions, to reflect the true cash flow that would be realized upon exiting the net position.

A credit reserve is also recorded to represent estimated credit losses on our overall exposure to counterparties, taking into account netting arrangements; expected default experience for the credit rating of the counterparties; and the overall diversification of the portfolio. Counterparties in the port-folio consist principally of major energy companies, munici-palities, and local distribution companies. We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counter-parties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.

The use of models and other valuation methods to deter-mine fair market value often requires subjective and com-plex judgement. Actual results could differ from the results estimated through application of these methods. However, essentially all of our marketing and trading activities are structured activities. This means our portfolio of forward sales positions is substantially hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. Our practice is to hedge within time-frames established by the ERMC.

Regulatory Accounting APS is regulated by the ACC and the FERC. The accompa-nying financial statements reflect the rate-making policies of these commissions. For regulated operations, we prepare our financial statements in accordance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements.

During 1997, the EITF of the FASB issued EITF 97-4.

EITF 97-4 requires that SFAS No. 71 be discontinued no later than when legislation is passed or a rate order is issued that contains sufficient detail to determine its effect on the portion of the business being deregulated, which could result in write-downs or write-offs of physical and/or regulatory assets. Additionally, the EITF determined that regulatory assets should not be written off if they are to be recovered from a portion of the entity which continues to apply SFAS No. 71.

The 1999 Settlement Agreement was approved by the ACC in September 1999 (see Note 3 for a discussion of the agreement). Consequently, we have discontinued the application of SFAS No. 71 for our generation operations.

As a result, we tested the generation assets for impairment and determined that the generation assets were not impaired. Pursuant to the 1999 Settlement Agreement, a regulatory disallowance removed $234 million pretax

($183 million net present value) from ongoing regulatory cash flows and was recorded as a net reduction of regulatory assets. This reduction ($140 million after income taxes) was reported as an extraordinary charge on the income state-ment during the third quarter of 1999. Prior to the 1999 Settlement Agreement, under the 1996 regulatory agree-ment (see Note 3), the ACC accelerated the amortization of substantially all of our regulatory assets to an eight-year period that would have ended June 30, 2004.

The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions):

p_40 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 We record depreciation on utility property on a straight-line basis. For the years 1999 through 2001 the rates, as prescribed by our regulators, ranged from a low of 1.49%

to a high of 20%. The weighted-average rate was 3.40% for 2001, 3.40% for 2000, and 3.34% for 1999. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 30 years.

We expense the costs of plant outages, major maintenance and routine maintenance as incurred.

El Dorado Investments El Dorado accounts for its investments using the equity method. Net other income has consisted primarily of El Dorados share of the earnings of a venture capital partner-ship. We record our share of the earnings from the partner-ship as the partnership adjusts the value of its investments.

In 2001, El Dorado received a distribution of securities rep-resenting substantially all of El Dorados investment in the partnership. The securities were sold in the first quarter of 2001 and a gain was recognized in other income. The book value of El Dorados investment in the partnership was approximately $1 million at December 31, 2001, and $7 million at December 31, 2000. El Dorados net investment book value was approximately $10 million at December 31, 2001 and $21 million at December 31, 2000.

Capitalized Interest Capitalized interest represents the cost of debt funds used to finance construction of utility plants. Plant construction costs, including capitalized interest, are expensed through depreciation when completed projects are placed into com-mercial operation. Capitalized interest does not represent current cash earnings. The rate used to calculate capitalized interest was a composite rate of 6.13% for 2001, 6.62%

for 2000, and 6.65% for 1999.

Revenues We record electric operating revenues on the accrual basis, which includes estimated amounts for service rendered but unbilled at the end of each accounting period. We exclude sales taxes on electric revenues from both revenue and taxes other than income taxes. Electric revenues are recorded gross on the statements of income, with the exception of unrealized gains and losses recorded under the mark-to-market method (see discussion above). Unrealized gains and losses are recorded net in electric revenues. When the gain or loss is realized, the gross amount is recorded as electric revenue and fuel or purchased power expense in the consolidated statements of income.

Cash and Cash Equivalents For purposes of the statement of cash flows, we consider all highly liquid debt instruments purchased with an initial maturity of three months or less to be cash equivalents.

Rate Synchronization Cost Deferrals As authorized by the ACC, operating costs (excluding fuel) and financing costs of Palo Verde Units 2 and 3 were deferred from the commercial operation dates (September December 31, (dollars in millions) 2001 2000 Electric plant in service and held for future use 3,954 3,854 Accumulated depreciation and amortization (1,990)

(1,902)

Construction work in progress 824 304 Nuclear fuel, net of amortization 49 47 The consolidated balance sheets include the amounts listed below for generation assets not subject to SFAS No. 71:

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

I material and labor; I contractor costs; I construction overhead costs (where applicable); and I capitalized interest or an allowance for funds used during construction.

We charge retired utility plant, plus removal costs less salvage realized, to accumulated depreciation. See Note 2 for information on a new accounting standard that impacts accounting for removal costs.

December 31, (dollars in millions) 2001 2000 Remaining balance recoverable under the 1999 Settlement Agreement (a) 219 364 Spent fuel storage (Note 10) 43 40 Electric industry restructuring transition costs (Note 3) 34 24 Other 46 42 Total regulatory assets 342 470 (a) The majority of our unamortized regulatory assets above relates to deferred income taxes (See Note 4) and rate synchronization cost deferrals (see Rate Synchronization Cost Deferrals below).

Regulatory assets are reported as deferred debits on the con-solidated balance sheets. As of December 31, 2001 and 2000, they are comprised of the following:

Regulatory liabilities are included in deferred credits and other on the consolidated balance sheets. As of December 31, 2001 and 2000, they are comprised of the following:

December 31, (dollars in millions) 2001 2000 Deferred gains on utility property 20 20 Other 7

8 Total regulatory liabilities 27 28

p_41 Home inventory consists of construction costs, improved lot costs, capitalized interest and property taxes on homes under construction. Home inventory is stated at the lower of accumulated cost or estimated fair value less costs to sell.

Investments in joint ventures for which SunCor does not have a controlling financial interest are not consolidated but are accounted for using the equity method of accounting.

2. ACCOUNTING MATTERS In July 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. This statement addresses financial accounting and reporting for acquired goodwill and other intangible assets and supersedes APB Opinion No. 17, Intangible Assets. This standard is effective for the year beginning January 1, 2002. We have no goodwill recorded in our consolidated balance sheets. The impacts of this new standard are not material to our financial statements.

In August 2001, the FASB issued SFAS No. 143 Accounting for Asset Retirement Obligations. The standard requires the estimated present value of the cost of decommissioning and certain other removal costs to be recorded as a liability, along with an offsetting plant asset when a decommissioning or other removal obligation is incurred. We are currently evaluating the impacts of the new standard, which is effective for the year beginning January 1, 2003.

In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. This statement supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, and the accounting and reporting provisions for the disposal of a segment of a business. SFAS No. 144 is effective for the year beginning January 1, 2002. This standard does not impact our financial statements at adoption.

In 2001, the American Institute of Certified Public Accountants (AICPA) issued an exposure draft of a proposed Statement of Position (SOP), Accounting for Certain Costs Related to Property, Plant, and Equipment. This proposed SOP would create a project timeline framework for capital-izing costs related to property, plant and equipment (PP&E) construction, which require that PP&E assets be accounted for at the component level, and require administrative and general costs incurred in support of capital projects to be expensed in the current period. The AICPA plans to issue the final SOP in the fourth quarter of 2002.

In 1986, APS entered into agreements with three separate special purpose entity (SPE) lessors in order to sell and lease back interests in Palo Verde Unit 2 (See Note 8). The leases are accounted for as operating leases in accordance with GAAP. In February 2002, the FASB discussed issues related to special purpose entities. It is expected that FASB will issue additional guidance on accounting for SPEs later this year. As a result of future FASB actions, we may be required 1986 for Unit 2 and January 1988 for Unit 3) until the date the units were included in a rate order (April 1988 for Unit 2 and December 1991 for Unit 3). In accordance with the 1999 Settlement Agreement, we are continuing to accelerate the amortization of the deferrals over an eight-year period that will end June 30, 2004. Amortization of the deferrals is included in depreciation and amortization expense in the consolidated statements of income.

Nuclear Fuel APS charges nuclear fuel to fuel expense by using the unit-of-production method. The unit-of-production method is an amortization method that is based on actual physical usage. APS divides the cost of the fuel by the estimated num-ber of thermal units that it expects to produce with that fuel.

APS then multiplies that rate by the number of thermal units that it produces within the current period. This calculation determines the current period nuclear fuel expense.

APS also charges nuclear fuel expense for the permanent disposal of spent nuclear fuel. The United States Department of Energy (DOE) is responsible for the perma-nent disposal of spent nuclear fuel, and it charges APS

$0.001 per kWh of nuclear generation. See Note 10 for information about spent nuclear fuel disposal and Note 11 for information on nuclear decommissioning costs.

Income Taxes Income taxes are provided using the asset and liability approach prescribed by SFAS No. 109. We file our federal income tax return on a consolidated basis and we file our state income tax returns on a consolidated or unitary basis.

In accordance with our intercompany tax sharing agree-ment, federal and state income taxes are allocated to each subsidiary as though each subsidiary filed a separate income tax return. Any difference between the aforementioned allocations and the consolidated (and unitary) income tax liability is attributed to the parent company.

Reacquired Debt Costs For debt related to the regulated portion of APS business, APS amortizes those gains and losses incurred upon early retirement over the remaining life of the debt. In accordance with the 1999 Settlement Agreement, APS is continuing to accelerate reacquired debt costs over an eight-year period that will end June 30, 2004. All regulatory asset amortiza-tion is included in depreciation and amortization expense in the consolidated statements of income.

Real Estate Investments Real estate investments primarily include SunCors land, home inventory and investments in joint ventures. Land includes acquisition costs, infrastructure costs, property taxes and capitalized interest directly associated with the acquisition and development of each project. Land under development and land held for future development are stated at accumulated cost, except to the extent that such land is believed to be impaired, it is written down to fair value. Land held for sale is stated at the lower of the accu-mulated cost or estimated fair value less costs to sell.

p_42 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

($7 million after income taxes) related to the 1996 regula-tory agreement. See 1996 Regulatory Agreement below.

Based on the price reductions authorized in the 1999 Settlement Agreement, there were also retail price decreases of approximately $28 million ($17 million after taxes),

or 1.5%, effective July 1, 2000, and approximately $27 million ($16 million after taxes), or 1.5%, effective July 1, 2001. For customers having loads three MW or greater, standard-offer rates will be reduced in varying annual increments that total 5% in the years 1999 through 2002.

I Unbundled rates being charged by APS for competitive direct access service (for example, distribution services) became effective upon approval of the 1999 Settlement Agreement, retroactive to July 1, 1999, and also became subject to annual reductions beginning January 1, 2000, that vary by rate class, through January 1, 2004.

I There will be a moratorium on retail price changes for standard-offer and unbundled competitive direct access services until July 1, 2004, except for the price reductions described above and certain other limited circumstances.

Neither the ACC nor APS will be prevented from seeking or authorizing rate changes prior to July 1, 2004 in the event of conditions or circumstances that constitute an emergency, such as an inability to finance on reasonable terms, or material changes in APS cost of service for ACC-regulated services resulting from federal, tribal, state or local laws, regulatory requirements, judicial decisions, actions or orders.

I APS will be permitted to defer for later recovery prudent and reasonable costs of complying with the ACC electric competition rules, system benefits costs in excess of the levels included in then-current (1999) rates, and costs associated with the provider of last resort and standard-offer obligations for service after July 1, 2004. These costs are to be recovered through an adjustment clause or clauses commencing on July 1, 2004.

I APS distribution system opened for retail access effective September 24, 1999. Customers were eligible for retail access in accordance with the phase-in adopted by the ACC under the electric competition rules (see Retail Electric Competition Rules below), including an additional 140 MW being made available to eligible non-residential customers. APS opened its distribution system to retail access for all customers on January 1, 2001.

I Prior to the 1999 Settlement Agreement, APS was recov-ering substantially all of its regulatory assets through July 1, 2004, pursuant to the 1996 regulatory agreement. In addition, the 1999 Settlement Agreement states that APS has demonstrated that its allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least

$533 million net present value. APS will not be allowed to recover $183 million net present value of the above amounts. The 1999 Settlement Agreement provides that APS will have the opportunity to recover $350 million net present value through a competitive transition charge that will remain in effect through December 31, 2004, at which time it will terminate. The costs subject to recovery to consolidate the Palo Verde SPEs in our financial state-ments. If consolidation is required, the assets and liabilities of the SPEs that relate to the sale-leaseback transactions would be reflected on our consolidated balance sheets. The SPE debt that is not reflected on our consolidated balance sheets is approximately $300 million at December 31, 2001. Rating agencies have already considered this debt when evaluating our credit ratings.

3. REGULATORY MATTERS Electric Industry Restructuring State 1999 Settlement Agreement. On May 14, 1999, APS entered into a comprehensive 1999 Settlement Agreement with various parties, including representatives of major consumer groups, related to the implementation of retail electric competition. On September 23, 1999, the ACC voted to approve the 1999 Settlement Agreement, with some modifications.

On December 13, 1999, two parties filed lawsuits challeng-ing the ACCs approval of the 1999 Settlement Agreement.

Each party bringing the lawsuits appealed the ACCs order approving the 1999 Settlement Agreement directly to the Arizona Court of Appeals, as provided by Arizona law. In one of the appeals, on December 26, 2000, the Arizona Court of Appeals affirmed the ACCs approval of the 1999 Settlement Agreement. This decision was not appealed and has become final. In the other appeal, on April 5, 2001, the Arizona Court of Appeals again affirmed the ACCs approval of the 1999 Settlement Agreement. The Arizona Consumers Council, which filed that appeal, petitioned the Arizona Supreme Court for review of the Court of Appeals decision. On October 5, 2001, the Arizona Supreme Court agreed to hear the appeal on the single issue of whether the ACC could itself become a party to the 1999 Settlement Agreement by virtue of its approval of the 1999 Settlement Agreement. On December 14, 2001, the Arizona Supreme Court vacated its own October 5, 2001 order accepting jurisdiction and decided to dismiss the appeal. As a result, the judicial challenges to the 1999 Settlement Agreement have terminated. Consistent with its obligations under the 1999 Settlement Agreement, on January 7, 2002, APS and the ACC filed in Maricopa County Superior Court a stipulation to dismiss all of APS litigation pending against the ACC. On January 15, 2002, a Maricopa County Superior Court judge issued an order dismissing such litigation.

The following are the major provisions of the 1999 Settlement Agreement, as approved:

I APS has reduced, and will reduce, rates for standard-offer service for customers with loads less than three MW in a series of annual retail electricity price reductions of 1.5%

beginning July 1, 1999 through July 1, 2003, for a total of 7.5%. The first reduction of approximately $24 mil-lion ($14 million after income taxes) included the July 1, 1999 retail price decrease of approximately $11 million

p_43 under the adjustment clause described above will be decreased or increased by any over/under-recovery due to sales volume variances.

I APS will form, or cause to be formed, a separate corporate affiliate or affiliates and transfer to such affiliate(s) its competitive electric assets and services at book value as of the date of transfer, and will complete the transfer no later than December 31, 2002. Accordingly, APS plans to com-plete the move of such assets and services from APS to the parent company or to Pinnacle West Energy by the end of 2002, as required, although the ACCs recent establishment of a generic docket to consider electric industry restruc-turing in Arizona and the consolidation of that docket with APS request for approval of a PPA between Pinnacle West and APS could affect APS ability to transfer assets to Pinnacle West Energy. APS will be allowed to defer and later collect, beginning July 1, 2004, sixty-seven percent of its costs to accomplish the required transfer of generation assets to an affiliate.

As discussed in Note 1 above, we have discontinued the application of SFAS No. 71 for our generation operations.

Proposed Rule Variance and Purchase Power Agreement.

As authorized by the 1999 Settlement Agreement, APS intends to move substantially all of its generation assets to Pinnacle West Energy no later than December 31, 2002.

Commencing upon the transfer of the fossil-fueled gener-ating assets and the receipt of certain regulatory approvals, Pinnacle West Energy expects to sell its power at wholesale to Pinnacle Wests marketing and trading division, which, in turn, is expected to sell power to APS and to non-affiliated power purchasers. In a filing with the ACC on October 18, 2001, APS requested the ACC to:

I grant APS a partial variance from an ACC rule that would obligate APS to acquire all of its customers standard-offer, full-service generation requirements from the competitive market (with at least 50% of those requirements coming from a competitive bidding process) starting in 2003; and I approve as just and reasonable a long-term purchase power agreement (PPA) between APS and Pinnacle West.

APS has requested these ACC actions to ensure ongoing reliable service to APS standard-offer, full-service customers in a volatile generation market and to recognize Pinnacle West Energys significant investment to serve APS load.

The following are the major provisions of the PPA:

I The PPA would run through 2015, with three optional five-year renewal terms, which renewals would occur automatically unless notice is given by either APS or Pinnacle West.

I The PPA would provide for all of APS anticipated standard-offer generation needs, including any necessary reserves, except for (a) those provided by APS itself through renewable resources or other generation assets retained by APS; (b) amounts that APS is obligated by law to purchase from qualified facilities and other forms of distributed generation; and (c) any purchased power agreements that APS cannot transfer to Pinnacle West Energy.

I Pinnacle West would assume contractual responsibility for reliability and would supplement any potential shortfall even after full utilization of Pinnacle West Energys dedicated generating resources.

I Pinnacle West would supply APS standard-offer require-ments through a combination of (a) APS generation assets transferred to Pinnacle West Energy; (b) certain of Pinnacle West Energys new Arizona generation projects to be constructed during the 2001-2004 period to reliably serve APS load requirements; (c) power procured by Pinnacle West under certain dedicated contracts; and (d) power procured on the open market, including a competitively-bid component described below.

I Beginning in 2003, Pinnacle West would acquire 270 MW of APS standard-offer requirements on the open market through a competitive bidding process. This competitive bid obligation would be increased by an additional 270 MW each year through 2008 (representing approximately 23% of estimated 2008 peak load).

I Pinnacle West would charge APS based on (a) a com-bination of fixed and variable price components for the Pinnacle West Energy assets, subject to periodic adjust-ment, and (b) a pass-through of Pinnacle Wests costs to procure power from the remaining sources.

I The PPA would take effect on the latest of the following events: (a) transfer of non-nuclear generating assets from APS to Pinnacle West Energy; (b) ACC approval of the rule variance and the PPA; and (c) the FERCs acceptance of the PPA and the companion agreement between Pinnacle West and Pinnacle West Energy.

APS is required to transfer its competitive electric assets and services to one or more corporate affiliates on or before December 31, 2002. Consistent with that requirement, APS has been addressing the legal and regulatory requirements necessary to complete the transfer of its generation assets to Pinnacle West Energy, on or before that date. In anticipation of APS transfer of generation assets, Pinnacle West Energy has completed, and is in the process of developing and plan-ning, various generation expansion projects so that APS can reliably meet the energy requirements of its Arizona customers.

By letter dated January 14, 2002, the Chairman of the ACC stated that the [ACCs] Electric Competition Rules, along with the Settlement Agreements approved for APS and

[Tucson Electric Company], establish the framework for the transition to a retail generation competitive market. The ACC Chairman then recommended that the ACC establish a new generic docket to determine if changed circum-stances require the [ACC] to take another look at electric

p_44 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 restructuring in Arizona. Matters that would be addressed by the ACC in the new docket would include:

I whether the ACC should continue implementation of the retail electric competition Rules adopted by the ACC in 1999 in their current form or with modifications; I whether the ACC should slow the pace of the implemen-tation of the [Rules] to provide an opportunity to consid-er the extent to which [Rule] modification and variance is in the public interest, including changing the direction to retail electric competition; and I whether the ACC should step back from electric industry restructuring until the [ACC] is convinced that there exists a viable competitive wholesale electric market to support retail electric competition in Arizona.

On January 22, 2002 the ACCs Chief ALJ issued a procedural order by which a generic docket was opened. On February 8, 2002, the ACCs ALJ issued a procedural order which consoli-dated the ACC docket relating to APS October 2001 filing with several other pending ACC dockets, including the generic docket. Although the order consolidates several dockets, it states that a hearing on the APS matter will commence on April 29, 2002. The order went on to state that, contrary to APS position the ALJ was construing the October 2001 filing as a request by APS to amend the ACC order that approved the 1999 Settlement Agreement.

On March 22, 2002, the ACC Staff issued a report to the ACC recommending that the ACC address the following issues in the generic docket:

I The extent and manner of the ACCs involvement in moni-toring market conditions and/or mitigating the develop-ment of market power for generation and transmission; I The lack of guidance in the Rules regarding the mechanics of the competitive bidding process referenced above; I The consideration of alternatives to the transfer of genera-tion assets required by the Rules (the ACC Staff stated that such transfers would be unwise at the present time and recommended that all transfer and separation of utilities assets be stayed pending the completion of the generic docket);

I The consideration of transmission constraints that could impact the development of the wholesale power market; I The reassessment of adjustor mechanisms for standard-offer rates in light of problems with the development of a whole-sale power market; and I The adequacy of customer shopping credits in the context of the development of a competitive retail market (a shopping credit is the cost a customer does not pay to a utility distribution company if the customer obtains generation from another party).

Although not a specific ACC Staff recommendation, the report was also critical of certain aspects of the proposed purchase power agreement between APS and Pinnacle West.

A modification to the competition Rules or the 1999 Settle-ment Agreement could, among other things, adversely affect APS ability to transfer its generation assets to Pinnacle West Energy by December 31, 2002. Pinnacle West cannot predict the outcome of the consolidated docket or its effect on the specific requests in APS October 2001 filing, the existing Arizona electric competition rules, or the 1999 Settlement Agreement.

Retail Electric Competition Rules. On September 21, 1999, the ACC voted to approve Rules that provide a frame-work for the introduction of retail electric competition in Arizona. Under the 1999 Settlement Agreement, the Rules are to be interpreted and applied, to the greatest extent possible, in a manner consistent with the 1999 Settlement Agreement. If the two cannot be reconciled, APS must seek, and the other parties to the 1999 Settlement Agreement must support, a waiver of the Rules in favor of the 1999 Settlement Agreement. On December 8, 1999, APS filed a lawsuit to protect its legal rights regarding the Rules. This lawsuit has been dismissed.

On November 27, 2000, a Maricopa County, Arizona, Superior Court judge issued a final judgment holding that the Rules are unconstitutional and unlawful in their entirety due to failure to establish a fair value rate base for competi-tive electric service providers and because certain of the Rules were not submitted to the Arizona Attorney General for certification. The judgment also invalidates all ACC orders authorizing competitive electric service providers, including APSES, to operate in Arizona. We do not believe the ruling affects the 1999 Settlement Agreement. The 1999 Settlement Agreement was not at issue in the consolidated cases before the judge. Further, the ACC made findings related to the fair value of APS property in the order approving the 1999 Settlement Agreement. The ACC and other parties aligned with the ACC have appealed the ruling to the Arizona Court of Appeals, as a result of which the Superior Courts ruling is automatically stayed pending further judicial review. In a similar appeal concerning the issuance of competitive telecommunications CC&Ns, the Arizona Court of Appeals invalidated rates for competitive carriers due to the ACCs failure to establish a fair value rate base for such carriers. That case has been appealed to the Arizona Supreme Court, where a decision is pending.

The Rules approved by the ACC include the following major provisions:

I They apply to virtually all Arizona electric utilities regulated by the ACC, including APS.

I Effective January 1, 2001, retail access became available to all APS retail electricity customers.

I Electric service providers that get CC&Ns from the ACC can supply only competitive services, including electric generation, but not electric transmission and distribution.

I Affected utilities must file ACC tariffs that unbundle rates for noncompetitive services.

I The ACC shall allow a reasonable opportunity for recovery of unmitigated stranded costs.

p_45 I Absent an ACC waiver, prior to January 1, 2001, each affected utility (except certain electric cooperatives) must transfer all competitive electric assets and services either to an unaffiliated party or to a separate corporate affiliate.

Under the 1999 Settlement Agreement, APS received a waiver to allow transfer of its competitive electric assets and services to affiliates no later than December 31, 2002.

APS plans to complete the move of such assets by the end of 2002, as required, although the ACCs recent establish-ment of a generic docket to consider electric industry restructuring in Arizona and the consolidation of that docket with APS request for approval of a PPA between Pinnacle West and APS could affect APS ability to transfer assets to Pinnacle West Energy (see Proposed Rule Variance and Purchase Power Agreement above).

Provider of Last Resort Obligation. Although the Rules allow retail customers to have access to competitive providers of energy and energy services (see Retail Electric Competi-tion Rules below), APS is the provider of last resort for standard-offer, full-service customers under rates that have been approved by the ACC. These rates are established until July 1, 2004. The 1999 Settlement Agreement allows APS to seek adjustment of these rates in the event of emergency conditions or circumstances, such as the inability to secure financing on reasonable terms, or material changes in APS cost of service for ACC-regulated services resulting from federal, tribal, state or local laws, regulatory requirements, judicial decisions, actions or orders. Energy prices in the western wholesale market vary and, during the course of the last two years, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount included in APS current retail rates. In the event of shortfalls due to unforeseen increases in load demand or generation outages, APS may need to purchase additional supplemental power in the wholesale spot market. Unless APS is able to obtain an adjustment of its rates under the emergency provisions of the 1999 Settlement Agreement, there can be no assurance that APS would be able to fully recover the costs of this power.

1996 Regulatory Agreement. In April 1996, the ACC approved a regulatory agreement between the ACC Staff and APS. Based on the price reduction formula authorized in the agreement, the ACC approved retail price decreases (approximate) as follows (dollars in millions):

ANNUAL ELECTRIC PERCENTAGE REVENUE DECREASE DECREASE EFFECTIVE DATE

$49 3.4%

July 1, 1996

$18 1.2%

July 1, 1997

$17 1.1%

July 1, 1998

$11 0.7%

July 1, 1999(a)

(a) Included in the first rate reduction under the 1999 Settlement Agreement (see above).

The regulatory agreement also required that we infuse $200 million of common equity into APS in annual payments of

$50 million from 1996 through 1999. All of these equity infusions were made by December 31, 1999.

Legislation. In May 1998, a law was enacted to facilitate implementation of retail electric competition in Arizona.

The law includes the following major provisions:

I Arizonas largest government-operated electric utility (Salt River Project) and, at their option, smaller municipal electric systems must (i) make at least 20% of their 1995 retail peak demand available to electric service providers by December 31, 1998 and for all retail customers by December 31, 2000; (ii) decrease rates by at least 10%

over a ten-year period beginning as early as January 1, 1991; (iii) implement procedures and public processes comparable to those already applicable to public service corporations for establishing the terms, conditions, and pricing of electric services as well as certain other decisions affecting retail electric competition; I describes the factors which form the basis of consideration by Salt River Project in determining stranded costs; an I metering and meter reading services must be provided on a competitive basis during the first two years of competi-tion only for customers having demands in excess of one MW (and that are eligible for competitive generation services), and thereafter for all customers receiving competitive electric generation.

General We cannot accurately predict the impact of full retail compe-tition on our financial position, cash flows, results of opera-tions, or liquidity. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete in the new regulatory environment.

Federal In June 2001, the FERC adopted a price mitigation plan that constrains the price of electricity in the wholesale spot electricity market in the western United States. The plan remains in effect until September 30, 2002. We cannot accurately predict the overall financial impact of the plan on the various aspects of our business, including our wholesale and purchased power activities.

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

APS has recorded a regulatory asset related to income taxes on its balance sheets in accordance with SFAS No. 71. This regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction.

APS amortizes this amount as the differences reverse. In accordance with the 1999 Settlement Agreement, APS is continuing to accelerate its amortization of the regulatory asset for income taxes over an eight-year period that will end June 30, 2004 (see Note 1). We are including all regulatory asset amortization in depreciation and amortization expense

p_46 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 December 31, (dollars in thousands) 2001 2000 DEFERRED TAX ASSETS Deferred gain on Palo Verde Unit 2 sale/leaseback 25,374 27,056 Risk management and trading activities 73,043 15,002 Other 110,002 94,306 Total deferred tax assets 208,419 136,364 DEFERRED TAX LIABILITIES Plant-related 1,069,207 1,081,637 Regulatory asset for income taxes 121,757 172,082 Risk management and trading activities 85,692 19,892 Total deferred tax liabilities 1,276,656 1,273,611 Accumulated deferred income taxes - net

$ 1,068,237

$ 1,137,247 The components of the net deferred income tax liability as of December 31, 2001 and 2000 were as follows:

Investment Tax Credit Because of a 1994 rate settlement agreement, we accelerated amortization of substantially all of our ITCs over a five-year period that ended December 31, 1999.

Income Tax Benefit From Discontinued Operations In 1999, the income tax benefit from discontinued operations for $38 million resulted from resolution of tax issues related to a former subsidiary, MeraBank, A Federal Savings Bank.

5. LINES OF CREDIT APS had committed lines of credit with various banks of $250 million at December 31, 2001 and 2000, which were available either to support the issuance of commercial paper or to be used for bank borrowings. The commitment fees at December 31, 2001 and 2000 for these lines of credit were 0.09% per annum. APS had no bank borrowings outstanding under these lines of credit at December 31, 2001 and 2000.

APS commercial paper borrowings outstanding were

$171 million at December 31, 2001 and $82 million at December 31, 2000. The weighted average interest rate on commercial paper borrowings was 4.72% for the year ended December 31, 2001 and 6.64% for the year ended December 31, 2000. By Arizona statute, APS short-term borrowings cannot exceed 7% of its total capitalization unless approved by the ACC.

Pinnacle West had committed lines of credit with various banks of $250 million at December 31, 2001 and 2000, which were available either to support the issuance of commercial paper or to be used for bank borrowings.

The commercial paper program was launched in May 2001.

The commitment fees ranged from 0.10% to 0.15% in 2001 and 2000. There were no short-term bank borrowings out-standing at December 31, 2001 and $188 million outstand-ing at December 31, 2000. Pinnacle West commercial paper borrowings were $235 million at December 31, 2001. The weighted average interest rate on commercial paper borrow-ings was 3.50% for the year ended December 31, 2001.

SunCor had revolving lines of credit totaling $140 million at December 31, 2001 and $120 million at December 31, 2000. The commitment fees were 0.125% in 2001 and 2000.

SunCor had $128 million outstanding at December 31, 2001 and $110 million outstanding at December 31, 2000. The balance is included in long-term debt on the consolidated balance sheets (see Note 6).

year ended December 31, (dollars in thousands) 2001 2000 1999 Federal income tax expense at 35%

statutory rate

$ 189,316

$ 173,786

$ 143,977 Increases (reductions) in tax expense resulting from:

Preferred stock dividends of APS 356 ITC amortization (264) 740 (23,514)

State income tax net of federal income tax benefit 23,353 19,848 19,595 Other 1,130 (174) 1,178 Income tax expense

$ 213,535

$ 194,200

$ 141,592 The following chart compares pretax income at the 35%

federal income tax rate to income tax expense:

year ended December 31, (dollars in thousands) 2001 2000 1999 Current Federal

$ 184,893

$ 189,779

$ 171,491 State 45,845 42,306 37,501 Total Current 230,738 232,085 208,992 Deferred (16,939)

(38,625)

(43,886)

ITC amortization (264) 740 (23,514)

Total expense

$ 213,535

$ 194,200

$ 141,592 on our consolidated statements of income. The components of income tax expense for continuing operations are:

p_47 MATURITY INTEREST December 31, (dollars in thousands)

DATES (a)

RATES 2001 2000 APS First mortgage bonds 2002 8.125%

$ 125,000 125,000 2004 6.625%

80,000 80,000 2021 9.5%

45,140 2021 9.0%

72,370 2023 7.25%

54,150 70,650 2024 8.75%

121,668 121,668 2025 8.0%

33,075 33,075 2028 5.5%

25,000 25,000 2028 5.875%

154,000 154,000 Unamortized discount and premium (5,266)

(5,993)

Pollution control bonds 2024-2034 Adjustable rate(b) 386,860 476,860 Pollution control bonds 2029 3.30%(c) 90,000 Unsecured notes 2004 5.875%

125,000 125,000 Unsecured notes 2005 6.25%

100,000 100,000 Unsecured notes 2005 7.625%

300,000 300,000 Unsecured notes 2011 6.375%

400,000 Floating rate notes 2001 Adjustable rate(d) 250,000 Senior notes (e) 2006 6.75%

83,695 83,695 Capitalized lease obligation 2001-2003 7.75%

417 709 Capitalized lease obligation 2006 5.89%

926 Subtotal 2,074,525 2,057,174 SUNCOR Revolving credit 2003-2004 (f) 128,000 110,000 Notes payable 2001-2008 (g) 7,912 8,163 Bonds payable 2024 5.95%

5,215 5,215 Bonds payable 2026 6.75%

7,500 Subtotal 148,627 123,378 PINNACLE WEST Revolving credit 2001 (h) 188,000 Senior notes 2003-2006 (i) 325,000 50,000 Floating rate notes 2003 Adjustable rate(j) 250,000 Capitalized lease obligation 2004 7.75%

1,066 Subtotal 576,066 238,000 Total long-term debt 2,799,218 2,418,552 Less current maturities 126,140 463,469 TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES

$2,673,078

$1,955,083

6. LONG-TERM DEBT Borrowings under the APS mortgage bond indenture are secured by substantially all utility plant. APS also has unse-cured debt. SunCors debt is collateralized by interests in certain real property and Pinnacle Wests debt is unsecured. The following table presents the components of consolidated long-term debt outstanding at December 31, 2001 and 2000:

(a) This schedule does not reflect the timing of redemptions that may occur prior to maturity.

(b) The weighted-average rate for the year ended December 31, 2001 was 2.55% and for December 31, 2000 was 4.06%. Changes in short-term interest rates would affect the costs associated with this debt.

(c) In November 2001 these bonds were converted to a one year fixed rate of 3.30%. These bonds were previously adjustable rate and from January 1, 2001 until October 31, 2001 the weighted average rate was 2.72%.

(d) The weighted-average rate for the year ended December 31, 2000 was 7.33%. Interest for 2000 was based on LIBOR plus 0.72%.

(e) APS currently has outstanding $84 million of first mortgage bonds (senior note mortgage bonds) issued to the senior note trustee as collateral for the senior notes.

The senior note mortgage bonds have the same interest rate, interest payment dates, maturity, and redemption provisions as the senior notes. APS payments of principal, premium, and/or interest on the senior notes satisfy its corresponding payment obligations on the senior note mortgage bonds. As long as the senior note mortgage bonds secure the senior notes, the senior notes will effectively rank equally with the first mortgage bonds. When APS repays all of its first mortgage bonds, other than those that secure senior notes, the senior note mortgage bonds will no longer secure the senior notes and will cease to be outstanding.

(f) The weighted-average rate at December 31, 2001 was 5.31% and at December 31, 2000 was 8.61%. Interest for 2001 and 2000 was based on LIBOR plus 2% or prime plus 0.5%.

(g) Multiple notes primarily with variable interest rates based mostly on the lenders prime plus 1.75% and lenders prime plus.25%.

(h) The weighted-average rate at December 31, 2000 was 7.51%. Interest for 2000 was based on LIBOR plus 0.75%.

(i) Includes two series of notes: $25 million at 6.87% due in 2003 and $300 million at 6.4% due in 2006.

(j) The weighted average rate for the year ended December 31, 2001 was 4.65%. Interest for 2001 was based on LIBOR plus 0.98%.

p_48 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 The Pinnacle West and APS bank agreements have financial covenants including an interest coverage test and a debt ratio.

We anticipate that we will be able to meet the covenant requirement levels.

The following is a list of principal payments due on total long-term debt and sinking fund requirements through 2006:

I $125 million in 2002; I $318 million in 2003; I $507 million in 2004; I $401 million in 2005; and I $387 million in 2006.

APS first mortgage bondholders share a lien on substantially all utility plant assets (other than nuclear fuel and transpor-tation equipment and other excluded assets). The mortgage bond indenture restricts the payment of common stock dividends under certain conditions. These conditions did not exist at December 31, 2001.

The parent company has issued parental guarantees and obtained surety bonds on behalf of its unregulated sub-sidiaries, primarily for Pinnacle West Energys expansion plans and APSES retail and energy business.

7. RETIREMENT PLANS AND OTHER BENEFITS Pension Plan Through 1999, Pinnacle West and its subsidiaries each sponsored defined benefit pension plans for their own employees. As of January 1, 2000, these plans were consolidated and now a single pension plan is sponsored by Pinnacle West for the employees of Pinnacle West and its subsidiaries. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. The plan covers nearly all of our employees. Our employees do not contribute to this plan.

Generally, we calculate the benefits under this plan based on age, years of service, and pay. We fund the plan by contributing at least the minimum amount required under Internal Revenue Service regulations but no more than the maximum tax-deductible amount. The assets in the plan at December 31, 2001 were mostly domestic and international common stocks and bonds and real estate.

Pension expense, including administrative costs and after consideration of amounts capitalized or billed to electric plant participants, was:

I $7 million in 2001; I $2 million in 2000; and I $4 million in 1999.

The following table shows the components of net periodic pension cost before consideration of amounts capitalized or billed to electric plant participants:

(dollars in thousands) 2001 2000 1999 Service cost - benefits earned during the period 26,640 24,955 24,982 Interest cost on projected benefit obligation 62,920 58,361 52,905 Expected return on plan assets (77,340)

(77,231)

(68,335)

Amortization of:

Transition asset (3,227)

(3,227)

(3,226)

Prior service cost 2,716 2,078 2,078 Net actuarial gain (1,633)

Net periodic pension cost 11,709 3,303 8,404 (dollars in thousands) 2001 2000 Funded status - pension plan assets less than projected benefit obligation

$ (116,213) $

(20,730)

Unrecognized net transition asset (13,554)

(16,781)

Unrecognized prior service cost 24,465 18,558 Unrecognized net actuarial (gains)/losses 94,952 (23,816)

Net pension liability recognized in the consolidated balance sheets (10,350) $

(42,769)

(dollars in thousands) 2001 2000 Projected pension benefit obligation at beginning of year

$ 795,926

$ 742,638 Service cost 26,640 24,955 Interest cost 62,920 58,361 Benefit payments (31,647)

(30,568)

Actuarial losses 18,625 540 Plan amendments 8,622 Projected pension benefit obligation at end of year

$ 881,086

$ 795,926 The following table shows a reconciliation of the funded status of the plan to the amounts recognized in the consolidated balance sheets:

The following table sets forth the defined benefit pension plans change in projected benefit obligation for the plan years 2001 and 2000:

p_49 Employee Savings Plan Benefits Through 1999, Pinnacle West and its subsidiaries each sponsored defined contribution savings plans for their own employees. As of January 1, 2000, these plans were consolidated and now a single defined contribution savings plan is sponsored by Pinnacle West for the employees of Pinnacle West and its subsidiaries. In a defined contribution plan, the benefits a participant will receive result from regular contributions they make to a participant account.

Under this plan, we make matching contributions in Pinnacle West stock to participant accounts. At December 31, 2001 approximately 30% of total plan assets were in Pinnacle West stock. We recorded expenses for this plan of approximately

$5 million for 2001 and $4 million for 2000 and 1999.

Postretirement Plan Through 1999, Pinnacle West and its subsidiaries each sponsored postretirement plans for their own employees.

As of January 1, 2000, these plans were consolidated and now a single postretirement plan is sponsored by Pinnacle West for the employees of Pinnacle West and its subsidiaries. We provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plans, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions to cover a portion of the plan costs. We retain the right to change or eliminate these benefits.

(dollars in thousands) 2001 2000 1999 Service cost - benefits earned during the period 9,438 8,613 8,939 Interest cost on accu-mulated projected benefit obligation 21,585 19,315 17,366 Expected return on plan assets (21,985)

(22,381)

(18,454)

Amortization of:

Transition obligation 7,698 7,698 7,698 Net actuarial gains (4,066)

(7,983)

(5,117)

Net periodic postretirement benefit cost 12,670 5,262 10,432 The following table shows a reconciliation of the funded status of the plan to the amounts recognized in the consolidated balance sheets:

(dollars in thousands) 2001 2000 Funded status - post retirement plan assets less than projected benefit obligation (80,544) $

(14,851)

Unrecognized net obligation at transition 84,748 92,446 Unrecognized net actuarial gains (8,606)

(81,280)

Net postretirement amount recognized in the balance sheets (4,402) $

(3,685)

(dollars in thousands) 2001 2000 Fair value of pension plan assets at beginning of year

$ 775,196

$ 779,913 Actual gain/(loss) on plan assets (22,876) 1,851 Employer contributions 44,200 24,000 Benefit payments (31,647)

(30,568)

Fair value of pension plan assets at end of year

$ 764,873

$ 775,196 2001 2000 Discount rate 7.50%

7.75%

Rate of increase in compensation levels 4.00%

4.25%

Expected long-term rate of return on assets 10.00%

10.00%

The following table sets forth the defined benefit pension plans change in the fair value of plan assets for the plan years 2001 and 2000:

We made the assumptions below to calculate the pension liability:

Funding is based upon actuarially determined contributions that take tax consequences into account. Plan assets consist primarily of domestic stocks and bonds. The postretirement benefit expense after consideration of amounts capitalized or billed to electric plant participants, was:

I $6 million for 2001; I $3 million for 2000; and I $7 million for 1999.

The following table shows the components of net periodic postretirement benefit costs before consideration of amounts capitalized or billed to electric plant participants:

p_50 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 We made the assumptions below to calculate the postretire-ment liability:

2001 2000 Discount rate 7.50%

7.75%

Expected long-term rate of return on assets - after tax 8.86%

8.77%

Initial health care cost trend rate -

under age 65 7.00%

7.00%

Initial health care cost trend rate -

age 65 and over 7.00%

6.00%

Ultimate health care cost trend rate 5.00%

5.00%

Year ultimate health care trend rate is reached 2006 2002 1%

1%

(dollars in millions)

INCREASE DECREASE Effect on 2001 cost of postretirement benefits other than pensions 6

(5)

Effect on the accumulated postretirement benefit obligation at December 31, 2001 54 (43)

The following table shows the effect of a 1% increase or decrease in the health care cost trend rate:

8. LEASES In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale-leaseback transactions. APS accounts for these leases as operating leases. The gain of approximately $140 million was deferred and is being amortized to operations expense over 29.5 years, the original term of the leases. There are options to renew the leases for two additional years and to purchase the property for fair market value at the end of the lease terms. Consistent with the ratemaking treatment, an amount equal to the annual lease payments is included in rent expense. A regulatory asset is recognized for the differ-ence between lease payments and rent expense calculated on a straight-line basis. See Note 2 for a discussion of special purpose entities, including the special purpose enti-ties involved in the Palo Verde sale-leaseback transactions.

The average amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year for the years 2002-2015.

In accordance with the 1999 Settlement Agreement, APS is continuing to accelerate amortization of the regulatory asset for leases over an eight-year period that will end June 30, 2004 (see Note 1). All regulatory asset amortization is included in depreciation and amortization expense in the consolidated statements of income. The balance of this regulatory asset at December 31, 2001 was $24 million.

In December 2000, APS purchased Units 1, 2, and 3 of West Phoenix Power Plant, which was previously leased under a capitalized lease obligation.

In addition, we lease certain land, buildings, equipment, and miscellaneous other items through operating rental agree-ments with varying terms, provisions, and expiration dates.

Total lease expense was $56 million in 2001, $58 million in 2000, and $52 million in 1999.

Estimated future minimum lease commitments, are approximately as follows (dollars in millions):

YEAR 2002 68 2003 66 2004 65 2005 64 2006 63 Thereafter 543 Total future commitments 869 The following table sets forth the postretirement benefit plans change in the fair value of plan assets for the plan years 2001 and 2000:

(dollars in thousands) 2001 2000 Fair value of postretirement plan assets at beginning of year

$ 249,154

$ 257,538 Actual loss on plan assets (12,550)

(4,436)

Employer contributions 11,400 4,958 Benefit payments (10,194)

(8,906)

Fair value of postretirement plan assets at end of year

$ 237,810

$ 249,154 The following table sets forth the postretirement benefit plans change in accumulated benefit obligation for the plan years 2001 and 2000:

(dollars in thousands) 2001 2000 Accumulated postretirement benefit obligation at beginning of year

$ 264,006

$ 231,989 Service cost 9,438 8,613 Interest cost 21,585 19,315 Benefit payments (10,194)

(8,905)

Actuarial losses 33,520 12,994 Accumulated postretirement benefit obligation at end of year

$ 318,355

$ 264,006

p_51

9. JOINTLY-OWNED FACILITIES APS shares ownership of some of its generating and trans-mission facilities with other companies. The following table shows APS interest in those jointly-owned facilities recorded on the consolidated balance sheets at December 31, 2001.

APS share of operating and maintaining these facilities is included in the income statement in operations and mainte-nance expense. Each participant is entitled to its share of power generated.

PERCENT CONSTRUCTION OWNED BY PLANT IN ACCUMULATED WORK IN (dollars in thousands)

COMPANY SERVICE DEPRECIATION PROGRESS Generating Facilities:

Palo Verde Nuclear Generating Station Units 1 and 3 29.1%

$ 1,822,369 (862,880) 10,984 Palo Verde Nuclear Generating Station Unit 2 (see Note 8) 17.0%

571,217 (278,234) 46,284 Four Corners Steam Generating Station Units 4 and 5 15.0%

150,298 (78,983) 503 Navajo Steam Generating Station Units 1, 2, and 3 14.0%

235,409 (104,189) 1,044 Cholla Steam Generating Station Common Facilities (a) 62.8%(b) 74,356 (41,555) 1,093 Transmission Facilities:

ANPP 500KV System 35.8%(b) 67,911 (24,293) 405 Navajo Southern System 31.4%(b) 27,053 (16,833) 202 Palo Verde - Yuma 500KV System 23.9%(b) 9,685 (4,029) 8 Four Corners Switchyards 27.5%(b) 3,071 (1,945)

Phoenix - Mead System 17.1%(b) 36,418 (2,766)

Palo Verde - Estrella 500KV system 50.0%(b) 2,215 (a) PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at the Cholla Plant are jointly-owned.

(b)Weighted average of interests.

10. COMMITMENTS AND CONTINGENCIES Enron We recorded charges totaling $21 million before income taxes for exposure to Enron and its affiliates in the fourth quarter of 2001. This amount is comprised of a $15 million reserve for the Companys net exposure to Enron and its affil-iates, and additional expenses of $6 million primarily related to 2002 power contracts with Enron that were cancelled.

Power Service Agreement By letter dated March 7, 2001, Citizens, which owns a utility in Arizona, advised APS that it believes APS has overcharged Citizens by over $50 million under a power service agreement. APS believes that its charges under the agreement were fully in accordance with the terms of the agreement. In addition, in testimony filed with the ACC March 13, 2002, Citizens acknowledged that, based on its review, if Citizens filed a complaint with FERC, it proba-bly would lose the central issue in the contract interpreta-tion dispute. APS and Citizens terminated the power service agreement effective July 15, 2001. In replacement of the power service agreement, the Company and Citizens entered into a power sale agreement under which the Company will supply Citizens with specified amounts of electricity and ancillary services through May 31, 2008.

This new agreement does not address issues previously raised by Citizens with respect to charges under the original power service agreement through June 1, 2001.

SunCor On March 15, 2001, a jury returned a verdict against SunCor in the amount of $28.6 million, $25.7 million of which represented a punitive damage award, in a lawsuit in Maricopa County, Arizona, Superior Court entitled SunCor Development Company v. Bergstrom Corporation, CV 98-11472. The verdict was based on the Bergstrom Corporations claims that it was defrauded in connection with the acquisition of approximately ten acres of land in a SunCor commercial development and a subsequent settle-ment agreement relating to those claims. On December 14, 2001, the Court ruled that the jury award was constitution-ally excessive and reduced the punitive damage award to

$5 million. Following this ruling, SunCor settled the matter for an amount that did not have a material impact on our 2001 results of operations.

Palo Verde Nuclear Generating Station Nuclear power plant operators are required to enter into spent fuel disposal contracts with DOE, and DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Act required DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before 2010, and that it does not intend to begin accepting spent fuel prior to that date. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C.

Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and DOEs delay, a number of utilities filed damages actions against DOE in the Court of Federal Claims.

p_52 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 In February 2002 the Secretary of Energy recommended to President Bush that the Yucca Mountain, Nevada site be developed as a permanent repository for spent nuclear fuel. The President transmitted this recommendation to Congress. A congressional decision on this issue is expected sometime during mid-summer 2002. We cannot currently predict what further steps will be taken in this area.

APS has existing fuel storage pools at Palo Verde and is in the process of completing construction of a new facility for on-site dry storage of spent fuel. With the existing storage pools and the addition of the new facility, APS believes that spent fuel storage or disposal methods will be available for use by Palo Verde to allow its continued operation through the term of the operating license for each Palo Verde unit.

Although some low-level waste has been stored on-site in a low-level waste facility, APS is currently shipping low-level waste to off-site facilities. APS currently believes that inter-im low-level waste storage methods are or will be available for use by Palo Verde to allow its continued operation and to safely store low-level waste until a permanent disposal facility is available.

APS currently estimates that it will incur $407 million (in 2001 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. As of December 31, 2001, APS had recorded a liability and regulatory asset of $43 million for on-site interim nuclear fuel storage costs related to nuclear fuel burned to date.

The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insur-ance carriers in the amount of $200 million and the balance by an industry-wide retrospective assessment program. If loss-es at any nuclear power plant covered by the programs exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately

$88 million, subject to an annual limit of $10 million per incident. Based upon our interest in the three Palo Verde units, our maximum potential assessment per incident for all three units is approximately $77 million, with an annual payment limitation of approximately $9 million.

The Palo Verde participants maintain all risk (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination.

APS has also secured insurance against portions of any increased cost of generation or purchased power and busi-ness interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

Fuel and Purchased Power Commitments APS and Pinnacle West are party to various fuel and purchased power contracts with terms expiring from 2002 through 2021 that include required purchase provisions.

We estimate the contract requirements to be approximately

$270 million in 2002; $124 million in 2003; $80 million in 2004; $65 million in 2005; and $68 million in 2006.

However, this amount may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.

Coal Mine Reclamation Obligations APS must reimburse certain coal providers for amounts incurred for coal mine reclamation. APS estimates its share of the total obligation to be about $103 million. The por-tion of the coal mine reclamation obligation related to coal already burned is about $59 million at December 31, 2001 and is included in deferred credits-other in the consolidated balance sheets.

A regulatory asset has been established for amounts not yet recovered from ratepayers related to the coal obligations. In accordance with the 1999 Settlement Agreement with the ACC, APS is continuing to accelerate the amortization of the regulatory asset for coal mine reclamation over an eight-year period that will end June 30, 2004. Amortization is included in depreciation and amortization expense on the statements of income.

California Energy Market Issues and Refunds in the Pacific Northwest SCE and PG&E have publicly disclosed that their liquidity has been materially and adversely affected because of, among other things, their inability to pass on to ratepayers the prices each has paid for energy and ancillary services procured through the PX and the ISO.

We are closely monitoring developments in the California energy market and the potential impact of these develop-ments on us and our subsidiaries. We have evaluated, among other things, SCEs role as a Palo Verde and Four Corners participant; APS transactions with the PX and the ISO; contractual relationships with SCE and PG&E; APSES retail transactions involving SCE and PG&E; and marketing and trading exposures. Based on our evaluations, we have reserved $10 million before income taxes for our credit exposure related to the California energy situation,

$5 million of which was recorded in the fourth quarter of 2000 and $5 million of which was recorded in first quarter of 2001. We cannot predict with certainty, however, the impact that any future resolution or attempted resolution, of the California energy market situation may have on us or our subsidiaries or the regional energy market in general.

In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. This order calls for a hearing, with findings of fact due to the FERC after the California ISO and PX provide necessary historical data.

p_53 The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The ALJ at the FERC in charge of that evidentiary proceeding made an initial finding that no refunds were appropriate.

The Pacific Northwest issues will now be addressed by the FERC Commissioners. Although the FERC has not yet made a final ruling in the Pacific Northwest matter or calculated the specific refund amounts due in California, we do not expect that the resolution of these issues, as to the amounts alleged in the proceedings, will have a material adverse impact on our financial position, results of operations or liquidity.

On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including Pinnacle West, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present. State of California v.

British Columbia Power Exchange et. Al., Docket No. EL02-71-000. The complaint requests the FERC to require the wholesale sellers to refund any rates that are found to exceed just and reasonable levels. The complaint indicates that Pinnacle West sold approximately $106 million of power to the California Department of Water Resources from January 17, 2001 to October 31, 2001 and does not allege any amount above just and reasonable levels. We believe that the claims as they relate to Pinnacle West are without merit.

Construction Program Consolidated capital expenditures in 2002 are estimated to be:

(dollars in millions) 2002 APS 498 Pinnacle West Energy 411 SunCor 79 Other (primarily APSES and Pinnacle West) 35 Total 1,023 Generation Expansion Pinnacle West Energy has completed or announced plans to build about 3,420 MW of natural gas-fired generating capacity from 2000 through 2007 at an estimated cost of about $1.9 billion. This does not reflect an expected reim-bursement in 2004 by SNWA of $100 million of Pinnacle West Energys cumulative capital expenditures in the Silverhawk project in exchange for SNWA purchase of a 25%

interest in the project. Our expansion plan will be sized to meet native load growth, cash flow and market conditions.

Pinnacle West Energy is currently funding its capital require-ments through capital infusions from Pinnacle West, which finances those infusions through debt financings and internal-ly-generated cash. As Pinnacle West Energy develops and obtains additional generation assets, including APS existing generation assets, Pinnacle West Energy expects to fund its capital requirements through internally-generated cash and its own debt issuances.

Pinnacle West Energy has completed or is currently planning the following projects:

I A 650 MW expansion of the West Phoenix Power Plant in Phoenix. The 120 MW West Phoenix Unit 4 began commercial operation on June 1, 2001. Construction has begun on the 530 MW West Phoenix Unit 5, with commercial operation expected to begin in mid-2003.

I The construction of a four-unit combined cycle 2,120 MW generating station near Palo Verde, called Redhawk.

Construction of Units 1 and 2 began in December 2000, and commercial operation is currently scheduled for the summer of 2002. Although Pinnacle West Energy currently plans to bring Units 3 and 4 on line in or before the first quarter of 2007, equipment procurement, engineering and construction plans will allow for these units to come on line as early as 2005 if warranted by market conditions.

I The construction of an 80 MW simple-cycle power plant at Saguaro in Southern Arizona. Commercial operation is currently scheduled for the summer of 2002.

I Development of an electric generating station 20 miles north of Las Vegas, Nevada. Construction of the 570 MW Silverhawk combined-cycle plant is expected to begin in the spring of 2002, with an expected commercial operation date of mid-2004. Pinnacle West Energy has signed a 25% participation agreement with Las Vegas-based SNWA.

I A Pinnacle West Energy affiliate is exploring the possibility of creating an underground natural gas storage facility on Company-owned land west of Phoenix. A feasibility study is in progress to determine if the proposed acreage can support a natural gas storage cavern.

Litigation We are party to various claims, legal actions, and complaints arising in the ordinary course of business. In our opinion, the ultimate resolution of these matters will not have a mate-rial adverse effect on our financial statements or liquidity.

11. NUCLEAR DECOMMISSIONING COSTS APS recorded $11 million for nuclear decommissioning expense in each of the years 2001, 2000, and 1999. APS estimates it will cost about $1.8 billion ($506 million in 2001 dollars) to decommission its share of the three Palo Verde units. The majority of decommissioning costs are expected to be incurred over a 14-year period beginning in 2024. APS charges decommissioning costs to expense over each units operating license term and includes them in the accumulated depreciation balance until each unit is retired.

Nuclear decommissioning costs are recovered in rates.

APS current estimates are based on a 2001 site-specific study for Palo Verde that assumes the prompt removal/dis-mantlement method of decommissioning. An independent consultant prepared this study. APS is required to update the study every three years.

p_54 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

12. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

Consolidated quarterly financial information for 2001 and 2000 is as follows:

(dollars in thousands, except per share amounts) 2001 QUARTER ENDED MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 Operating revenues (a)

Electric 906,494

$ 1,261,358

$ 1,531,005 683,608 Real estate 32,335 32,454 43,024 61,095 Operating income 136,063 138,888 298,606 101,070 Income from continuing operations 62,205 66,857 162,499 35,806 Cumulative effect of change in accounting -

net of income tax (2,755)

(12,446)

Net income 59,450 66,857 150,053 35,806 Earnings (loss) per weighted average common share outstanding - basic Continuing operations - basic 0.73 0.79 1.92 0.42 Cumulative effect of change in accounting - basic (0.03)

(0.15)

Earnings per weighted average common share outstanding - basic 0.70 0.79 1.77 0.42 Earnings (loss) per weighted average common share outstanding - diluted Continuing operations - diluted 0.73 0.79 1.91 0.42 Cumulative effect of change in accounting - diluted (0.03)

(0.14)

Earnings per weighted average common share outstanding - diluted 0.70 0.79 1.77 0.42 Dividends declared per share 0.375 0.375 0.375 0.40 To fund the costs APS expects to incur to decommission the plant, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds primarily in fixed income securities and domestic stock and classifies them as available for sale. Realized and unrealized gains and losses are reflected in accumulated depreciation in accordance with industry practice. The following table shows the cost and fair value of our nuclear decommissioning trust fund assets which are reported in investments and other assets on the consolidated balance sheets at December 31, 2001 and 2000:

See Note 2 for information on a new accounting standard on accounting for certain liabilities related to closure or removal of long-lived assets.

(dollars in millions) 2001 2000 Trust fund assets - at cost Fixed income securities 103 94 Domestic stock 61 52 Total 164 146 Trust fund assets - fair value Fixed income securities 106 97 Domestic stock 96 100 Total 202 197

p_55

13. FAIR VALUE OF FINANCIAL INSTRUMENTS We believe that the carrying amounts of our cash equiva-lents and commercial paper are reasonable estimates of their fair values at December 31, 2001 and 2000 due to their short maturities.

We hold investments in debt and equity securities for purposes other than trading. The December 31, 2001 and 2000 fair values of such investments, which we determine by using quoted market values, approximate their carrying amount.

On December 31, 2001, the carrying value of our long-term debt (excluding a capitalized lease obligation) was

$2.80 billion, with an estimated fair value of $2.82 billion.

The carrying value of our long-term debt (excluding a capitalized lease obligation) was $2.42 billion on December 31, 2000, with an estimated fair value of $2.48 billion.

The fair value estimates are based on quoted market prices of the same or similar issues.

14. EARNINGS PER SHARE The following table presents earnings per weighted average common share outstanding (EPS):

2001 2000 1999 Basic EPS:

Continuing operations 3.86 3.57 3.18 Discontinued operations 0.45 Extraordinary charge (1.65)

Cumulative effect of change in accounting (0.18)

Earnings per share - basic 3.68 3.57 1.98 Diluted EPS:

Continuing operations 3.85 3.56 3.17 Discontinued operations 0.45 Extraordinary charge (1.65)

Cumulative effect of change in accounting (0.17)

Earnings per share - diluted 3.68 3.56 1.97 Dilutive stock options increased average common shares outstanding by 212,491 shares in 2001, 202,738 shares in 2000, and 291,392 shares in 1999. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 84,930,140 shares in 2001, 84,935,282 shares in 2000, and 85,008,527 shares in 1999.

Options to purchase 212,562 shares of common stock were outstanding at December 31, 2001 but were not included in the computation of diluted EPS because the options exercise price was greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted EPS were 517,614 at December 31, 2000 and 506,734 at December 31, 1999.

15. STOCK-BASED COMPENSATION Pinnacle West offers two stock incentive plans for officers and key employees of our company and our subsidiaries.

One of the plans (1994 plan) provides for the granting of new options (which may be non-qualified stock options or incentive stock options) of up to 3.5 million shares at a price per option not less than the fair market value on the date the option is granted. The other plan (1985 plan) includes outstanding options but no new options will be granted from this plan. Options vest one-third of the grant per year beginning one year after the date the option is granted and expire ten years from the date of the grant.

The plan also provides for the granting of any combination of shares of restricted stock, stock appreciation rights or dividend equivalents.

The awards outstanding under the incentive plans at December 31, 2001, are 1,832,725 non-qualified stock options, 237,833 shares of restricted stock, and no incentive stock options, stock appreciation rights or dividend equivalents.

(dollars in thousands, except per share amounts) 2000 QUARTER ENDED MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 Operating revenues (a)

Electric 446,228 720,174

$ 1,567,960 797,448 Real estate 41,889 36,374 39,396 40,706 Operating income 91,565 190,942 241,264 117,976 Net income 54,070 89,901 116,049 42,312 Earnings per weighted average common share outstanding Net income - basic 0.64 1.06 1.37 0.50 Net income - diluted 0.64 1.06 1.37 0.50 Dividends declared per share 0.35 0.35 0.35 0.375 (a) Electric revenues are seasonal in nature, with the peak sales periods generally occurring during the summer months. Comparisons among quarters of a year may not represent overall trends and changes in operations.

p_56 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 The following table is a summary of the status of our stock option plans as of December 31, 2001, 2000, and 1999 and changes during the years ending on those dates:

2001 WEIGHTED 2000 WEIGHTED 1999 WEIGHTED 2001 AVERAGE 2000 AVERAGE 1999 AVERAGE (dollars in thousands)

SHARES EXERCISE PRICE SHARES EXERCISE PRICE SHARES EXERCISE PRICE Outstanding at beginning of year 1,569,171 37.55 1,441,124 33.45 1,563,512 27.95 Granted 444,200 42.55 451,450 43.28 458,450 35.95 Exercised (162,229) 28.53 (283,819) 20.90 (516,838) 18.19 Forfeited (18,417) 41.67 (39,584) 39.86 (64,000) 40.36 Outstanding at end of year 1,832,725 39.52 1,569,171 37.55 1,441,124 33.45 Options exercisable at year-end 926,315 37.41 831,537 34.37 835,381 29.69 Weighted average fair value of options granted during the year 8.84 11.81 7.05 The following table summarizes information about our stock option plans at December 31, 2001:

WEIGHTED AVERAGE EXERCISE OPTIONS WEIGHTED-AVERAGE REMAINING OPTIONS WEIGHTED-AVERAGE PRICES PER SHARE OUTSTANDING EXERCISE PRICE CONTRACT LIFE (YEARS)

EXERCISABLE EXERCISE PRICE

$14.03-18.71 15,150 18.09 0.5 15,150 18.09 18.71-23.39 88,284 20.53 2.3 88,284 20.53 23.39-28.07 78,167 27.39 4.6 64,834 27.44 28.07-32.75 72,250 31.44 4.8 72,250 31.44 32.75-37.42 285,024 34.69 7.7 165,245 34.69 37.42-42.10 217,500 40.15 6.1 175,500 39.95 42.10-46.78 1,076,350 43.96 8.8 345,052 45.70 1,832,725 926,315 2001 2000 1999 Risk-free interest rate 4.08%

5.81%

5.68%

Dividend yield 3.70%

3.48%

3.33%

Volatility 27.66%

32.00%

20.50%

Expected life (months) 60 60 60 In order to present the pro forma information above, we calculated the fair value of each fixed stock option in the incentive plans using the Black-Scholes option-pricing model. The fair value was calculated based on the date the option was granted. The following weighted-average assumptions were also used in order to calculate the fair value of the stock options:

(dollars in thousands) 2001 2000 1999 Net income As reported

$312,166

$302,332

$167,887 Pro forma (fair value method)

$309,800

$301,102

$166,913 Earnings per share -

basic As reported 3.68 3.57 1.98 Pro forma (fair value method) 3.66 3.55 1.97 SFAS No. 123, Accounting for Stock-Based Compensation encourages, but does not require, that a company record compensation expense based on the fair value of options granted (the fair value method). We continue to recognize expense based on Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees.

If we had recorded compensation expense based on the fair value method, our net income and earnings per share would have been reduced to the following pro forma amounts:

p_57

16. BUSINESS SEGMENTS We have two principal business segments (determined by products, services and regulatory environment), which consist of regulated retail electricity business and related activities (retail business segment) and competitive business activities (marketing and trading segment). Our retail business segment currently includes activities related to electricity transmission and distribution, as well as electricity generation. Our marketing and trading business segment currently includes activities related to wholesale marketing and trading and APSES competitive energy services.

These reportable segments reflect a change in the reporting of our segment information. Before the fourth quarter of 2001, we had two segments (generation and delivery). The generation segment information combined our marketing and trading activities with our generation of electricity activities. The delivery segment included transmission and distribution activities.

In the fourth quarter of 2001, APS filed with the ACC a proposed rule variance and purchase power agreement with the ACC (see Note 3) that inherently views our business in the new reportable segments described above. Internal man-agement reporting has been changed to reflect this align-ment. The corresponding information for earlier periods has been restated. The other amounts include activity relating to the parent company and other subsidiaries including SunCor and El Dorado. Financial data for the business segments is provided as follows:

BUSINESS SEGMENTS FOR THE YEAR ENDED DECEMBER 31, 2001 MARKETING (dollars in millions)

RETAIL AND TRADING OTHER TOTAL Operating revenues 2,562 1,820 169 4,551 Purchased power and fuel costs 1,161 1,503 2,664 Other operating expenses 602 32 156 790 Operating margin 799 285 13 1,097 Depreciation and amortization 423 1

4 428 Interest and other expenses 124 4

128 Pretax margin 252 284 5

541 Income taxes 100 112 2

214 Income from continuing operations 152 172 3

327 Cumulative effect of change in accounting for derivatives - net of income taxes of $10 (15)

(15)

Net income 137 172 3

312 Total assets 6,938 556 488 7,982 Capital expenditures 1,004 23 102 1,129 BUSINESS SEGMENTS FOR THE YEAR ENDED DECEMBER 31, 2000 MARKETING (dollars in millions)

RETAIL AND TRADING OTHER TOTAL Operating revenues 2,539 993 158 3,690 Purchased power and fuel costs 1,066 867 1,933 Other operating expenses 538 21 126 685 Operating margin 935 105 32 1,072 Depreciation and amortization 425 1

5 431 Interest and other expenses 141 4

145 Pretax margin 369 104 23 496 Income taxes 144 41 9

194 Net income 225 63 14 302 Total assets 6,326 386 451 7,163 Capital expenditures 665 50 715

p_58 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

17. DERIVATIVE INSTRUMENTS We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal and emissions allowances. We employ established procedures to manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options, and swaps. As part of our overall risk management program, we enter into derivative transactions to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodity. In addition, subject to specified risk parameters established by the Board of Directors and monitored by the Energy Risk Management Committee, we engage in trading activities intended to profit from market price movements.

We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including one counterparty for which a worst case exposure represents approximately 50% of our $267 million of risk manage-ment and trading assets as of December 31, 2001. We use a risk management process to assess and monitor the financial exposure of this and all other counterparties. Despite the fact that the great majority of trading counterparties are rated as investment grade by the credit rating agencies, including the counterparty noted above, there is still a pos-sibility 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 prin-cipally of 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 counter-parties is based upon a number of factors, including credit ratings, and our evaluation of their financial condition. In many contracts, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.

Credit reserves are established representing our estimated credit losses on our overall exposure to counterparties. See Note 1 for a discussion of our credit reserve policy.

Effective January 1, 2001, we adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheets and measure those instruments at fair value. Changes in the fair value of derivative financial instruments are either recog-nized periodically in income or shareholders equity (as a component of other comprehensive income), depending on whether or not the derivative meets specific hedge account-ing criteria. Hedge effectiveness is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in the fair value resulting from ineffectiveness is recognized immediately in net income. This new standard may result in additional volatility in our net income and comprehensive income.

As a result of adopting SFAS No. 133, we recognized $118 million of derivative assets and $16 million of derivative liabilities in our consolidated balance sheets as of January 1, 2001. Also as of January 1, 2001, we recorded a $3 million after-tax loss in net income and a $64 million after-tax gain in equity (as a component of other comprehensive income) both as a cumulative effect of a change in accounting principle. The gain resulted from unrealized gains on cash flow hedges.

In June 2001, the FASB issued new guidance related to electricity contracts. The effective date of this new guidance was July 1, 2001. As of July 1, 2001, we recorded an additional $12 million after-tax loss in net income and an additional $8 million after-tax gain in equity (as a BUSINESS SEGMENTS FOR THE YEAR ENDED DECEMBER 31, 1999 MARKETING (dollars in millions)

RETAIL AND TRADING OTHER TOTAL Operating revenues 1,916 377 130 2,423 Purchased power and fuel costs 433 360 793 Other operating expenses 549 9

95 653 Operating margin 934 8

35 977 Depreciation and amortization 417 3

420 Interest and other expenses 142 3

145 Pretax margin 375 8

29 412 Income taxes 129 3

10 142 Income from continuing operations 246 5

19 270 Income tax benefit from discontinued operations 38 38 Extraordinary charge - net of income taxes of $94 (140)

(140)

Net income 144 5

19 168 Capital expenditures 353 126 479

p_59 component of other comprehensive income), as a result of adopting the new guidance related to electricity contracts.

The loss resulted primarily from electricity options con-tracts. The gain resulted from unrealized gains on cash flow hedges. The impact of the new guidance is reflected in net income and other comprehensive income as a cumulative effect of change in accounting principle.

In December 2001, the FASB issued revised guidance on the accounting for electricity contracts with option charac-teristics and the accounting for contracts that combine a forward contract and a purchased option contract. The effective date for the revised guidance is April 1, 2002.

We are currently evaluating the new guidance to determine what impact, if any, it will have on our financial statements.

The change in derivative fair value included in the consolidated statements of income for the year ending December 31, 2001 is comprised of the following:

December 31, (dollars in thousands) 2001 Ineffective portion of derivatives qualifying for hedge accounting (a)

(8,371)

Discontinuance of cash flow hedges for forecasted transactions that will not occur (9,525)

Reclassification of mark-to-market losses to realized 25,948 Total 8,052 The following table summarizes our assets and liabilities from risk management and trading activities related to CURRENT CURRENT OTHER NET December 31, 2001 ASSETS INVESTMENTS LIABILITIES LIABILITIES ASSET(LIABILITY)

Mark-to-market:

Trading 56,876 148,457 (14,154)

(53,253) 137,926 System 10,097 (21,840)

(95,159)

(106,902)

Trading - at cost 51,894 (59,164)

(7,270)

Total 66,973 200,351 (35,994)

(207,576) 23,754 CURRENT CURRENT OTHER NET December 31, 2000 ASSETS INVESTMENTS LIABILITIES LIABILITIES ASSET (LIABILITY)

Trading - mark-to-market 17,506 32,955 (37,179)

(877) 12,405 Trading - at cost (13,834)

(13,834)

Total 17,506 32,955 (37,179)

(14,711)

(1,429)

Net gains and losses on instruments utilized for trading activities are recognized in marketing and trading revenues on a current basis (the mark-to-market method). Trading positions are measured at fair value as of the balance sheet date. The unrealized trading gains recognized in marketing and trading revenues were $127 million for the year ended December 31, 2001 and $14 million for the year ended December 31, 2000.

18. SUBSEQUENT EVENTS On February 8, 2002, Pinnacle West issued $215 million of 4.5% Notes due 2004. On March 1, 2002, APS issued

$375 million of 6.50% Notes due 2012. On March 15, 2002, APS announced the redemption on April 15, 2002 of approximately $125 million of its First Mortgage Bonds, 8.75% series during 2024.

(a) Time value component of options excluded from assessment of hedge effectiveness.

As of December 31, 2001, the maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted transactions is thirty-six months.

During the twelve months ended December 31, 2002, we estimate that a net loss of $23 million before income taxes will be reclassified from accumulated other comprehensive loss as an offset to the effect on earnings of market price changes for the related hedged transaction.

On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including Pinnacle West, failed to properly file rate information at the FERC in connection with sales to California from 2000 to present. State of California v. British Columbia Power Exchange et. Al., Docket No. EL02-71-000.

The complaint requests the FERC to require the wholesale sellers to refund any rates that are found to exceed just and reasonable levels. The complaint indicates that Pinnacle West sold approximately $106 million of power to California Department of Water Resources from January 17, 2001 to October 31, 2001 and does not allege any amount above just and reasonable levels. We believe that the claims as they relate to Pinnacle West are without merit.

See Note 3 for information relating to the March 22, 2002 ACC Staff report addressing issues in the generic docket.

trading and system (retail and traditional wholesale activities) as of December 31, 2001 and 2000 (dollars in thousands):

p_60 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 PAMELA GRANT (63) 1980*

Civic Leader Committees:

Human Resources, Chairman Audit MARTHA O. HESSE (59) 1991 President, Hesse Gas Company Committees:

Audit, Chairman Finance and Operating THE REV. BILL JAMIESON, JR.

(58) 1991 President, Institute for Servant Leadership of Asheville, North Carolina Committee:

Human Resources ROY A. HERBERGER, JR.

(59) 1992 President, Thunderbird, The American Graduate School of International Management Committees:

Finance and Operating, Chairman Human Resources ROBERT G. MATLOCK (68) 1993 Management Consultant R.G. Matlock & Associates, Inc.

Committee:

Human Resources WILLIAM J. POST (51) 1994 Chairman of the Board &

Chief Executive Officer Committee:

Finance and Operating HUMBERTO S. LOPEZ (56) 1995 President, HSL Properties, Inc.

Committee:

Audit MICHAEL L. GALLAGHER (57) 1997 Chairman Emeritus Gallagher & Kennedy, P.A.

Committee:

Human Resources BRUCE J. NORDSTROM (52) 1997 Certified Public Accountant, Nordstrom and Associates, P.C.

Committee:

Audit JACK E. DAVIS (55) 1998 President Committee:

Finance and Operating WILLIAM L. STEWART (58) 1998 President, Pinnacle West Energy EDDIE BASHA (64) 1999 Chairman of the Board, Bashas Committee:

Audit KATHRYN L. MUNRO (53) 1999 Chairman, BridgeWest L.L.C.

Committee:

Finance and Operating

• The year in which the individual first joined the Board of a Pinnacle West company.

BOARD OF DIRECTORS

p_61 PINNACLE WEST William J. Post (51) 1973*

Chairman of the Board &

Chief Executive Officer Jack E. Davis (55) 1973 President Armando B. Flores (58) 1991 Executive Vice President, Corporate Business Services Steven M. Wheeler (53) 2001 Senior Vice President, Transmission, Regulation & Planning Robert S. Aiken (45) 1986 Vice President, Federal Affairs John G. Bohon (56) 1971 Vice President, Corporate Services &

Human Resources Dennis L. Brown (51) 1973 Vice President &

Chief Information Officer Edward Z. Fox (48) 1995 Vice President, Communications, Environment & Safety Chris N. Froggatt (44) 1986 Vice President & Controller David A. Hansen (42) 1980 Vice President, Bulk Power Marketing & Trading Nancy C. Loftin (48) 1985 Vice President & General Counsel Michael V. Palmeri (43) 1982 Vice President, Finance Donald G. Robinson (48) 1978 Vice President, Regulation & Planning Martin L. Shultz (57) 1979 Vice President, Government Affairs Faye Widenmann (53) 1978 Vice President & Secretary Barbara M. Gomez (47) 1978 Treasurer ARIZONA PUBLIC SERVICE William J. Post Chairman of the Board &

Chief Executive Officer Jack E. Davis President, Energy Delivery & Sales William L. Stewart (58) 1994 President, Generation Steven M. Wheeler Senior Vice President Transmission, Regulation & Planning Michael V. Palmeri Vice President, Finance Faye Widenmann Vice President & Secretary Nancy C. Loftin Vice President & General Counsel Barbara M. Gomez Treasurer Jan H. Bennett (54) 1967 Vice President, Customer Service James M. Levine (52) 1989 Executive Vice President, Generation Gregg R. Overbeck (55) 1990 Senior Vice President, Nuclear Generation John R. Denman (59) 1964 Vice President, Fossil Generation William E. Ide (55) 1977 Vice President, Nuclear Production David Mauldin (52) 1990 Vice President, Nuclear Engineering & Support PINNACLE WEST ENERGY William L. Stewart President James M. Levine Chief Operating Officer Ajoy K. Banerjee (56) 1999 Vice President, Generation Expansion Ajit P. Bhatti (56) 1973 Vice President, Generation Planning Warren C. Kotzmann (52) 1989 Vice President, Business &

Corporate Services APS ENERGY SERVICES Vicki G. Sandler (45) 1982 President, Energy Services SUNCOR DEVELOPMENT William J. Post Chairman of the Board John C. Ogden (56) 1972 President & Chief Executive Officer Geoffrey L. Appleyard (48) 1987 Vice President & Chief Financial Officer Duane S. Black (49) 1989 Vice President & Chief Operating Officer Jay T. Ellingson (52) 1992 Vice President, Development -

Palm Valley Steven Gervais (46) 1987 Vice President & General Counsel Margaret E. Kirch (52) 1988 Vice President, Commercial Development Thomas A. Patrick (48) 1995 Vice President, Golf Operations EL DORADO INVESTMENT William J. Post Chairman of the Board, President & CEO

• The year in which the individual was first employed within the Pinnacle West group of companies.

OFFICERS

p_62 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 Design: www.cfd2k.com CORPORATE HEADQUARTERS 400 North 5th Street P.O. Box 53999 Phoenix, Arizona 85004 Main telephone number: (602) 250-1000 ANNUAL MEETING OF SHAREHOLDERS Wednesday, May 22, 2002 10:30 a.m.

The Herberger Theatre 222 East Monroe Street Phoenix, Arizona 85004 STOCK LISTING Ticker symbol: PNW on New York Stock Exchange and Pacific Stock Exchange Newspaper financial listings: PinWst FORM 10-K Pinnacle Wests Annual Report to the Securities and Exchange Commission on Form 10-K will be available after April 1, 2002 to shareholders upon written request, without charge. Write: Office of the Secretary.

INVESTORS ADVANTAGE PLAN Pinnacle West offers a direct stock purchase plan. Any interested investor may purchase Pinnacle West common stock through the Investors Advantage Plan. Features of the Plan include a variety of options for reinvesting dividends, direct deposit of cash dividends, automatic monthly investment, certificate safekeeping, reduced brokerage commissions and more. An Investors Advantage Plan prospectus and enrollment materials may be obtained by calling the Company at (800) 457-2983, at the corporate Web site - www.pinnaclewest.com, or by writing to:

Pinnacle West Capital Corporation Shareholder Department P.O. Box 52133 Phoenix, AZ 85072-2133 CORPORATE WEB SITE www.pinnaclewest.com TRANSFER AGENTS AND REGISTRAR Common Stock Pinnacle West Capital Corporation Stock Transfer Department P.O. Box 52134 Phoenix, Arizona 85072-2134 Or:

After January 1, 2003, 400 North 5th Street Phoenix, Arizona 85004 Telephone: (602) 250-5506 SHAREHOLDER ACCOUNT AND ADMINISTRATIVE INFORMATION Shareholder Department telephone number (toll-free):

(800) 457-2983 STATISTICAL REPORT A detailed Statistical Report for Financial Analysis for 1996-2001 will be available in April on the Companys Web site or by writing to the Investor Relations Department.

INVESTOR RELATIONS CONTACT Rebecca L. Hickman Director, Investor Relations P.O. Box 53999 Station 9998 Phoenix, Arizona 85072-3999 Telephone: (602) 250-5668 Fax: (602) 250-2789 STATEWIDE ASSOCIATION FOR UTILITY INVESTORS The Arizona Utility Investors Association represents the interests of investors in Arizona utilities. If interested, send your name and address to:

Arizona Utility Investors Association P.O. Box 34805 Phoenix, Arizona 85067 (602) 257-9200 www.auia.org ENVIRONMENTAL, HEALTH AND SAFETY REPORT To view the APS Environmental, Health and Safety Report please visit www.aps.com, or to receive a printed summary report, call (602) 250-3282.

IMPORTANT NOTICE TO SHAREHOLDERS:

Pinnacle West posts quarterly results and other important information on its Web site (www.pinnaclewest.com). If you would like to receive news by regular mail, fax or e-mail, let us know by mail or phone at the addresses and numbers listed on this page. Also, let us know if you would like to be kept abreast of legislative and regulatory activities at the state and federal levels that could impact investor-owned utilities.

SHAREHOLDER INFORMATION