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

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

The logo at left is the mathematical symbol for differentiate.

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

Growth rate FINANCIAL HIGHLIGHTS 2001 2000 1999 2001 2000 vs. vs.

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

ABOUT THE COMPANY 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.

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

2001 HIGHLIGHTS 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 five-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 five-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.

MOVING FORWARD 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 flow 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.

p_1

FROM WILLIAM J. POST, CHAIRMAN To our shareholders:

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 financial years in our companys history.

Our direction going forward: Stay on plan. It may be hard to recall now - just 12 months Use what we have learned. Figure out answers to later - how different the energy situation looked new questions - both known and unknown. Mix in 2001. In May 2001 the futures price for power discipline with creativity. Stay agile. delivered in August ended up ten times Augusts As a company, we actual price. Our Power Marketing group steered strive to remain flexible through this volatility and produced outstanding in the face of changing results.

markets, yet unwavering Our performance looks even better against the in our commitments to national and industry backdrop of a slowing increasing customer satis- economy and the missteps of some large compa-faction and shareholder nies. We made different choices. We put our trust value. We stood like a in real assets generating real electrons that travel rock on those commit- over real wires into real homes and businesses.

ments in 2001. Our cus- Even as some of the fundamentals of our business tomer satisfaction ratings change, this approach will not.

have never been higher. Our customer base continues to grow. Last Our financial results have year, APS experienced 3.7 percent customer never been stronger. growth - about three times the national average.

Despite some hefty expenses last summer to To meet this growing demand, we added a 120-ensure reliability, earnings from continuing oper- megawatt unit at our West Phoenix plant - our ations increased year-over-year by 8.1 percent. first generation addition since 1988. This summer Outstanding power marketing results and steady well add more than 1,000 megawatts at our new customer growth allowed us to improve earnings Redhawk facility, and next year well complete while providing customers with their seventh our West Phoenix expansion by firing up another price decrease in eight years. 530-megawatt unit. When these new gas-fired p_2 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

units are completed, they will enhance our supply While the Arizona economy is slowing some-options by providing a balanced fuel mix of coal, what, it remains robust by comparison with the nuclear and natural gas. rest of the nation - and growth will continue. We Equally important, weve recently received expect to add customers at a rate of 3.2 percent in approval to build a new 500,000-volt transmis- 2002, compared to the 3.7 to 4.2 percent of the sion line extending from the Palo Verde last few years. Moving forward, this continued Switchyard to a new substation west of Phoenix. growth will drive our top-line revenues and This much-needed line will add to our system strengthen our bottom-line results.

capacity, further strengthening our reliability. We also believe market volatility may increase With that, lets get right to the future. Looking in Western power markets later in the year. That ahead, I see opportunities in three significant could create trading opportunities, especially as areas. First, although today we face tougher power we bring Redhawk Units 1 and 2 on line.

markets and a slower economy, customer growth These new gas-fired units, with their greater and wholesale market opportunities will prevail. efficiency in converting natural gas to electricity, Second, weve taken on an important regulatory will have a higher profit potential over the long agenda. And third, evolutionary market develop- run. Analysts refer to this margin as spark ments will determine the structure and substance spread- the relationship between the price of of future electric competition. natural gas and the price of wholesale power pro-duced from gas. While our generation capacity THE POWER MARKET OPPORTUNITY will remain close to the size of our native cus-tomer demand, these more efficient units will For Pinnacle West, the key to mastering the widen our power marketing options in the future.

power market challenge is risk management - one of our core strengths. Risk management is not just Price caps - assuming they remain - present power marketing and trading, though that is key another challenge to power markets and to gener-to our approach. We build in risk management ators and suppliers trying to negotiate those from the bottom up by staying close to our core markets. At first, the soft price caps imposed last business, managing our exposure in new markets, year had a dramatic effect on prices, treating growing generation in a disciplined manner, com- the entire region as one pricing point, ignoring peting in regulatory arenas, adhering to tight regional differences and transmission bottlenecks.

financial guidelines and testing every action for While price caps are benign in the current impact on customers and shareholders. depressed market, over the long-term they will likely prevent price signals from attracting new Power Marketing is part of our parent compa- capital and generation where they are needed.

ny, which positions it uniquely to manage our enterprise-wide energy risk. Power Marketing Anticipating future regulatory impacts - from supplements our existing resources with short- federal price caps to individual state actions - is term purchases and reduces financial exposure the key to success in Western power markets.

with hedging techniques. By buying wholesale power to serve our retail customers, and selling THE REGULATORY OPPORTUNITY available output from our generating facilities and other energy resources, this group optimizes If our industry learned anything from results of energy markets and owned generation. California, it is that the public will not tolerate price volatility or low levels of reliability.

Weve been both calculating and aggressive Regulators and politicians will act accordingly.

with our power marketing. We calculate our risks in buying and selling power, striking a balance To avoid that situation in our state, last between moderate risk and the cost of hedging October we filed with the Arizona Corporation those risks. When opportunities arise, we move Commission (ACC) a plan designed to provide swiftly and aggressively to improve our positions. our APS customers with reliable electricity sup-Weve exceeded expectations in the past, and it is plies at stable prices well into the future. This plan our intention to do so in the future. also permits a more deliberate approach to com-petitive markets in the Southwest.

Given the current depressed wholesale power prices, we expect lower gross margins from Power Our plan doesnt change the substance of our Marketing. On the other hand, we foresee lower 1999 Settlement Agreement, which provided rate expenditures for reliability and purchased power decreases for customers through 2003, opened in 2002 - we wont have to spend the $140 the door to competition for our retail customers million we spent in 2001 to ensure uninterrupted and required that we transfer APS generation electric service for our customers. assets to a competitive subsidiary.

p_3

Our plan deals with current realities and pro- During the Arizona restructuring debates, we vides a sure path to meeting our states energy were adamant about not divesting our power sta-needs. The plan builds toward a robust wholesale tions and exposing APS customers to an untested market, supporting the move to competition wholesale market. It was clear, few customers rather than allowing the old rules to fail. - and almost no residential and small business What were requesting is a modification to one customers - had the technology or expertise to part of the ACC competition rules - a very respond to real-time power prices, alter their important part that never measured up to expect- usage and hedge their market risk. Dealing with ed realities. market risk for our customers and shareholders is our job, and we expect to meet their demands.

At the time the rules were put in place, the expectation was that the wholesale market would As they consider our plan, the ACC - like develop over the following years. As California many state commissions in the wake of the has shown, the market hasnt developed as expect- California experience - is taking another look at ed and without change to the competition rules the existing competition rules. We cant say at this well be required in 2003 to obtain all APS time how far this look will go. While the com-customer power from the wholesale market. missioners have not indicated a need for sweeping Acquiring all of APS customer power needs in change, they are prudently responding to the todays wholesale market is simply not possible. same environment and the same concerns that led us to propose our regulatory plan for reliability, price stability and competition.

We enjoyed solid customer growth and a growing economy.

Under our proposal, the competitive bidding THE MARKET STRUCTURE OPPORTUNITY would begin in 2003 with a 270-megawatt auc- The most significant factor affecting future tion. The same amount would be added each year electric competition in the West is the sputtering through 2008. By that time, competitive bidding development of the electric market structure.

would supply at least 1,620 megawatts - nearly This structure, both physical and financial, is 25 percent - of APS customer needs. At that beset by its complex composition - a collection point, the market should be mature enough to of entities comprising state and federal regulators, supply that amount without distortion. federal agencies, public power, municipalities, For our customers, this plan offers stable and industry associations and private companies all predictable prices from a diversity of fuel sources, simultaneously operating to meet instantaneous and reliability that cannot be obtained elsewhere customer demand.

in todays wholesale market. We have an obliga- This structure requires an extraordinary tion to keep the lights on. Thats an obligation we amount of coordination and distinguishes elec-accept and our customers expect us to keep. But tricity from any other commodity, making the without this or a similar plan, we think the cost development of a competitive electric wholesale of keeping the lights on will be more than our market particularly difficult. Regulators - focused customers will want to pay. on the theme and promise of competition - did For our shareholders, the plan provides a solid not fully consider the complexity of this process generation earnings platform plus the ability to or the laws of physics and set up unworkable sell extra capacity and energy in the wholesale markets - or none at all.

market. The end result will be a generation com- This competitive theme camouflaged what, in ponent comprised of substantial owned assets, substance, was increased and incomplete regula-considerable earnings strength and opportunities tion. These regulatory efforts produced real world for profit in the wholesale market. problems and reinforced movement toward even For regulators, our reliability plan protects greater regulation. The difficulties of many com-customers from price volatility and guarantees panies and the higher prices charged to California reliable power while preserving an orderly consumers can be traced to the imperfect market progression toward an increasingly competitive structures California created and regulators are wholesale market in the Southwest. now trying to correct through re-regulation.

p_4 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

This re-regulation goes beyond California to most of the Western states. When compounded with the significant 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 But these natural advantages are not as WestConnect RTO. WestConnect, encompassing important as the ones weve created:

roughly the Southwest, recognizes regional differ-

• an unwavering focus on customer satisfaction ences and state authority and complies with the FERCs requirements for RTOs. Public power is a

• outstanding power plant operations part of it, and it is designed to interact effectively

• an increasingly balanced fuel mix with other RTOs - addressing the so-called

• disciplined generation expansion roughly seams issue - while providing a firm structure to matching our native load growth enhance the competitive generation market.

• a creative but risk-averse approach to power As long as incomplete or unworkable themes marketing continue to mark our industry and competitive power markets, the threat of re-regulation and These advantages support a strategy that is our potential loss of customer choice will loom over definition of creating value: combined growth of every regulatory proceeding. earnings and dividends above the industry aver-age. Our advantages form a strategic mix we believe is unique and sustainable. Im confident HOW WE ARE DIFFERENT the people of Pinnacle West will meet the com-Last year was turbulent. There were challenges. plex challenges of the future. We have the skills, There were pitfalls. We set our company apart. experience and intellectual capital to develop the We were different. We prospered. answers and deliver shareholder value. We have, Were different because weve disregarded sim- and we will.

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.

William J. Post 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.

p_5

In 2001, Pinnacle West produced near record earnings.

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

$R,ES In 2001, we increased our annual dividend In its third year of operation, APS Energy by 10 cents per share of common stock. Our Services (APSES), our competitive retail five-year annualized dividend growth rate energy services affiliate, continued to carve was about 8 percent, compared with a nega- a niche for itself by providing integrated tive growth rate for the industry as a whole. solutions of commodity energy and energy-We intend to grow our dividend by similar related products and services to commercial dollar amounts each year, steadily increasing and industrial customers.

the cash return to our shareholders and APSES is a relatively new company in an maintaining a pace ahead of our industry. industry experiencing some stop-and-go reg-About half of the Companys earnings in ulatory transitions, but was able to secure a 2001 came from power marketing and trad- number of profitable multi-year contracts in ing activities. Our Power Marketing group the fourth quarter of 2001. These contracts managed a wholesale power market that allowed APSES to more than double its gross peaked around $2 a kilowatt-hour; then, in margin in 2001 while keeping operating just a few months, plummeted as low as two expenses flat.

cents a kilowatt-hour. In early 2001, El Dorado, our investment A commitment to provide our customers subsidiary, sold a substantial portion of its reliable energy impacted 2001 earnings from holdings in a technology venture capital lim-APS, our electric utility. We spent more than ited partnership. By doing so, El Dorado is

$140 million to ensure customers had reli- continuing a strategy of liquidating its exist-able power throughout the summer of 2001 ing portfolio as quickly as prudent. Looking and future summers. We dont foresee a need ahead, we expect El Dorado to make limited to repeat these expenses in 2002. strategic investments in companies offering energy-related technologies and services.

p_6 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

U,LTS p_7

r Ow G

p_8 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

h Last year, APS experienced 3.7 percent t

customer growth.

w 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-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-profile 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 tan Phoenix, Delivery installed 70 substation home sales at its existing projects in Arizona, New feeders. In a typical year, it adds 12 to 15. Mexico and Utah, while initiating home sales at This growing customer base also has increased its new StoneRidge community in northern energy demand. Pinnacle West Energy - our Arizona.

unregulated generation subsidiary - has built (and is currently building) new generation resources. In summer 2001, Pinnacle West p_9

In the 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 last two Pinnacle West and APS. This doesnt change our 1999 Settlement Agreement. We will continue to years, meet our commitments under that agreement, including lowering customer prices each year our peak through 2003.

In October 2001, we filed a request with the load Federal Energy Regulatory Commission (FERC) to form WestConnect, a for-profit regional trans-mission organization (RTO) made up of APS and demand other Southwestern transmission owners. If approved, WestConnect will be based on policies has grown and procedures developed over the last four years by its predecessor - DesertSTAR, a previously 15.3 proposed non-profit RTO.

The for-profit governance structure is designed percent. to motivate innovation, efficiency and creativity in the operation of the Western transmission grid.

We believe its formation will preserve states In the next five years, load growth is projected rights but encourage regional cooperation, while to increase nearly 30 percent. Considering these allowing us to retain our transmission assets.

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-In the ance allows us flexibility in times of spiking wholesale prices or power shortages. next Initial electric competition rules for Arizona were adopted under the assumption that the five years, market would provide enough energy to keep prices low and supply plentiful. This hasnt been the case. Weve seen deregulation fail - most load notably in California.

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

Our filing supports a responsible transition to 30 competition, while providing reliable power supplies to our customers at stable prices. It asks percent.

p_10 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

PN L I AN NG p_11

p_12 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001 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-Customers out all parts of our company and is reflected in our recent customer satisfaction scores. In a 2001 survey, 85 percent of APS residential customers count on us rated themselves as satisfied or very satisfied with their service from APS. In the same survey, 94 for reliable percent rated the reliability of our electricity as good, very good or excellent.

These numbers reflect our ongoing efforts to energy and take care of our customers. For example:

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

Our region of the country continues to expand,

• Our focus on reliability was underlined when and each year more customers count on us for 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 reliable energy and fair prices. This responsibility storm knocked out more than 100 trans-is familiar - weve served this part of the country mission poles in Gila Bend, an Arizona town for more than 116 years. southwest of Phoenix.

While other Western utilities were raising

• In 2001, we spent more than $140 million customer prices, APS lowered retail rates for the to ensure we could continue to meet the ener-seventh time since 1993. During that time, weve gy needs of our customers.

reduced electric prices by 13 percent and saved The Better Business Bureau of Central and our customers more than $800 million - the Northern Arizona recently presented us with its largest cumulative rate decrease among all Business Ethics Award. Were proud of this honor.

investor-owned electric companies in the nation. It underscores our philosophy that areas such as Such price reductions are possible, in part, financial integrity, business practices, safety, through the efficient performance of our power community involvement and environmental plants. Last year, the Palo Verde Nuclear stewardship are not afterthoughts - theyre key Generating Station was the nations number one ingredients in delivering value and defining who power producer for the 10th consecutive year - we are.

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.

p_13

RESULTS AND PERFORMANCE - A BETTER UNDERSTANDING We have increased the type and extent of information we er scrutiny by the SEC and rating agencies, and more rigor make available to investors to facilitate better understanding from investors and analysts seem inevitable. Such changes of our business performance and our financial results. The should result in more confidence in numbers reported by cor-quality of our disclosure is a reflection of who we are and our porate America. We welcome this trend.

attitude about the need to be open and clear about our Since our power marketing and trading activities have con-business operations and their effects on our financial results. tributed significantly to our bottom line in the last two years, On our Web site - www.pinnaclewest.com - we provide con- we have expanded our disclosures to include more data on siderable detail about our operating statistics and financial those operations. In addition to required disclosure in the performance to complement our other reports. financial statements and managements discussion of financial All public companies will face tougher analysis and a position and results of operations, some of the key data is demand for greater financial transparency to develop investor explained below.

trust and confidence. Changes in accounting standards, clos-ARY (a)

S MARG IN SU MM D TRAD ING GROS MARKETING AN 2000 2001 s) before income taxe (millions of dollars, High and volatile ON ENTS (b) market prices in 2001 AR KET COMP Realized margins are D MARK-TO-M REALIZE D AN enabled our marketing cash gains or losses effects and trading activities related to deliveries Current period modities on delivered com to produce over 70%

of commodity con- Realized margin 79 $ 54

$ higher contribution tracts in current period. Electricity load 69 other than native 119 than in 2000.

Generation sales ing 123 ma rketing and trad 198 Other electricity (9)

Due to high market (14)

Total electri city 114 prices in early 2001, es 184 58% of our marketing Other commoditi and trading margin sales of our generation rgin Total realized ma losses on contrac ts was related to to other utilities and o-market (gains) power marketers con- Prior-period mark-t (15)

(2) commodity contracts current per iod delivered during - delivered during 2001.

tributed 43% of our 27 realized marketing and Electricity es trading margin. Other commoditi with Enron (8) trading activities Charge related to 6 (2)

When commodity and its affiliat es 112 190 contracts are delivered, Subtotal gains or losses iod effects Total current per previously recorded (losses) for future ang e in ma rk- to-market gains 7 through mark-to-Ch 146 s (c) period deliverie 7 market are reversed.

(19)

Electricity 14 127 es Our mark-to-market Other commoditi 317 $ 126 effects $

value is substantially Total future period ss ma rgin bef ore income taxes protected against Total gro Accumulated gains at

$ 128 future market price SOLD OR TRAD ED $ 329 the end of 2001 are changes (c). BY COMMOD ITY (12)

(2) expected to be realized Electricity $ 126

$ 317 as follows: 31%

es Other commoditi es in 2002; 33% in before income tax Total gross margin 11 2003-2004; and the KET GAINS (LOSS ES) 138 $

MARK-TO-MAR $ remainder thereafter.

ACCU MU LATED EN D OF YE AR (c)

AT es, before er and fuel expens us purchased pow electric ope rating revenues min (a) Gross margin equals tain contracts for s book value of cer nge income taxes. cip les (G AA P) require that thes in their fair value caused by cha -cash prin nge epted accounting ed to reflect cha et represents non (b) Generally acc ses of commodities be adjust led mark-to-market. Mark-to-mark sales or purcha t prices. This process is cal in prevailing marke tfolio meaning our por nomic gains or losses. ctured activities, eco and trad ing activities are struard purchases that protects the of our marketing tfolio of forw (c) Essentially all es positions is hedged with a por nges.

of forward sal market price cha the sales tran sactions against value of p_14 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

2001 FINANCIAL STATEMENTS CONTENTS 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 GLOSSARY 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_15

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 (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.

p_16 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

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_17

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.

QUARTERLY STOCK PRICES AND DIVIDENDS PER SHARE Stock Symbol: PNW 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 p_18 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS In this section, we explain the results of operations, general Affecting Our Financial Outlook, recent Arizona regulatory financial condition, and outlook for Pinnacle West Capital developments have raised uncertainty about the status and Corporation and our subsidiaries: Arizona Public Service pace of retail electric competition in Arizona, including APS Company (APS), Pinnacle West Energy Corporation transfer of generation assets to Pinnacle West Energy.

(Pinnacle West Energy), APS Energy Services Company, Inc.

BUSINESS SEGMENTS (APSES), SunCor Development Company (SunCor), and We have two principal business segments (determined by El Dorado Investment Company (El Dorado) including:

products, services and regulatory environment), which the changes in our earnings from 2000 to 2001 and from consist of regulated retail electricity business and related 1999 to 2000; activities (retail business segment) and competitive business our capital needs, liquidity and capital resources; activities (marketing and trading segment). Our retail our marketing and trading activities; business segment currently includes activities related to our financial outlook; electricity transmission and distribution, as well as electricity our critical accounting policies generation. Our marketing and trading segment currently major factors that affect our financial outlook; and includes activities related to wholesale marketing and our management of market risks. trading, and APSES competitive energy services.

OVERVIEW OF OUR BUSINESS These reportable segments reflect a change in the reporting Pinnacle West owns all of the outstanding common stock of our segment information. Before the fourth quarter of of APS. APS is Arizonas largest electric utility and provides 2001, we had two segments (generation and delivery). The either retail or wholesale electric service to substantially all generation segment information combined our marketing of the state, with the major exceptions of the Tucson metro- and trading activities with our generation of electricity politan area and about one-half of the Phoenix metropolitan activities. The delivery segment included transmission area. APS also generates and, through our marketing and and distribution activities.

trading division, sells and delivers electricity to wholesale In the fourth quarter, APS filed with the ACC a request for customers in the western United States.

a proposed rule variance and approval of a purchase power Our other major subsidiaries are: agreement (see Note 3) that inherently views our business in the new reportable segments described as presented herein.

Pinnacle West Energy, through which we conduct our Internal management reporting has been changed to reflect unregulated electricity generation operations; this alignment. See Business Segments in Note 16 for APSES, which provides commodity energy and energy-more information about our business segments.

related products to key customers in competitive markets in the western United States; The following is a summary of net income by business SunCor, a developer of residential, commercial, and segment for 2001, 2000, and 1999:

industrial real estate projects in Arizona, New Mexico, (dollars in millions) 2001 2000 1999 and Utah; and El Dorado, an investment firm.

Retail $ 152 $ 225 $ 246 Pinnacle Wests marketing and trading division sells in the Marketing and trading 172 63 5 wholesale market APS and Pinnacle West Energy generation Other 3 14 19 production output that is not needed for APS native load, Income from continuing which includes loads for retail customers and traditional operations 327 302 270 cost-of-service wholesale customers. Subject to specified Income tax benefit from risk parameters established by our Board of Directors, the discontinued operations - - 38 marketing and trading division also engages in activities to Extraordinary charge -

hedge purchases and sales of electricity, fuels, and emissions net of income taxes - - (140) allowance and credits and to profit from market price Cumulative effect of movements. We explain in detail below the historical and change in accounting -

prospective contribution of marketing and trading activities net of income taxes (15) - -

to our financial results. Net Income $ 312 $ 302 $ 168 APS is required to transfer its competitive electric assets and services to one or more corporate affiliates no later than Throughout this section, we refer to specific Notes in the December 31, 2002. Consistent with that requirement, APS Notes to Consolidated Financial Statements that begin on has been addressing the legal and regulatory requirements page 38. These Notes add further details to the discussion.

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 p_19

RESULTS OF OPERATIONS 2001 Compared With 2000 The following is a summary of our net income by legal Our consolidated net income for the year ended December entity for 2001, 2000, and 1999: 31, 2001 was $312 million compared with $302 million for (dollars in millions) 2001 2000 1999 the year ended December 31, 2000. In 2001, we recognized a $15 million after-tax loss in net income as a cumulative APS $ 281 $ 307 $ 267 effect of a change in accounting for derivatives. See Note 17 Pinnacle West Energy 18 (2) - for further discussion on accounting for derivatives.

APSES (10) (13) (9) Income from continuing operations for the year ended SunCor 3 11 6 December 31, 2001 was $327 million compared with El Dorado - 2 11 $302 million for the year ended December 31, 2000.

Parent company (a) 35 (3) (5) The year-to-year comparison benefited from strong market-Income from continuing ing and trading results, including significant benefits in the operations 327 302 270 2001 third quarter from structured trading activities, and Income tax benefit from retail customer growth. These factors were partially offset by discontinued operations - - 38 higher purchased power and fuel costs, due in part to Extraordinary charge - increased power plant maintenance; generation reliability net of income taxes - - (140) measures; continuing retail electricity price decreases; and Cumulative effect of change a charge related to Enron and its affiliates.

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:

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.

p_20 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

Electric operating revenues increased approximately $850 reliability program (the addition of generating capability to million because of: enhance reliability for the summer of 2001 ($42 million)) and increased employee benefit costs, plant outage and mainte-changes in marketing and trading revenues ($827 million, nance, and other costs ($38 million). The comparison reflects net increase):

Pinnacle Wests $10 million provision for our credit exposure increased revenues related to generation sales other related to the California energy situation, $5 million of which than native load as a result of higher average market was recorded in the fourth quarter of 2000 and $5 million of prices ($32 million);

which was recorded in the first quarter of 2001.

increased realized revenues related to other marketing and trading in current period primarily due to more Net other expense increased $5 million primarily because transactions ($681 million); of a change in the market value of El Dorados investment decreased prior period mark-to-market value related in a technology-related venture capital partnership in 2000 to trading with Enron and its affiliates ($8 million); (see Note 1) and other non-operating costs partially offset by increased prior period mark-to-market value for losses an insurance recovery of environmental remediation costs.

transferred to realized margin in current period Interest expense decreased by $17 million primarily

($9 million);

because of increased capitalized interest resulting from increased mark-to-market value for future periods our generation expansion plan partially offset with higher primarily as a result of more forward sales volumes interest expense due to higher debt balances.

($113 million);

decreased revenues related to other wholesale sales and 2000 Compared With 1999 miscellaneous revenues as a result of sales volumes Our consolidated net income for the year ended December

($28 million); 31, 2000 was $302 million compared with $168 million for increased retail revenues primarily related to higher the year ended December 31, 1999. Our 2000 net income sales volumes primarily due to customer growth increased $134 million over 1999 primarily because of a

($78 million); and $140 million after-tax extraordinary charge that we recorded decreased retail revenues related to reductions in retail in 1999. This charge reflected a regulatory disallowance electricity prices ($27 million). resulting from an ACC-approved Settlement Agreement related to the implementation of retail electric competition.

Purchased power and fuel expenses increased approximately The resulting increase in our 2000 net income was partially

$731 million primarily because of:

offset by the absence of a $38 million income tax benefit changes in marketing and trading purchased power and from discontinued operations that we also recorded in fuel costs ($636 million, net increase) due to: 1999. See Regulatory Agreements below and Notes 1 increased fuel costs related to generation sales other and 3 for additional information about the 1999 Settlement than native load as a result of higher fuel prices Agreement and the resulting regulatory disallowance. See

($7 million); Note 4 for additional information about the income tax increased fuel and purchased power costs related to benefit from discontinued operations.

other realized marketing and trading in current period Income from continuing operations for the year ended primarily due to more transactions ($636 million);

December 31, 2000 was $302 million compared with $270 decreased mark-to-market fuel costs related to million for the year ended December 31, 1999. The year-accounting for derivatives ($7 million) (see Note 17) to-year comparison benefited from strong wholesale and decreased costs related to other wholesale sales as a retail electric sales and real estate profits. These positive result of lower volumes ($31 million);

factors more than offset decreases resulting from the higher replacement power costs primarily due to higher completion of ITC amortization in 1999, reductions in market prices and increased plant outages ($70 million),

retail electricity prices, lower earnings from El Dorado, and including costs of $12 million related to a Palo Verde out-miscellaneous factors. See Regulatory Agreements below age extension to replace fuel control element assemblies; and Note 3 for information on the price reductions. See higher costs related to retail sales volumes due to customer Regulatory Agreements below and Note 4 for additional growth ($43 million); and information about ITC amortization.

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 p_21

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

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.

Electric operating revenues increased approximately $1.24 increased fuel costs related to generation sales other billion because of: than native load as a result of higher fuel prices

($39 million);

changes in marketing and trading revenues ($616 million, increased fuel and purchased power costs related net increase):

to other realized marketing and trading in current increased revenues related to generation sales other period primarily due to more transactions than native load as a result of higher market prices

($468 million);

($86 million);

increased costs related to increased volumes and higher increased realized revenues related to other marketing market prices for wholesale sales resulting from retail and trading in current period primarily due to more hedging activities ($513 million); and transactions and higher market prices ($519 million);

higher costs related to retail sales volumes due to customer decreased prior period mark-to-market value for gains growth and increased fuel and purchased power prices transferred to realized margin in current period

($118 million).

($2 million);

increased mark-to-market value for future periods The increase in real estate profits of $13 million resulted pri-primarily as a result of more forward sales volumes marily from increases in sales of land and homes by SunCor.

($13 million);

The increase in operations and maintenance expenses of $4 increased revenues related to increased volumes and million primarily related to customer growth was substan-higher market prices for other wholesale sales resulting tially offset by $20 million of other items recorded in 1999.

from retail load hedging activities and miscellaneous revenues ($523 million); The increase in depreciation and amortization of $11 million increased retail revenues primarily related to higher sales primarily related to higher plant in service balances offset by volumes due to customer growth ($127 million); and lower regulatory asset amortization.

decreased retail revenues related to reductions in retail Net other expense decreased $10 million primarily because electricity prices ($28 million).

of changes in 2000 in the market value of El Dorados Purchased power and fuel expenses increased approximately investment in a technology-related venture capital partner-

$1.14 billion primarily due to: ship. See Note 1 for additional information about the valuation of El Dorados investments.

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

p_22 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

Regulatory Agreements $11 million annually ($7 million after income taxes),

Regulatory agreements approved by the ACC affect the or 0.7%, effective July 1, 1999 (as noted above, this results of APS operations. The following discussion focuses reduction was included in the July 1, 1999 price on three agreements approved by the ACC, each of which reduction under the 1999 Settlement Agreement).

included retail electricity price reductions:

1994 Rate Settlement The 1999 Settlement Agreement to implement retail As part of a 1994 rate settlement, APS accelerated amortiza-electric competition; tion of substantially all of its ITCs over a five-year period A 1996 agreement that accelerated the amortization of that ended on December 31, 1999. The amortization of APS regulatory assets; and ITCs decreased annual consolidated income tax expense by A 1994 settlement that accelerated the amortization of about $24 million. Beginning in 2000, no further benefits APS deferred ITCs. were reflected in income tax expense related to the accelera-tion of the ITCs (see Note 4).

1999 Settlement Agreement As part of the 1999 Settlement Agreement, APS agreed to LIQUIDITY AND CAPITAL RESOURCES reduce retail electricity prices for standard-offer, full-service Capital Needs and Resources customers with loads less than three megawatts in a series Capital Expenditure Requirements of annual decreases of 1.5% on July 1, 1999 through The following table summarizes the actual capital expendi-July 1, 2003, for a total of 7.5%. The first reduction of tures for the year ended December 31, 2001 and estimated approximately $24 million ($14 million after income taxes) capital expenditures for the next three years.

included the July 1, 1999 retail price decrease required by (ACTUAL) (ESTIMATED) the 1996 regulatory agreement (see below). For customers (dollars in millions) 2001 2002 2003 2004 having loads three megawatts or greater, standard-offer rates will be reduced in annual increments that total 5% in APS the years 1999 through 2002.

Delivery $ 354 $ 349 $ 271 $ 280 The 1999 Settlement Agreement also removed, as a regulatory Existing generation (a) 117 149 - -

disallowance, $234 million before income taxes ($183 million Subtotal 471 498 271 280 net present value) from ongoing regulatory cash flows. APS Pinnacle West Energy (b) recorded this regulatory disallowance as a net reduction of Generation expansion 533 411 255 113(e) regulatory assets and reported it as a $140 million after-tax Existing generation(a) - - 107 99 extraordinary charge on the 1999 income statement.

Subtotal 533 411 362 212 Under the 1996 regulatory agreement, APS was recovering SunCor (c) 80 79 48 52 substantially all of its regulatory assets through accelerated Other (d) 45 35 15 16 amortization over an eight-year period that would have Total $1,129 $ 1,023 $ 696 $ 560 ended June 30, 2004. For more details, see Note 1. The regulatory assets to be recovered under the 1999 Settlement (a) Pursuant to the 1999 Settlement Agreement, APS is required to Agreement are currently being amortized as follows (dollars transfer its competitive electric assets and services no later than in millions): December 31, 2002.

(b)See Note 10 for further discussion of Pinnacle West Energys 1/1- 6/30 1999 2000 2001 2002 2003 2004 TOTAL generation expansion program and Capital Resources and Cash Requirements - Pinnacle West Energy below.

(c) Consists primarily of capital expenditures for land development and

$164 $158 $145 $115 $86 $18 $686 retail and office building construction reflected in the Increase in real estate investments in the consolidated statements of cash flows.

See Note 3 and Business Outlook - Electric Competition (d)Primarily Pinnacle West and APSES.

(Retail) below for additional information regarding the 1999 (e) This amount does not include an expected reimbursement by Southern Settlement Agreement. Nevada Water Authority (SNWA) of $100 million of these costs in 2004 in exchange for SNWAs purchase of a 25% interest 1996 Regulatory Agreement in the Silverhawk project at that time.

As part of the 1996 regulatory agreement, APS reduced its APS and the other Palo Verde participants are currently con-retail electricity prices by 3.4% effective July 1, 1996. This sidering issues related to replacement of the steam generators reduction decreased electric revenue by about $49 million in Units 1 and 3. Although a final determination of whether annually ($29 million after income taxes). APS also agreed Units 1 and 3 will require steam generator replacement to to share future cost savings with its customers during the operate over their current full licensed lives has not yet been term of this agreement, which resulted in the following made, APS and the other participants have approved an additional retail price reductions:

expenditure in 2002 to procure long lead-time materials for

$18 million annually ($11 million after income taxes), or fabrication of a spare set of steam generators for either Unit 1 1.2%, effective July 1, 1997; or 3. APS portion of this expenditure is approximately $7

$17 million annually ($10 million after income taxes), or million and is included in the estimated expenditures above.

1.1%, effective July 1, 1998; and p_23

This action will provide the Palo Verde participants an Pinnacle West had available lines of credit in the amount option to replace the steam generators at either Unit 1 or 3 of $250 million at December 31, 2001. APS had lines of as early as fall 2005 should they ultimately choose to do so. credit available in the amount of $250 million at December If the participants decide to proceed with steam generator 31, 2001. There was no outstanding balance on either the replacement at both Units 1 and 3, APS has estimated that Pinnacle West or APS lines of credit at December 31, 2001.

its portion of the fabrication and installation costs and asso- Pinnacle West and APS project that these lines of credit will ciated power uprate modifications would be approximately be available over the next three years. The lines of credit

$130 million over the next seven years, which will be funded are anticipated to be renewed at their expiration dates. See with internally generated cash or external financings. Note 5 for further information on Pinnacle Wests and APS lines of credit.

Existing generation capital expenditures are comprised of multiple improvements for our existing fossil and nuclear SunCor had an available line of credit at December 31, plants. Examples of the types of projects included in this 2001 in the amount of $140 million. This line of credit category are additions, upgrades and capital replacements of had an outstanding balance at December 31, 2001 of $128 various power plant equipment such as turbines, boilers, and million. SunCor projects that this line of credit will be environmental equipment. The increase in this category in available over the next three years. SunCor also anticipates 2002 is due primarily to Four Corners and various gas-fired renewing the line of credit at its expiration date. See Note 5 units. The increased work on equipment is due to higher for further details on SunCors line of credit.

use of the units and also a stack replacement project for Four The parent company has issued parental guarantees and Corners Units 1 and 2. The existing generation also obtained surety bonds on behalf of its unregulated sub-contains nuclear fuel expenditures of approximately $30 sidiaries, primarily for Pinnacle West Energys expansion million annually in 2002, 2003 and 2004.

plans, which are reflected in the capital expenditure table Delivery capital expenditures are comprised of transmission above, and APSES retail and energy business.

and distribution (T&D) infrastructure additions and APS has obtained approximately $500 million in letters of upgrades, capital replacements, new customer construction, credit primarily to provide credit support for its variable and related information systems and facility costs. Examples rate tax-exempt bonds and its Palo Verde sale-leaseback of the types of projects included in the forecast include T&D transactions. Pinnacle West has obtained approximately lines and substations, line extensions to new residential

$40 million in letters of credit to provide credit support and commercial developments, and upgrades to customer for Pinnacle West Energys generation expansion plans.

information systems. In addition, we began several major transmission projects in 2001. These projects are periodic Pinnacle West and APS do not have ratings triggers in any in nature and are driven by strong regional customer growth. of their debt agreements. Ratings triggers are provisions that We expect to spend about $150 million on major transmis- would result in the acceleration of repayment obligations sion projects during the 2002-2004 time frame. based upon a credit rating agency downgrade. Although those rating triggers appear in certain power marketing and Capital Resources and Cash Requirements trading agreements, their financial impacts are not expected The following table summarizes cash commitments for to be significant.

the year ended December 31, 2001 and estimated commit-ments for the next three years: APS first mortgage bondholders share a lien on substantially (ACTUAL) (ESTIMATED) all utility plant assets (other than nuclear fuel, transportation (dollars in millions) 2001 2002 2003 2004 equipment and other excluded assets). The mortgage bond indenture restricts the payment of common stock dividends Long-term debt pay-under certain conditions. These conditions did not exist at ments (see Note 6)

December 31, 2001.

APS $ 384 $ 247 $ - $ 205 See the Companys consolidated debt structure in Note 6.

Pinnacle West 213 - 276 216 The parent company and our subsidiaries capital needs and SunCor 24 - 42 86 resources are described as follows.

Total long-term debt payments 621 247 318 507 Pinnacle West (Parent Company)

Operating leases pay-During the past three years, our primary cash needs were for:

ments (see Note 8) 67 68 66 65 dividends to our shareholders; Fuel and purchase equity infusions into our subsidiaries; power commitments interest payments; and (see Note 10) 374 270 124 80 optional and mandatory repayment of principal on our Total cash commitments $ 1,062 $ 585 $ 508 $ 652 long-term debt.

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

p_24 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

This investment completed the funding of Pinnacle Wests APS long-term debt was approximately $2.1 billion at commitment under the 1996 regulatory agreement (see December 31, 2001 and 2000 (see Note 6).

Note 3) to infuse $50 million a year into APS ($200 million Although ACC financing orders establish maximum total) from 1996 through 1999. The investments into amounts of additional debt that APS may issue, APS Pinnacle West Energy were $484 million in 2001 and $193 does not expect these orders to limit its ability to meet million in 2000 to fund portions of its capital expenditures its capital requirements.

for its generation expansion program.

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

Over the next three years, we anticipate that our cash needs Notes due 2012. On March 15, 2002, APS announced will fall into these same categories. We expect our equity the redemption on April 15, 2002 of approximately $125 infusions into Pinnacle West Energy to continue as it invests million of its First Mortgage Bonds, 8.75% series due 2024.

in additional generating facilities (see Note 10) until it begins to finance its own construction needs. Pinnacle West Energy See Note 10 for a discussion of Pinnacle West Energys Our primary sources of cash are dividends from APS, our generation expansion plans. Pinnacle West Energy is marketing and trading operations, and external financing.

currently funding its capital requirements through capital For the years 1999 through 2001, total dividends from infusions from the parent. We finance those infusions APS were $510 million.

through debt financing and internally generated cash, as Our long-term debt at December 31, 2001 was $576 mil- Pinnacle West Energy develops and obtains additional lion compared with $238 million at December 31, 2000. generation assets. Pinnacle West Energy also expects to fund We had $235 million of borrowings outstanding on our its capital requirements through internally generated cash commercial paper at December 31, 2001. Our debt repay- and its own debt issuances. See the Capital Expenditures ment requirements for the parent company for the next Table above for actual capital expenditures in 2001 and three years are approximately: zero in 2002, $276 million projected capital expenditures for the next three years.

in 2003, and $216 million in 2004.

Other Subsidiaries On February 8, 2002, we issued $215 million of our 4.5% During the past three years, both SunCor and El Dorado Notes due 2004. funded all of their cash requirements with cash from operations and, in the case of SunCor, its own external APS financings. APSES funded its cash requirements with APS capital requirements consist primarily of capital cash infusions from Pinnacle West.

expenditures and optional and mandatory redemptions of long-term debt. APS pays for its capital requirements with SunCors capital needs consist primarily of capital expendi-cash from operations and, to the extent necessary, external tures for land development and retail and office building financing. APS pays for its dividends to Pinnacle West construction. See the Capital Expenditures Table above for with cash from operations. actual capital expenditures in 2001 and projected capital expenditures for the next three years. SunCor expects to During the period from 1999 through 2001, APS paid for fund its capital requirements with cash from operations and substantially all of its capital expenditures with cash from external financings.

operations. APS expects to do so in 2002 through 2004 with cash from operations and its own debt issuances. As of December 31, 2001, SunCor had a $140 million line of credit, under which $128 million of borrowings were See the capital expenditure table above for additional infor-outstanding. SunCors debt repayment obligations for the mation regarding actual capital expenditures in 2001 and next three years are approximately: zero in 2002; $42 mil-projected capital expenditures for the next three years.

lion in 2003; and $86 million in 2004.

During 2001, APS redeemed approximately $384 million El Dorado does not have any capital requirements over the of long-term debt, including premiums, with cash from next three years. El Dorado intends to focus on prudently operations and from the issuance of long- and short-term realizing the value of its existing investments. El Dorados debt. APS long-term debt redemption requirements for future investments are expected to be related to the the next three years are approximately: $247 million in energy sector.

2002; zero in 2003; and $205 million in 2004. Based on market conditions and call provisions, APS may make APSES capital expenditures and other cash requirements are optional redemptions of long-term debt from time to time. increasingly funded by operations, with some funding from cash infused by Pinnacle West. See the Capital Expendi-As of December 31, 2001, APS had credit commitments tures Table above regarding APSES capital expenditures.

from various banks totaling about $250 million, which were available either to support the issuance of commercial paper See Notes 5 and 6 for additional information about or to be used as bank borrowings. At the end of 2001, APS outstanding lines of credit and long-term debt obligations.

had about $171 million of commercial paper outstanding and no bank borrowings.

p_25

CRITICAL ACCOUNTING POLICIES from unrealized gains on cash flow hedges. See Note 17 In preparing the financial statements in accordance with for further information on accounting for derivatives under generally accepted accounting principles (GAAP), manage- SFAS No. 133, including discussion on new guidance ment must often make estimates and assumptions that effective on April 1, 2002.

affect the reported amounts of assets, liabilities, revenues, In July 2001, the FASB issued SFAS No. 142, Goodwill expenses, and related disclosures at the date of the financial and Other Intangible Assets. This Statement addresses statements and during the reporting period. Some of those financial accounting and reporting for acquired goodwill judgements can be subjective and complex, and actual and other intangible assets and supersedes Accounting results could differ from those estimates. Our most critical Principles Board Opinion No. 17, Intangible Assets.

accounting policies include the determination of the appro-This standard is effective for the year beginning January 1, priate accounting for our derivative instruments, mark-to-2002. We have no goodwill recorded in our consolidated market accounting and the impacts of regulatory accounting balance sheets. The impacts of this new standard are not on our financial statements. See Note 1 for a discussion of material to our consolidated financial statements.

these critical accounting policies.

The FASB issued SFAS No. 143, Accounting for Asset OTHER ACCOUNTING MATTERS Retirement Obligations in August 2001. The standard We prepare our financial statements in accordance with requires the estimated present value of the cost of decommis-Statement of Financial Accounting Standards (SFAS) No.

sioning and certain other removal costs to be recorded as a 71, Accounting for the Effects of Certain Types of liability, along with an offsetting plant asset when a decom-Regulation. SFAS No. 71 requires a cost-based, rate-regu-missioning or other removal obligation is incurred. We are lated enterprise to reflect the impact of regulatory decisions currently evaluating the impacts of the new standard, which in its financial statements. As a result of the 1999 is effective for the year beginning January 1, 2003.

Settlement Agreement (see Regulatory Agreements above and Note 3), we discontinued the application of SFAS No. In October 2001, the FASB issued SFAS No. 144, 71 for our generation operations. As a result, we tested Accounting for the Impairment or Disposal of Long-Lived the generation assets for impairment and determined that Assets. This statement supersedes SFAS No. 121, the generation assets were not impaired. Pursuant to the Accounting for the Impairment of Long-Lived Assets 1999 Settlement Agreement, we reported a regulatory and for Long-Lived Assets to be Disposed Of, and the disallowance ($140 million after income taxes) as an extra- accounting and reporting provisions for the disposal of a ordinary charge on the 1999 consolidated income state- segment of a business. SFAS No. 144 is effective for the ment. See Note 1 for additional information on regulatory year beginning January 1, 2002. This standard does not accounting and Note 3 for additional information on the impact our financial statements at adoption.

1999 Settlement Agreement.

In 2001, the American Institute of Certified Public Effective January 1, 2001, we adopted SFAS No. 133, Accountants (AICPA) issued an exposure draft of a Accounting for Derivative Instruments and Hedging proposed Statement of Position (SOP), Accounting for Activities. SFAS No. 133 requires that entities recognize all Certain Costs Related to Property, Plant and Equipment derivatives as either assets or liabilities on the balance sheets (PP&E). This proposed SOP would create a project and measure those instruments at fair value. Changes in the timeline framework for capitalizing costs related to PP&E fair value of derivative financial instruments are either rec- construction, require that PP&E assets be accounted for at ognized periodically in income or stockholders equity the component level and require administrative and general (as a component of other comprehensive income), depend- cost incurred in support of capital projects to be expensed ing on whether or not the derivative meets specific hedge in the current period. The AICPA plans to issue the final accounting criteria. Hedge effectiveness is measured based SOP in the fourth quarter of 2002. We are currently on the relative changes in fair value between the derivative evaluating the impacts of the proposed SOP.

contract and the hedged commodity over time. Any change In 1986, APS entered into agreements with three separate in the fair value resulting from ineffectiveness is recognized special purpose entity (SPE) lessors in order to sell and lease immediately in net income. This new standard may result back interests in Palo Verde Unit 2 (See Note 8). The leases in additional volatility in our net income and other are accounted for as operating leases in accordance with comprehensive income.

GAAP. In February 2002, the FASB discussed issues related As a result of adopting SFAS No. 133 in 2001, we recorded to special purpose entities. It is expected that FASB will a $15 million after-tax loss in consolidated net income and issue additional guidance on accounting for SPEs later this a $72 million after-tax gain in equity (as a component of year. As a result of future FASB actions, we may be required other comprehensive income), both as a cumulative effect to consolidate the Palo Verde SPEs in our financial state-of a change in accounting principle. The loss primarily ments. If consolidation is required, the assets and liabilities resulted from electricity options contracts. The gain resulted 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_26 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

sheets is approximately $300 million at December 31, As of December 31, 2001, the indicated annual dividend rate 2001. Rating agencies have already considered this debt on our common stock was $1.60 per share. Since 1994, we when evaluating our credit ratings. have increased the dividend on our common stock ten cents per share per year. We currently plan to continue annual divi-BUSINESS OUTLOOK dend increases of relatively consistent amounts, which would Financial Outlook continue dividend growth at a pace above the industry average.

We currently believe that it will be a challenge for us in 2002 to repeat our 2001 earnings. For 2001, our reported income The foregoing discussion of future expectations is forward-from continuing operations was $327 million, or $3.85 per looking information. Actual results may differ materially from diluted share of common stock, and included charges totaling expectations. See Forward-Looking Statements below.

$21 million before income taxes, or $0.15 per diluted share, Other Factors Affecting Our Financial Outlook that we do not expect to recur related to our exposure to Competition and Industry Restructuring Enron and its affiliates. Our earnings in 2002 are expected to Electric Competition (Wholesale) be negatively affected by a significant decrease in the earnings The FERC regulates rates for wholesale power sales and trans-contribution from our marketing and trading activities and mission services. Our marketing and trading division sells in retail electricity price decreases. These negative factors are the wholesale market APS and Pinnacle West Energy genera-expected to be substantially offset in 2002 by the absence of tion production output that is not needed for APS native significant expenses for reliability and power plant outages load and, in doing so, competes with other utilities, power that we incurred in 2001 that we do not expect to recur in marketers, and independent power producers. Wholesale 2002 and by retail customer growth, although the pace of market prices significantly fell during 2001 and remain low growth is expected to be slower than in the past. These factors for the reasons discussed under Financial Outlook above.

are described in more detail below.

We cannot predict whether these lower prices will continue, In 2001, our marketing and trading activities contributed or whether changes in various factors that affect demand and about one-half of our income from continuing operations capacity, including regulatory actions, will cause the market before the Enron related charges. These activities are currently prices to rise during 2002 or thereafter.

expected to provide about one-fourth of our earnings in 2002.

Electric Competition (Retail)

The drivers of such reduced earnings contributions from our On September 21, 1999, the ACC approved Rules that marketing and trading activities in 2002 are significant reduc-provide a framework for the introduction of retail electric tions in: wholesale market prices for electricity that occurred competition in Arizona. A Maricopa County, Arizona, during 2001; wholesale market liquidity, which affects our Superior Court later found the Rules unlawful and uncon-ability to buy and resell electricity; and market volatility, stitutional; however, the Rules remain in effect pending which affects our ability to capture profitable structured the outcome of appeals. See Retail Electric Competition trading activities. These reductions in regional market factors Rules in Note 3 for additional information about the were due, in large part, to conservation measures in California Rules and the outstanding legal challenges to the Rules.

and throughout the West; more generating plants in service in the West; lower natural gas prices; and the price mitigation Although the Rules allow retail customers to have access to plan that took effect in June 2001 as mandated by the FERC. competitive providers of energy and energy services, APS is the provider of last resort for standard-offer, full-service During 2001, in order to meet highest customer demand in customers under rates that have been approved by the ACC.

APS history, we incurred significant expenses for our summer These rates are established until July 1, 2004. The 1999 reliability program and for higher replacement power costs Settlement Agreement allows APS to seek adjustment of related to power plant outages. These efforts cost approxi-these rates in the event of emergency conditions or circum-mately $140 million before income taxes, which is not stances, such as the inability to secure financing on reason-expected to be repeated in 2002. See Results of Operations -

able terms, or material changes in APS cost of service for 2001 Compared with 2000 above.

ACC-regulated services resulting from federal, tribal, state We estimate our retail customer growth in 2002 to be 3.2%, or local laws, regulatory requirements, judicial decisions, which is slower than the pace of growth in recent years, actions or orders. Energy prices in the western U.S. whole-although still about three times the national average. Our sale market vary and, during the course of the last two customer growth in 2001 was 3.7%. We expect the customer years, have been volatile. At various times, prices in the spot growth rate to be weak in the first two quarters of 2002, then wholesale market have significantly exceeded the amount begin a rebound. Our current estimate for customer growth included in APS current retail rates. In the event in 2003 and 2004 is between 3.5% and 4.0% annually. of shortfalls due to unforeseen increases in load demand or generation outages, APS may need to purchase additional The retail price decreases are described above in Results supplemental power in the wholesale spot market. Unless of Operations - Regulatory Agreements.

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_27

On September 23, 1999, the ACC approved a comprehen- On March 22, 2002, the ACC Staff issued a report to the sive 1999 Settlement Agreement among APS and various ACC recommending that the ACC address the following parties related to the implementation of retail electric issues in the generic docket:

competition in Arizona. See 1999 Settlement Agreement The extent and manner of the ACCs involvement in moni-in Note 3 for additional information about the 1999 toring market conditions and/or mitigating the develop-Settlement Agreement, including the recent resolution of ment of market power for generation and transmission; legal challenges to the 1999 Settlement Agreement.

The lack of guidance in the Rules regarding the mechanics Under the Rules, as modified by the 1999 Settlement Agree- of the competitive bidding process referenced above; ment, APS is required to transfer all of its competitive electric The consideration of alternatives to the transfer of genera-assets and services either to an unaffiliated party or to a tion assets required by the Rules (the ACC Staff stated separate corporate affiliate no later than December 31, 2002. that such transfers would be unwise at the present time Consistent with that requirement, APS has been addressing and recommended that all transfer and separation of the legal and regulatory requirements necessary to complete utilities assets be stayed pending the completion of the the transfer of its generation assets to Pinnacle West Energy generic docket);

on or before that date. In anticipation of APS transfer of The consideration of transmission constraints that could generation assets, Pinnacle West Energy has completed, impact the development of the wholesale power market; and is in the process of developing and planning, various The reassessment of adjustor mechanisms for standard-offer generation expansion projects so that APS can reliably meet rates in light of problems with the development of a whole-the energy requirements of its Arizona customers. sale power market; and The adequacy of customer shopping credits in the Following APS transfer of its fossil-fueled generation assets context of the development of a competitive retail market and the receipt of certain regulatory approvals, Pinnacle West (a shopping credit is the cost a customer does not pay to Energy expects to sell its power at wholesale to our marketing a utility distribution company if the customer obtains and trading division, which, in turn, is expected to sell power generation from another party).

to APS and to non-affiliated power purchasers. In a filing with the ACC on October 18, 2001, APS requested the ACC to: Although not a specific ACC Staff recommendation, the report was also critical of certain aspects of the proposed grant APS a partial variance from an ACC Rule that would purchase power agreement between APS and Pinnacle West.

obligate APS to acquire all of its customers standard-offer generation requirements from the competitive market A modification to the Rules or the 1999 Settlement (with at least 50% of those requirements coming from a Agreement as a result of the consolidated docket could, competitive bidding process) starting in 2003; and among other things, adversely affect APS ability to transfer approve as just and reasonable a long-term purchase its generation assets to Pinnacle West Energy by December power agreement between APS and Pinnacle West. 31, 2002. We cannot predict the outcome of the consolidated docket or its effect on the specific requests in APS October APS requested these ACC actions to ensure ongoing reliable 2001 filing, the existing Arizona electric competition rules, service to APS standard-offer, full-service customers in a vola-or the 1999 Settlement Agreement.

tile generation market and to recognize Pinnacle West Ener-gys significant investment to serve APS load. See Proposed As a result of the foregoing matters, as well as energy market Rule Variance and Purchase Power Agreement in Note 3 for developments, including those relating to Californias failed additional information about APS October 2001 ACC filing. deregulation efforts and to Enrons recent bankruptcy filing, electric utility restructuring is in a state of flux in the western On February 8, 2002, the ACCs Chief ALJ issued a proce-United States, including Arizona, and around the country.

dural order which consolidated the ACC docket relating to APS October, 2001 filing with several other pending ACC Generation Expansion dockets, including a generic docket request by the ACC See Note 10 for information regarding our generation expan-Chairman to determine if changed circumstances require sion plans. The planned additional generation is expected to the [ACC] to take another look at restructuring in Arizona. increase revenues, fuel expenses, operating expenses, and Although the order consolidates several dockets, it states that financing costs.

a hearing on the APS matter will commence on April 29, California Energy Market Issues 2002. The order went on to state that, contrary to APS See Note 10 for information regarding California energy position, the ALJ was construing the October, 2001 filing market issues.

as a request by APS to amend the 1999 ACC order that approved the 1999 Settlement Agreement. 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_28 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

growth and average usage per customer, as well as electricity The annual earnings contribution from APSES is expected prices and variations in weather from period to period. to be modest, yet positive, over the next several years due primarily to a number of retail electricity contracts in In APS regulated retail market area, APS will provide California. APSES pretax losses were $10 million in 2001 electricity services to standard-offer, full-service customers and $13 million in 2000.

and to energy delivery customers who have chosen another provider for their electricity commodity needs (unbundled The annual earnings contribution from SunCor is expected customers). Customer growth in APS service territory to remain modest over the next several years. SunCors averaged about 4% a year for the three years 1999 through earnings were $3 million in 2001, $11 million in 2000 2001; we currently expect customer growth to be about and $6 million in 1999.

3.2% in 2002 and between 3.5% and 4.0% a year in 2003 El Dorados historical results are not necessarily indicative and 2004. We currently estimate that retail electricity sales of future performance for El Dorado. El Dorados strategies in kilowatt-hours will grow 3.5% to 5.5% a year in 2002 focus on prudently realizing the value of its existing invest-through 2004, before the retail effects of weather variations.

ments. Any future investments are expected to be related to The customer growth and sales growth referred to in this the energy sector. See Note 1 for additional information paragraph apply to energy delivery customers. As industry regarding El Dorado.

restructuring evolves in the regulated market area, we cannot predict the number of APS standard-offer customers that will We cannot accurately predict the impact of full retail switch to unbundled service. As previously noted, under the competition on our financial position, cash flows, results 1999 Settlement Agreement, we have annual retail electricity of operations, or liquidity. As competition in the electric price reductions of 1.5% through July 1, 2003 (see Note 3). industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete Competitive sales of energy and energy-related products and effectively in a restructured industry.

services are made by APSES in western states that have opened to competitive supply. Such activities currently are Our financial results may be affected by the application of not material to our consolidated financial results. SFAS No. 133. See Critical Accounting Policies above and Note 17 for further information.

Other Factors Affecting Future Financial Results Purchased power and fuel costs are impacted by our electric- Our financial results may be affected by a number of broad ity sales volumes, existing contracts for generation fuel and factors. See Forward-Looking Statements below for further purchased power, our power plant performance, prevailing information on such factors, which may cause our actual future market prices, new generating plants being placed in service results to differ from those we currently seek or anticipate.

and our hedging program for managing such costs.

MARKET RISKS Operations and maintenance expenses are expected to be Our operations include managing market risks related to affected by sales mix and volumes, power plant operations, changes in interest rates, commodity prices, and investments inflation, outages and other factors. held by the nuclear decommissioning trust fund.

Depreciation and amortization expenses are expected to be Interest Rate and Equity Risk affected by net additions to existing utility plant and other Our major financial market risk exposure is changing property, changes in regulatory asset amortization, and our interest rates. Changing interest rates will affect interest paid generation expansion program. See Note 1 for the regulato- on variable-rate debt and interest earned by our nuclear ry asset amortization that is being recorded in 1999 through decommissioning trust fund (see Note 11). Our policy is to 2004 pursuant to the 1999 Settlement Agreement. Also, see manage interest rates through the use of a combination of Note 1 regarding current depreciation rates. fixed-rate and floating-rate debt. The nuclear decommis-sioning fund also has risks associated with changing market Taxes other than income taxes consist primarily of property values of equity investments. Nuclear decommissioning taxes, which are affected by tax rates and the value of proper-costs are recovered in regulated electricity prices.

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.

p_29

The tables below present contractual balances of our long- December 31, 2001 and 2000. The interest rates presented term debt and commercial paper at the expected maturity in the tables below represent the weighted average interest dates as well as the fair value of those instruments on rates for 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, 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 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 Commodity Price Risk The following schedule shows the changes in mark-to-We are exposed to the impact of market fluctuations in the market of our trading positions during the years ended price and transportation costs of electricity, natural gas, coal, December 31, 2001 and 2000:

and emissions allowances. We employ established proce- (dollars in millions) 2001 2000 dures to manage risks associated with these market fluctua-tions by utilizing various commodity derivatives, including Mark-to-market of net trading positions exchange-traded futures and options and over-the-counter at beginning of year $ 12 $ -

forwards, options, and swaps. As part of our overall risk Prior period marked-to-market gains management program, we enter into derivative transactions realized during the year (1) (2) to hedge purchases and sales of electricity, fuels, and Change in marked-to-market gains emissions allowances and credits. The changes in market for future period deliveries 127 14 value of such contracts have a high correlation to price Mark-to-market of net trading positions changes in the hedged commodity. at end of year $ 138 $ 12 In addition, subject to specified risk parameters established Net gains at inception include a reasonable marketing margin by the Board of Directors and monitored by the Energy Risk and were approximately $3 million in 2001 and $2 million Management Committee, we engage in trading activities in 2000. See Note 17 for disclosure of risk management intended to profit from market price movements. In accor-activities recorded on the consolidated balance sheets.

dance with Emerging Issues Task Force (EITF) 98-10.

Accounting For Contracts Involved in Energy Trading and The table below shows the maturities of our trading Risk Management Activities, such trading positions are positions as of December 31, 2001 in millions of dollars marked-to-market. These trading activities are part of our by the type of valuation that is performed to calculate the marketing and trading activities and are reflected in the fair value of the contract. In addition, see Note 1 for more marketing and trading revenues and expenses. discussion on our valuation methods.

p_30 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

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 risk management and trading assets and liabilities included on movements of 10% would have on the market value of our the consolidated balance sheets at December 31, 2001 and 2000.

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.

We are exposed to losses in the event of nonperformance or differ materially from expectations, we caution readers not nonpayment by counterparties. We have risk management to place undue reliance on these statements. A number of and trading contracts with many counterparties, including factors could cause future results to differ materially from one counterparty for which a worst case exposure represents historical results, or from results or outcomes currently approximately 50% of our $267 million of risk manage- expected or sought by us. These factors include the ment and trading assets as of December 31, 2001. We use a ongoing restructuring of the electric industry, including the risk management process to assess and monitor the financial introduction of retail electric competition in Arizona and exposure of this and all other counterparties. Despite the APS October 2001 ACC filing; the outcome of regulatory fact that the great majority of trading counterparties are and legislative proceedings relating to the restructuring; rated as investment grade by the credit rating agencies, state and federal regulatory and legislative decisions and including the counterparty noted above, there is still a pos- actions, including the price mitigation plan adopted by sibility that one or more of these companies could default, the FERC in June 2001; regional economic and market resulting in a material impact on consolidated earnings for a conditions, including the California energy situation and given period. Counterparties in the portfolio consist princi- completion of generation construction in the region, pally of major energy companies, municipalities, and local which could affect customer growth and the cost of power distribution companies. We maintain credit policies that supplies; the cost of debt and equity capital; weather varia-we believe minimize overall credit risk to within acceptable tions affecting local and regional customer energy usage; limits. Determination of the credit quality of our counter- conservation programs; power plant performance; the parties is based upon a number of factors, including credit successful completion of our generation expansion program; ratings and our evaluation of their financial condition. In regulatory issues associated with generation expansion, such many contracts, we employ collateral requirements and stan- as permitting and licensing; our ability to compete success-dardized agreements that allow for the netting of positive and fully outside traditional regulated markets (including the negative exposures associated with a single counterparty. wholesale market); technological developments in the Credit reserves are established representing our estimated electric industry; and the strength of the real estate market credit losses on our overall exposure to counterparties. See in SunCors market areas, which include Arizona, New Note 1 for a discussion of our credit reserve policy. Mexico and Utah.

FORWARD-LOOKING STATEMENTS These factors and the other matters discussed above may The above discussion contains forward-looking statements cause future results to differ materially from historical results, based on current expectations and we assume no obligation or from results or outcomes we currently expect or seek.

to update these statements. Because actual results may p_31

REPORT OF MANAGEMENT AND INDEPENDENT AUDITORS REPORT REPORT OF MANAGEMENT INDEPENDENT AUDITORS REPORT The responsibility for the integrity of our financial informa- To the Board of Directors and Stockholders of tion rests with management, which has prepared the accom- Pinnacle West Capital Corporation panying financial statements and related information. This Phoenix, Arizona information was prepared in accordance with generally We have audited the accompanying consolidated balance accepted accounting principles as appropriate in the circum-sheets of Pinnacle West Capital Corporation and subsidiaries stances, and based on managements best estimates and as of December 31, 2001 and 2000, and the related consoli-judgments. These financial statements have been audited dated statements of income, changes in common stock by independent auditors and their report is included.

equity, and cash flows for each of the three years in the period Management maintains and relies upon systems of internal ended December 31, 2001. Our audits also included the control. A limiting factor in all systems of internal control is financial statement schedule listed in the Index at Item 14.

that the cost of the system should not exceed the benefits to These financial statements and the financial statement be derived. Management believes that our system provides schedule are the responsibility of the Corporations manage-the appropriate balance between such costs and benefits. ment. Our responsibility is to express an opinion on the financial statements and the financial statement schedule Periodically the internal control system is reviewed by both based on our audits.

our internal auditors to test for compliance and our inde-pendent auditors in conjunction with their audit of our We conducted our audits in accordance with auditing stan-financial statements. Reports issued by the internal auditors dards generally accepted in the United States of America.

are released to management, and such reports or summaries Those standards require that we plan and perform the audit thereof are transmitted to the Audit Committee of the Board to obtain reasonable assurance about whether the financial of Directors and the independent auditors on a timely basis. statements are free of material misstatement. An audit By letter dated February 8, 2002, to the Audit Committee, includes examining, on a test basis, evidence supporting the our independent auditors confirmed that they are indepen- amounts and disclosures in the financial statements. An audit dent accountants with respect to us within the meaning of also includes assessing the accounting principles used and sig-the Securities Act and the requirements of the Independence nificant estimates made by management, as well as evaluating Standards Board. the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

The Audit Committee, composed solely of outside direc-tors, meets periodically with the internal auditors and inde- In our opinion, such consolidated financial statements pre-pendent auditors (as well as management) to review the sent fairly, in all material respects, the financial position of work of each. The internal auditors and independent audi- Pinnacle West Capital Corporation and subsidiaries at tors have free access to the Audit Committee, without man- December 31, 2001 and 2000, and the results of their opera-agement present, to discuss the results of their audit work. tions and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with Management believes that our systems, policies and proce-accounting principles generally accepted in the United States dures provide reasonable assurance that operations are con-of America. Also, in our opinion, such financial statement ducted in conformity with the law and with managements schedule, when considered in relation to the basic consoli-commitment to a high standard of business conduct.

dated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

William J. Post Chris N. Froggatt Chairman and Vice President and As discussed in Note 17 to the financial statements, in 2001 Chief Executive Officer Controller 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) p_32 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

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_33

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_34 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

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_35

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_36 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

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_37

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES In addition, subject to specified risk parameters established Consolidation and Nature of Operations by the Board of Directors and monitored by the ERMC, The consolidated financial statements include the accounts we engage in trading activities intended to profit from of Pinnacle West and our subsidiaries: APS, Pinnacle West market price movements. If a contract was entered into Energy, APSES, SunCor, and El Dorado. Significant inter- for trading purposes, we account for it in accordance with company accounts and transactions between the consolidated EITF 98-10, Accounting for Contracts Involved in Energy companies have been eliminated. Trading and Risk Management Activities. EITF 98-10 requires energy trading contracts to be measured at fair APS, our major subsidiary and Arizonas largest electric value as of the balance sheet date, with unrealized gains and utility, provides either retail or wholesale electric service to losses included in earnings on a current basis (the mark-to-substantially all of the state, with the major exceptions of market method). See Mark-to-Market Method below and the Tucson metropolitan area and about one-half of the Note 17 for further information about our trading contracts.

Phoenix metropolitan area. APS also generates and, directly or through our marketing and trading division, sells and We examine contracts at inception to determine the appro-delivers electricity to wholesale customers in the western priate accounting treatment. If a contract is not considered United States. During 2001, APS transferred most of its energy trading we must determine if it is a derivative as marketing and trading activities to the parent company. defined in SFAS No. 133 (see Note 17 for further infor-Pinnacle West Energy, which was formed in 1999, is the mation on SFAS No. 133). If a contract does not meet the subsidiary through which we conduct our unregulated derivative criteria or if it qualifies for a SFAS No. 133 generation operations. APSES was formed in 1998 and scope exception, we account for the contract using accrual provides commodity energy and energy-related products accounting (this means that costs and revenues are recorded to key customers in competitive markets in the western when physical delivery occurs). For contracts that qualify United States. SunCor is a developer of residential, as a derivative and do not meet a SFAS No. 133 scope commercial, and industrial real estate projects in Arizona, exception, we further examine the contract to determine if New Mexico, and Utah. El Dorado is an investment firm. it will qualify for hedge accounting. If a contract does not meet the hedging criteria in SFAS No. 133, we recognize Accounting Records and Use of Estimates the changes in the fair value of the derivative instrument in Our accounting records are maintained in accordance income each period (mark-to-market). If it does qualify for with accounting principles generally accepted in the United hedge accounting, changes in the fair value are recognized States of America (GAAP). The preparation of financial as either an asset or liability or in stockholders equity (as statements in accordance with GAAP requires management a component of accumulated other comprehensive income) to make estimates and assumptions that affect the reported depending on the nature of the hedge.

amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial Gains and losses related to derivatives that qualify as cash statements and reported amounts of revenues and expenses flow hedges of expected transactions are recognized in during the reporting period. Actual results could differ revenue or fuel and purchased power expense as an offset to from those estimates. We have reclassified certain prior the related item being hedged when the underlying hedged year amounts to conform to current year presentation. physical transaction impacts earnings (deferral method). See Note 17 for further discussion on derivative accounting.

Derivative Instruments We are exposed to the impact of market fluctuations in Mark-to-Market Method the price and transportation costs of electricity, natural Under mark-to-market accounting the purchase or sale gas, coal, and emissions allowances. We employ established of energy commodities are reflected at fair market value, procedures to manage risks associated with these market net of reserves, with resulting unrealized gains and losses fluctuations by utilizing various commodity derivatives, recorded as assets and liabilities from risk management including exchange-traded futures and options and over- and trading activities in the consolidated balance sheets.

the-counter forwards, options, and swaps. As part of our We determine fair market value using actively-quoted prices overall risk management program, we enter into derivative when available. We consider quotes for exchange-traded transactions to hedge purchases and sales of electricity, contracts and over-the-counter quotes obtained from fuels, and emissions allowances and credits. The changes independent brokers to be actively-quoted.

in market value of such contracts have a high correlation to price changes in the hedged commodity. 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.

p_38 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

For options, long-term contracts and other contracts SFAS No. 71 requires a cost-based, rate-regulated where price quotes are not available, we use models and enterprise to reflect the impact of regulatory decisions in other valuation methods. For illiquid or unquoted market its financial statements.

locations, we consider the historical relationship to readily-During 1997, the EITF of the FASB issued EITF 97-4.

available market quotations. The valuation models we EITF 97-4 requires that SFAS No. 71 be discontinued no employ utilize spot prices, forward prices, historical market later than when legislation is passed or a rate order is issued data and other factors to forecast future prices.

that contains sufficient detail to determine its effect on the For non-exchange traded contracts, we calculate fair market portion of the business being deregulated, which could value based on the average of the bid and offer price, result in write-downs or write-offs of physical and/or and we discount to reflect net present value. We maintain regulatory assets. Additionally, the EITF determined that certain reserves for a number of risks associated with the regulatory assets should not be written off if they are to be valuation of future commitments. These include reserves recovered from a portion of the entity which continues to for liquidity and credit risks based on the financial condi- apply SFAS No. 71.

tion of counterparties. The liquidity reserve represents the The 1999 Settlement Agreement was approved by the cost that would be incurred if all unmatched positions were ACC in September 1999 (see Note 3 for a discussion of closed-out or hedged. As we mark positions to a mid-the agreement). Consequently, we have discontinued the market value this reserve adjusts the mid-market valuation application of SFAS No. 71 for our generation operations.

to the bid or offer, after taking into consideration offsetting As a result, we tested the generation assets for impairment positions, to reflect the true cash flow that would be and determined that the generation assets were not realized upon exiting the net position.

impaired. Pursuant to the 1999 Settlement Agreement, a A credit reserve is also recorded to represent estimated credit regulatory disallowance removed $234 million pretax losses on our overall exposure to counterparties, taking into ($183 million net present value) from ongoing regulatory account netting arrangements; expected default experience cash flows and was recorded as a net reduction of regulatory for the credit rating of the counterparties; and the overall assets. This reduction ($140 million after income taxes) was diversification of the portfolio. Counterparties in the port- reported as an extraordinary charge on the income state-folio consist principally of major energy companies, munici- ment during the third quarter of 1999. Prior to the 1999 palities, and local distribution companies. We maintain Settlement Agreement, under the 1996 regulatory agree-credit policies that management believes minimize overall ment (see Note 3), the ACC accelerated the amortization credit risk. Determination of the credit quality of counter- of substantially all of our regulatory assets to an eight-year parties is based upon a number of factors, including credit period that would have ended June 30, 2004.

ratings, financial condition, project economics and collateral The regulatory assets to be recovered under the 1999 requirements. When applicable, we employ standardized Settlement Agreement are currently being amortized as agreements that allow for the netting of positive and follows (dollars in millions):

negative exposures associated with a single counterparty.

1/1- 6/30 The use of models and other valuation methods to deter- 1999 2000 2001 2002 2003 2004 TOTAL mine fair market value often requires subjective and com-plex judgement. Actual results could differ from the results $164 $158 $145 $115 $86 $18 $686 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.

p_39

Regulatory assets are reported as deferred debits on the con- We record depreciation on utility property on a straight-solidated balance sheets. As of December 31, 2001 and 2000, line basis. For the years 1999 through 2001 the rates, as they are comprised of the following: prescribed by our regulators, ranged from a low of 1.49%

December 31, to a high of 20%. The weighted-average rate was 3.40% for (dollars in millions) 2001 2000 2001, 3.40% for 2000, and 3.34% for 1999. We depreciate non-utility property and equipment over the estimated Remaining balance recoverable under useful lives of the related assets, ranging from 3 to 30 years.

the 1999 Settlement Agreement (a) $ 219 $ 364 We expense the costs of plant outages, major maintenance Spent fuel storage (Note 10) 43 40 and routine maintenance as incurred.

Electric industry restructuring transition costs (Note 3) 34 24 El Dorado Investments Other 46 42 El Dorado accounts for its investments using the equity Total regulatory assets $ 342 $ 470 method. Net other income has consisted primarily of El Dorados share of the earnings of a venture capital partner-(a) The majority of our unamortized regulatory assets above relates to ship. We record our share of the earnings from the partner-deferred income taxes (See Note 4) and rate synchronization cost deferrals (see Rate Synchronization Cost Deferrals below). ship as the partnership adjusts the value of its investments.

In 2001, El Dorado received a distribution of securities rep-Regulatory liabilities are included in deferred credits and resenting substantially all of El Dorados investment in the other on the consolidated balance sheets. As of December partnership. The securities were sold in the first quarter of 31, 2001 and 2000, they are comprised of the following: 2001 and a gain was recognized in other income. The book value of El Dorados investment in the partnership was December 31, (dollars in millions) 2001 2000 approximately $1 million at December 31, 2001, and $7 million at December 31, 2000. El Dorados net investment Deferred gains on utility property $ 20 $ 20 book value was approximately $10 million at December 31, Other 7 8 2001 and $21 million at December 31, 2000.

Total regulatory liabilities $ 27 $ 28 Capitalized Interest Capitalized interest represents the cost of debt funds used The consolidated balance sheets include the amounts listed to finance construction of utility plants. Plant construction below for generation assets not subject to SFAS No. 71:

costs, including capitalized interest, are expensed through December 31, depreciation when completed projects are placed into com-(dollars in millions) 2001 2000 mercial operation. Capitalized interest does not represent current cash earnings. The rate used to calculate capitalized Electric plant in service and held for interest was a composite rate of 6.13% for 2001, 6.62%

future use $ 3,954 $ 3,854 for 2000, and 6.65% for 1999.

Accumulated depreciation and amortization (1,990) (1,902) Revenues Construction work in progress 824 304 We record electric operating revenues on the accrual basis, Nuclear fuel, net of amortization 49 47 which includes estimated amounts for service rendered but unbilled at the end of each accounting period. We exclude Utility Plant and Depreciation sales taxes on electric revenues from both revenue and taxes Utility plant is the term we use to describe the business other than income taxes. Electric revenues are recorded property and equipment that supports electric service, gross on the statements of income, with the exception of consisting primarily of generation, transmission, and unrealized gains and losses recorded under the mark-to-distribution facilities. We report utility plant at its original market method (see discussion above). Unrealized gains and cost, which includes: losses are recorded net in electric revenues. When the gain material and labor; or loss is realized, the gross amount is recorded as electric contractor costs; revenue and fuel or purchased power expense in the construction overhead costs (where applicable); and consolidated statements of income.

capitalized interest or an allowance for funds used Cash and Cash Equivalents during construction.

For purposes of the statement of cash flows, we consider We charge retired utility plant, plus removal costs less all highly liquid debt instruments purchased with an initial salvage realized, to accumulated depreciation. See Note 2 maturity of three months or less to be cash equivalents.

for information on a new accounting standard that impacts Rate Synchronization Cost Deferrals accounting for removal costs.

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 p_40 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

1986 for Unit 2 and January 1988 for Unit 3) until the date Home inventory consists of construction costs, improved lot the units were included in a rate order (April 1988 for Unit costs, capitalized interest and property taxes on homes under 2 and December 1991 for Unit 3). In accordance with the construction. Home inventory is stated at the lower of 1999 Settlement Agreement, we are continuing to accelerate accumulated cost or estimated fair value less costs to sell.

the amortization of the deferrals over an eight-year period Investments in joint ventures for which SunCor does not that will end June 30, 2004. Amortization of the deferrals have a controlling financial interest are not consolidated but is included in depreciation and amortization expense in the are accounted for using the equity method of accounting.

consolidated statements of income.

2. ACCOUNTING MATTERS Nuclear Fuel In July 2001, the FASB issued SFAS No. 142, Goodwill APS charges nuclear fuel to fuel expense by using the and Other Intangible Assets. This statement addresses unit-of-production method. The unit-of-production method financial accounting and reporting for acquired goodwill is an amortization method that is based on actual physical and other intangible assets and supersedes APB Opinion usage. APS divides the cost of the fuel by the estimated num- No. 17, Intangible Assets. This standard is effective for ber of thermal units that it expects to produce with that fuel. the year beginning January 1, 2002. We have no goodwill APS then multiplies that rate by the number of thermal units recorded in our consolidated balance sheets. The impacts of that it produces within the current period. This calculation this new standard are not material to our financial statements.

determines the current period nuclear fuel expense.

In August 2001, the FASB issued SFAS No. 143 APS also charges nuclear fuel expense for the permanent Accounting for Asset Retirement Obligations. The disposal of spent nuclear fuel. The United States standard requires the estimated present value of the cost of Department of Energy (DOE) is responsible for the perma- decommissioning and certain other removal costs to be nent disposal of spent nuclear fuel, and it charges APS recorded as a liability, along with an offsetting plant asset

$0.001 per kWh of nuclear generation. See Note 10 for when a decommissioning or other removal obligation is information about spent nuclear fuel disposal and Note 11 incurred. We are currently evaluating the impacts of the for information on nuclear decommissioning costs. new standard, which is effective for the year beginning January 1, 2003.

Income Taxes Income taxes are provided using the asset and liability In October 2001, the FASB issued SFAS No. 144, approach prescribed by SFAS No. 109. We file our federal Accounting for the Impairment or Disposal of Long-Lived income tax return on a consolidated basis and we file our Assets. This statement supersedes SFAS No. 121, state income tax returns on a consolidated or unitary basis. Accounting for the Impairment of Long-Lived Assets In accordance with our intercompany tax sharing agree- and for Long-Lived Assets to be Disposed Of, and the ment, federal and state income taxes are allocated to each accounting and reporting provisions for the disposal of a subsidiary as though each subsidiary filed a separate income segment of a business. SFAS No. 144 is effective for the tax return. Any difference between the aforementioned year beginning January 1, 2002. This standard does not allocations and the consolidated (and unitary) income tax impact our financial statements at adoption.

liability is attributed to the parent company.

In 2001, the American Institute of Certified Public Reacquired Debt Costs Accountants (AICPA) issued an exposure draft of a proposed For debt related to the regulated portion of APS business, Statement of Position (SOP), Accounting for Certain Costs APS amortizes those gains and losses incurred upon early Related to Property, Plant, and Equipment. This proposed retirement over the remaining life of the debt. In accordance SOP would create a project timeline framework for capital-with the 1999 Settlement Agreement, APS is continuing to izing costs related to property, plant and equipment (PP&E) accelerate reacquired debt costs over an eight-year period construction, which require that PP&E assets be accounted that will end June 30, 2004. All regulatory asset amortiza- for at the component level, and require administrative and tion is included in depreciation and amortization expense general costs incurred in support of capital projects to be in the consolidated statements of income. expensed in the current period. The AICPA plans to issue the final SOP in the fourth quarter of 2002.

Real Estate Investments Real estate investments primarily include SunCors land, In 1986, APS entered into agreements with three separate home inventory and investments in joint ventures. Land special purpose entity (SPE) lessors in order to sell and lease includes acquisition costs, infrastructure costs, property back interests in Palo Verde Unit 2 (See Note 8). The leases taxes and capitalized interest directly associated with the are accounted for as operating leases in accordance with acquisition and development of each project. Land under GAAP. In February 2002, the FASB discussed issues related development and land held for future development are to special purpose entities. It is expected that FASB will stated at accumulated cost, except to the extent that such issue additional guidance on accounting for SPEs later this land is believed to be impaired, it is written down to fair year. As a result of future FASB actions, we may be required value. Land held for sale is stated at the lower of the accu-mulated cost or estimated fair value less costs to sell.

p_41

to consolidate the Palo Verde SPEs in our financial state- ($7 million after income taxes) related to the 1996 regula-ments. If consolidation is required, the assets and liabilities tory agreement. See 1996 Regulatory Agreement below.

of the SPEs that relate to the sale-leaseback transactions Based on the price reductions authorized in the 1999 would be reflected on our consolidated balance sheets. The Settlement Agreement, there were also retail price decreases SPE debt that is not reflected on our consolidated balance of approximately $28 million ($17 million after taxes),

sheets is approximately $300 million at December 31, or 1.5%, effective July 1, 2000, and approximately $27 2001. Rating agencies have already considered this debt million ($16 million after taxes), or 1.5%, effective July 1, when evaluating our credit ratings. 2001. For customers having loads three MW or greater, standard-offer rates will be reduced in varying annual

3. REGULATORY MATTERS increments that total 5% in the years 1999 through 2002.

Electric Industry Restructuring Unbundled rates being charged by APS for competitive State direct access service (for example, distribution services) 1999 Settlement Agreement. On May 14, 1999, APS became effective upon approval of the 1999 Settlement entered into a comprehensive 1999 Settlement Agreement Agreement, retroactive to July 1, 1999, and also became with various parties, including representatives of major subject to annual reductions beginning January 1, 2000, consumer groups, related to the implementation of retail that vary by rate class, through January 1, 2004.

electric competition. On September 23, 1999, the ACC There will be a moratorium on retail price changes for voted to approve the 1999 Settlement Agreement, with standard-offer and unbundled competitive direct access some modifications.

services until July 1, 2004, except for the price reductions On December 13, 1999, two parties filed lawsuits challeng- described above and certain other limited circumstances.

ing the ACCs approval of the 1999 Settlement Agreement. Neither the ACC nor APS will be prevented from seeking Each party bringing the lawsuits appealed the ACCs order or authorizing rate changes prior to July 1, 2004 in the approving the 1999 Settlement Agreement directly to the event of conditions or circumstances that constitute an Arizona Court of Appeals, as provided by Arizona law. In emergency, such as an inability to finance on reasonable one of the appeals, on December 26, 2000, the Arizona terms, or material changes in APS cost of service for Court of Appeals affirmed the ACCs approval of the 1999 ACC-regulated services resulting from federal, tribal, state Settlement Agreement. This decision was not appealed and or local laws, regulatory requirements, judicial decisions, has become final. In the other appeal, on April 5, 2001, actions or orders.

the Arizona Court of Appeals again affirmed the ACCs APS will be permitted to defer for later recovery prudent approval of the 1999 Settlement Agreement. The Arizona and reasonable costs of complying with the ACC electric Consumers Council, which filed that appeal, petitioned the competition rules, system benefits costs in excess of the Arizona Supreme Court for review of the Court of Appeals levels included in then-current (1999) rates, and costs decision. On October 5, 2001, the Arizona Supreme Court associated with the provider of last resort and standard-agreed to hear the appeal on the single issue of whether offer obligations for service after July 1, 2004. These costs the ACC could itself become a party to the 1999 are to be recovered through an adjustment clause or Settlement Agreement by virtue of its approval of the 1999 clauses commencing on July 1, 2004.

Settlement Agreement. On December 14, 2001, the APS distribution system opened for retail access effective Arizona Supreme Court vacated its own October 5, 2001 September 24, 1999. Customers were eligible for retail order accepting jurisdiction and decided to dismiss the access in accordance with the phase-in adopted by the appeal. As a result, the judicial challenges to the 1999 ACC under the electric competition rules (see Retail Settlement Agreement have terminated. Consistent with Electric Competition Rules below), including an its obligations under the 1999 Settlement Agreement, on additional 140 MW being made available to eligible non-January 7, 2002, APS and the ACC filed in Maricopa residential customers. APS opened its distribution system County Superior Court a stipulation to dismiss all of APS to retail access for all customers on January 1, 2001.

litigation pending against the ACC. On January 15, 2002, Prior to the 1999 Settlement Agreement, APS was recov-a Maricopa County Superior Court judge issued an order ering substantially all of its regulatory assets through July dismissing such litigation. 1, 2004, pursuant to the 1996 regulatory agreement. In addition, the 1999 Settlement Agreement states that APS The following are the major provisions of the 1999 has demonstrated that its allowable stranded costs, after Settlement Agreement, as approved:

mitigation and exclusive of regulatory assets, are at least APS has reduced, and will reduce, rates for standard-offer $533 million net present value. APS will not be allowed service for customers with loads less than three MW in a to recover $183 million net present value of the above series of annual retail electricity price reductions of 1.5% amounts. The 1999 Settlement Agreement provides that beginning July 1, 1999 through July 1, 2003, for a total APS will have the opportunity to recover $350 million of 7.5%. The first reduction of approximately $24 mil- net present value through a competitive transition charge lion ($14 million after income taxes) included the July 1, that will remain in effect through December 31, 2004, at 1999 retail price decrease of approximately $11 million which time it will terminate. The costs subject to recovery p_42 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

under the adjustment clause described above will be generation; and (c) any purchased power agreements that decreased or increased by any over/under-recovery due to APS cannot transfer to Pinnacle West Energy.

sales volume variances. Pinnacle West would assume contractual responsibility for APS will form, or cause to be formed, a separate corporate reliability and would supplement any potential shortfall affiliate or affiliates and transfer to such affiliate(s) its even after full utilization of Pinnacle West Energys competitive electric assets and services at book value as of dedicated generating resources.

the date of transfer, and will complete the transfer no later Pinnacle West would supply APS standard-offer require-than December 31, 2002. Accordingly, APS plans to com- ments through a combination of (a) APS generation assets plete the move of such assets and services from APS to the transferred to Pinnacle West Energy; (b) certain of parent company or to Pinnacle West Energy by the end of Pinnacle West Energys new Arizona generation projects 2002, as required, although the ACCs recent establishment to be constructed during the 2001-2004 period to reliably of a generic docket to consider electric industry restruc- serve APS load requirements; (c) power procured by turing in Arizona and the consolidation of that docket with Pinnacle West under certain dedicated contracts; and APS request for approval of a PPA between Pinnacle West (d) power procured on the open market, including a and APS could affect APS ability to transfer assets to competitively-bid component described below.

Pinnacle West Energy. APS will be allowed to defer and Beginning in 2003, Pinnacle West would acquire 270 later collect, beginning July 1, 2004, sixty-seven percent of MW of APS standard-offer requirements on the open its costs to accomplish the required transfer of generation market through a competitive bidding process. This assets to an affiliate. competitive bid obligation would be increased by an additional 270 MW each year through 2008 (representing As discussed in Note 1 above, we have discontinued the approximately 23% of estimated 2008 peak load).

application of SFAS No. 71 for our generation operations.

Pinnacle West would charge APS based on (a) a com-Proposed Rule Variance and Purchase Power Agreement. bination of fixed and variable price components for the As authorized by the 1999 Settlement Agreement, APS Pinnacle West Energy assets, subject to periodic adjust-intends to move substantially all of its generation assets to ment, and (b) a pass-through of Pinnacle Wests costs Pinnacle West Energy no later than December 31, 2002. to procure power from the remaining sources.

Commencing upon the transfer of the fossil-fueled gener- The PPA would take effect on the latest of the following ating assets and the receipt of certain regulatory approvals, events: (a) transfer of non-nuclear generating assets from Pinnacle West Energy expects to sell its power at wholesale APS to Pinnacle West Energy; (b) ACC approval of the to Pinnacle Wests marketing and trading division, which, in rule variance and the PPA; and (c) the FERCs acceptance turn, is expected to sell power to APS and to non-affiliated of the PPA and the companion agreement between power purchasers. In a filing with the ACC on October 18, Pinnacle West and Pinnacle West Energy.

2001, APS requested the ACC to:

APS is required to transfer its competitive electric assets and grant APS a partial variance from an ACC rule that would services to one or more corporate affiliates on or before obligate APS to acquire all of its customers standard-offer, December 31, 2002. Consistent with that requirement, APS full-service generation requirements from the competitive has been addressing the legal and regulatory requirements market (with at least 50% of those requirements coming necessary to complete the transfer of its generation assets to from a competitive bidding process) starting in 2003; and Pinnacle West Energy, on or before that date. In anticipation approve as just and reasonable a long-term purchase of APS transfer of generation assets, Pinnacle West Energy power agreement (PPA) between APS and Pinnacle West. has completed, and is in the process of developing and plan-ning, various generation expansion projects so that APS can APS has requested these ACC actions to ensure ongoing reliably meet the energy requirements of its Arizona customers.

reliable service to APS standard-offer, full-service customers in a volatile generation market and to recognize Pinnacle By letter dated January 14, 2002, the Chairman of the ACC West Energys significant investment to serve APS load. stated that the [ACCs] Electric Competition Rules, along The following are the major provisions of the PPA: with the Settlement Agreements approved for APS and

[Tucson Electric Company], establish the framework for the The PPA would run through 2015, with three optional transition to a retail generation competitive market. The five-year renewal terms, which renewals would occur ACC Chairman then recommended that the ACC establish automatically unless notice is given by either APS or a new generic docket to determine if changed circum-Pinnacle West.

stances require the [ACC] to take another look at electric 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 p_43

restructuring in Arizona. Matters that would be addressed APS ability to transfer its generation assets to Pinnacle West by the ACC in the new docket would include: Energy by December 31, 2002. Pinnacle West cannot predict the outcome of the consolidated docket or its effect whether the ACC should continue implementation of the on the specific requests in APS October 2001 filing, the retail electric competition Rules adopted by the ACC in existing Arizona electric competition rules, or the 1999 1999 in their current form or with modifications; Settlement Agreement.

whether the ACC should slow the pace of the implemen-tation of the [Rules] to provide an opportunity to consid- Retail Electric Competition Rules. On September 21, er the extent to which [Rule] modification and variance is 1999, the ACC voted to approve Rules that provide a frame-in the public interest, including changing the direction to work for the introduction of retail electric competition in retail electric competition; and Arizona. Under the 1999 Settlement Agreement, the Rules whether the ACC should step back from electric industry are to be interpreted and applied, to the greatest extent restructuring until the [ACC] is convinced that there possible, in a manner consistent with the 1999 Settlement exists a viable competitive wholesale electric market to Agreement. If the two cannot be reconciled, APS must seek, support retail electric competition in Arizona. and the other parties to the 1999 Settlement Agreement must support, a waiver of the Rules in favor of the 1999 On January 22, 2002 the ACCs Chief ALJ issued a procedural Settlement Agreement. On December 8, 1999, APS filed a order by which a generic docket was opened. On February 8, lawsuit to protect its legal rights regarding the Rules. This 2002, the ACCs ALJ issued a procedural order which consoli-lawsuit has been dismissed.

dated the ACC docket relating to APS October 2001 filing with several other pending ACC dockets, including the generic On November 27, 2000, a Maricopa County, Arizona, docket. Although the order consolidates several dockets, it Superior Court judge issued a final judgment holding that states that a hearing on the APS matter will commence on the Rules are unconstitutional and unlawful in their entirety April 29, 2002. The order went on to state that, contrary to due to failure to establish a fair value rate base for competi-APS position the ALJ was construing the October 2001 filing tive electric service providers and because certain of the as a request by APS to amend the ACC order that approved Rules were not submitted to the Arizona Attorney General the 1999 Settlement Agreement. for certification. The judgment also invalidates all ACC orders authorizing competitive electric service providers, On March 22, 2002, the ACC Staff issued a report to the including APSES, to operate in Arizona. We do not believe ACC recommending that the ACC address the following the ruling affects the 1999 Settlement Agreement. The 1999 issues in the generic docket:

Settlement Agreement was not at issue in the consolidated The extent and manner of the ACCs involvement in moni- cases before the judge. Further, the ACC made findings toring market conditions and/or mitigating the develop- related to the fair value of APS property in the order ment of market power for generation and transmission; approving the 1999 Settlement Agreement. The ACC and The lack of guidance in the Rules regarding the mechanics other parties aligned with the ACC have appealed the ruling of the competitive bidding process referenced above; to the Arizona Court of Appeals, as a result of which the The consideration of alternatives to the transfer of genera- Superior Courts ruling is automatically stayed pending tion assets required by the Rules (the ACC Staff stated further judicial review. In a similar appeal concerning the that such transfers would be unwise at the present time issuance of competitive telecommunications CC&Ns, the and recommended that all transfer and separation of Arizona Court of Appeals invalidated rates for competitive utilities assets be stayed pending the completion of the carriers due to the ACCs failure to establish a fair value generic docket); rate base for such carriers. That case has been appealed to The consideration of transmission constraints that could the Arizona Supreme Court, where a decision is pending.

impact the development of the wholesale power market; The Rules approved by the ACC include the following The reassessment of adjustor mechanisms for standard-offer major provisions:

rates in light of problems with the development of a whole-sale power market; and They apply to virtually all Arizona electric utilities The adequacy of customer shopping credits in the regulated by the ACC, including APS.

context of the development of a competitive retail market Effective January 1, 2001, retail access became available (a shopping credit is the cost a customer does not pay to to all APS retail electricity customers.

a utility distribution company if the customer obtains Electric service providers that get CC&Ns from the ACC generation from another party). can supply only competitive services, including electric generation, but not electric transmission and distribution.

Although not a specific ACC Staff recommendation, the Affected utilities must file ACC tariffs that unbundle rates report was also critical of certain aspects of the proposed for noncompetitive services.

purchase power agreement between APS and Pinnacle West.

The ACC shall allow a reasonable opportunity for A modification to the competition Rules or the 1999 Settle- recovery of unmitigated stranded costs.

ment Agreement could, among other things, adversely affect p_44 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

Absent an ACC waiver, prior to January 1, 2001, each Legislation. In May 1998, a law was enacted to facilitate affected utility (except certain electric cooperatives) must implementation of retail electric competition in Arizona.

transfer all competitive electric assets and services either to The law includes the following major provisions:

an unaffiliated party or to a separate corporate affiliate.

Arizonas largest government-operated electric utility Under the 1999 Settlement Agreement, APS received a (Salt River Project) and, at their option, smaller municipal waiver to allow transfer of its competitive electric assets electric systems must (i) make at least 20% of their 1995 and services to affiliates no later than December 31, 2002.

retail peak demand available to electric service providers APS plans to complete the move of such assets by the end by December 31, 1998 and for all retail customers by of 2002, as required, although the ACCs recent establish-December 31, 2000; (ii) decrease rates by at least 10%

ment of a generic docket to consider electric industry over a ten-year period beginning as early as January 1, restructuring in Arizona and the consolidation of that 1991; (iii) implement procedures and public processes docket with APS request for approval of a PPA between comparable to those already applicable to public service Pinnacle West and APS could affect APS ability to corporations for establishing the terms, conditions, and transfer assets to Pinnacle West Energy (see Proposed pricing of electric services as well as certain other decisions Rule Variance and Purchase Power Agreement above).

affecting retail electric competition; Provider of Last Resort Obligation. Although the Rules describes the factors which form the basis of consideration allow retail customers to have access to competitive providers by Salt River Project in determining stranded costs; an of energy and energy services (see Retail Electric Competi- metering and meter reading services must be provided on tion Rules below), APS is the provider of last resort for a competitive basis during the first two years of competi-standard-offer, full-service customers under rates that have tion only for customers having demands in excess of one been approved by the ACC. These rates are established until MW (and that are eligible for competitive generation July 1, 2004. The 1999 Settlement Agreement allows APS services), and thereafter for all customers receiving to seek adjustment of these rates in the event of emergency competitive electric generation.

conditions or circumstances, such as the inability to secure General financing on reasonable terms, or material changes in APS We cannot accurately predict the impact of full retail compe-cost of service for ACC-regulated services resulting from tition on our financial position, cash flows, results of opera-federal, tribal, state or local laws, regulatory requirements, tions, or liquidity. As competition in the electric industry judicial decisions, actions or orders. Energy prices in the continues to evolve, we will continue to evaluate strategies western wholesale market vary and, during the course of the and alternatives that will position us to compete in the new last two years, have been volatile. At various times, prices in regulatory environment.

the spot wholesale market have significantly exceeded the amount included in APS current retail rates. In the event Federal of shortfalls due to unforeseen increases in load demand or In June 2001, the FERC adopted a price mitigation plan generation outages, APS may need to purchase additional that constrains the price of electricity in the wholesale spot supplemental power in the wholesale spot market. Unless electricity market in the western United States. The plan APS is able to obtain an adjustment of its rates under the remains in effect until September 30, 2002. We cannot emergency provisions of the 1999 Settlement Agreement, accurately predict the overall financial impact of the plan on there can be no assurance that APS would be able to fully the various aspects of our business, including our wholesale recover the costs of this power. and purchased power activities.

1996 Regulatory Agreement. In April 1996, the ACC 4. INCOME TAXES approved a regulatory agreement between the ACC Staff Income Taxes and APS. Based on the price reduction formula authorized Certain assets and liabilities are reported differently for income in the agreement, the ACC approved retail price decreases tax purposes than they are for financial statements. The tax (approximate) as follows (dollars in millions): effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates.

ANNUAL ELECTRIC PERCENTAGE REVENUE DECREASE DECREASE EFFECTIVE DATE APS has recorded a regulatory asset related to income taxes

$49 3.4% July 1, 1996 on its balance sheets in accordance with SFAS No. 71. This

$18 1.2% July 1, 1997 regulatory asset is for certain temporary differences, primarily

$17 1.1% July 1, 1998 the allowance for equity funds used during construction.

$11 0.7% July 1, 1999(a) APS amortizes this amount as the differences reverse. In accordance with the 1999 Settlement Agreement, APS is (a) Included in the first rate reduction under the 1999 Settlement Agreement (see above). continuing to accelerate its amortization of the regulatory asset for income taxes over an eight-year period that will end The regulatory agreement also required that we infuse $200 June 30, 2004 (see Note 1). We are including all regulatory million of common equity into APS in annual payments of asset amortization in depreciation and amortization expense

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

p_45

on our consolidated statements of income. The components Investment Tax Credit of income tax expense for continuing operations are: Because of a 1994 rate settlement agreement, we accelerated year ended December 31, amortization of substantially all of our ITCs over a five-year (dollars in thousands) 2001 2000 1999 period that ended December 31, 1999.

Income Tax Benefit From Discontinued Operations Current In 1999, the income tax benefit from discontinued operations Federal $ 184,893 $ 189,779 $ 171,491 for $38 million resulted from resolution of tax issues related to State 45,845 42,306 37,501 a former subsidiary, MeraBank, A Federal Savings Bank.

Total Current 230,738 232,085 208,992

5. LINES OF CREDIT Deferred (16,939) (38,625) (43,886)

APS had committed lines of credit with various banks of $250 ITC amortization (264) 740 (23,514) million at December 31, 2001 and 2000, which were available Total expense $ 213,535 $ 194,200 $ 141,592 either to support the issuance of commercial paper or to be used for bank borrowings. The commitment fees at December The following chart compares pretax income at the 35%

31, 2001 and 2000 for these lines of credit were 0.09% per federal income tax rate to income tax expense:

annum. APS had no bank borrowings outstanding under year ended December 31, these lines of credit at December 31, 2001 and 2000.

(dollars in thousands) 2001 2000 1999 APS commercial paper borrowings outstanding were Federal income tax $171 million at December 31, 2001 and $82 million at expense at 35% December 31, 2000. The weighted average interest rate on statutory rate $ 189,316 $ 173,786 $ 143,977 commercial paper borrowings was 4.72% for the year Increases (reductions) ended December 31, 2001 and 6.64% for the year ended in tax expense December 31, 2000. By Arizona statute, APS short-term resulting from: borrowings cannot exceed 7% of its total capitalization Preferred stock unless approved by the ACC.

dividends of Pinnacle West had committed lines of credit with various APS - - 356 banks of $250 million at December 31, 2001 and 2000, ITC amortization (264) 740 (23,514) which were available either to support the issuance of State income tax commercial paper or to be used for bank borrowings.

net of federal The commercial paper program was launched in May 2001.

income tax The commitment fees ranged from 0.10% to 0.15% in 2001 benefit 23,353 19,848 19,595 and 2000. There were no short-term bank borrowings out-Other 1,130 (174) 1,178 standing at December 31, 2001 and $188 million outstand-Income tax expense $ 213,535 $ 194,200 $ 141,592 ing at December 31, 2000. Pinnacle West commercial paper borrowings were $235 million at December 31, 2001. The The components of the net deferred income tax liability as weighted average interest rate on commercial paper borrow-of December 31, 2001 and 2000 were as follows:

ings was 3.50% for the year ended December 31, 2001.

December 31, (dollars in thousands) 2001 2000 SunCor had revolving lines of credit totaling $140 million at December 31, 2001 and $120 million at December 31, DEFERRED TAX ASSETS 2000. The commitment fees were 0.125% in 2001 and 2000.

Deferred gain on Palo Verde SunCor had $128 million outstanding at December 31, 2001 Unit 2 sale/leaseback $ 25,374 $ 27,056 and $110 million outstanding at December 31, 2000. The Risk management and balance is included in long-term debt on the consolidated trading activities 73,043 15,002 balance sheets (see Note 6).

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 p_46 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

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

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 (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_47

The Pinnacle West and APS bank agreements have financial The following table shows the components of net periodic covenants including an interest coverage test and a debt ratio. pension cost before consideration of amounts capitalized or We anticipate that we will be able to meet the covenant billed to electric plant participants:

requirement levels. (dollars in thousands) 2001 2000 1999 The following is a list of principal payments due on total long-term debt and sinking fund requirements through 2006: Service cost - benefits earned during the

$125 million in 2002; period $ 26,640 $ 24,955 $ 24,982

$318 million in 2003; Interest cost on

$507 million in 2004; projected benefit

$401 million in 2005; and obligation 62,920 58,361 52,905

$387 million in 2006. Expected return on APS first mortgage bondholders share a lien on substantially plan assets (77,340) (77,231) (68,335) all utility plant assets (other than nuclear fuel and transpor- Amortization of:

tation equipment and other excluded assets). The mortgage Transition asset (3,227) (3,227) (3,226) bond indenture restricts the payment of common stock Prior service cost 2,716 2,078 2,078 dividends under certain conditions. These conditions did Net actuarial gain - (1,633) -

not exist at December 31, 2001. Net periodic pension cost $ 11,709 $ 3,303 $ 8,404 The parent company has issued parental guarantees and obtained surety bonds on behalf of its unregulated sub- The following table shows a reconciliation of the funded sidiaries, primarily for Pinnacle West Energys expansion status of the plan to the amounts recognized in the plans and APSES retail and energy business. consolidated balance sheets:

7. RETIREMENT PLANS AND OTHER BENEFITS (dollars in thousands) 2001 2000 Pension Plan Through 1999, Pinnacle West and its subsidiaries each Funded status - pension plan sponsored defined benefit pension plans for their own assets less than projected employees. As of January 1, 2000, these plans were benefit obligation $ (116,213) $ (20,730) consolidated and now a single pension plan is sponsored by Unrecognized net transition asset (13,554) (16,781)

Pinnacle West for the employees of Pinnacle West and its Unrecognized prior service cost 24,465 18,558 subsidiaries. A defined benefit plan specifies the amount of Unrecognized net actuarial benefits a plan participant is to receive using information (gains)/losses 94,952 (23,816) about the participant. The plan covers nearly all of our Net pension liability recognized employees. Our employees do not contribute to this plan. in the consolidated Generally, we calculate the benefits under this plan based balance sheets $ (10,350) $ (42,769) on age, years of service, and pay. We fund the plan by contributing at least the minimum amount required under The following table sets forth the defined benefit pension Internal Revenue Service regulations but no more than the plans change in projected benefit obligation for the plan maximum tax-deductible amount. The assets in the plan at years 2001 and 2000:

December 31, 2001 were mostly domestic and international (dollars in thousands) 2001 2000 common stocks and bonds and real estate.

Projected pension benefit Pension expense, including administrative costs and after obligation at beginning of year $ 795,926 $ 742,638 consideration of amounts capitalized or billed to electric Service cost 26,640 24,955 plant participants, was:

Interest cost 62,920 58,361

$7 million in 2001; Benefit payments (31,647) (30,568)

$2 million in 2000; and Actuarial losses 18,625 540

$4 million in 1999. Plan amendments 8,622 -

Projected pension benefit obligation at end of year $ 881,086 $ 795,926 p_48 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

The following table sets forth the defined benefit pension Funding is based upon actuarially determined contributions plans change in the fair value of plan assets for the plan that take tax consequences into account. Plan assets consist years 2001 and 2000: primarily of domestic stocks and bonds. The postretirement (dollars in thousands) 2001 2000 benefit expense after consideration of amounts capitalized or billed to electric plant participants, was:

Fair value of pension plan assets $6 million for 2001; at beginning of year $ 775,196 $ 779,913 $3 million for 2000; and Actual gain/(loss) on plan assets (22,876) 1,851 $7 million for 1999.

Employer contributions 44,200 24,000 Benefit payments (31,647) (30,568)

The following table shows the components of net periodic Fair value of pension plan assets postretirement benefit costs before consideration of amounts at end of year $ 764,873 $ 775,196 capitalized or billed to electric plant participants:

(dollars in thousands) 2001 2000 1999 We made the assumptions below to calculate the pension liability: Service cost - benefits 2001 2000 earned during the period $ 9,438 $ 8,613 $ 8,939 Discount rate 7.50% 7.75% Interest cost on accu-Rate of increase in mulated projected compensation levels 4.00% 4.25% benefit obligation 21,585 19,315 17,366 Expected long-term rate of Expected return on return on assets 10.00% 10.00% plan assets (21,985) (22,381) (18,454)

Amortization of:

Employee Savings Plan Benefits Transition obligation 7,698 7,698 7,698 Through 1999, Pinnacle West and its subsidiaries each Net actuarial gains (4,066) (7,983) (5,117) sponsored defined contribution savings plans for their Net periodic own employees. As of January 1, 2000, these plans were postretirement consolidated and now a single defined contribution savings benefit cost $ 12,670 $ 5,262 $ 10,432 plan is sponsored by Pinnacle West for the employees of Pinnacle West and its subsidiaries. In a defined contribution The following table shows a reconciliation of the funded plan, the benefits a participant will receive result from status of the plan to the amounts recognized in the regular contributions they make to a participant account. consolidated balance sheets:

Under this plan, we make matching contributions in Pinnacle (dollars in thousands) 2001 2000 West stock to participant accounts. At December 31, 2001 approximately 30% of total plan assets were in Pinnacle West Funded status - post retirement stock. We recorded expenses for this plan of approximately plan assets less than

$5 million for 2001 and $4 million for 2000 and 1999. projected benefit obligation $ (80,544) $ (14,851)

Unrecognized net obligation Postretirement Plan at transition 84,748 92,446 Through 1999, Pinnacle West and its subsidiaries each Unrecognized net actuarial gains (8,606) (81,280) sponsored postretirement plans for their own employees.

Net postretirement amount As of January 1, 2000, these plans were consolidated and recognized in the now a single postretirement plan is sponsored by Pinnacle balance sheets $ (4,402) $ (3,685)

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.

p_49

The following table sets forth the postretirement benefit 8. LEASES plans change in accumulated benefit obligation for the plan In 1986, APS sold about 42% of its share of Palo Verde years 2001 and 2000: Unit 2 and certain common facilities in three separate sale-leaseback transactions. APS accounts for these leases as (dollars in thousands) 2001 2000 operating leases. The gain of approximately $140 million was deferred and is being amortized to operations expense Accumulated postretirement over 29.5 years, the original term of the leases. There are benefit obligation at beginning options to renew the leases for two additional years and to of year $ 264,006 $ 231,989 purchase the property for fair market value at the end of the Service cost 9,438 8,613 lease terms. Consistent with the ratemaking treatment, an Interest cost 21,585 19,315 amount equal to the annual lease payments is included in Benefit payments (10,194) (8,905) rent expense. A regulatory asset is recognized for the differ-Actuarial losses 33,520 12,994 ence between lease payments and rent expense calculated Accumulated postretirement on a straight-line basis. See Note 2 for a discussion of benefit obligation at special purpose entities, including the special purpose enti-end of year $ 318,355 $ 264,006 ties involved in the Palo Verde sale-leaseback transactions.

The following table sets forth the postretirement benefit The average amounts to be paid for the Palo Verde Unit 2 plans change in the fair value of plan assets for the plan years leases are approximately $49 million per year for the years 2001 and 2000: 2002-2015.

(dollars in thousands) 2001 2000 In accordance with the 1999 Settlement Agreement, APS is continuing to accelerate amortization of the regulatory Fair value of postretirement plan asset for leases over an eight-year period that will end June assets at beginning of year $ 249,154 $ 257,538 30, 2004 (see Note 1). All regulatory asset amortization is Actual loss on plan assets (12,550) (4,436) included in depreciation and amortization expense in the Employer contributions 11,400 4,958 consolidated statements of income. The balance of this Benefit payments (10,194) (8,906) regulatory asset at December 31, 2001 was $24 million.

Fair value of postretirement plan assets at end of year $ 237,810 $ 249,154 In December 2000, APS purchased Units 1, 2, and 3 of West Phoenix Power Plant, which was previously leased We made the assumptions below to calculate the postretire- under a capitalized lease obligation.

ment liability:

In addition, we lease certain land, buildings, equipment, 2001 2000 and miscellaneous other items through operating rental agree-ments with varying terms, provisions, and expiration dates.

Discount rate 7.50% 7.75%

Expected long-term rate of Total lease expense was $56 million in 2001, $58 million return on assets - after tax 8.86% 8.77% in 2000, and $52 million in 1999.

Initial health care cost trend rate -

Estimated future minimum lease commitments, are under age 65 7.00% 7.00%

approximately as follows (dollars in millions):

Initial health care cost trend rate -

age 65 and over 7.00% 6.00% YEAR Ultimate health care cost 2002 $ 68 trend rate 5.00% 5.00% 2003 66 Year ultimate health care trend 2004 65 rate is reached 2006 2002 2005 64 2006 63 The following table shows the effect of a 1% increase or Thereafter 543 decrease in the health care cost trend rate:

Total future commitments $ 869 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) p_50 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

9. JOINTLY-OWNED FACILITIES APS shares ownership of some of its generating and trans- APS share of operating and maintaining these facilities is mission facilities with other companies. The following table included in the income statement in operations and mainte-shows APS interest in those jointly-owned facilities recorded nance expense. Each participant is entitled to its share of on the consolidated balance sheets at December 31, 2001. 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 Maricopa County, Arizona, Superior Court entitled Enron SunCor Development Company v. Bergstrom Corporation, We recorded charges totaling $21 million before income CV 98-11472. The verdict was based on the Bergstrom taxes for exposure to Enron and its affiliates in the fourth Corporations claims that it was defrauded in connection quarter of 2001. This amount is comprised of a $15 million with the acquisition of approximately ten acres of land in reserve for the Companys net exposure to Enron and its affil- a SunCor commercial development and a subsequent settle-iates, and additional expenses of $6 million primarily related ment agreement relating to those claims. On December 14, to 2002 power contracts with Enron that were cancelled. 2001, the Court ruled that the jury award was constitution-ally excessive and reduced the punitive damage award to Power Service Agreement

$5 million. Following this ruling, SunCor settled the matter By letter dated March 7, 2001, Citizens, which owns a for an amount that did not have a material impact on our utility in Arizona, advised APS that it believes APS has 2001 results of operations.

overcharged Citizens by over $50 million under a power service agreement. APS believes that its charges under the Palo Verde Nuclear Generating Station agreement were fully in accordance with the terms of the Nuclear power plant operators are required to enter into agreement. In addition, in testimony filed with the ACC spent fuel disposal contracts with DOE, and DOE is March 13, 2002, Citizens acknowledged that, based on its required to accept and dispose of all spent nuclear fuel and review, if Citizens filed a complaint with FERC, it proba- other high-level radioactive wastes generated by domestic bly would lose the central issue in the contract interpreta- power reactors. Although the Nuclear Waste Act required tion dispute. APS and Citizens terminated the power DOE to develop a permanent repository for the storage service agreement effective July 15, 2001. In replacement and disposal of spent nuclear fuel by 1998, the DOE has of the power service agreement, the Company and Citizens announced that the repository cannot be completed before entered into a power sale agreement under which the 2010, and that it does not intend to begin accepting spent Company will supply Citizens with specified amounts of fuel prior to that date. In November 1997, the United States electricity and ancillary services through May 31, 2008. Court of Appeals for the District of Columbia Circuit (D.C.

This new agreement does not address issues previously Circuit) issued a decision preventing the DOE from excusing raised by Citizens with respect to charges under the original its own delay, but refused to order the DOE to begin power service agreement through June 1, 2001. accepting spent nuclear fuel. Based on this decision and DOEs delay, a number of utilities filed damages actions SunCor against DOE in the Court of Federal Claims.

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 p_51

In February 2002 the Secretary of Energy recommended Fuel and Purchased Power Commitments to President Bush that the Yucca Mountain, Nevada site be APS and Pinnacle West are party to various fuel and developed as a permanent repository for spent nuclear purchased power contracts with terms expiring from 2002 fuel. The President transmitted this recommendation to through 2021 that include required purchase provisions.

Congress. A congressional decision on this issue is expected We estimate the contract requirements to be approximately sometime during mid-summer 2002. We cannot currently $270 million in 2002; $124 million in 2003; $80 million predict what further steps will be taken in this area. in 2004; $65 million in 2005; and $68 million in 2006.

However, this amount may vary significantly pursuant to APS has existing fuel storage pools at Palo Verde and is in certain provisions in such contracts that permit us to the process of completing construction of a new facility for decrease required purchases under certain circumstances.

on-site dry storage of spent fuel. With the existing storage pools and the addition of the new facility, APS believes that Coal Mine Reclamation Obligations spent fuel storage or disposal methods will be available for APS must reimburse certain coal providers for amounts use by Palo Verde to allow its continued operation through incurred for coal mine reclamation. APS estimates its share the term of the operating license for each Palo Verde unit. of the total obligation to be about $103 million. The por-tion of the coal mine reclamation obligation related to coal Although some low-level waste has been stored on-site in a already burned is about $59 million at December 31, 2001 low-level waste facility, APS is currently shipping low-level and is included in deferred credits-other in the consolidated waste to off-site facilities. APS currently believes that inter-balance sheets.

im low-level waste storage methods are or will be available for use by Palo Verde to allow its continued operation and A regulatory asset has been established for amounts not yet to safely store low-level waste until a permanent disposal recovered from ratepayers related to the coal obligations. In facility is available. accordance with the 1999 Settlement Agreement with the ACC, APS is continuing to accelerate the amortization of APS currently estimates that it will incur $407 million (in the regulatory asset for coal mine reclamation over an eight-2001 dollars) over the life of Palo Verde for its share of the year period that will end June 30, 2004. Amortization is costs related to the on-site interim storage of spent nuclear included in depreciation and amortization expense on the fuel. As of December 31, 2001, APS had recorded a liability statements of income.

and regulatory asset of $43 million for on-site interim nuclear fuel storage costs related to nuclear fuel burned to date. California Energy Market Issues and Refunds in the Pacific Northwest The Palo Verde participants have insurance for public liability SCE and PG&E have publicly disclosed that their liquidity resulting from nuclear energy hazards to the full limit of has been materially and adversely affected because of, liability under federal law. This potential liability is covered among other things, their inability to pass on to ratepayers by primary liability insurance provided by commercial insur-the prices each has paid for energy and ancillary services ance carriers in the amount of $200 million and the balance procured through the PX and the ISO.

by an industry-wide retrospective assessment program. If loss-es at any nuclear power plant covered by the programs exceed We are closely monitoring developments in the California the accumulated funds, APS could be assessed retrospective energy market and the potential impact of these develop-premium adjustments. The maximum assessment per reactor ments on us and our subsidiaries. We have evaluated, under the program for each nuclear incident is approximately among other things, SCEs role as a Palo Verde and Four

$88 million, subject to an annual limit of $10 million per Corners participant; APS transactions with the PX and the incident. Based upon our interest in the three Palo Verde ISO; contractual relationships with SCE and PG&E; units, our maximum potential assessment per incident for APSES retail transactions involving SCE and PG&E; and all three units is approximately $77 million, with an annual marketing and trading exposures. Based on our evaluations, payment limitation of approximately $9 million. we have reserved $10 million before income taxes for our credit exposure related to the California energy situation, The Palo Verde participants maintain all risk (including

$5 million of which was recorded in the fourth quarter of nuclear hazards) insurance for property damage to, and 2000 and $5 million of which was recorded in first quarter decontamination of, property at Palo Verde in the aggregate of 2001. We cannot predict with certainty, however, the amount of $2.75 billion, a substantial portion of which impact that any future resolution or attempted resolution, must first be applied to stabilization and decontamination.

of the California energy market situation may have on us APS has also secured insurance against portions of any or our subsidiaries or the regional energy market in general.

increased cost of generation or purchased power and busi-ness interruption resulting from a sudden and unforeseen In July 2001, the FERC ordered an expedited fact-finding outage of any of the three units. The insurance coverage hearing to calculate refunds for spot market transactions in discussed in this and the previous paragraph is subject to California during a specified time frame. This order calls certain policy conditions and exclusions. for a hearing, with findings of fact due to the FERC after the California ISO and PX provide necessary historical data.

p_52 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

The FERC also ordered an evidentiary proceeding to discuss Pinnacle West Energy has completed or is currently and evaluate possible refunds for the Pacific Northwest. The planning the following projects:

ALJ at the FERC in charge of that evidentiary proceeding A 650 MW expansion of the West Phoenix Power Plant made an initial finding that no refunds were appropriate.

in Phoenix. The 120 MW West Phoenix Unit 4 began The Pacific Northwest issues will now be addressed by the commercial operation on June 1, 2001. Construction FERC Commissioners. Although the FERC has not yet has begun on the 530 MW West Phoenix Unit 5, with made a final ruling in the Pacific Northwest matter or commercial operation expected to begin in mid-2003.

calculated the specific refund amounts due in California, The construction of a four-unit combined cycle 2,120 MW we do not expect that the resolution of these issues, as to generating station near Palo Verde, called Redhawk.

the amounts alleged in the proceedings, will have a material Construction of Units 1 and 2 began in December 2000, adverse impact on our financial position, results of and commercial operation is currently scheduled for the operations or liquidity.

summer of 2002. Although Pinnacle West Energy currently On March 19, 2002, the State of California filed a complaint plans to bring Units 3 and 4 on line in or before the first with the FERC alleging that wholesale sellers of power and quarter of 2007, equipment procurement, engineering and energy, including Pinnacle West, failed to properly file rate construction plans will allow for these units to come on information at the FERC in connection with sales to line as early as 2005 if warranted by market conditions.

California from 2000 to the present. State of California v. The construction of an 80 MW simple-cycle power plant British Columbia Power Exchange et. Al., Docket No. EL02- at Saguaro in Southern Arizona. Commercial operation 71-000. The complaint requests the FERC to require the is currently scheduled for the summer of 2002.

wholesale sellers to refund any rates that are found to exceed Development of an electric generating station 20 miles just and reasonable levels. The complaint indicates that north of Las Vegas, Nevada. Construction of the 570 Pinnacle West sold approximately $106 million of power to MW Silverhawk combined-cycle plant is expected to the California Department of Water Resources from January begin in the spring of 2002, with an expected commercial 17, 2001 to October 31, 2001 and does not allege any operation date of mid-2004. Pinnacle West Energy has amount above just and reasonable levels. We believe that signed a 25% participation agreement with Las Vegas-the claims as they relate to Pinnacle West are without merit. based SNWA.

A Pinnacle West Energy affiliate is exploring the possibility Construction Program of creating an underground natural gas storage facility on Consolidated capital expenditures in 2002 are estimated to be:

Company-owned land west of Phoenix. A feasibility study (dollars in millions) 2002 is in progress to determine if the proposed acreage can support a natural gas storage cavern.

APS $ 498 Pinnacle West Energy 411 Litigation SunCor 79 We are party to various claims, legal actions, and complaints Other (primarily APSES and arising in the ordinary course of business. In our opinion, Pinnacle West) 35 the ultimate resolution of these matters will not have a mate-Total $ 1,023 rial adverse effect on our financial statements or liquidity.

Generation Expansion 11. NUCLEAR DECOMMISSIONING COSTS Pinnacle West Energy has completed or announced plans to APS recorded $11 million for nuclear decommissioning build about 3,420 MW of natural gas-fired generating expense in each of the years 2001, 2000, and 1999. APS capacity from 2000 through 2007 at an estimated cost of estimates it will cost about $1.8 billion ($506 million in about $1.9 billion. This does not reflect an expected reim- 2001 dollars) to decommission its share of the three Palo bursement in 2004 by SNWA of $100 million of Pinnacle Verde units. The majority of decommissioning costs are West Energys cumulative capital expenditures in the expected to be incurred over a 14-year period beginning in Silverhawk project in exchange for SNWA purchase of a 25% 2024. APS charges decommissioning costs to expense over interest in the project. Our expansion plan will be sized to each units operating license term and includes them in the meet native load growth, cash flow and market conditions. accumulated depreciation balance until each unit is retired.

Pinnacle West Energy is currently funding its capital require- Nuclear decommissioning costs are recovered in rates.

ments through capital infusions from Pinnacle West, which APS current estimates are based on a 2001 site-specific finances those infusions through debt financings and internal-study for Palo Verde that assumes the prompt removal/dis-ly-generated cash. As Pinnacle West Energy develops and mantlement method of decommissioning. An independent obtains additional generation assets, including APS existing consultant prepared this study. APS is required to update generation assets, Pinnacle West Energy expects to fund its the study every three years.

capital requirements through internally-generated cash and its own debt issuances.

p_53

To fund the costs APS expects to incur to decommission (dollars in millions) 2001 2000 the plant, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust Trust fund assets - at cost funds primarily in fixed income securities and domestic Fixed income securities $ 103 $ 94 stock and classifies them as available for sale. Realized and Domestic stock 61 52 unrealized gains and losses are reflected in accumulated Total $ 164 $ 146 depreciation in accordance with industry practice. The Trust fund assets - fair value following table shows the cost and fair value of our nuclear Fixed income securities $ 106 $ 97 decommissioning trust fund assets which are reported in Domestic stock 96 100 investments and other assets on the consolidated balance Total $ 202 $ 197 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.

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 p_54 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

(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.

13. FAIR VALUE OF FINANCIAL INSTRUMENTS We believe that the carrying amounts of our cash equiva- Dilutive stock options increased average common shares lents and commercial paper are reasonable estimates of their outstanding by 212,491 shares in 2001, 202,738 shares in fair values at December 31, 2001 and 2000 due to their 2000, and 291,392 shares in 1999. Total average common short maturities. shares outstanding for the purposes of calculating diluted earnings per share were 84,930,140 shares in 2001, We hold investments in debt and equity securities for purposes 84,935,282 shares in 2000, and 85,008,527 shares in 1999.

other than trading. The December 31, 2001 and 2000 fair values of such investments, which we determine by using Options to purchase 212,562 shares of common stock were quoted market values, approximate their carrying amount. outstanding at December 31, 2001 but were not included in the computation of diluted EPS because the options On December 31, 2001, the carrying value of our long-exercise price was greater than the average market price of term debt (excluding a capitalized lease obligation) was the common shares. Options to purchase shares of common

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

stock that were not included in the computation of diluted The carrying value of our long-term debt (excluding a EPS were 517,614 at December 31, 2000 and 506,734 at capitalized lease obligation) was $2.42 billion on December December 31, 1999.

31, 2000, with an estimated fair value of $2.48 billion.

The fair value estimates are based on quoted market prices 15. STOCK-BASED COMPENSATION of the same or similar issues. Pinnacle West offers two stock incentive plans for officers and key employees of our company and our subsidiaries.

14. EARNINGS PER SHARE The following table presents earnings per weighted average One of the plans (1994 plan) provides for the granting of common share outstanding (EPS): new options (which may be non-qualified stock options or 2001 2000 1999 incentive stock options) of up to 3.5 million shares at a price per option not less than the fair market value on the Basic EPS: date the option is granted. The other plan (1985 plan)

Continuing operations $ 3.86 $ 3.57 $ 3.18 includes outstanding options but no new options will be Discontinued operations - - 0.45 granted from this plan. Options vest one-third of the grant Extraordinary charge - - (1.65) per year beginning one year after the date the option is Cumulative effect of granted and expire ten years from the date of the grant.

change in accounting (0.18) - - The plan also provides for the granting of any combination Earnings per share - basic $ 3.68 $ 3.57 $ 1.98 of shares of restricted stock, stock appreciation rights or dividend equivalents.

Diluted EPS:

Continuing operations $ 3.85 $ 3.56 $ 3.17 The awards outstanding under the incentive plans at Discontinued operations - - 0.45 December 31, 2001, are 1,832,725 non-qualified stock Extraordinary charge - - (1.65) options, 237,833 shares of restricted stock, and no Cumulative effect of incentive stock options, stock appreciation rights or change in accounting (0.17) - - dividend equivalents.

Earnings per share - diluted $ 3.68 $ 3.56 $ 1.97 p_55

SFAS No. 123, Accounting for Stock-Based Compensation In order to present the pro forma information above, we encourages, but does not require, that a company record calculated the fair value of each fixed stock option in the compensation expense based on the fair value of options incentive plans using the Black-Scholes option-pricing granted (the fair value method). We continue to recognize model. The fair value was calculated based on the date the expense based on Accounting Principles Board Opinion option was granted. The following weighted-average No. 25, Accounting for Stock Issued to Employees. assumptions were also used in order to calculate the fair value of the stock options:

If we had recorded compensation expense based on the fair 2001 2000 1999 value method, our net income and earnings per share would have been reduced to the following pro forma amounts:

Risk-free interest rate 4.08% 5.81% 5.68%

(dollars in thousands) 2001 2000 1999 Dividend yield 3.70% 3.48% 3.33%

Volatility 27.66% 32.00% 20.50%

Net income Expected life (months) 60 60 60 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 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 p_56 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

16. BUSINESS SEGMENTS generation segment information combined our marketing We have two principal business segments (determined by and trading activities with our generation of electricity products, services and regulatory environment), which activities. The delivery segment included transmission and consist of regulated retail electricity business and related distribution activities.

activities (retail business segment) and competitive business In the fourth quarter of 2001, APS filed with the ACC a activities (marketing and trading segment). Our retail proposed rule variance and purchase power agreement with business segment currently includes activities related to the ACC (see Note 3) that inherently views our business in electricity transmission and distribution, as well as electricity the new reportable segments described above. Internal man-generation. Our marketing and trading business segment agement reporting has been changed to reflect this align-currently includes activities related to wholesale marketing ment. The corresponding information for earlier periods has and trading and APSES competitive energy services.

been restated. The other amounts include activity relating to These reportable segments reflect a change in the reporting the parent company and other subsidiaries including SunCor of our segment information. Before the fourth quarter of and El Dorado. Financial data for the business segments is 2001, we had two segments (generation and delivery). The 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_57

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

17. DERIVATIVE INSTRUMENTS We are exposed to the impact of market fluctuations in ratings, and our evaluation of their financial condition. In the price and transportation costs of electricity, natural many contracts, we employ collateral requirements and gas, coal and emissions allowances. We employ established standardized agreements that allow for the netting of positive procedures to manage risks associated with these market and negative exposures associated with a single counterparty.

fluctuations by utilizing various commodity derivatives, Credit reserves are established representing our estimated including exchange-traded futures and options and over- credit losses on our overall exposure to counterparties. See the-counter forwards, options, and swaps. As part of our Note 1 for a discussion of our credit reserve policy.

overall risk management program, we enter into derivative Effective January 1, 2001, we adopted SFAS No. 133, transactions to hedge purchases and sales of electricity, Accounting for Derivative Instruments and Hedging fuels, and emissions allowances and credits. The changes Activities. SFAS No. 133 requires that entities recognize all in market value of such contracts have a high correlation derivatives as either assets or liabilities on the balance sheets to price changes in the hedged commodity. In addition, and measure those instruments at fair value. Changes in the subject to specified risk parameters established by the fair value of derivative financial instruments are either recog-Board of Directors and monitored by the Energy Risk nized periodically in income or shareholders equity (as a Management Committee, we engage in trading activities component of other comprehensive income), depending on intended to profit from market price movements.

whether or not the derivative meets specific hedge account-We are exposed to losses in the event of nonperformance or ing criteria. Hedge effectiveness is measured based on the nonpayment by counterparties. We have risk management relative changes in fair value between the derivative contract and trading contracts with many counterparties, including and the hedged item over time. Any change in the fair value one counterparty for which a worst case exposure represents resulting from ineffectiveness is recognized immediately in approximately 50% of our $267 million of risk manage- net income. This new standard may result in additional ment and trading assets as of December 31, 2001. We use a volatility in our net income and comprehensive income.

risk management process to assess and monitor the financial As a result of adopting SFAS No. 133, we recognized $118 exposure of this and all other counterparties. Despite the million of derivative assets and $16 million of derivative fact that the great majority of trading counterparties are liabilities in our consolidated balance sheets as of January 1, rated as investment grade by the credit rating agencies, 2001. Also as of January 1, 2001, we recorded a $3 million including the counterparty noted above, there is still a pos-after-tax loss in net income and a $64 million after-tax gain sibility that one or more of these companies could default, in equity (as a component of other comprehensive income) resulting in a material impact on consolidated earnings for both as a cumulative effect of a change in accounting a given period. Counterparties in the portfolio consist prin-principle. The gain resulted from unrealized gains on cash cipally of major energy companies, municipalities, and local flow hedges.

distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable In June 2001, the FASB issued new guidance related to limits. Determination of the credit quality of our counter- electricity contracts. The effective date of this new guidance parties is based upon a number of factors, including credit 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 p_58 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

December 31, component of other comprehensive income), as a result of (dollars in thousands) 2001 adopting the new guidance related to electricity contracts.

The loss resulted primarily from electricity options con- Ineffective portion of derivatives qualifying tracts. The gain resulted from unrealized gains on cash flow for hedge accounting (a) $ (8,371) hedges. The impact of the new guidance is reflected in net Discontinuance of cash flow hedges for income and other comprehensive income as a cumulative forecasted transactions that will not occur (9,525) effect of change in accounting principle. Reclassification of mark-to-market losses to realized 25,948 In December 2001, the FASB issued revised guidance on Total $ 8,052 the accounting for electricity contracts with option charac-teristics and the accounting for contracts that combine a (a) Time value component of options excluded from assessment of forward contract and a purchased option contract. The hedge effectiveness.

effective date for the revised guidance is April 1, 2002. As of December 31, 2001, the maximum length of time over We are currently evaluating the new guidance to determine which we are hedging our exposure to the variability in future what impact, if any, it will have on our financial statements. cash flows for forecasted transactions is thirty-six months.

The change in derivative fair value included in the During the twelve months ended December 31, 2002, we consolidated statements of income for the year ending estimate that a net loss of $23 million before income taxes December 31, 2001 is comprised of the following: 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.

The following table summarizes our assets and liabilities trading and system (retail and traditional wholesale activities) from risk management and trading activities related to as of December 31, 2001 and 2000 (dollars in thousands):

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 On March 19, 2002, the State of California filed a complaint activities are recognized in marketing and trading revenues with the FERC alleging that wholesale sellers of power and on a current basis (the mark-to-market method). Trading energy, including Pinnacle West, failed to properly file rate positions are measured at fair value as of the balance sheet information at the FERC in connection with sales to date. The unrealized trading gains recognized in marketing California from 2000 to present. State of California v. British and trading revenues were $127 million for the year ended Columbia Power Exchange et. Al., Docket No. EL02-71-000.

December 31, 2001 and $14 million for the year ended The complaint requests the FERC to require the wholesale December 31, 2000. sellers to refund any rates that are found to exceed just and reasonable levels. The complaint indicates that Pinnacle

18. SUBSEQUENT EVENTS West sold approximately $106 million of power to California On February 8, 2002, Pinnacle West issued $215 million Department of Water Resources from January 17, 2001 to of 4.5% Notes due 2004. On March 1, 2002, APS issued October 31, 2001 and does not allege any amount above

$375 million of 6.50% Notes due 2012. On March 15, just and reasonable levels. We believe that the claims as they 2002, APS announced the redemption on April 15, 2002 relate to Pinnacle West are without merit.

of approximately $125 million of its First Mortgage Bonds, 8.75% series during 2024. See Note 3 for information relating to the March 22, 2002 ACC Staff report addressing issues in the generic docket.

p_59

BOARD OF DIRECTORS PAMELA GRANT HUMBERTO S. LOPEZ (63) 1980* (56) 1995 Civic Leader President, HSL Properties, Inc.

Committees: Committee:

Human Resources, Chairman Audit Audit MARTHA O. HESSE MICHAEL L. GALLAGHER (59) 1991 (57) 1997 President, Hesse Gas Company Chairman Emeritus Committees: Gallagher & Kennedy, P.A.

Audit, Chairman Committee:

Finance and Operating Human Resources THE REV. BILL JAMIESON, JR. BRUCE J. NORDSTROM (58) 1991 (52) 1997 President, Institute for Servant Certified Public Accountant, Leadership of Asheville, Nordstrom and Associates, P.C.

North Carolina Committee:

Committee: Audit Human Resources ROY A. HERBERGER, JR. JACK E. DAVIS (59) 1992 (55) 1998 President, Thunderbird, The President American Graduate School of Committee:

International Management Finance and Operating Committees:

Finance and Operating, Chairman Human Resources ROBERT G. MATLOCK WILLIAM L. STEWART (68) 1993 (58) 1998 Management Consultant President, Pinnacle West Energy R.G. Matlock & Associates, Inc.

Committee:

Human Resources WILLIAM J. POST EDDIE BASHA (51) 1994 (64) 1999 Chairman of the Board & Chairman of the Board, Bashas Chief Executive Officer Committee:

Committee: Audit Finance and Operating 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.

p_60 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001

OFFICERS PINNACLE WEST Faye Widenmann PINNACLE WEST ENERGY (53) 1978 William J. Post William L. Stewart Vice President & Secretary (51) 1973* President Chairman of the Board &

Barbara M. Gomez James M. Levine Chief Executive Officer (47) 1978 Chief Operating Officer Jack E. Davis Treasurer Ajoy K. Banerjee (55) 1973 (56) 1999 President ARIZONA PUBLIC SERVICE Vice President, Generation Expansion Armando B. Flores William J. Post Ajit P. Bhatti (58) 1991 Chairman of the Board &

Chief Executive Officer (56) 1973 Executive Vice President, Vice President, Generation Planning Corporate Business Services Jack E. Davis Warren C. Kotzmann Steven M. Wheeler President, Energy Delivery & Sales (52) 1989 (53) 2001 Vice President, Business &

Senior Vice President, William L. Stewart Corporate Services Transmission, Regulation & Planning (58) 1994 Robert S. Aiken President, Generation APS ENERGY SERVICES (45) 1986 Steven M. Wheeler Vicki G. Sandler Vice President, Federal Affairs Senior Vice President (45) 1982 John G. Bohon Transmission, Regulation & Planning President, Energy Services (56) 1971 Michael V. Palmeri Vice President, Corporate Services & SUNCOR DEVELOPMENT Vice President, Finance Human Resources William J. Post Faye Widenmann Dennis L. Brown Chairman of the Board Vice President & Secretary (51) 1973 John C. Ogden Vice President & Nancy C. Loftin (56) 1972 Chief Information Officer Vice President & General Counsel President & Chief Executive Officer Edward Z. Fox Barbara M. Gomez Geoffrey L. Appleyard (48) 1995 Treasurer (48) 1987 Vice President, Communications, Jan H. Bennett Vice President & Chief Financial Officer Environment & Safety (54) 1967 Duane S. Black Chris N. Froggatt Vice President, Customer Service (49) 1989 (44) 1986 James M. Levine Vice President & Chief Operating Officer Vice President & Controller (52) 1989 Jay T. Ellingson David A. Hansen Executive Vice President, (52) 1992 (42) 1980 Generation Vice President, Development -

Vice President, Bulk Power Gregg R. Overbeck Palm Valley Marketing & Trading (55) 1990 Steven Gervais Nancy C. Loftin Senior Vice President, (46) 1987 (48) 1985 Nuclear Generation Vice President & General Counsel Vice President & General Counsel John R. Denman Margaret E. Kirch Michael V. Palmeri (59) 1964 (52) 1988 (43) 1982 Vice President, Fossil Generation Vice President, Vice President, Finance William E. Ide Commercial Development Donald G. Robinson (55) 1977 Thomas A. Patrick (48) 1978 Vice President, (48) 1995 Vice President, Nuclear Production Vice President, Golf Operations Regulation & Planning David Mauldin Martin L. Shultz (52) 1990 EL DORADO INVESTMENT (57) 1979 Vice President, Nuclear William J. Post Vice President, Government Affairs Engineering & Support Chairman of the Board, President & CEO

• The year in which the individual was first employed within the Pinnacle West group of companies.

p_61

SHAREHOLDER INFORMATION CORPORATE HEADQUARTERS TRANSFER AGENTS AND REGISTRAR 400 North 5th Street Common Stock P.O. Box 53999 Pinnacle West Capital Corporation Phoenix, Arizona 85004 Stock Transfer Department P.O. Box 52134 Main telephone number: (602) 250-1000 Phoenix, Arizona 85072-2134 ANNUAL MEETING OF SHAREHOLDERS Or:

Wednesday, May 22, 2002 After January 1, 2003, 10:30 a.m. 400 North 5th Street The Herberger Theatre Phoenix, Arizona 85004 222 East Monroe Street Telephone: (602) 250-5506 Phoenix, Arizona 85004 SHAREHOLDER ACCOUNT AND STOCK LISTING ADMINISTRATIVE INFORMATION Ticker symbol: PNW on New York Stock Exchange and Shareholder Department telephone number (toll-free):

Pacific Stock Exchange (800) 457-2983 Newspaper financial listings: PinWst STATISTICAL REPORT FORM 10-K A detailed Statistical Report for Financial Analysis for 1996-Pinnacle Wests Annual Report to the Securities and 2001 will be available in April on the Companys Web site or Exchange Commission on Form 10-K will be available by writing to the Investor Relations Department.

after April 1, 2002 to shareholders upon written request, INVESTOR RELATIONS CONTACT without charge. Write: Office of the Secretary.

Rebecca L. Hickman INVESTORS ADVANTAGE PLAN Director, Investor Relations Pinnacle West offers a direct stock purchase plan. Any P.O. Box 53999 Station 9998 interested investor may purchase Pinnacle West common Phoenix, Arizona 85072-3999 stock through the Investors Advantage Plan. Features of the Telephone: (602) 250-5668 Plan include a variety of options for reinvesting dividends, Fax: (602) 250-2789 direct deposit of cash dividends, automatic monthly STATEWIDE ASSOCIATION FOR UTILITY INVESTORS investment, certificate safekeeping, reduced brokerage The Arizona Utility Investors Association represents the commissions and more. An Investors Advantage Plan interests of investors in Arizona utilities. If interested, send prospectus and enrollment materials may be obtained by your name and address to:

calling the Company at (800) 457-2983, at the corporate Web site - www.pinnaclewest.com, or by writing to: Arizona Utility Investors Association P.O. Box 34805 Pinnacle West Capital Corporation Phoenix, Arizona 85067 Shareholder Department (602) 257-9200 P.O. Box 52133 www.auia.org Phoenix, AZ 85072-2133 ENVIRONMENTAL, HEALTH AND SAFETY REPORT CORPORATE WEB SITE To view the APS Environmental, Health and Safety Report www.pinnaclewest.com 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 Design: www.cfd2k.com 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.

p_62 PINNACLE WEST CAPITAL CORPORATION ANNUAL REPORT 2001