ML041330419

Pinnacle West Capital Corporation - 2003 Annual Report

ML041330419
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Site:	Palo Verde
Issue date:	03/11/2004
From:	Pinnacle West Capital Corp
To:	Office of Nuclear Reactor Regulation
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In Our Element Pinnacle West Capital Corporation 2002 ANNUAL REPORT

THIS YEARS ANNUAL REPORT Throughout this Annual Report, youll see examples of the unique plants, animals and cultures found in Arizona. Each highlighted example thrives in Arizonas diverse climate by relying on characteristics such as agility, resourcefulness, durability, discipline and adaptability. These are also characteristics of Pinnacle West.

Pinnacle West is a Phoenix-based company with consolidated assets of approximately

$8.4 billion and consolidated revenues of $2.6 billion. Through our subsidiaries, we generate, sell and deliver electricity and sell energy-related products and services to retail and wholesale customers in the western United States. We also develop residential, commercial and industrial real estate projects.

2 Letter to Shareholders 6 Operational Overview 15 Consolidated Financial Statements 74 Board of Directors 75 Officers 76 Shareholder Information Table of Contents

CORE STRATEGIC OBJECTIVES Focus on superior long-term total returns for shareholders

• Provide Arizona electricity customers with reliable energy at stable prices

• Capture growth opportunities in our electricity markets

• Actively manage our costs and business risks

• Maximize the long-term value of our assets

• Maintain a disciplined focus on our long-term goals while remaining agile

• Build our generation portfolio consistent with our native load, cash flow and market conditions FINANCIAL HIGHLIGHTS (dollars in thousands, except per share amounts)

Growth Rate Growth Rate year ended December 31, 2002 2001 2000 2002 VS. 2001 2001 VS. 2000 INCOME HIGHLIGHTS Operating revenues

$ 2,637,279

$ 3,393,998

$ 3,119,522 (22.3%)

8.8%

Income before accounting change 215,153 327,367 302,332 (34.3%)

8.3%

BALANCE SHEET HIGHLIGHTS Total assets - year-end

$ 8,425,806

$ 7,939,399

$ 7,122,667 6.1%

11.5%

Common stock equity - year-end

$ 2,686,153

$ 2,499,323

$ 2,382,714 7.5%

4.9%

PER SHARE HIGHLIGHTS Earnings per share before accounting change - diluted 2.53 3.85 3.56 (34.3%)

8.1%

Indicated annual dividend - year-end 1.70 1.60 1.50 6.3%

6.7%

Book value per share - year-end 29.40 29.46 28.09 (0.2%)

4.9%

STOCK PERFORMANCE Stock price per share - year-end 34.09 41.85 47.63 Stock price appreciation (18.5%)

(12.1%)

55.8%

Total return (14.8%)

(9.0%)

61.8%

Market capitalization - year-end

$ 3,115,142

$ 3,549,924

$ 4,039,788 (12.2%)

(12.1%)

$200

$150

$100

$50

$0 Dec 1999 Dec 2000 Dec 2001 Dec 2002 Pinnacle West EEI Electric Index S&P 500 Index Value of $100 invested at end of 1999, with dividends reinvested.

STOCK PERFORMANCE COMPARISON A $100 investment in Pinnacle West in December 1999 (with dividends reinvested) would have been worth $125 at the end of 2002. By comparison, the same $100 would have been worth $115 if invested in the EEI Electric Index, and $62 if invested in the S&P 5000 Index.

2002 PNW 1

2 PNW 2002 WILLIAM J. POST, CHAIRMAN To Our Shareholders Last year the economy didnt perform. Our company did.

Still, our earnings were down. In 2002, net income dropped due to a depressed electric wholesale market and non-recurring charges. However, earnings from our core operations remained relatively strong as a result of outstanding operational performance.

Despite punishing markets and a slack economy over the last two years, we continued to improve reliability and customer satisfaction, and took extraordinary steps to meet customer demand. In this challenging environment, flexibility and agility remain essential to our success.

We continued an unprecedented series of price reductions, insulated customers from volatile wholesale markets and added new generation capacity to meet Arizona Public Service (APS) electricity demand not met by existing APS generation. Our power plant performance set records. We saw significant earnings improvement from unregulated subsidiaries SunCor and APS Energy Services.

Going forward, our story will include a large component of state regulation. We know the regulatory environment and have shown the ability to adjust to its changes. This is a challenge, but its familiar.

There is no place wed rather do business than here in Arizona. This is a unique and dynamic state. Our growth has been robust, and has slowed little through the current economic downturn. Were still adding customers at about three times the national average. When economic growth and business investment return to historical norms, our strong fundamentals will, again, support earnings growth. Excellent performance has softened the blow of a weak economy and changing regulation. Weve been through a turbulent year, and we wont attempt to minimize its impact. In coming years, the overall picture looks brighter.

Throughout these pages youll see images of our state. Those that survive and thrive here possess unique adaptive abilities, hard-earned experience and the flexibility to adjust to change. I see a lot of our company in these examples.

WE ARE ADAPTABLE If youre a long-time owner of our company, you know we emphasized agility, long-term growth and adaptability as we prepared for competition. We knew changes would come. This approach has served us well. For example, we didnt sell our generating plants, even though we felt the same pressure to sell as other utilities. We also didnt over-commit to competitive markets.

We built new generation, primarily in Arizona, to match the growing needs of APS customers.

After preparing for deregulation for nearly a decade, we neared completion of that process in 2002. Under the 1999 regulatory settlement agreement with the Arizona Corporation Commission (ACC), we were to transfer APS generation to Pinnacle West Energy by the end of 2002.

The competition and affiliate rules adopted by the ACC kept APS from adding new generation to serve its needs, while requiring APS to remain the provider of last resort.

To meet APS growing demand for power, Pinnacle West Energy built state-of-the-art, gas-fired combined-cycle power plants, financed with temporary bridge debt. This temporary financing was to be converted to permanent financing when the APS generation assets were consolidated with Pinnacle West Energys new plants as required by the 1999 settlement. Meanwhile, our company and the ACC recognized market conditions were radically different than envisioned in 1999. Serious structural flaws in the wholesale market were painfully apparent. In response, the ACC reversed course in August of 2002 and prohibited the transfer of APS generation to Pinnacle West Energy.

Prior to that, in the fall of 2001, we proposed a different solution in response to the same market weaknesses. The company and the ACC each sought to protect Arizona customers from a competitive debacle that could have mirrored the California disaster.

When the ACC changed its policy on competitive generation, however, it did not address the treatment of our plants built since 1999 to serve APS customers. Our request for financial treatment of the plants followed, and recognizing that the debt markets are essentially closed to unregulated generation companies, the ACC acted quickly on our application to allow APS to extend Pinnacle West a $125 million line of credit. Then, in March of 2003, the ACC also approved a $500 million loan from APS to Pinnacle West Energy. The loan will provide sufficient liquidity while the ACC decides the long-term rate treatment of these plants.

As required by the 1999 settlement agreement, we will file a full general rate case in 2003 - our first in well over a decade - to update our cost of service and address issues arising from the change in direction by the ACC. These issues include folding Pinnacle West Energys Arizona plants into rates, reversal of the $234 million write-off we took as part of the 1999 settlement agreement, and consideration of the costs incurred preparing to transfer APS generation to Pinnacle West Energy. We face a hefty regulatory agenda, but its an agenda we will continue to address to the benefit of our customers and shareholders. We have anticipated the issues and are resolving them before they turn into greater problems. We believe the ACC recognizes the importance of this agenda.

WE MANAGE CONFLICTING AGENDAS When California wanted more natural gas at the expense of our transportation contract (and the contracts of other southwestern companies) with El Paso Natural Gas, we went to the Federal Energy Regulatory Commission (FERC) and fought against erosion of this full requirements contract. Erosion of the El Paso gas contract would increase our costs and make for a less stable supply. We expect resolution by mid-2003 without material cost increases.

2002 PNW 3

4 PNW 2002 We have actively sought a workable transmission structure for the Southwest by forming an independent transmission group known as WestConnect. In 2002, the FERC granted conditional approval of WestConnect, its for-profit structure and its departures from the current standard model.

A for-profit structure will provide incentive for new investment in the transmission grid, which is needed in the West. Weve said for years, without a robust transmission system, there can be no robust wholesale market. Without a robust wholesale market, we cant have broad retail competition.

In fact, the current path is leading to more regulation, not competition.

In the West, we believe the FERC must spend more effort addressing the real barriers to competition - insufficient transmission capacity and the inability to incorporate public power into the competitive structure. Municipal and federal agencies control large chunks of transmission, making tight coordination of scarce capacity even more difficult. Patchwork rules only result in disorder. Without a set of common protocols and full participation by all parties, western wholesale market development is problematic.

There are other unique issues in the West that must be respected. We have long geographic distances between load centers, typically with only one or two transmission lines. Our systems are not networked to the degree of denser East Coast systems. The West has large amounts of hydro capacity that often cannot be scheduled a day ahead.

The mantra of competition will continue to be the catalyst for greater state and federal regulatory involvement. Competition, regulation and the physics of a western electric system will coexist, inconsistencies aside. With the FERC continuing to push for generation deregulation and the ACC maintaining vertical integration, we must deal with incompatibilities and live in different universes at the same time. Business opportunities have and will continue to develop from these apparently colliding forces. We plan to capitalize on them by remaining agile and versatile enough to occupy the ground between these two, while always remaining focused on the ultimate best interests of our customers and shareholders.

OUR BUSINESS STRATEGY IS SOLID Pinnacle West and APS occupy a solid niche in the business landscape. Well continue to concentrate primarily on our core business in an area our employees know well - Arizona and the western U.S. power markets - with a combination of customer focus, exceptional operational performance and financial strength.

We have worked hard to shape this landscape. We avoided price increases by keeping control of our power plants. We didnt sell our generation. We brought in temporary generating resources and built new permanent plants to protect our customers. When prices reached hundreds of dollars per megawatt-hour in 2000 and 2001, we had hedged our market position - with financial instruments as well as short-term power contracts - to insulate customers from price volatility, ensure reliability and protect our shareholders returns.

The growth of APS customers implies a strong core business that will drive future financial performance.

2002 PNW 5

This risk management expertise has served us well. We learned to manage purchased power and fuel price risks, then market risk. Even in todays battered wholesale market, our Power Marketing group has produced positive results, and we expect they will continue to do so in the future.

By July of 2003, we will have decreased our electricity prices 16 percent over the last decade while significantly improving customer satisfaction. Thats customer value. Our employees - the we Ive referred to throughout this letter - will continue our tenacious focus on efficiency and operational excellence.

As we work through the implications of our change in course - the 1999 regulatory write-off, the expense of creating a generation subsidiary, the rate treatment of plants built to serve APS customers and the many issues that affect a traditional rate case - we will not accept inferior outcomes. We acted responsibly in protecting our customers during the power market debacle.

We avoided the blackouts, price spikes and bankruptcies that afflicted other states. We honored the terms of our 1999 settlement agreement and the ACCs competition rules. We expect to achieve a regulatory solution that is fair to our customers and shareholders.

Despite major regulatory shifts, our business strategy has seen little fundamental change. Our core strategic objectives - outlined on page one of this report - still lock together, allowing us to occupy a rewarding business niche, positioning us well to provide solid shareholder returns.

WE ARE FOCUSED ON DELIVERING VALUE For our shareholders, our performance is judged by the delivery of returns in the form of share appreciation and dividends over time. In 2002, the convergence of regulatory change, financial and credit market fears, a weak economy, wholesale electric market declines and our own non-recurring charges contributed to a lower stock price. Although our stock performance for the year mirrored the industry, we are not satisfied with relative industry performance, let alone a decline.

Steps taken in 2002 to reposition our regulatory structure, improve efficiency, reduce staffing, realign our generation portfolio and improve our liquidity, place us well for the future. Although 2003 continues to be a transition year as we work through regulatory and other issues, our operations and market base are strong. We expect debt ratios to improve as we complete our current power plant projects, and even now we have a sound liquidity position, significantly exceeding our cash requirements. The growth of APS customers - both in number and energy usage - implies a strong core business that will drive future financial performance. Meanwhile, we will continue to emphasize dividends for our shareholders tied to factors such as our cash flow, dividend payout trends and financial market conditions.

Our company, and others in our industry, moved in one direction for nearly a decade - toward a new competitive industry. In 2002, that direction reversed. Such sudden change is not easy, and it caused disruptions. But everything that makes us a good company and a good investment remains intact. Our customer growth is powerful and customer satisfaction has never been higher.

Our power plants and wires networks are operating beyond our previous high performance.

We know this region and the opportunities it holds.

Our course is set. Arizona - with its intense climate, aesthetic beauty and nearly limitless potential - has never seemed more attractive. This is our home. This is our future. This is our element.*

William J. Post

• After approximately a decade of preparing for retail electric competition, in mid-2002, the Arizona Corporation Commission changed its generation divestiture policy, resulting in APS remaining a vertically integrated utility. We quickly adapted to this reversal of direction and demonstrated our ability to remain agile in the face of changing regulatory and marketplace climates.

• We continue to meet the changing needs of our customers. Since 1999, our peak load has grown 18 percent, while we have continued to improve our reliability measurements.

• Streamlined processes and a more productive workforce allow us to do more with less. In 1998, we served approximately 775,000 retail electric customers with about 5,900 employees*.

In 2002, we served more than 900,000 customers with approximately 6,100 employees.

• Process and workforce improvements also enable us to keep generation production costs low. In 2002, our nuclear and coal production costs averaged 1.68 cents per kilowatt-hour, well below expected national averages.

• We continue to have a diverse generation mix. By 2004, our estimated generation mix will consist of roughly 43 percent coal, 31 percent nuclear and 26 percent natural gas.

This diversity will allow us to continue effectively managing risk in the face of changing wholesale markets and fuel prices.

• We continue to offer customers greater flexibility, and reduce our operating costs through our utility Web site - APS.com. In recognition of these efforts, APS.com was named Best Energy Site for 2002 by the Web Marketing Association, a national organization made up of Internet marketing, advertising, public relations and design professionals.

• Employee counts reflect workforce serving retail electric business In an evolving climate, those that are agile and adaptable survive. Those that combine these traits with a solid strategic core thrive.

We are such a company.

2002 PNW 7

Our region continues to grow rapidly.

Growth is our future and we will manage it to benefit our customers, our shareholders, our employees and our state.

• APS experienced 3.1 percent customer growth (nearly 30,000 new customers) in 2002 -

about three times the national average. Our customer base is projected to continue to grow about 3.5 percent annually in the next three years.

• Much of this growth occurs in the heart of our service territory - the greater Phoenix area. The Phoenix metro area issued nearly 41,000 building permits in 2002 - ranking second among the 10 largest metropolitan areas in the United States in building permits per 1,000 residents.

• As our customer base grows, we also are expanding our power resources. By bringing on line two new gas-fired units at the Redhawk Power Plant and a new unit at the Saguaro Power Plant, we added more than 1,000 megawatts of new generating capacity in 2002.

In addition, a 530-megawatt unit at the West Phoenix Power Plant is expected to be completed in summer 2003, and the 570-megawatt Silverhawk Plant in summer 2004.

• As an internationally recognized leader in the research and development of solar technology, we are dedicated to finding renewable energy solutions for future generations.

In 2002, APS began construction of the Prescott (Ariz.) Airport Solar Power Plant, which, when completed, should be the largest photovoltaic solar plant in the world. Completion of the solar plant is expected in the next five years, when the facilitys capacity will reach 5 megawatts.

• We expanded our transmission and distribution system in 2002, adding nearly 800 miles of wires. On average, a new substation was completed every seven-and-a-half weeks.

We also began construction on a 500-kilovolt transmission line that, when completed in mid-2003, will bring needed transmission capacity to support the continued growth of the greater Phoenix area.

8 PNW 2002

© photographed by Jerry Jacka

A strong plan is important. Execution of that plan is vital. Our people continue to perform and raise the standards by which we measure success.

• Our fossil power plants operated at high levels throughout 2002. The five coal-fired Four Corners units achieved a combined capacity factor of 83 percent, placing the site in the top 20 percent in the nation. Our Cholla coal plant and the combined gas and oil plants at Ocotillo, Saguaro, West Phoenix, Yucca and Douglas had availabilities of more than 90 percent.

• In 2002, the Palo Verde Nuclear Generating Station produced a national record 30.8 billion kilowatt-hours of electricity, breaking its own record of 30.4 billion kilowatt-hours set in 1999 and repeated in 2000.

• Palo Verde also operated at a best-ever 94.4 percent capacity factor and marked its eleventh consecutive year as the number one power producer of any kind in the United States. This focus on efficient plant production continues to be exceeded only by our intense focus on plant safety.

• We continue to believe areas such as safety, financial integrity, business practices, community involvement and environmental stewardship are key ingredients in creating shareholder value. We emphasize continuous improvement in our safety record and again reduced our number of preventable recordable injuries.

• We grew our common dividend 6.3 percent in 2002. Our dividend growth over the past five years averaged 7.2 percent per year and ranked number one among U.S. electric utilities.

• Pinnacle West again earned the top rating (AAA) for environmental, economic and social performance from Innovest, an international investment advisory firm. The firm ranked us number two out of the 28 electric utilities included in the S&P 500. We also were presented the Better Business Bureau of Central and Northern Arizonas Business Ethics Award.

2002 PNW 11

Our roots run deep in Arizona and the West. Weve been here for 116 years.

We know the landscape. We know the people. We know the opportunities.

• APS has reduced customer electricity prices 14.5 percent since 1993. This number will reach 16 percent in mid-2003 and represents the largest cumulative price decrease among investor-owned utilities nationwide in that time period. These reductions have saved our customers more than a billion dollars.

• In the 2002 electric utility customer satisfaction studies conducted by J.D. Power and Associates, APS residential and midsize business customers rated us higher than any other investor-owned utility in the western region.

• In a year of low wholesale energy prices and a market in which most industry power marketing functions lost millions, our Power Marketing group effectively managed wholesale risk and contributed more than $100 million of pretax gross margin to our company.

• In its fourth year of operation, APS Energy Services, our competitive retail energy services company, continued to carve a profitable niche for itself by providing integrated solutions from commodity energy to energy efficiency-related products and services. In 2002, APS Energy Services began $40 million worth of energy efficiency work for Arizonas three major universities, continued adding commercial and industrial commodity customers in the West and contributed more than $28 million to pretax earnings.

• SunCor, our real estate development company and one of Arizonas premier home-builders, had a strong financial year as well, contributing $19 million to earnings.

SunCor is also expected to make cash distributions to Pinnacle West of $80 million to $100 million annually from 2003 to 2005 from matured asset sales. In 2002, the company opened its newest development, the 1,850-acre StoneRidge golf community in Prescott Valley, Ariz. Nearly 140 homes and 20 custom home sites had been sold at StoneRidge by the end of 2002.

12 PNW 2002

2000 2001 2002 2003 2004 APS Industry Average 5.0 4.0 3.0 2.0 1.0 0.0 Projected Percent change Employees* Customers

• Employee counts reflect workforce serving retail electric business 1999 2000 2001 2002 15 12 9

6 3

0 Cumulative percent change 2.00 1.80 1.60 1.40 1.20 1.00 1998 1999 2000 2001 2002 APS National Average

$/kWh

• 2002 national average not available at press time 1st 2nd 3rd 4th 5th 6th 7th 8th 9th 10th Overall Customer Satisfaction Power Quality &

Reliablity Company Image Price &

Value Billing &

Payment Customer Service Source: J.D. Power & Associates 2002 Midsize Business Customer Satisfaction Survey APS regional ranking COAL AND NUCLEAR PRODUCTION COST CUMULATIVE PERCENT INCREASE OF CUSTOMERS AND EMPLOYEES SINCE 1999 APS CUSTOMER GROWTH We continue to experience unique customer growth - about three times the industry average These efficiencies have also allowed us to keep power plant production costs below national averages Though were rapidly adding customers, increasingly efficient operations have helped keep workforce increases minimal And our customer satisfaction scores continue to improve, ranking at or near the top of the western region.

CUSTOMER SATISFACTION RANKING 14 PNW 2002

15 2002 PNW 15 16 Selected Consolidated Financial Data 18 Glossary 19 Managements Discussion and Analysis of Financial Condition and Results of Operations 38 Independent Auditors Report 39 Consolidated Statements of Income 40 Consolidated Balance Sheets 42 Consolidated Statements of Cash Flows 43 Consolidated Statements of Changes in Common Stock Equity 44 Notes to Consolidated Financial Statements 2002 Consolidated Financial Statements

16 16 PNW 2002 SELECTED CONSOLIDATED FINANCIAL DATA (dollars in thousands, except shares and per share amounts) 2002 2001 2000 1999 1998 OPERATING RESULTS Operating revenues:

Regulated electricity segment

$ 2,013,023

$ 2,562,089

$ 2,538,752

$ 1,915,108

$ 1,741,148 Marketing and trading segment 325,931 651,230 418,532 154,125 180,145 Real estate segment 236,388 168,908 158,365 130,169 124,188 Other revenues 61,937 11,771 3,873 439 Income from continuing operations 215,153 327,367 302,332 269,772 242,892 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)(d)

(65,745)

(15,201)

Net income 149,408 312,166 302,332 167,887 242,892 COMMON STOCK DATA Book value per share - year-end 29.40 29.46 28.09 26.00 25.50 Earnings (loss) per weighted average common share outstanding:

Continuing operations - basic 2.53 3.86 3.57 3.18 2.87 Discontinued operations 0.45 Extraordinary charge (1.65)

Cumulative effect of change in accounting (0.77)

(0.18)

Net income - basic 1.76 3.68 3.57 1.98 2.87 Continuing operations - diluted 2.53 3.85 3.56 3.17 2.85 Net income - diluted 1.76 3.68 3.56 1.97 2.85 Dividends declared per share 1.625 1.525 1.425 1.325 1.225 Indicated annual dividend rate per share - year-end 1.70 1.60 1.50 1.40 1.30 Weighted-average common shares outstanding - basic 84,902,946 84,717,649 84,732,544 84,717,135 84,774,218 Weighted-average common shares outstanding - diluted 84,963,921 84,930,140 84,935,282 85,008,527 85,345,946 BALANCE SHEET DATA Total assets

$ 8,425,806

$ 7,939,399

$ 7,122,667

$ 6,571,023

$ 6,789,975 Liabilities and equity:

Long-term debt less current maturities

$ 2,881,695

$ 2,673,078

$ 1,955,083

$ 2,206,052

$ 2,048,961 Other liabilities 2,857,958 2,766,998 2,784,870 2,159,238 2,482,422 Total liabilities 5,739,653 5,440,076 4,739,953 4,365,290 4,531,383 Minority interests:

Non-redeemable preferred stock of APS 85,840 Redeemable preferred stock of APS 9,401 Common stock equity 2,686,153 2,499,323 2,382,714 2,205,733 2,163,351 Total liabilities and equity

$ 8,425,806

$ 7,939,399

$ 7,122,667

$ 6,571,023

$ 6,789,975 (a)

Tax benefit stemming from the resolution of income tax matters related to a former subsidiary MeraBank, A Federal Savings Bank.

(b) Charges associated with a regulatory disallowance. See Regulatory Accounting in Note 1.

(c)

Change in accounting standards related to derivatives in 2001. See Note 18.

(d) Change in accounting standards related to trading activities in 2002. See Note 18.

SELECTED CONSOLIDATED FINANCIAL DATA (CONTINUED)

(dollars in thousands) 2002 2001 2000 1999 1998 REGULATED ELECTRICITY AND MARKETING AND TRADING SEGMENTS REVENUES Regulated electricity segment:

Residential - retail 906,069 914,711 880,468 805,173 766,378 Business - retail 927,773 952,627 935,214 911,449 889,244 Total retail 1,833,842 1,867,338 1,815,682 1,716,622 1,655,622 Wholesale revenue on delivered electricity:

Traditional contracts 8,616 73,305 120,618 60,486 58,184 Retail load hedge management (a) 122,630 577,784 560,493 108,153 Transmission for others 29,803 25,971 14,765 11,348 11,058 Other miscellaneous services 18,132 17,691 27,194 18,499 16,284 Total regulated electricity revenue 2,013,023 2,562,089 2,538,752 1,915,108 1,741,148 Marketing and trading segment:

Delivered marketing and trading:

Generation sales other than Native Load (a) 50,364 148,316 115,476 29,551 Realized margin on electricity trading 47,897 62,067 55,910 8,565 2,157 Other delivered electricity (a) 207,810 328,972 244,183 112,551 170,796 Total delivered marketing and trading 306,071 539,355 415,569 150,667 172,953 Other marketing and trading:

Realized margins on delivered commodities other than electricity 7,771 (13,646)

(8,789) 2,483 7,192 Prior period mark-to-market gains on contracts delivered during current period (40,072)

(1,059)

(2,079)

Change in mark-to-market for future period deliveries 52,161 126,580 13,831 975 Total other marketing and trading 19,860 111,875 2,963 3,458 7,192 Total marketing and trading revenue 325,931 651,230 418,532 154,125 180,145 Total regulated electricity and marketing and trading segments revenues 2,338,954 3,213,319 2,957,284 2,069,233 1,921,293 ELECTRIC SALES (MWh)

Regulated electricity segment:

Residential - retail 10,443,820 10,334,860 9,780,680 8,774,822 8,310,689 Business - retail 12,917,935 13,064,152 12,753,844 12,299,748 12,152,394 Total retail 23,361,755 23,399,012 22,534,524 21,074,570 20,463,083 Wholesale electricity delivered:

Traditional contracts 473,699 1,213,704 1,610,032 1,421,522 1,410,392 Retail load hedge management (a) 2,641,714 3,039,905 6,673,658 630,945 Total regulated electricity 26,477,168 27,652,621 30,818,214 23,127,037 21,873,475 Delivered marketing and trading:

Generation sales other than Native Load (a) 1,791,319 1,387,860 1,494,299 1,267,349 Electricity trading 16,924,509 12,031,055 9,259,054 5,679,023 846,864 Other delivered electricity (a) 4,138,055 2,581,942 2,960,314 6,694,995 8,060,135 Total delivered marketing and trading 22,853,883 16,000,857 13,713,667 13,641,367 8,906,999 Total regulated electricity and marketing and trading sales 49,331,051 43,653,478 44,531,881 36,768,404 30,780,474 ELECTRIC CUSTOMERS - AVERAGE Retail:

Residential 801,801 776,339 749,285 719,774 689,871 Business 100,228 98,198 94,128 90,496 87,831 Total retail 902,029 874,537 843,413 810,270 777,702 Wholesale 67 66 67 69 60 Total average electric customers 902,096 874,603 843,480 810,339 777,762 (a)

The break-out of retail load hedge management and generation sales other than Native Load is not available for 1998. These amounts are included in other delivered electricity in the marketing and trading segment for 1998.

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

17 2002 PNW 17

18 18 PNW 2002 Dividends Dividends Per Per 2002 High Low Close Share 2001 High Low Close Share 1st Quarter

$ 45.60

$ 39.36

$ 45.35

$0.400 1st Quarter

$ 47.96

$39.06

$ 45.87

$ 0.375 2nd Quarter 46.68 37.08 39.50 0.400 2nd Quarter 50.70 45.20 47.40 0.375 3rd Quarter 39.72 25.82 27.76 0.400 3rd Quarter 49.93 37.65 39.70 0.375 4th Quarter 34.36 21.70 34.09 0.425 4th Quarter 43.50 38.00 41.85 0.400 QUARTERLY STOCK PRICES AND DIVIDENDS PER SHARE Stock Symbol: PNW GLOSSARY ACC - Arizona Corporation Commission ACC Staff - Staff of the Arizona Corporation Commission ADEQ - Arizona Department of Environmental Quality ALJ - Administrative Law Judge ANPP - Arizona Nuclear Power Project, also known as Palo Verde APS - Arizona Public Service Company, a subsidiary of the Company APS Energy Services - APS Energy Services Company, Inc.,

a subsidiary of the Company CC&N - Certificate of Convenience and Necessity Cholla - Cholla Power Plant Citizens - Citizens Communications Company Clean Air Act - the Clean Air Act, as amended Company - Pinnacle West Capital Corporation CPUC - California Public Utility Commission DOE - United States Department of Energy EITF - the FASBs Emerging Issues Task Force El Dorado - El Dorado Investment Company, a subsidiary of the Company ERMC - the Companys Energy Risk Management Committee FASB - Financial Accounting Standards Board FERC - United States Federal Energy Regulatory Commission FIN - FASB Interpretation Financing Application - APS application filed with the ACC on September 16, 2002 Fitch - Fitch, Inc.

Four Corners - Four Corners Power Plant GAAP - accounting principles generally accepted in the United States of America Interim Financing Application - APS application filed with the ACC on November 8, 2002 IRS - United States Internal Revenue Service ISO - California Independent System Operator kWh - kilowatt-hour, one thousand watts per hour Moodys - Moodys Investors Service MW - megawatt, one million watts MWh - megawatt-hours, one million watts per hour NAC - NAC International Inc., a subsidiary of El Dorado Native Load - retail and wholesale sales supplied under traditional cost-based rate regulation 1999 Settlement Agreement - comprehensive settlement agreement related to the implementation of retail electric competition NRC - United States Nuclear Regulatory Commission Nuclear Waste Act - Nuclear Waste Policy Act of 1982, as amended OCI - other comprehensive income Palo Verde - Palo Verde Nuclear Generating Station PG&E - PG&E Corp.

Pinnacle West - Pinnacle West Capital Corporation, the Company Pinnacle West Energy - Pinnacle West Energy Corporation, a subsidiary of the Company PX - California Power Exchange Rules - ACC retail electric competition rules SCE - Southern California Edison Company SFAS - Statement of Financial Accounting Standards SMD - standard market design SNWA - Southern Nevada Water Authority SPE - special-purpose entity Standard & Poors - Standard & Poors Corporation SunCor - SunCor Development Company, a subsidiary of the Company System - non-trading energy related activities T&D - transmission and distribution Track A Order - ACC order dated September 10, 2002 regarding generation asset transfers and related issues Track B Order - ACC order dated March 14, 2003 regarding competitive solicitation requirements for power purchases by Arizonas investor-owned electric utilities Trading - energy-related activities entered into with the objective of generating profits on changes in market prices VIE - variable interest entity

19 2002 PNW 19 consultation and facility audits, cogeneration analysis and installation and project management) to commercial, industrial and institutional retail customers in the western United States; SunCor, a developer of residential, commercial, and industrial real estate projects in Arizona, New Mexico, and Utah; and El Dorado, which owns a majority interest in NAC (specializing in spent nuclear fuel technology) and holds miscellaneous small invest-ments, including interests in Arizona community-based ventures.

SUMMARY

OF KEY FACTORS AFFECTING OUR FINANCIAL OUTLOOK We believe the following are among the key factors affecting our financial outlook:

The following ACC regulatory matters:

APS $500 million financing application which the ACC approved on March 27, 2003; the implementation of the ACC-mandated process by which APS must competitively procure energy; and APS general rate case to be filed in 2003.

Wholesale power market conditions in the western United States.

We discuss each of these, and other factors in detail below in the section entitled Factors Affecting Our Financial Outlook.

EARNINGS CONTRIBUTIONS BY SUBSIDIARY AND BUSINESS SEGMENT We have three principal business segments (determined by products, services and the regulatory environment):

Our regulated electricity segment, which consists of regulated tradi-tional retail and wholesale electricity businesses and related activities and includes electricity transmission, distribution and generation; our marketing and trading segment, which consists of our com-petitive energy business activities, including wholesale marketing and trading and APS Energy Services commodity-related energy services; and our real estate segment, which consists of SunCors real estate development and investment activities.

INTRODUCTION In this section, we explain the results of operations, general financial con-dition, and outlook for Pinnacle West and our subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and El Dorado, including:

the changes in our earnings from 2001 to 2002 and from 2000 to 2001; our capital needs, liquidity and capital resources; our critical accounting policies; our business outlook and major factors that affect our financial outlook; and our management of market risks.

Throughout this section, we refer to specific Notes in the Notes to Consolidated Financial Statements in this report. These Notes add further details to the discussion.

BUSINESS OVERVIEW The Company owns all of the outstanding common stock of APS. APS is an electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of the Tucson metropolitan area and about one-half of the Phoenix metropolitan area. Electricity is delivered through a distribution system owned by APS.

APS also generates, sells and delivers electricity to wholesale customers in the western United States. The marketing and trading division sells, in the wholesale market, APS and Pinnacle West Energy generation output that is not needed for APS Native Load, which includes loads for retail customers and traditional cost-of-service wholesale customers. APS does not distribute any products.

Our other major subsidiaries are:

Pinnacle West Energy, through which we conduct our competitive electricity generation operations; APS Energy Services, which provides competitive commodity-related energy services (such as direct access commodity contracts, energy procurement and energy supply consultation) and energy-related products and services (such as energy master planning, energy use Regulated Marketing Real (dollars in millions)

TOTAL Electricity and Trading Estate Other (a) 2002 APS (b) 199 198 1

Pinnacle West Energy (b)

(19)

(21) 2 APS Energy Services (c) 28 23 5

SunCor 19 19 El Dorado (principally NAC) (c)

(55)

(55)

Parent company (c) 43 (7) 32 18 Income (loss) before accounting change 215 170 58 19 (32)

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

(66)

(66)

Net income (loss) 149 170 (8) 19 (32)

MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following tables summarize net income and segment details for the years ended December 31, 2002, 2001 and 2000 for Pinnacle West and each of our subsidiaries:

20 20 PNW 2002 Our income before accounting change for the year ended December 31, 2002 was $215 million compared with $327 million for the prior year. The period-to-period comparison was lower due to:

lower earnings contributions from our marketing and trading activities, reflecting lower liquidity and lower price volatility in the wholesale power markets in the western United States; pretax losses of $59 million related to our investment in NAC; a $49 million pretax write-off related to the cancellation of Redhawk Units 3 and 4, of which $47 million was recorded in operations and maintenance expense and $2 million was recorded in capitalized interest; and severance costs of approximately $36 million pretax recorded in the second half of 2002 relating to a voluntary workforce reduction.

The above decreases were partially offset by:

increased earnings contributions from our regulated electricity activities, reflecting lower replacement power costs for power plant outages, RESULTS OF OPERATIONS General Throughout the following explanations of our results of operations, we refer to gross margin. With respect to our regulated electricity segment and marketing and trading segment, gross margin refers to electric oper-ating revenues less purchased power and fuel costs. Our real estate segment gross margin refers to real estate revenues less real estate operations costs of SunCor. Other gross margin refers to other operating revenues less other operating expenses, which includes El Dorados investment in NAC, which we began consolidating in our financial state-ments in July 2002 (see Note 22). Other gross margin also includes amounts related to APS Energy Services energy consulting services.

2002 Compared with 2001 Our consolidated net income for the year ended December 31, 2002 was $149 million compared with $312 million for the prior year. We recognized a $66 million after-tax charge in 2002 for the cumulative effect of a change in accounting for trading activities for the early adoption of EITF 02-3 on October 1, 2002 (see Note 18). In 2001, we recognized a

$15 million after-tax charge for the cumulative effect of a change in accounting for derivatives, as required by SFAS No. 133 (see Note 18).

Regulated Marketing Real (dollars in millions)

TOTAL Electricity and Trading Estate Other 2001 APS (b) 281 139 142 Pinnacle West Energy (b) 18 18 APS Energy Services (c)

(10)

(11) 1 SunCor 3

3 El Dorado Parent company 35 (5) 40 Income before accounting change 327 152 171 3

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

(15)

(15)

Net income 312 137 171 3

1 Regulated Marketing Real (dollars in millions)

TOTAL Electricity and Trading Estate Other 2000 APS 307 228 79 Pinnacle West Energy (2)

(2)

APS Energy Services (c)

(13)

(16) 3 SunCor 11 11 El Dorado 2

2 Parent company (3)

(5) 2 Net income 302 221 65 11 5

(a) Primarily includes activities related to El Dorado, principally NAC. See Note 22.

(b) Consistent with APS October 2001 ACC filing, APS entered into agreements with its affiliates to buy power. The agreements reflected a price based on the fully-dispatchable dedication of the Pinnacle West Energy generating assets to APS Native Load customers. In 2002, Pinnacle West Energy recorded a $49 million pretax write-off related to the cancellation of Redhawk Units 3 and 4.

(c) APS Energy Services and El Dorados net income is primarily reported before income taxes. The income tax expense or benefit for these subsidiaries is recorded at the parent company.

(d) We recorded a $66 million after-tax charge in 2002 for the cumulative effect of a change in accounting for trading activities, for the early adoption of EITF 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, as of October 1, 2002. See Note 18.

(e) APS recorded a $15 million after-tax charge in 2001 for the cumulative effect of a change in accounting for derivatives related to the adoption of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. See Note 18.

See Note 17 for additional financial information regarding our business segments.

21 2002 PNW 21 retail customer growth and higher average usage per customer, partially offset by the effects of milder weather, retail electricity price decreases and higher costs for purchased power and gas due to higher hedged gas and power prices; and Increase (dollars in millions)

(Decrease)

Regulated electricity segment gross margin:

Lower replacement power costs for plant outages due to lower market prices and fewer unplanned outages 127 Increased purchased power and fuel costs due to higher hedged gas and power prices, partially offset by improved hedge management, net of mark-to-market reversals (9)

Higher retail sales volumes due to customer growth and higher average usage, excluding weather effects 38 2001 charges related to purchased power contracts with Enron and its affiliates 13 Retail price reductions effective July 1, 2001 and July 1, 2002 (28)

Effects of milder weather on retail sales (27)

Miscellaneous factors, net (2)

Net increase in regulated electricity segment gross margin 112 Marketing and trading segment gross margin:

Decrease in generation sales other than Native Load due to lower market prices partially offset by higher sales volumes (66)

Lower realized wholesale margins net of related mark-to-market reversals due to lower prices and volumes (91)

Higher competitive retail sales in California by APS Energy Services 32 2001 write-off of prior period mark-to-market value related to trading with Enron and its affiliates 8

Lower mark-to-market reversals due to the adoption of EITF 02-3 8

Lower mark-to-market gains for future delivery due to lower market liquidity and lower price volatility (76)

Net decrease in marketing and trading segment gross margin (185)

Net decrease in regulated electricity and marketing and trading segments gross margins (73)

Higher real estate segment gross margin primarily due to increased sales activities 16 Lower other gross margin primarily related to NAC losses (44)

Higher operations and maintenance expense related to a $47 million write-off of Redhawk Units 3 and 4 and 2002 severance costs of approximately $36 million, partially offset by lower generation reliability costs (54)

Higher taxes other than income taxes (7)

Lower other income primarily due to a 2001 insurance recovery of environmental remediation costs (11)

Higher net interest expense primarily due to higher debt balances and lower capitalized interest (16)

Miscellaneous factors, net 2

Net decrease in income before income taxes (187)

Lower income taxes primarily due to lower income 75 Net decrease in income before accounting change (112)

The major factors that increased (decreased) income before accounting change were as follows:

REGULATED ELECTRICITY SEGMENT GROSS MARGIN Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $549 million lower in the year ended December 31, 2002, compared with the prior year as a result of:

decreased revenues related to traditional wholesale sales as a result of lower sales volumes and lower prices ($64 million);

decreased revenues related to retail load hedge management wholesale sales, primarily as a result of lower prices and lower sales volumes ($455 million);

decreased retail revenues related to milder weather ($60 million);

increased retail revenues related to customer growth and higher average usage, excluding weather effects ($69 million);

decreased retail revenues related to reductions in retail electricity prices ($28 million); and other miscellaneous factors ($11 million net decrease).

Regulated electricity segment purchased power and fuel costs were

$661 million lower in the year ended December 31, 2002, compared with the prior year as a result of:

decreased costs related to traditional wholesale sales as a result of lower sales volumes and lower prices ($64 million);

decreased costs related to retail load hedge management wholesale sales, primarily as a result of lower prices and lower sales volumes

($460 million);

increased earnings contributions from real estate operations, primarily as a result of increased sales activities.

For additional details, see the following discussion.

22 22 PNW 2002 increased costs related to higher prices for hedged natural gas and purchased power, net of mark-to-market reversals ($14 million);

decreased costs related to the effects of milder weather on retail sales

($33 million);

increased costs related to retail sales growth, excluding weather effects ($31 million);

charges in 2001 related to purchased power contracts with Enron and its affiliates ($13 million net decrease);

decreased replacement power costs for power plant outages due to lower market prices and fewer unplanned outages ($127 million); and miscellaneous factors ($9 million net decrease).

MARKETING AND TRADING SEGMENT GROSS MARGIN Marketing and trading segment revenues were $325 million lower in the year ended December 31, 2002, compared with the prior year as a result of:

decreased revenues from generation sales other than Native Load primarily due to lower market prices partially offset by higher sales volumes ($98 million);

lower realized wholesale revenues net of related mark-to-market reversals primarily due to lower prices partially offset by higher volumes ($273 million);

increased revenues from higher competitive retail sales in California by APS Energy Services ($105 million);

2001 write-off of prior period mark-to-market value related to trading with Enron and its affiliates ($8 million increase);

higher revenues related to the adoption of EITF 02-3 ($8 million); and lower mark-to-market gains for future delivery primarily as a result of lower market liquidity and lower price volatility, resulting in lower volumes ($75 million).

Marketing and trading segment purchased power and fuel costs were

$140 million lower in the year ended December 31, 2002, compared to the prior year as a result of:

decreased fuel costs related to generation sales other than Native Load primarily because of lower natural gas prices partially offset by higher sales volumes ($32 million);

decreased purchased power costs related to other realized marketing activities in the current period primarily due to lower prices partially offset by higher volumes ($182 million);

increased purchased power costs related to higher competitive retail sales in California by APS Energy Services ($73 million); and change in mark-to-market fuel costs for future delivery

($1 million increase).

OTHER INCOME STATEMENT ITEMS The increase in real estate segment gross margin of $16 million was primarily due to increased sales activities.

The decrease in other gross margin of $44 million was primarily due to losses on El Dorados investment in NAC (see further discussion in Note 22). These losses for 2002 totaled approximately $59 million on a pretax basis and were primarily related to NAC contracts with two customers

($51 million was recorded in other gross margin and $8 million was recorded in other expense). We believe we have reserved our exposure with respect to these contracts in all material respects and, as a result, we consider these charges to be non-recurring.

The increase in operations and maintenance expense of $54 million was due to a $47 million write-off related to the cancellation of Redhawk Units 3 and 4, severance costs of $36 million related to a 2002 volun-tary workforce reduction and other costs of $9 million, partially offset by lower costs related to generation reliability, plant outages and maintenance costs of $38 million.

The increase in taxes other than income taxes of $7 million is primarily due to increased property taxes on higher property balances.

Other income decreased $11 million primarily due to an insurance recovery recorded in 2001 related to environmental remediation costs and other costs (see Note 19).

Other expense was comparable with the prior year primarily due to losses recorded related to El Dorados investment in NAC of approxi-mately $8 million (see further discussion in Note 22) offset by $8 million of lower miscellaneous non-operating costs (see Note 19).

Net interest expense increased $16 million primarily because of higher debt balances related to our generation construction program and lower capitalized interest on our generation construction program due to completion of Redhawk Units 1 and 2 in mid-2002.

2001 Compared with 2000 Our consolidated net income for the year ended December 31, 2001 was $312 million compared with $302 million for the prior year. In 2001, we recognized a $15 million after-tax charge for the cumulative effect of a change in accounting for derivatives, as required by SFAS No. 133 (see Note 18).

Our income before accounting change for the year ended December 31, 2001 was $327 million compared with $302 million for the prior year. The period-to-period comparison benefited from:

strong marketing and trading results, including significant benefits recognized in the third quarter of 2001 from structured trading activities; and retail customer growth.

The above increases were partially offset by:

lower earnings contributions from our regulated electricity activities, reflecting higher purchased power and fuel costs, due in part to increased power plant maintenance, generation reliability measures and continuing retail electricity price decreases; and 2001 charges related to Enron and its affiliates.

For additional details, see the following discussion.

23 2002 PNW 23 Increase (dollars in millions)

(Decrease)

Regulated electricity segment gross margin:

Higher replacement power costs for plant outages related to higher market prices (70)

Retail price reductions effective July 1, 2001 and July 1, 2000 (27)

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

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

Net decrease in regulated electricity segment gross margin (72)

Marketing and trading segment gross margin:

Increase from generation sales other than Native Load due to higher market prices 25 Higher realized wholesale margin net of related mark-to-market reversals 61 Change in prior period mark-to-market value related to trading with Enron and its affiliates (8) (a)

Increase in mark-to-market value related to future periods 113 Net increase in marketing and trading segment gross margin 191 Net increase in regulated electricity and marketing and trading segments gross margins 119 Decrease in real estate segment 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 (4)

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

Net increase in income before accounting change 25 (a) We recorded charges totaling $21 million before income taxes for exposure to Enron and its affiliates in the fourth quarter of 2001.

The major factors that increased (decreased) income before accounting change were as follows:

REGULATED ELECTRICITY SEGMENT GROSS MARGIN Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $23 million higher in the year ended December 31, 2001 compared to the prior year as a result of:

decreased revenues related to other wholesale sales and miscella-neous revenues as a result of lower sales volumes ($28 million);

increased retail revenues primarily related to higher sales volumes primarily due to customer growth ($78 million); and decreased retail revenues related to reductions in retail electricity prices ($27 million).

Regulated electricity segment purchased power and fuel costs were

$95 million higher in the year ended December 31, 2001 compared to the prior year as a result of:

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

higher replacement power costs primarily due to higher market prices and increased plant outages ($70 million), including costs of $12 million related to a Palo Verde outage extension to replace fuel control element assemblies; higher costs related to retail sales volumes due to customer growth

($43 million); and charges related to purchased power contracts with Enron and its affiliates ($13 million).

MARKETING AND TRADING SEGMENT GROSS MARGIN Marketing and trading segment revenues were $233 million higher in the year ended December 31, 2001 compared with the prior year as a result of:

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

increased realized wholesale revenues net of related mark-to-market reversals primarily due to more transactions ($96 million);

decreased prior period mark-to-market value related to trading with Enron and its affiliates ($8 million); and increased mark-to-market value for future periods primarily as a result of more forward sales volumes ($113 million).

Marketing and trading segment purchased power and fuel costs were

$42 million higher in the year ended December 31, 2001 compared to the prior year as a result of:

increased fuel costs related to generation sales other than Native Load as a result of higher fuel prices ($7 million); and increased purchased power and fuel costs net of related mark-to-market reversals primarily due to more transactions ($35 million).

OTHER INCOME STATEMENT ITEMS The decrease in real estate segment profits of $8 million resulted primarily from reduced sales of land and homes by SunCor.

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

Net other expense increased $4 million primarily because of a change in the market value of El Dorados investment in a technology-related venture capital partnership in 2000 and other nonoperating costs partially offset by an insurance recovery of environmental remediation costs (see Note 19).

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

See Regulatory Matters - 1999 Settlement Agreement in Note 3 for a discussion of the 1999 Settlement Agreement under which, among other things, APS agreed to five annual retail electricity price reductions of 1.5% with the last decrease to take effect July 1, 2003.

LIQUIDITY AND CAPITAL RESOURCES Capital Needs and Resources CAPITAL EXPENDITURE REQUIREMENTS The following table summarizes the actual capital expenditures for the year ended December 31, 2002 and estimated capital expenditures for the next three years.

Actual Estimated (dollars in millions) 2002 2003 2004 2005 APS Delivery 369 273 275 329 Generation (a) 132 123 99 164 Other (e) 5 5

5 Subtotal 501 401 379 498 Pinnacle West Energy (a)(b) 374 268 31 20 SunCor (c) 72 64 23 20 Other (d) 37 17 13 14 Total 984 750 446 552 (a) As discussed below under Factors Affecting Our Financial Outlook, as part of its 2003 general rate case, APS intends to seek rate-base treatment of certain power plants in Arizona currently owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3).

(b) See Note 11 for further discussion of Pinnacle West Energys generation construction program and Capital Resources and Cash Requirements - Pinnacle West Energy below. These amounts do not include an expected reimbursement in 2004 by SNWA of about $100 million, assuming SNWA exercises its option to purchase a 25% interest in the Silverhawk project at that time.

24 24 PNW 2002 Delivery capital expenditures are comprised of T&D infrastructure addi-tions and upgrades, capital replacements, new customer construction and related information systems and facility costs. Examples of the types of projects included in the forecast include T&D lines and substa-tions, line extensions to new residential and commercial developments and upgrades to customer information systems. In addition, APS began several major transmission projects in 2001. These projects are periodic in nature and are driven by strong regional customer growth. APS expects to spend about $105 million on major transmission projects during the 2003 to 2005 time frame, and these amounts are included in APS-Delivery in the table above.

Generation capital expenditures are comprised of various improvements for APS existing fossil and nuclear plants and the replacement of Palo Verde steam generators. Examples of the types of projects included in this category are additions, upgrades and capital replacements of vari-ous power plant equipment such as turbines, boilers and environmental equipment. Generation also contains nuclear fuel expenditures of approximately $30 million annually for 2003 to 2005.

Replacement of the steam generators in Palo Verde Unit 2 is presently scheduled for completion during the fall outage of 2003. The Palo Verde owners have approved the manufacture of two additional sets of steam generators. We expect that these generators will be installed in Units 1 and 3 in the 2005 to 2008 time frame. Our portion of steam generator expenditures for Units 1, 2 and 3 is approximately $145 million, which will be spent from 2003 through 2008. In 2003 through 2005, $94 million of the costs are included in the generation capital expenditures table above and would be funded with internally-generated cash or external financings.

(c) Consists primarily of capital expenditures for land development and retail and office building construction reflected in the Change in real estate investments in the Consolidated Statements of Cash Flows.

(d) Primarily related to the parent company and APS Energy Services.

(e) The other amounts relate to capital expenditures for our marketing and trading segment. These costs were in the parent company for 2002.

Off-Balance Sheet Arrangements In January 2003, the FASB issued FIN No. 46, Consolidation of Variable Interest Entities. FIN No. 46 requires that we consolidate a VIE if we have a majority of the risk of loss from the VIEs activities or we are entitled to receive a majority of the VIEs residual returns or both. A VIE is a corporation, partnership, trust or any other legal structure that either does not have equity investors with voting rights or has equity investors that do not provide sufficient financial resources for the entity to support its activities. FIN No. 46 is effective immediately for any VIE created after January 31, 2003 and is effective July 1, 2003 for VIEs created before February 1, 2003.

In 1986, APS entered into agreements with three separate SPE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP.

See Note 9 for further information about the sale-leaseback transactions.

Based on our preliminary assessment of FIN No. 46, we do not believe we will be required to consolidate the Palo Verde SPEs. However, we continue to evaluate the requirements of the new guidance to determine what impact, if any, it will have on our financial statements.

APS is also exposed to losses under the Palo Verde sale-leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2002, APS would have been required to assume approximately $285 million of debt and pay the equity participants approximately $200 million.

Guarantees We and certain of our subsidiaries have issued guarantees in support of our unregulated businesses. We have also obtained surety bonds on behalf of APS Energy Services. We have not recorded any liability on our Consolidated Balance Sheets with respect to these obligations.

See Note 23 for additional information regarding guarantees.

Credit Ratings The ratings of securities of Pinnacle West and APS as of March 28, 2003 are shown below and are considered to be investment-grade ratings. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle Wests or APS securities and serve to increase those companies cost of and access to capital.

Standard Moodys

& Poors Fitch PINNACLE WEST Senior unsecured Baa2 BBB-BBB Commercial paper P-2 A-2 F-2 APS Senior secured A3 A-A-

Senior unsecured Baa1 BBB BBB+

Secured lease obligation bonds Baa2 BBB BBB Commercial paper P-2 A-2 F-2 25 2002 PNW 25 Actual Estimated (dollars in millions) 2002 2003 2004 2005 2006 2007 Thereafter Long-term debt payments:

APS 337 205 400 84

$ 1,518 Pinnacle West 275 215 300 SunCor 3

126 3

15 El Dorado 13 1

1 1

Total long-term debt payments 353 276 547 401 387 1,533 Capital lease payments 1

5 5

4 3

3 6

Operating lease payments 69 70 66 64 63 63 478 Purchase power and fuel commitments 338 173 82 28 31 17 162 Total contractual commitments 761 524 700 497 484 83

$ 2,179 Contractual Obligations The following table summarizes actual contractual requirements for the year ended December 31, 2002 and estimated contractual commitments for the next five years and thereafter:

26 26 PNW 2002 On November 4, 2002, Standard & Poors affirmed the APS debt ratings in the above chart, but lowered Pinnacle Wests senior unsecured debt rating from BBB to BBB-because of the structural subordination of this debt as compared to the unsecured debt at APS. On that same date, Standard & Poors lowered APS corporate credit rating from BBB+ to BBB and affirmed the BBB corporate credit rating of Pinnacle West.

Standard & Poors assigned a stable outlook to the ratings. All of Pinnacle Wests and APS credit ratings remain investment grade. In December 2002, Fitch placed certain of our debt and that of APS on Ratings Watch Negative. The ratings watch affects our senior unsecured debt and commercial paper ratings. It also affects all of APS debt ratings, with the exception of its commercial paper rating.

On December 31, 2002, Moodys affirmed the ratings set forth above.

Debt Provisions Pinnacle Wests and APS significant debt covenants related to their respective financing arrangements include debt-to-total-capitalization ratio and an interest coverage test. Pinnacle West and APS are in com-pliance with such covenants and each anticipates it will continue to meet all the significant covenant requirement levels. The ratio of debt to total capitalization cannot exceed 65% for both the Company and APS.

At December 31, 2002, the ratios are approximately 54% and 48% for the parent company and APS, respectively. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for both the Company and APS. The coverages are approximately 4 times for the parent company, 5 times for the APS bank agreements and 15 times for the APS mortgage indenture. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants.

Neither Pinnacle Wests nor APS financing agreements contain ratings triggers that would result in an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a ratings downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.

All of Pinnacle Wests bank agreements contain cross-default provi-sions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under other agreements. All of APS bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under other agreements. Pinnacle Wests and APS credit agree-ments generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in our financial condition or financial prospects.

Pinnacle West (Parent Company)

Our primary cash needs are for dividends to our shareholders; equity infu-sions into our subsidiaries, primarily Pinnacle West Energy; and interest payments and optional and mandatory repayments of principal on our long-term debt (see the table above for our contractual requirements, including our debt repayment obligations, but excluding optional repay-ments). On October 23, 2002, our board of directors increased the com-mon stock dividend to an indicated annual rate of $1.70 per share from

$1.60 per share, effective with the December 1, 2002 dividend payment.

The level of our common dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.

Our primary sources of cash are dividends from APS, external financings, and cash distributions from our other subsidiaries, primarily SunCor. For the years 2000 through 2002, total dividends from APS were $510 million and total distributions from SunCor were $33 million.

For the year ended December 31, 2002, dividends from APS were approximately $170 million and distributions from SunCor were approxi-mately $13 million. We expect SunCor to make cash distributions to the parent company of $80 million to $100 million annually in 2003 through 2005 due to anticipated accelerated asset sales activity.

On December 23, 2002, we issued 6,555,000 shares of common stock, no par value, which resulted in net proceeds of $199 million. See Note 7.

We have financed Pinnacle West Energys generation construction pro-gram premised upon Pinnacle West Energys receipt of APS generation assets by the end of 2002. On November 22, 2002, the ACC approved APS request (Interim Financing Application) to permit APS to (a) make short-term advances to Pinnacle West in the form of an inter-affiliate line of credit in the amount of $125 million, or (b) guarantee $125 million of Pinnacle Wests short-term debt, subject to certain conditions. As of December 31, 2002, there were no borrowings outstanding under this financing arrangement. On March 27, 2003, the ACC authorized APS to lend up to $500 million to Pinnacle West Energy, guarantee up to $500 million of Pinnacle West Energy debt, or a combination of both, not to exceed $500 million in the aggregate. See Factors Affecting our Financial Outlook - Regulatory Matters and ACC Applications in Note 3 for additional information.

In 2002, the parent company issued $215 million in long-term debt and had no repayments of long-term debt (see Note 6).

The parent companys outstanding long and short-term debt was approximately $887 million at December 31, 2002. At December 31, 2002, our commitments totaled $475 million, which were available to support the issuance of commercial paper or to be used as bank borrowings. At December 31, 2002, we had about $24 million of com-mercial paper outstanding and $72 million of short-term borrowings.

Our long-term debt including current maturities totaled $791 million at December 31, 2002.

27 2002 PNW 27 In mid-2003, we will need to refinance approximately $475 million of parent company indebtedness, including a total of $225 million we expect to borrow under an existing credit facility. We expect that this indebtedness will be repaid through funds borrowed by Pinnacle West Energy from APS under the $500 million financing arrangement recently approved by the ACC.

As part of a multi-employer pension plan sponsored by Pinnacle West, we contribute at least the minimum amount required under IRS regula-tions, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of the fund assets and our pension obligation. We elected to contribute cash to our pension plan in each of the last five years; our minimum required contributions during each of those years was zero. Specifically, we contributed $27 million for 2002, $24 million for 2001, $44 million for 2000, $25 million for 1999 and $14 million for 1998. APS and other subsidiaries fund their share of the pension contribution, of which APS represents approximately 90% of the total funding amounts described above. The assets in the plan are mostly domestic common stocks, bonds and real estate. We currently forecast a pension contribution in 2003 of approximately $50 million, all or part of which may be required.

If the fund performance continues to decline as a result of a continued decline in equity markets, larger contributions may be required in future years.

As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on the 2001 federal consolidated income tax return. The accelerated deduction has resulted in a $200 million reduction in the current income tax liability. In 2002, we received an income tax refund of approximately $115 million related to our 2001 federal consolidated income tax return.

APS APS capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. See Factors Affecting Our Financial Outlook - Regulatory Matters below and Note 3 for discussion of the $500 million financing arrangement between APS and Pinnacle West Energy recently approved by the ACC. See Pinnacle West (Parent Company) above and Note 3 for discussion of a $125 million financing arrangement between APS and Pinnacle West.

APS pays for its capital requirements with cash from operations and, to the extent necessary, external financings. APS has historically paid for its dividends to Pinnacle West with cash from operations.

In 2002, APS issued $375 million in long-term debt, refinanced $90 million in long-term debt and redeemed approximately $247 million in long-term debt (see Note 6). On April 7, 2003, APS will redeem

$33 million of its first mortgage bonds.

APS outstanding debt was approximately $2.2 billion at December 31, 2002. At December 31, 2002, APS had credit commitments from various banks totaling about $250 million, which were available either to support the issuance of commercial paper or to be used as bank borrowings. At December 31, 2002, APS had no outstanding commercial paper or bank borrowings.

Although provisions in APS first mortgage bond indenture, articles of incorporation and ACC financing orders establish maximum amounts of additional first mortgage bonds, debt and preferred stock that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements.

Pinnacle West Energy The costs of Pinnacle West Energys construction of generating capacity from 2000 through 2004 are expected to be about $1.4 billion. This does not reflect an expected reimbursement in 2004 by SNWA of about

$100 million of Pinnacle West Energys cumulative capital expenditures in the Silverhawk project assuming SNWA exercises its option to pur-chase a 25% interest in the project. Pinnacle West Energy is currently funding its capital requirements through capital infusions from Pinnacle West, which finances those infusions through debt and equity financings and internally-generated cash. See the capital expenditures table above for actual capital expenditures in 2002 and projected capital expenditures for the next three years.

See Factors Affecting Our Financial Outlook - Regulatory Matters below and Note 3 for discussion of the $500 million.

Other Subsidiaries During the past three years, SunCor funded its cash requirements with cash from operations and its own external financings. SunCors capital needs consist primarily of capital expenditures for land development and retail and office building construction. See the capital expenditures table above for actual capital expenditures in 2002 and projected capital expenditures for the next three years. SunCor expects to fund its capital requirements with cash from operations and external financings.

In 2002, SunCor issued $50 million in long-term debt, and redeemed, refinanced or repaid $53 million in long-term debt (see Note 6).

SunCors outstanding long and short-term debt was approximately

$153 million as of December 31, 2002. As of December 31, 2002, SunCor had a $140 million line of credit, under which $126 million of borrowings were outstanding. SunCors short-term debt was $6 million and other long-term debt, including current maturities, totaled $21 million at December 31, 2002.

We expect SunCor to make cash distributions to the parent company of

$80 to $100 million annually in 2003 through 2005 due to anticipated accelerated asset sales activity.

28 28 PNW 2002 El Dorado funded its cash requirements during the past three years, primarily for NAC in 2002, with cash infused by the parent company and with cash from operations. El Dorado expects minimal capital require-ments over the next three years and intends to focus on prudently realizing the value of its existing investments. El Dorados long-term debt was approximately $3 million at December 31, 2002 and it had no long-term debt outstanding at December 31, 2001. El Dorados long-term debt increased primarily due to its consolidation of NAC for financial reporting purposes (see Notes 6 and 22).

APS Energy Services cash requirements during the past three years were funded with cash infusions from the parent company. APS Energy Services capital expenditures and other cash requirements are increas-ingly funded by operations, with some funding from cash infused by Pinnacle West. See the capital expenditures table above regarding APS Energy Services actual capital expenditures for 2002 and projected capital expenditures for the next three years.

CRITICAL ACCOUNTING POLICIES In preparing the financial statements in accordance with GAAP, man-agement must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the report-ing period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.

Regulatory Accounting - Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to be reflected in the financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies.

Pensions and Other Postretirement Benefit Accounting - Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit liability and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term.

Derivative Accounting - Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, will determine whether we use accrual accounting or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in fair value be recorded in earnings or, if certain hedge accounting criteria are met, in other comprehensive income.

Mark-to-Market Accounting - The market value of our derivative contracts is not always readily determinable. In some cases, we use models and other valuation techniques to determine fair value. The use of these models and valuation techniques sometimes requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our market-ing and trading portfolio consists of structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions.

See the discussion below for further details on our critical accounting policies.

Regulatory Accounting For our regulated operations, we prepare our financial statements in accordance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. SFAS No. 71 requires a cost-based, rate-regulat-ed enterprise to reflect the impact of regulatory decisions in its financial statements. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies.

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates.

Regulatory liabilities generally represent obligations to make refunds to customers for previous collections of costs not likely to be incurred.

We are required to discontinue applying SFAS No. 71 when deregulatory legislation is passed or a rate order is issued that contains sufficient detail to determine its effect on the portion of the business being deregulated.

In 1999, we discontinued the application of SFAS No. 71 for APS gener-ation operations due to the 1999 Settlement Agreement with the ACC.

See Note 3 for a discussion of the 1999 Settlement Agreement.

In 2002, the ACC directed APS not to transfer its generation assets, as previously required by the 1999 Settlement Agreement (see Track A Order in Note 3). Accordingly, we now consider APS generation to be cost-based, rate-regulated and subject to the requirements of SFAS No. 71. The impact of this change was immaterial to our consolidated financial statements.

Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings. We had $241 million of regulatory assets included on the Consolidated Balance Sheets at December 31, 2002. See Notes 1 and 3 for more information.

Pensions and Other Postretirement Benefit Accounting We sponsor a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for our employees and employees of our subsidiaries. Our reported costs of providing defined pension and other postretirement benefits are dependent upon numer-ous factors resulting from actual plan experience and assumptions of future experience. Pension and other postretirement benefit costs, for

29 2002 PNW 29 example, are impacted by actual employee demographics (including age, compensation levels and employment periods), the level of contri-butions we make to the plans and earnings on plan assets. Changes made to the provisions of the plans may also impact current and future pension and other postretirement benefit costs. Pension and other postretirement benefit costs may also be significantly affected by changes in key actuarial assumptions, including the expected long-term rate of return on plan assets and the discount rates used in determining the projected benefit obligation and pension and other postretirement benefit costs.

Pinnacle Wests pension and other postretirement plan assets are pri-marily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased pension and other postretirement benefit costs in future periods. Likewise, changes in assumptions regarding current discount rates and the expected long-term rate of return on plan assets could also increase or decrease recorded pension and other postretirement benefit costs.

We account for our defined benefit pension plans in accordance with SFAS No. 87, Employers Accounting for Pensions, which requires amounts recognized in our financial statements to be determined on an actuarial basis. Changes in pension obligations associated with these factors may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, signifi-cant portions of pension costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants.

The following chart reflects the sensitivities associated with a one percent increase or decrease in certain actuarial assumptions related to our defined benefit pension plans. Each sensitivity below reflects the impact of changing only that assumption. The chart shows the increase (decrease) each change in assumption would have on the 2002 projected benefit obligation, our 2002 reported pension liability on the Consolidated Balance Sheets and our 2002 reported annual pension expense, after consideration of amounts capitalized or billed to electric plant participants, on the Consolidated Statements of Income (dollars in millions).

Increase/(Decrease)

Impact on Impact on Impact on Projected Benefit Pension Pension Actuarial Assumption Obligation Liability Expense Discount rate:

Increase 1%

(143)

(107)

(4)

Decrease 1%

177 130 9

Expected long-term rate of return on plan assets:

Increase 1%

(4)

Decrease 1%

4 Increase/(Decrease)

Impact on Accumulated Impact on Other Postretirement Postretirement Actuarial Assumption Benefit Obligation Benefit Expense Discount rate:

Increase 1%

(38)

(2)

Decrease 1%

43 2

Health care cost trend rate (a):

Increase 1%

54 5

Decrease 1%

(43)

(4)

Expected long-term rate of return on plan assets - pretax:

Increase 1%

(1)

Decrease 1%

1 (a) This assumes a 1% change in the initial and ultimate health care cost trend rate.

At the end of each year, we determine the discount rate to be used to calculate the present value of plan liabilities. The discount rate is an estimate of the current interest rate at which the pension liabilities could be effectively settled at the end of the year. The discount rate is selected by comparison to current yields on high-quality, long-term bonds. We changed our discount rate assumption from 7.5% at December 31, 2001 to 6.75% at December 31, 2002.

In 2002, we assumed that the expected long-term rate of return on plan assets would be 10%. However, the plan assets have earned a rate of return substantially less than 10% in the last three years due to sharp declines in the equity markets. For 2003, we decreased our expected long-term rate of return on plan assets to 9%, as a result of continued declines in general equity and bond market returns.

The following chart reflects the sensitivities associated with a one per-cent increase or decrease in certain actuarial assumptions related to our other postretirement benefit plans. Each sensitivity below reflects the impact of changing only that assumption. The chart shows the increase (decrease) each change in assumption would have on the 2002 accu-mulated other postretirement benefit obligation and our 2002 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on the Consolidated Statements of Income (dollars in millions).

30 30 PNW 2002 The discount rate is selected by comparison to current yields on high-quality, long-term bonds. We changed our discount rate assumption from 7.5% at December 31, 2001 to 6.75% at December 31, 2002.

In selecting our health care cost trend rate, we consider past perfor-mance and forecasts of health care costs. In 2002, we increased our initial health care cost trend rate to 8% from 7% based on an analysis of our actual plan experience. We also assume an ultimate health care cost trend rate of 5% is reached in 2007.

In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan. The market value of the plan assets has been affected by sharp declines in the equity markets. For 2003, we decreased our pretax expected long-term rate of return on plan assets from 10% to 9%, as a result of continued declines in general equity and bond market returns.

Pension and other postretirement benefit costs and cash funding requirements may increase in future years without a substantial recovery in the equity markets. Due to the actual investment performance of our pension and other postretirement benefit funds and the changes in the actuarial assumptions discussed above, we expect an increase of approximately $29 million before income taxes in 2003 expense over 2002. See Note 8 for further details about our pension and other postretirement benefit plans.

Derivative Accounting We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps.

As part of our risk management program, we enter into derivative trans-actions to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

We examine contracts at inception to determine the appropriate accounting treatment. If a contract does not meet the derivative criteria or if it qualifies for a SFAS No. 133 scope exception, we account for the contract on an accrual basis with associated revenues and costs recorded at the time the contracted commodities are delivered or received. SFAS No. 133 provides a scope exception for contracts that meet the normal purchases and sales criteria specified in the standard.

Most of our non-trading electricity purchase and sales agreements qualify as normal purchases and sales and are exempted from recognition in the financial statements until the electricity is delivered.

For contracts that qualify as a derivative and do not meet a SFAS No. 133 scope exception, we further examine the contract to determine if it will qualify for hedge accounting. Changes in the fair value of the effective portion of derivative instruments that qualify for cash flow hedge account-ing treatment are recognized as either an asset or liability and in common stock equity (as a component of accumulated other comprehensive income (loss)). Gains and losses related to derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earn-ings. If a contract does not meet the hedging criteria in SFAS No. 133, we recognize the changes in the fair value of the derivative instrument in income each period through mark-to-market accounting.

On October 1, 2002, we adopted EITF 02-3, which rescinded EITF 98-10. As a result, our energy trading contracts that are derivatives continue to be accounted for at fair value under SFAS No. 133.

Contracts that were previously marked-to-market as trading activities under EITF 98-10 that do not meet the accounting definition of a deriva-tive are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received. Additionally, all gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Consolidated Statements of Income on a net basis. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading activities, which continue to be accounted for in accordance with SFAS No. 133. See Other Accounting Matters - Accounting for Derivative and Trading Activities below for details on the change in accounting for energy trading contracts. See Note 18 for further discussion on derivative accounting.

Mark-to-Market Accounting Under mark-to-market accounting, the purchase or sale of energy commodities is reflected at fair market value, net of valuation adjust-ments, with resulting unrealized gains and losses recorded as assets and liabilities from risk management and trading activities in the Consolidated Balance Sheets.

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

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

For options, long-term contracts and other contracts for which price quotes are not available, we use models and other valuation methods.

The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. The

31 2002 PNW 31 primary valuation technique we use to calculate the fair value of con-tracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points. We also value option contracts using a variation of the Black-Scholes option-pricing model.

For non-exchange traded contracts, we calculate fair market value based on the average of the bid and offer price, and we discount to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments.

These include valuation adjustments for liquidity and credit risks based on the financial condition of counterparties. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed-out or hedged.

A credit valuation adjustment is also recorded to represent estimated credit losses on our overall exposure to counterparties, taking into account netting arrangements; expected default experience for the credit rating of the counterparties; and the overall diversification of the portfolio. Counterparties in the portfolio consist principally of major energy companies, municipalities and local distribution companies.

We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. See Factors Affecting our Financial Outlook - Market Risks - Commodity Price Risk below and Note 18 for further discussion on credit risk.

The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our marketing and trading portfolio includes structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. To illustrate, as presented in the Factors Affecting our Financial Outlook - Market Risks - Commodity Price Risk section below, a 10% increase in the price of trading commodities would result in only a $2 million decrease in pretax income. Our practice is to hedge within timeframes established by the ERMC.

OTHER ACCOUNTING MATTERS Accounting for Derivative and Trading Activities During 2002, the EITF discussed EITF 02-3 and reached a consensus on certain issues. EITF 02-3 rescinded EITF 98-10 and was effective October 25, 2002 for any new contracts, and on January 1, 2003 for existing contracts, with early adoption permitted. We adopted the EITF 02-3 guidance for all contracts in the fourth quarter of 2002. We recorded a $66 million after-tax charge in net income as a cumulative effect adjustment for the previously recorded accumulated unrealized mark-to-market on energy trading contracts that did not meet the accounting definition of a derivative. As a result, our energy trading contracts that are derivatives continue to be accounted for at fair value under SFAS No. 133. Contracts that were previously marked-to-market as trading activities under EITF 98-10 that do not meet the definition of a derivative are now accounted for on an accrual basis with the associ-ated revenues and costs recorded at the time the contracted commodi-ties are delivered or received. Additionally, all gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Consolidated Statements of Income on a net basis. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading activities, which continue to be accounted for in accordance with SFAS No. 133.

EITF 02-3 requires that derivatives held for trading purposes, whether settled financially or physically, be reported in the income statement on a net basis. Previous guidance under EITF 98-10 permitted physically settled energy trading contracts to be reported either gross or net in the income statement. Beginning in the third quarter of 2002, we netted all of our energy trading activities on the Consolidated Statements of Income and restated prior year amounts for all periods presented.

Reclassification of such trading activity to a net basis of reporting resulted in reductions in both revenues and purchased power and fuel costs, but did not have any impact on our financial condition, results of operations or cash flows.

In 2001, we adopted SFAS No. 133 and recorded a $15 million after-tax charge in net income and a $72 million after-tax credit in common stock equity (as a component of other comprehensive income), both as a cumulative effect of a change in accounting for derivatives. See Notes 1 and 18 for further information on accounting for derivatives under SFAS No. 133.

Asset Retirement Obligations On January 1, 2003 we adopted SFAS No. 143, Accounting for Asset Retirement Obligations. The standard requires the fair value of asset retirement obligations to be recorded as a liability, along with an offsetting plant asset, when the obligation is incurred. Accretion of the liability due to the passage of time will be an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. (See Note 1 for more information regarding our previous accounting for removal costs.)

We determined that we have asset retirement obligations for our nuclear facilities (nuclear decommissioning) and certain other generation, trans-mission and distribution assets. On January 1, 2003 we recorded a liability of $219 million for our asset retirement obligations including the accretion impacts; a $67 million increase in the carrying amount of the associated assets; and a net reduction of $192 million in accumulated depreciation related primarily to the reversal of previously recorded accumulated decommissioning and other removal costs related to these

32 32 PNW 2002 obligations. Additionally, we recorded a regulatory liability of $40 million for our asset retirement obligations related to our regulated utility. This regulatory liability represents the difference between the amount currently being recovered in regulated rates and the amount calculated under SFAS No. 143. We believe we can recover in regulated rates the transition costs and ongoing current period costs calculated in accordance with SFAS No. 143.

Stock-Based Compensation In the third quarter of 2002, we began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123, Accounting for Stock-Based Compensation. We recorded approximately $500,000 in stock option expense before income taxes in our Consolidated Statements of Income for 2002. See Notes 1 and 16 for further information on the impacts of adopting the fair value method provided in SFAS No. 123.

Variable Interest Entities See Liquidity and Capital Resources - Off Balance Sheet Arrange-ments and Note 20 for discussion of VIEs.

Other See Note 2 for discussion of other new accounting standards that are not expected to have a material impact on the Company.

FACTORS AFFECTING OUR FINANCIAL OUTLOOK Regulatory Matters GENERAL On September 21, 1999, the ACC approved Rules that provide a frame-work for the introduction of retail electric competition in Arizona. On September 23, 1999, the ACC approved a comprehensive settlement agreement among APS and various parties related to the implementation of retail electric competition in Arizona. Under the Rules, as modified by the 1999 Settlement Agreement, APS was required to transfer all of its competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates no later than December 31, 2002. Consistent with that requirement, APS had been addressing the legal and regulatory requirements necessary to complete the transfer of its generation assets to Pinnacle West Energy on or before that date. On September 10, 2002, the ACC issued the Track A Order which, among other things, directed APS not to transfer its generation assets to Pinnacle West Energy.

1999 SETTLEMENT AGREEMENT The 1999 Settlement Agreement has affected, and will affect, our results of operations. As part of the 1999 Settlement Agreement, APS agreed to reduce retail electricity prices for standard-offer, full-service customers with loads less than three megawatts in a series of annual decreases of 1.5%

on July 1, 1999 through July 1, 2003, for a total of 7.5%. For customers with loads three megawatts or greater, standard-offer rates were reduced in annual increments totaling 5% in the years 1999 through 2002.

The 1999 Settlement Agreement also removed, as a regulatory disal-lowance, $234 million before income taxes ($183 million net present value) from ongoing regulatory cash flows. APS recorded this regulatory disallowance as a net reduction of regulatory assets and reported it as a $140 million after-tax extraordinary charge on the 1999 Consolidated Statement of Income. As discussed under APS General Rate Case below, APS intends to seek recovery of this $234 million write-off in its next general rate case.

Prior to the 1999 Settlement Agreement, the ACC accelerated the amortization of substantially all of APS regulatory assets to an eight-year period that would have ended June 30, 2004. The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions):

See Note 3 for additional information regarding the 1999 Settlement Agreement.

APS FINANCING APPLICATION On September 16, 2002, APS filed an application with the ACC request-ing the ACC to allow APS to borrow up to $500 million and to lend the proceeds to Pinnacle West Energy or to the Company; to guarantee up to

$500 million of Pinnacle West Energys or the Companys debt; or a com-bination of both, not to exceed $500 million in the aggregate. In its appli-cation, APS stated that the ACCs reversal of the generation asset transfer requirement and the resulting bifurcation of generation assets between APS and Pinnacle West Energy under different regulatory regimes result in Pinnacle West Energy being unable to attain investment-grade credit rat-ings. This, in turn, precludes Pinnacle West Energy from accessing capital markets to refinance the bridge financing that we provided to fund the construction of Pinnacle West Energy generation assets or from effectively competing in the wholesale markets. On March 27, 2003, the ACC autho-rized APS to lend up to $500 million to Pinnacle West Energy, guarantee up to $500 million of Pinnacle West Energy debt, or a combination of both, not to exceed $500 million in the aggregate. See ACC Applications in Note 3 for further discussion of the approval and related conditions.

TRACK A ORDER On September 10, 2002, the ACC issued the Track A Order. See Track A Order in Note 3.

COMPETITIVE PROCUREMENT PROCESS On September 10, 2002, the ACC issued an order that, among other things, established a requirement that APS competitively procure certain power requirements. On March 14, 2003, the ACC issued the Track B Order which documented the decision made by the ACC at its open meeting on February 27, 2003 addressing this requirement. Under the ACCs Track B Order, APS will be required to solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. For 2003, APS will be required to solicit competitive bids 1999 2000 2001 2002 2003 2004 TOTAL

$164

$158

$145

$115

$86

$18

$686

33 2002 PNW 33 for about 2,500 MW of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of APS total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in APS retail load and APS retail energy sales. The Track B Order also confirmed that it was not intended to change the current rate base status of [APS] existing assets. The order recognizes APS right to reject any bids that are unreasonable, uneconomical or unreliable.

APS expects to issue requests for proposals in March 2003 and to com-plete the selection process by June 1, 2003. Pinnacle West Energy will be eligible to bid to supply APS electricity requirements. See Track B Order in Note 3 for additional information.

APS GENERAL RATE CASE As required by the 1999 Settlement Agreement, on or before June 30, 2003, APS will file a general rate case with the ACC. In this rate case, APS will update its cost of service and rate design. In addition, APS expects to seek:

rate base treatment of certain power plants currently owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3);

recovery of the $234 million pretax asset write-off recorded by APS as part of the 1999 Settlement Agreement ($140 million extraordinary charge recorded on the 1999 Consolidated Statement of Income); and recovery of costs incurred by APS in preparation for the previously required transfer of generation assets to Pinnacle West Energy.

We assume that the ACC will make a decision in this general rate case by the end of 2004.

WHOLESALE POWER MARKET CONDITIONS The marketing and trading division, which we moved to APS in early 2003 for future marketing and trading activities (existing wholesale contracts will remain at Pinnacle West) as a result of the ACCs Track A Order prohibiting APS transfer of generating assets to Pinnacle West Energy, focuses primarily on managing APS purchased power and fuel risks in connection with its costs of serving retail customer demand.

Additionally, the marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels and emis-sion allowances and credits. Earnings contributions from our marketing and trading division were lower in 2002 compared to 2001 due to weak wholesale power market conditions in the western United States, which included a lack of market liquidity, fewer creditworthy counterparties, lower wholesale market prices and resulting decreases in sales volumes.

Our 2003 earnings will be affected by the strength (or weakness) of the wholesale power market.

GENERATION CONSTRUCTION See Capital Needs and Resources - Pinnacle West Energy above and Note 11 for information regarding Pinnacle West Energys generation construction program. The planned additional generation is expected to increase revenues, fuel expenses, operating expenses and financing costs.

FACTORS AFFECTING OPERATING REVENUES General 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 rev-enues are expected to be affected by electricity sales volumes related to customer mix, customer growth and average usage per customer, as well as electricity prices and variations in weather from period to period.

Competitive sales of energy and energy-related products and services are made by APS Energy Services in western states that have opened to competitive supply.

Customer Growth Customer growth in APS service territory averaged about 3.6% a year for the three years 2000 through 2002; we currently expect customer growth to average about 3.5% per year from 2003 to 2005. We currently estimate that retail electricity sales in kilowatt-hours will grow 3.5% to 5.5% a year in 2003 through 2005, before the retail effects of weather variations. The customer growth and sales growth referred to in this paragraph applies to energy delivery customers. As previously noted, under the 1999 Settlement Agreement, we agreed to retail electricity price reductions of 1.5% annually through July 1, 2003 (see Note 3).

OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS Purchased Power and Fuel Costs Purchased power and fuel costs are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, prevailing market prices, new generating plants being placed in service and our hedging program for managing such costs.

Operations and Maintenance Expenses Operations and maintenance expenses are expected to be affected by sales mix and volumes, power plant additions and operations, inflation, outages, higher trending pension and other postretirement benefit costs and other factors. In July 2002, we implemented a voluntary workforce reduction as part of our cost reduction program. We recorded $36 million before taxes in voluntary severance costs in the second half of 2002. In addition, we are expecting to pro-duce annual operating expense savings of approximately $30 million beginning in 2003 as a result of this workforce reduction.

Depreciation and Amortization Expenses Depreciation and amortiza-tion expenses are expected to be affected by net additions to existing utility plant and other property, changes in regulatory asset amortization and our generation construction program. West Phoenix Unit 4 was placed in service in June 2001. Redhawk Units 1 and 2 and the new Saguaro Unit 3 began commercial operations in July 2002. West Phoenix Unit 5 is expected to be on line in mid-2003 and Silverhawk is expected to be in service in mid-2004 (see Note 11 for further details about our generation construction program). The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions):

1999 2000 2001 2002 2003 2004 TOTAL

$164

$158

$145

$115

$86

$18

$686

34 34 PNW 2002 EXPECTED MATURITY/PRINCIPAL REPAYMENT (dollars in thousands)

Short-Term Debt Variable-Rate Long-Term Debt Fixed-Rate Long-Term Debt Interest Interest Interest December 31, 2002 Rates Amount Rates Amount Rates Amount 2003 2.59%

102,183 2.68%

250,800 6.73%

30,223 2004 3.76%

126,813 5.32%

424,697 2005 3.39%

1,294 7.27%

403,931 2006 10.10%

2,954 6.47%

387,018 2007 8.00%

209 6.04%

2,738 Years thereafter 2.00%

390,537 6.08%

1,148,371 Total 102,183 772,607

$ 2,396,978 Fair Value 102,183 772,607

$ 2,501,073 The tables below present contractual balances of our consolidated long-term debt and commercial paper at the expected maturity dates as well as the fair value of those instruments on December 31, 2002 and 2001. The interest rates presented in the tables below represent the weighted-average interest rates for the years ended December 31, 2002 and 2001.

Property Taxes Taxes other than income taxes consist primarily of property taxes, which are affected by tax rates and the value of property in-service and under construction. The average property tax rate for APS, which currently owns the majority of our property, was 9.7% of assessed value for 2002 and 9.3% for 2001. We expect property taxes to increase primarily due to our generation construction program and our additions to existing facilities.

Interest Expense Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels in the next several years are expected to be our capital requirements and our internally-generated cash flow.

Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop recording capitalized interest on a project when it is placed in commercial operation. As noted above, we have placed new power plants in commercial operation in 2001 and 2002 and we expect to bring additional plants on-line in 2003 and 2004. We are continuing to evaluate our generation construction program. Interest expense is affected by interest rates on variable-rate debt and interest rates on the refinancing of the Companys future liquidity needs.

Retail Competition The regulatory developments and legal challenges to the Rules discussed in Note 3 have raised considerable uncertainty about the status and pace of retail electric competition in Arizona.

Although some very limited retail competition existed in APS service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS customers.

As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS service territory.

Subsidiaries In the case of SunCor, we are undertaking an aggressive effort to accelerate asset sales activities to approximately double SunCors annual earnings in 2003 to 2005 compared to the $19 million in earnings recorded in 2002. A portion of these sales could be reported as discon-tinued operations on the Consolidated Statements of Income.

The annual earnings contribution from APS Energy Services is expected to be positive over the next several years due primarily to a number of retail electricity contracts in California. APS Energy Services had pretax earnings of $28 million in 2002.

El Dorados historical results are not necessarily indicative of future performance for El Dorado. El Dorados strategies focus on prudently realizing the value of its existing investments.

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

Market Risks Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by the nuclear decommissioning trust fund and our pension plans.

INTEREST RATE AND EQUITY RISK Our major financial market risk exposure is changing interest rates.

Changing interest rates will affect interest paid on variable-rate debt and interest earned by our pension plan (see Note 8) and nuclear decom-missioning trust fund (see Note 12). Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. The pension plan and nuclear decommissioning fund also have risks associated with changing market values of equity investments.

Pension (APS only) and nuclear decommissioning costs are recovered in regulated electricity prices. See Critical Accounting Policies -

Pension and Other Postretirement Benefit Accounting for a sensitivity analysis on the long-term rate of return on plan assets.

35 2002 PNW 35 EXPECTED MATURITY/PRINCIPAL REPAYMENT (dollars in thousands)

Short-Term Debt Variable-Rate Long-Term Debt Fixed-Rate Long-Term Debt Interest Interest Interest December 31, 2001 Rates Amount Rates Amount 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 COMMODITY PRICE RISK We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options, and over-the-counter forwards, options and swaps. The ERMC, consisting of senior officers, oversees company-wide energy risk management activities and monitors the results of marketing and trading activities to ensure compliance with our stated energy-risk management and trading policies. As part of our risk management program, we enter into derivative transactions to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

Prior to October 1, 2002, we accounted for our energy trading con-tracts at fair value in accordance with EITF 98-10. On October 1, 2002, we adopted EITF 02-3, which rescinded EITF 98-10. As a result, our energy trading contracts that are derivatives continue to be accounted for at fair value under SFAS No. 133. Contracts that were previously marked to market as trading activities under EITF 98-10 that do not meet the definition of a derivative are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received. Additionally, all gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Consolidated Statements of Income on a net basis.

The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading activities, which continue to be accounted for in accordance with SFAS No. 133. See Note 18 for details on the change in accounting for energy trading contracts and further discussion regarding derivative accounting.

Both non-trading and trading derivatives are classified as assets and lia-bilities from risk management and trading activities in the Consolidated Balance Sheets. For non-trading derivative instruments that qualify for hedge accounting treatment, changes in the fair value of the effective portion are recognized in common stock equity (as a component of accumulated other comprehensive income (loss)). Non-trading deriva-tives, or any portion thereof, that are not effective hedges are adjusted to fair value through income. Gains and losses related to non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted transaction will not occur, we discontinue the use of hedge accounting and recognize in income the unrealized gains and losses that were previously recorded in other comprehensive income (loss). In the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain in other comprehensive income (loss), and are recognized in income when the underlying transaction impacts earnings.

Derivatives associated with trading activities are adjusted to fair value through income. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business are exempt from the requirements of SFAS No. 133 under the normal purchase and sales exception and are not reflected on the balance sheet at fair value. Most of our non-trading electricity purchase and sales agreements qualify as normal purchases and sales and are exempted from recognition in the financial statements until the electricity is delivered.

Our assets and liabilities from risk management and trading activities are presented in two categories consistent with our business segments:

System - our regulated electricity business segment, which consists of non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for our Native Load requirements; and Marketing and Trading - our non-regulated, competitive business segment, which includes both non-trading and trading derivative instruments.

36 36 PNW 2002 The following tables show the changes in mark-to-market of our system and marketing and trading derivative positions in 2002 and 2001 (dollars in millions):

Marketing System and Trading Mark-to-market of net positions at December 31, 2001 (107) 138 Cumulative effect adjustment due to adoption of EITF 02-3 (109)

Change in mark-to-market gains for future period deliveries (13) 47 Changes in cash flow hedges recorded in OCI 57 16 Ineffective portion of changes in fair value recorded in earnings 11 Mark-to-market losses/(gains) realized during the year 3

(38)

Change in valuation techniques 3

Mark-to-market of net positions at December 31, 2002 (49) 57 Marketing System and Trading Mark-to-market of net positions at December 31, 2000 12 Cumulative effect adjustment due to adoption of SFAS No. 133 95 Change in mark-to-market (losses)/gains for future period deliveries (12) 203 Changes in cash flow hedges recorded in OCI (166)

Ineffective portion of changes in fair value recorded in earnings (6)

Mark-to-market gains realized during the year (18)

(77)

Change in valuation techniques Mark-to-market of net positions at December 31, 2001 (107) 138 The Company no longer reports non-derivative energy contracts or physical inventories at fair value. Since July 1, 2002, the Company has not recognized a dealer profit or unrealized gain or loss at the inception of a derivative unless the fair value of that instrument (in its entirety) is evidenced by quoted market prices or current market transactions.

Prior to the change in our policy, we recorded net gains at inception of

$10 million in 2002 and $3 million in 2001. These amounts included a reasonable marketing margin.

The tables below show the maturities of our system and marketing and trading derivative positions at December 31, 2002 by the type of valuation that is performed to calculate the fair value of the contract (dollars in millions). See Critical Accounting Policies - Mark-to-Market Accounting above for more discussion on our valuation methods.

SYSTEM Total Years Fair Source of Fair Value 2003 2004 2005 2006 2007 Thereafter Value Prices actively quoted (23)

(10)

(33)

Prices provided by other external sources (1)

(12)

(13)

Prices based on models and other valuation methods (1)

(2)

(3)

Total by maturity (25)

(24)

(49)

MARKETING AND TRADING Total Years Fair Source of Fair Value 2003 2004 2005 2006 2007 Thereafter Value Prices actively quoted (1) 5 6

3 3

7 23 Prices provided by other external sources 2

8 9

12 31 Prices based on models and other valuation methods 6

3 (3)

(4) 5 (4) 3 Total by maturity 7

16 12 11 8

3 57

37 2002 PNW 37 The table below shows the impact hypothetical price movements of 10% would have on the market value of our risk management and trading assets and liabilities included on the Consolidated Balance Sheets at December 31, 2002 and 2001 (dollars in millions).

December 31, 2002 December 31, 2001 Gain (Loss)

Gain (Loss)

Price Up Price Down Price Up Price Down Commodity 10%

10%

10%

10%

Mark-to-market changes reported in earnings (a):

Electricity (2) 3 (3) 3 Natural gas (4) 4 (1) 1 Other 1

2 Mark-to-market changes reported in OCI (b):

Electricity 32 (32)

Natural gas 18 (16) 23 (23)

Total 45 (41) 19 (17)

(a) These contracts are structured sales activities 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 and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.

CREDIT RISK We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including two counterparties for which a worst case exposure represents approximately 33% of our $181 million of risk man-agement and trading assets as of December 31, 2002. Our risk manage-ment process assesses and monitors the financial exposure of these and all other counterparties. Despite the fact that the great majority of trading counterparties are rated as investment grade by the credit rating agencies, including the counterparties noted above, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. In many contracts, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are estab-lished representing our estimated credit losses on our overall exposure to counterparties. See Critical Accounting Policies - Mark-to-Market Accounting above for a discussion of our credit valuation adjustment policy.

FORWARD-LOOKING STATEMENTS The above discussion contains forward-looking statements based on cur-rent expectations and we assume no obligation to update these state-ments or make any further statements on any of these issues, except as required by applicable laws. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by us. These factors include the ongoing restructuring of the electric industry, including the introduction of retail electric competi-tion in Arizona and decisions impacting wholesale competition; the out-come of regulatory and legislative proceedings relating to the restructuring; state and federal regulatory and legislative decisions and actions, including price caps and other market constraints imposed by the FERC; regional economic and market conditions, including the California energy situation and completion of generation and transmission construc-tion in the region, which could affect customer growth and the cost of power supplies; the cost of debt and equity capital and access to capital markets; weather variations affecting local and regional customer energy usage; the effect of conservation programs on energy usage; power plant performance; the successful completion of our generation construction program; regulatory issues associated with generation construction, such as permitting and licensing; our ability to compete successfully outside traditional regulated markets (including the wholesale market); our ability to manage our marketing and trading activities and the use of derivative contracts in our business; technological developments in the electric industry; the performance of the stock market, which affects the amount of our required contributions to our pension plan and nuclear decommis-sioning trust funds; the strength of the real estate market in SunCors market areas, which include Arizona, New Mexico and Utah; and other uncertainties, all of which are difficult to predict and many of which are beyond our control.

38 38 PNW 2002 To the Board of Directors and Stockholders of Pinnacle West Capital Corporation Phoenix, Arizona We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the Corporation) as of December 31, 2002 and 2001 and the related consolidated statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2002.

These financial statements are the responsibility of the Corporations management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.

An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Pinnacle West Capital INDEPENDENT AUDITORS REPORT Corporation and subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 18 to the consolidated financial statements, in 2002 Pinnacle West Capital Corporation changed its method of accounting for trading activities in order to comply with the provisions of Emerging Issues Task Force Issue 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.

As discussed in Note 18 to the consolidated financial statements, in 2001 Pinnacle West Capital Corporation changed its method of accounting for derivatives and hedging activities in order to comply with the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities.

DELOITTE & TOUCHE LLP Phoenix, Arizona February 3, 2003 (March 4, 14, 26, and 27, 2003 as to Note 24)

39 2002 PNW 39 CONSOLIDATED STATEMENTS OF INCOME (dollars and shares in thousands, except per share amounts) year ended December 31, 2002 2001 2000 OPERATING REVENUES Regulated electricity segment 2,013,023 2,562,089 2,538,752 Marketing and trading segment 325,931 651,230 418,532 Real estate segment 236,388 168,908 158,365 Other revenues 61,937 11,771 3,873 Total 2,637,279 3,393,998 3,119,522 OPERATING EXPENSES Regulated electricity segment purchased power and fuel 499,543 1,160,863 1,065,597 Marketing and trading segment purchased power and fuel 194,039 334,209 292,669 Operations and maintenance 584,538 530,095 450,205 Real estate operations segment 205,315 153,462 134,422 Depreciation and amortization 424,886 427,903 431,229 Taxes other than income taxes 107,952 101,068 99,780 Other expenses 104,959 10,375 782 Total 2,121,232 2,717,975 2,474,684 OPERATING INCOME 516,047 676,023 644,838 OTHER Other income 15,104 26,416 21,832 Other expenses (33,655)

(33,577)

(25,329)

Total (18,551)

(7,161)

(3,497)

INTEREST EXPENSE Interest charges 188,353 175,822 166,447 Capitalized interest (44,110)

(47,862)

(21,638)

Total 144,243 127,960 144,809 INCOME BEFORE INCOME TAXES 353,253 540,902 496,532 INCOME TAXES 138,100 213,535 194,200 INCOME BEFORE ACCOUNTING CHANGE 215,153 327,367 302,332 Cumulative effect of a change in accounting for derivatives -

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

Cumulative effect of a change in accounting for trading activities -

net of income taxes of $43,123 (65,745)

NET INCOME 149,408 312,166 302,332 WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC 84,903 84,718 84,733 WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED 84,964 84,930 84,935 EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING Income before accounting change - basic 2.53 3.86 3.57 Net income - basic 1.76 3.68 3.57 Income before accounting change - diluted 2.53 3.85 3.56 Net income - diluted 1.76 3.68 3.56 DIVIDENDS DECLARED PER SHARE 1.625 1.525 1.425 See Notes to Consolidated Financial Statements.

40 40 PNW 2002 CONSOLIDATED BALANCE SHEETS (dollars in thousands)

December 31, 2002 2001 ASSETS CURRENT ASSETS Cash and cash equivalents 77,707 28,619 Customer and other receivables - net 374,995 367,241 Accrued utility revenues 72,915 76,131 Materials and supplies (at average cost) 91,652 81,215 Fossil fuel (at average cost) 28,185 27,023 Deferred income taxes (Note 4) 4,094 Assets from risk management and trading activities (Note 18) 59,162 66,973 Other current assets 103,978 80,203 Total current assets 812,688 727,405 INVESTMENTS AND OTHER ASSETS Real estate investments - net (Notes 1 and 6) 425,331 418,673 Assets from risk management and trading activities - long-term (Note 18) 122,336 200,351 Other assets 229,891 304,453 Total investments and other assets 777,558 923,477 PROPERTY, PLANT AND EQUIPMENT (NOTES 1, 6, 9 AND 10)

Plant in service and held for future use 9,058,900 8,030,847 Less accumulated depreciation and amortization 3,474,325 3,290,097 Total 5,584,575 4,740,750 Construction work in progress 777,542 1,047,072 Intangible assets, net of accumulated amortization (Note 21) 109,815 86,782 Nuclear fuel, net of accumulated amortization of $102,821 and $99,185 7,466 6,933 Net property, plant and equipment 6,479,398 5,881,537 DEFERRED DEBITS Regulatory assets (Notes 1, 3 and 4) 241,045 342,383 Other deferred debits 115,117 64,597 Total deferred debits 356,162 406,980 TOTAL ASSETS 8,425,806 7,939,399 See Notes to Consolidated Financial Statements.

41 2002 PNW 41 CONSOLIDATED BALANCE SHEETS (dollars in thousands)

December 31, 2002 2001 LIABILITIES AND EQUITY CURRENT LIABILITIES Accounts payable 356,305 269,124 Accrued taxes 71,109 96,729 Accrued interest 53,018 48,806 Short-term borrowings (Note 5) 102,183 405,762 Current maturities of long-term debt (Note 6) 281,023 126,140 Customer deposits 55,838 30,232 Deferred income taxes (Note 4) 3,244 Liabilities from risk management and trading activities (Note 18) 70,667 35,994 Other current liabilities 64,972 69,475 Total current liabilities 1,055,115 1,085,506 LONG-TERM DEBT LESS CURRENT MATURITIES (NOTE 6) 2,881,695 2,673,078 DEFERRED CREDITS AND OTHER Liabilities from risk management and trading activities - long-term (Note 18) 75,642 207,576 Deferred income taxes (Note 4) 1,209,074 1,064,993 Unamortized gain - sale of utility plant (Note 9) 59,484 64,060 Pension liability (Note 8) 183,880 49,032 Other 274,763 295,831 Total deferred credits and other 1,802,843 1,681,492 COMMITMENTS AND CONTINGENCIES (NOTES 3, 11 AND 12)

COMMON STOCK EQUITY (NOTE 7)

Common stock, no par value; authorized 150,000,000 shares; issued 91,379,947 at end of 2002 and 84,824,947 at end of 2001 1,737,258 1,536,924 Treasury stock; 124,830 shares at end of 2002 and 101,307 shares at end of 2001 (4,358)

(5,886)

Total common stock 1,732,900 1,531,038 Accumulated other comprehensive loss:

Minimum pension liability adjustment (71,264)

(966)

Derivative instruments (20,020)

(63,599)

Total accumulated other comprehensive loss (91,284)

(64,565)

Retained earnings 1,044,537 1,032,850 Total common stock equity 2,686,153 2,499,323 TOTAL LIABILITIES AND EQUITY 8,425,806 7,939,399 See Notes to Consolidated Financial Statements.

42 42 PNW 2002 CONSOLIDATED STATEMENTS OF CASH FLOWS (dollars in thousands) year ended December 31, 2002 2001 2000 CASH FLOWS FROM OPERATING ACTIVITIES Income before accounting change 215,153 327,367 302,332 Items not requiring cash:

Depreciation and amortization 424,886 427,903 431,229 Nuclear fuel amortization 31,185 28,362 30,083 Deferred income taxes 196,324 (17,203)

(37,885)

Change in mark-to-market (18,146)

(133,573)

(11,752)

Redhawk Units 3 and 4 cancellation 49,192 Changes in current assets and liabilities:

Customer and other receivables 18,615 146,581 (269,223)

Materials, supplies and fossil fuel (11,599)

(16,867) 475 Other current assets (9,784)

(1,276)

(39,083)

Accounts payable 74,833 (127,782) 193,502 Accrued taxes (36,039) 7,483 18,736 Accrued interest 4,212 5,852 9,701 Other current liabilities 17,489 5,260 98,493 Change in real estate investments (6,112)

(44,173)

(25,937)

Increase in regulatory assets (11,029)

(17,516)

(14,138)

Change in risk management and trading - assets (11,700)

(51,894)

Changes in risk management and trading - liabilities (22,783) 45,330 13,834 Change in customer advances (23,780) 28,599 2,544 Change in pension liability (1,571)

(28,347)

(16,575)

Change in long-term assets (16,918) 13,874 54,829 Change in long-term liabilities 8,346 (26,937)

(27,771)

Net cash flow provided by operating activities 870,774 571,043 713,394 CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (895,522)

(1,055,574)

(658,608)

Capitalized interest (44,110)

(47,862)

(21,638)

Other 36,635 (16,481)

(55,595)

Net cash flow used for investing activities (902,997)

(1,119,917)

(735,841)

CASH FLOWS FROM FINANCING ACTIVITIES Issuance of long-term debt 725,419 995,447 651,000 Short-term borrowings and payments - net (303,579) 322,987 44,475 Dividends paid on common stock (137,721)

(129,199)

(120,733)

Repayment of long-term debt (404,670)

(621,057)

(558,019)

Common stock equity issuance 199,238 Other 2,624 (1,048)

(4,618)

Net cash flow provided by financing activities 81,311 567,130 12,105 NET CASH FLOW 49,088 18,256 (10,342)

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 28,619 10,363 20,705 CASH AND CASH EQUIVALENTS AT END OF YEAR 77,707 28,619 10,363 Supplemental disclosure of cash flow information Cash paid during the period for:

Income taxes paid/(refunded) (Note 4)

(17,918) 223,037 219,411 Interest paid, net of amounts capitalized 126,322 115,276 132,434 See Notes to Consolidated Financial Statements.

43 2002 PNW 43 CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (dollars in thousands) for the years ended December 31, 2002 2001 2000 COMMON STOCK (NOTE 7)

Balance of beginning of year 1,536,924 1,537,920 1,540,197 Issuance of common stock 199,238 Other 1,096 (996)

(2,277)

Balance at end of year 1,737,258 1,536,924 1,537,920 TREASURY STOCK (NOTE 7)

Balance at beginning of year (5,886)

(5,089)

(2,748)

Purchase of treasury stock (5,971)

(16,393)

(12,968)

Reissuance of treasury stock used for stock compensation, net 7,499 15,596 10,627 Balance at end of year (4,358)

(5,886)

(5,089)

RETAINED EARNINGS Balance at beginning of year 1,032,850 849,883 668,284 Net income 149,408 312,166 302,332 Common stock dividends (137,721)

(129,199)

(120,733)

Balance at end of year 1,044,537 1,032,850 849,883 ACCUMULATED OTHER COMPREHENSIVE LOSS Balance at beginning of year (64,565)

Minimum pension liability adjustment, net of tax of $46,109 and $634 (70,298)

(966)

Cumulative effect of a change in accounting for derivatives, net of tax of $47,404 72,274 Unrealized gain/(loss) on derivative instruments, net of tax of $28,820 and $71,720 43,939 (109,346)

Reclassification of realized gain to income, net of tax of $237 and $17,399 (360)

(26,527)

Balance at end of year (91,284)

(64,565)

TOTAL COMMON STOCK EQUITY 2,686,153 2,499,323 2,382,714 COMPREHENSIVE INCOME Net income 149,408 312,166 302,332 Other comprehensive loss (26,719)

(64,565)

Comprehensive income 122,689 247,601 302,332 See Notes to Consolidated Financial Statements.

44 44 PNW 2002

1.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES Consolidation and Nature of Operations The consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and El Dorado (principally NAC). Significant intercom-pany accounts and transactions between the consolidated companies have been eliminated.

APS is an electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major excep-tions of the Tucson metropolitan area and about half of the Phoenix metropolitan area. Electricity is delivered through a distribution system owned by APS. APS also generates, sells and delivers electricity to wholesale customers in the western United States. In early 2003, the marketing and trading division of Pinnacle West was moved to APS for future marketing and trading activities (existing wholesale contracts will remain at Pinnacle West) as a result of the ACCs Track A Order prohibit-ing the previously required transfer of APS generating assets to Pinnacle West Energy. See Note 3 for a discussion of the Track A Order. Pinnacle West Energy, which was formed in 1999, is the subsidiary through which we conduct our competitive generation operations. APS Energy Services was formed in 1998 and provides competitive commodity energy and energy-related products to key customers in competitive markets in the western United States. SunCor is a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico and Utah. El Dorado is an investment firm, and its principal investment is in NAC, which is a company specializing in spent nuclear fuel technology.

Accounting Records and Use of Estimates Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (GAAP).

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. We have reclassified certain prior year amounts to conform to the current year presentation.

Derivative Accounting We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal and emissions allow-ances. We manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we enter into derivative transac-tions to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

We examine contracts at inception to determine the appropriate accounting treatment. If a contract does not meet the derivative criteria or if it qualifies for a SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, scope exception, we account for the contract on an accrual basis with associated revenues and costs recorded at the time the contracted commodities are delivered or received. SFAS No. 133 provides a scope exception for contracts that meet the normal purchases and sales criteria specified in the standard. Most of our non-trading electricity purchase and sales agree-ments qualify as normal purchases and sales and are exempted from recognition in the financial statements until the electricity is delivered.

For contracts that qualify as a derivative and do not meet a SFAS No.

133 scope exception, we further examine the contract to determine if it will qualify for hedge accounting. Changes in the fair value of the effec-tive portion of derivative instruments that qualify for cash flow hedge accounting treatment are recognized as either an asset or liability and in common stock equity (as a component of accumulated other compre-hensive income (loss)). Gains and losses related to derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If a contract does not meet the hedging criteria in SFAS No. 133, we recognize the changes in the fair value of the derivative instrument in income each period through mark-to-market accounting.

On October 1, 2002, we adopted EITF 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, which rescinded EITF 98-10. As a result, our energy trading contracts that are derivatives continue to be accounted for at fair value under SFAS No. 133. Contracts that were previously marked-to-market as trading activities under EITF 98-10 that do not meet the definition of a derivative are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received. Additionally, all gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in mar-keting and trading segment revenues on the Consolidated Statements of Income on a net basis. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading activities, which continue to be accounted for in accordance with SFAS No. 133.

See Note 18 for more details on the change in accounting for energy trading contracts and for further discussion on derivative accounting.

Mark-to-Market Accounting Under mark-to-market accounting, the purchase or sale of energy commodities is reflected at fair market value, net of valuation adjust-ments, with resulting unrealized gains and losses recorded as assets NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2002 PNW 45 and liabilities from risk management and trading activities in the Consolidated Balance Sheets.

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

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

For options, long-term contracts and other contracts for which price quotes are not available, we use models and other valuation methods.

The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. The primary valuation technique we use to calculate the fair value of con-tracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points. We also value option contracts using a variation of the Black-Scholes option-pricing model.

For non-exchange traded contracts, we calculate fair market value based on the average of the bid and offer price, and we discount to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments.

These include valuation adjustments for liquidity and credit risks based on the financial condition of counterparties. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed-out or hedged.

A credit valuation adjustment is also recorded to represent estimated credit losses on our overall exposure to counterparties, taking into account netting arrangements; expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio.

Counterparties in the portfolio consist principally of major energy compa-nies, municipalities and local distribution companies. We maintain credit policies that management believes minimize overall credit risk. Determin-ation of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. See Note 18 for further discussion on credit risk.

The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our marketing and trading portfolio includes structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. Our practice is to hedge within timeframes established by the ERMC.

Regulatory Accounting APS is regulated by the ACC and the FERC. The accompanying finan-cial statements reflect the rate-making policies of these commissions.

For regulated operations, we prepare our financial statements in accor-dance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. SFAS No. 71 requires a cost-based, rate-regulated enter-prise to reflect the impact of regulatory decisions in its financial state-ments. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections of costs not likely to be incurred.

We are required to discontinue applying SFAS No. 71 when deregulatory legislation is passed or a rate order is issued that contains sufficient detail to determine its effect on the portion of the business being deregulated.

In 1999, we discontinued the application of SFAS No. 71 for APS genera-tion operations due to the 1999 Settlement Agreement with the ACC.

See Note 3 for a discussion of the 1999 Settlement Agreement.

As a result, we tested the generation assets for impairment and deter-mined the generation assets were not impaired. Pursuant to the 1999 Settlement Agreement, a regulatory disallowance removed $234 million pretax ($183 million net present value) from ongoing regulatory cash flows and was recorded as a net reduction of regulatory assets. This reduction ($140 million after income taxes) was reported as an extra-ordinary charge on the 1999 Consolidated Statement of Income.

In 2002, the ACC directed APS not to transfer its generation assets, as previously required by the 1999 Settlement Agreement (see Track A Order in Note 3). Accordingly, we now consider APS generation to be cost-based, rate-regulated and subject to the requirements of SFAS No. 71. The impact of this change was immaterial to our consolidated financial statements.

Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and recent rate orders to other regulat-ed entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.

Prior to the 1999 Settlement Agreement, the ACC accelerated the amortization of substantially all of APS regulatory assets to an eight-year period that would have ended June 30, 2004. The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions):

1999 2000 2001 2002 2003 2004 TOTAL

$164

$158

$145

$115

$86

$18

$686

46 46 PNW 2002 ing average useful lives of our utility property at December 31, 2002 were as follows:

Fossil plant - 22 years; Nuclear plant - 22 years; Transmission - 34 years; Distribution - 28 years; and Other utility property - 9 years.

For the years 2000 through 2002 the depreciation rates, as prescribed by our regulators, ranged from a low of 1.51% to a high of 20%. The weight-ed-average rate was 3.35% for 2002, 3.40% for 2001 and 2000. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 30 years.

El Dorado Investments El Dorado accounts for its investments using the consolidated (if controlled), equity (if significant influence) and cost (less than 20%

ownership) methods. Beginning in the third quarter of 2002, El Dorado began consolidating the operations of NAC. See Note 22 for further details on El Dorados investment in NAC.

Capitalized Interest Capitalized interest represents the cost of debt funds used to finance construction projects. Plant construction costs, including capitalized interest, are expensed through depreciation when completed projects are placed into commercial operation. Capitalized interest does not represent current cash earnings. The rate used to calculate capitalized interest was a composite rate of 4.80% for 2002, 6.13% for 2001 and 6.62% for 2000.

Electric Revenues Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading and the corresponding unbilled revenue are estimated. We exclude sales taxes on electric revenues from both revenue and taxes other than income taxes. Other than revenues and purchased power costs related to energy trading activities, revenues are reported on a gross basis in our Consolidated Statements of Income.

All gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Consolidated Statements of Income on a net basis.

SunCor SunCor recognizes revenue from land, home and qualifying commercial operating assets sales in full, provided (a) the income is determinable, that is, the collectibility of the sales price is reasonably assured or the amount that will not be collectible can be estimated, and (b) the earn-ings process is virtually complete, that is, SunCor is not obligated to perform significant activities after the sale to earn the income. Unless Rate Synchronization Cost Deferrals As authorized by the ACC, operating costs (excluding fuel) and financing costs of Palo Verde Units 2 and 3 were deferred from the commercial operation dates (September 1986 for Unit 2 and January 1988 for Unit

3) until the date the units were included in a rate order (April 1988 for Unit 2 and December 1991 for Unit 3). In accordance with the 1999 Settlement Agreement, we are continuing to accelerate the amortization of the deferrals over an eight-year period that will end June 30, 2004.

Amortization of the deferrals is included in depreciation and amortization expense in the Consolidated Statements of Income.

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

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

We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant, plus removal costs less salvage realized, to accumulated depreciation. See Note 2 for information on a new accounting standard that impacts accounting for removal costs.

We record depreciation on utility property on a straight-line basis over the remaining useful life of the related assets. The approximate remain-December 31, 2002 2001 Remaining balance recoverable under the 1999 Settlement Agreement (a) 104 219 Spent nuclear fuel storage (Note 11) 46 43 Electric industry restructuring transition costs (Note 3) 40 34 Other 51 46 Total regulatory assets 241 342 (a) The majority of our unamortized regulatory assets above relates to deferred income taxes (See Note 4) and rate synchronization cost deferrals (see Rate Synchronization Cost Deferrals below).

Regulatory assets are reported as deferred debits on the Consolidated Balance Sheets. As of December 31, 2002 and 2001, they are comprised of the following (dollars in millions):

Regulatory liabilities are included in deferred credits and other on the Consolidated Balance Sheets. As of December 31, 2002 and 2001, they are comprised of the following (dollars in millions):

December 31, 2002 2001 Deferred gains on utility property 20 20 Other 6

7 Total regulatory liabilities 26 27

47 2002 PNW 47 Reacquired Debt Costs For debt related to the regulated portion of APS business, APS amortizes those gains and losses incurred upon early retirement over the original remaining life of the debt. In accordance with the 1999 Settlement Agreement, APS is continuing to accelerate reacquired debt costs over an eight-year period that will end June 30, 2004. All regulatory asset amortization is included in depreciation and amortiza-tion expense in the Consolidated Statements of Income.

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

Home inventory is stated at the lower of accumulated cost or estimated fair value less costs to sell. Investments in joint ventures for which SunCor does not have a controlling financial interest are not consoli-dated but are accounted for using the equity method of accounting.

Stock-Based Compensation In 2002, we began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123, Accounting for Stock-Based Compensation. The fair value method of accounting is the preferred method. In accordance with the transi-tion requirements of SFAS No. 123, we applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock compensation expense based on the intrinsic value method allowed in Accounting Principles Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees.

The following chart compares our net income, stock compensation expense and earnings per share to what those items would have been if we had recorded stock compensation expense based on the fair value method for all stock grants through 2002 (dollars in thousands, except per share amounts):

both conditions exist, recognition of all or part of the income is post-poned. A single method of recognizing income is applied to all sales transactions within an entire home, land or commercial development project. Commercial property and management revenues are recorded over the term of the lease or period in which services are provided.

Percentage of Completion - NAC Certain NAC contract revenues are accounted for under the percentage-of-completion method. Revenues are recognized based upon total costs incurred to date compared to total costs expected to be incurred for each contract. Revisions in contract revenue and cost estimates are reflected in the accounting period when known. Provisions are made for the full amounts of anticipated losses in the periods in which they are first determined. Changes in job performance, job conditions and esti-mated profitability, including those arising from contract penalty provi-sions and final contract settlements, may result in revisions to costs and income, and are recognized in the period in which revisions are deter-mined. Profit incentives are included in revenues when their realization is reasonably assured.

Contract costs include all direct material and labor costs and those indirect costs related to contract performance, such as indirect labor, supplies, tools, repairs and depreciation costs. General and administra-tive costs are charged to expense as incurred.

Cash and Cash Equivalents For purposes of the Consolidated Statements of Cash Flows, we con-sider all highly liquid debt instruments purchased with an initial maturity of three months or less to be cash equivalents.

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

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

APS also charges nuclear fuel expense for the permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel, and it charges APS $0.001 per kWh of nuclear generation. See Note 11 for information about spent nuclear fuel dispos-al and Note 12 for information on nuclear decommissioning costs.

Income Taxes Income taxes are provided using the asset and liability approach pre-scribed by SFAS No. 109, Accounting for Income Taxes. We file our federal income tax return on a consolidated basis and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between the afore-mentioned allocations and the consolidated (and unitary) income tax liability is attributed to the parent company.

2002 2001 2000 Net Income:

As reported

$149,408

$ 312,166

$ 302,332 Pro forma (fair value method) 148,013 309,874 301,102 Stock compensation expense (net of tax):

As reported 300 Pro forma (fair value method) 1,395 2,292 1,230 Earnings per share - basic:

As reported 1.76 3.68 3.57 Pro forma (fair value method) 1.74 3.66 3.55 Earnings per share - diluted:

As reported 1.76 3.68 3.56 Pro forma (fair value method) 1.74 3.65 3.55

In order to calculate the fair value of the 2002 stock option grants and the pro forma information above, we calculated the fair value of each fixed stock option in the incentive plans using the Black-Scholes option-pricing model. The fair value was calculated based on the date the option was granted. The following weighted-average assumptions were also used in order to calculate the fair value of the stock options:

2002 2001 2000 Risk-free interest rate 4.17%

4.08%

5.81%

Dividend yield 4.17%

3.70%

3.48%

Volatility 22.59%

27.66%

32.00%

Expected life (months) 60 60 60 See Note 16 for further discussion about our stock compensation plans.

48 48 PNW 2002

2. ACCOUNTING MATTERS On January 1, 2003 we adopted SFAS No. 143, Accounting for Asset Retirement Obligations. The standard requires the fair value of asset retirement obligations to be recorded as a liability, along with an offset-ting plant asset, when the obligation is incurred. Accretion of the liability due to the passage of time will be an operating expense and the capi-talized cost is depreciated over the useful life of the long-lived asset.

See Note 1 for more information regarding our previous accounting for removal costs.

We determined that we have asset retirement obligations for our nuclear facilities (nuclear decommissioning) and certain other fossil generation, transmission and distribution assets. On January 1, 2003 we recorded a liability of $219 million for our asset retirement obligations including the accretion impacts; a $67 million increase in the carrying amount of the associated assets; and a net reduction of $192 million in accumulated depreciation related primarily to the reversal of previously recorded accumulated decommissioning and other removal costs related to these obligations. Additionally, we recorded a net regulatory liability of $40 million for our asset retirement obligations related to our regulated utility.

This regulatory liability represents the difference between the amount currently being recovered in regulated rates and the amount calculated under SFAS No. 143. We believe we can recover in regulated rates the transition costs and ongoing current period costs calculated in accordance with SFAS No. 143.

In November 2002, the EITF reached a consensus on EITF 00-21, Revenue Arrangements with Multiple Deliverables. EITF 00-21 addresses certain aspects of the accounting by a vendor for arrange-ments under which it will perform multiple revenue-generating activities.

EITF 00-21 specifically addresses how to determine whether an arrangement has identifiable, separable revenue-generating activities.

EITF 00-21 does not address when the criteria for revenue recognition are met or provide guidance on the appropriate revenue recognition convention. EITF 00-21 is effective for revenue arrangements entered into after July 1, 2003. We are currently evaluating the impacts of this new guidance, but we do not believe it will have a material impact on our financial statements.

On January 1, 2002, we adopted SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. This statement super-sedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, and the account-ing and reporting provisions for the disposal of a segment of a business.

This standard did not impact our financial statements at adoption. For each of the years 2002, 2001 and 2000, items requiring discontinued operations reporting were immaterial.

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements Nos. 4, 44, and 64, Amendment of FASB Statement No.

13, and Technical Corrections which, among other things, supersedes previous guidance for reporting gains and losses from extinguishment of debt. This standard did not impact our financial statements at adoption.

In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. The guidance will be applied to exit or disposal activities initiated after December 31, 2002. This standard did not impact our financial statements at adoption.

In 2001, the American Institute of Certified Public Accountants (AICPA) issued an exposure draft of a proposed Statement of Position (SOP), Accounting for Certain Costs Related to Property, Plant, and Equipment. This proposed SOP would create a project timeline frame-work for capitalizing costs related to property, plant and equipment construction. It would require that property, plant and equipment assets be accounted for at the component level and require administrative and general costs incurred in support of capital projects to be expensed in the current period. In November 2002, the AICPA announced they would no longer issue general purpose SOPs. The work they have performed on the proposed SOP will be transitioned to the FASB staff.

In February 2003, the FASB determined that the AICPA should continue their deliberations on certain aspects of the proposed SOP. We are waiting for further guidance from the FASB staff and the AICPA on the timing of the final guidance.

See the following Notes for other new accounting standards:

Notes 1 and 16 for a new accounting standard (SFAS No. 148) related to stock-based compensation; Note 18 for a new EITF issue (EITF 02-3) related to accounting for energy trading contracts; Note 20 for a new interpretation (FIN No. 46) related to VIEs; Note 21 for a new standard (SFAS No. 142) related to goodwill and intangible assets; and Note 23 for a new interpretation (FIN No. 45) on guarantees.

3. REGULATORY MATTERS Electric Industry Restructuring STATE Overview On September 21, 1999, the ACC approved Rules that provide a framework for the introduction of retail electric competition in Arizona. On September 23, 1999, the ACC approved a comprehensive settlement agreement among APS and various parties related to the implementation of retail electric competition in Arizona. Under the Rules, as modified by the 1999 Settlement Agreement, APS was required to transfer all of its competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates no later than December 31, 2002. Consistent with that requirement, APS had been addressing the legal and regulatory requirements necessary to complete the transfer of its generation assets to Pinnacle West Energy on or before that date. On September 10, 2002, the ACC issued the Track A Order, which, among other things, directed APS not to transfer its generation assets to Pinnacle West Energy. See Track A Order below.

On September 16, 2002, APS filed an application with the ACC requesting the ACC to allow APS to borrow up to $500 million and to lend the proceeds to Pinnacle West Energy or to the Company; to guar-antee up to $500 million of Pinnacle West Energys or the Companys debt; or a combination of both, not to exceed $500 million in the aggre-gate. In its application, APS stated that the ACCs reversal of the gener-ation asset transfer requirement and the resulting bifurcation of generation assets between APS and Pinnacle West Energy under differ-ent regulatory regimes result in Pinnacle West Energy being unable to attain investment-grade credit ratings. This, in turn, precludes Pinnacle West Energy from accessing capital markets to refinance the bridge financing provided by the Company to fund the construction of Pinnacle West Energy generation assets or from effectively competing in the whole-sale markets. On March 27, 2003, the ACC authorized APS to lend up to

$500 million to Pinnacle West Energy, guarantee up to $500 million of Pinnacle West Energy debt, or a combination of both, not to exceed $500 million in the aggregate. See ACC Applications below.

Competitive Procurement Process On September 10, 2002, the ACC issued an order that, among other things, established a requirement that APS competitively procure certain power requirements. On March 14, 2003, the ACC issued the Track B Order which documented the decision made by the ACC at its open meeting on February 27, 2003, addressing this requirement. Under the order, APS will be required to solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. For 2003, APS will be required to solicit competitive bids for about 2,500 megawatts of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of APS total retail energy requirements.

The bid amounts are expected to increase in 2004 and 2005 based largely on growth in APS retail load and APS retail energy sales. The Track B Order also confirmed that it was not intended to change the current rate base status of [APS] existing assets. The order recognizes APS right to reject any bids that are unreasonable, uneconomical or unreliable.

APS expects to issue requests for proposals in March 2003 and to complete the selection process by June 1, 2003. Pinnacle West Energy will be eligible to bid to supply APS electricity requirements. See Track B Order below.

These regulatory developments and legal challenges to the Rules have raised considerable uncertainty about the status and pace of retail electric competition in Arizona. These matters are discussed in more detail below.

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

APS has reduced, and will reduce, rates for standard-offer service for customers with loads less than three MW in a series of annual retail electricity price reductions of 1.5% on July 1 for each of the years 1999 to 2003 for a total of 7.5%. Based on the price reductions authorized in the 1999 Settlement Agreement, there were retail price decreases of approximately $24 million ($14 million after taxes), effective July 1, 1999; approximately $28 million ($17 million after taxes), effective July 1, 2000; approximately $27 million ($16 million after taxes), effective July 1, 2001; and approximately $28 million ($17 million after taxes), effective July 1, 2002. The final price reduction is to be implemented July 1, 2003.

For customers having loads of three MW or greater, standard-offer rates have been reduced in varying annual increments that total 5% in the years 1999 through 2002.

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

There will be a moratorium on retail price changes for standard-offer and unbundled competitive direct access services until July 1, 2004, except for the price reductions described above and certain other lim-ited circumstances. Neither the ACC nor APS will be prevented from seeking or authorizing rate changes prior to July 1, 2004 in the event of conditions or circumstances that constitute an emergency, such as an inability to finance on reasonable terms; material changes in APS cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders.

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

APS distribution system opened for retail access effective September 24, 1999. Customers were eligible for retail access in accordance with the phase-in adopted by the ACC under the Rules (see Retail Electric Competition Rules below), including an additional 140 MW being 49 2002 PNW 49

50 50 PNW 2002 made available to eligible non-residential customers. APS opened its distribution system to retail access for all customers on January 1, 2001. The regulatory developments and legal challenges to the Rules discussed in this note have raised considerable uncertainty about the status and pace of electric competition in Arizona. Although some very limited retail competition existed in APS service area in 1999 and 2000, there are currently no active retail competitors providing unbun-dled energy or other utility services to APS customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS service territory.

Prior to the 1999 Settlement Agreement, APS was recovering sub-stantially all of its regulatory assets through July 1, 2004, pursuant to a 1996 regulatory agreement. In addition, the 1999 Settlement Agree-ment states that APS has demonstrated that its allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least

$533 million net present value (in 1999 dollars). APS will not be allowed to recover $183 million net present value (in 1999 dollars) of the above amounts. The 1999 Settlement Agreement provides that APS will have the opportunity to recover $350 million net present value (in 1999 dollars) through a competitive transition charge that will remain in effect through December 31, 2004, at which time it will terminate. The costs subject to recovery under the adjustment clause described above will be decreased or increased by any over/under-recovery due to sales volume variances.

APS will form, or cause to be formed, a separate corporate affiliate or affiliates and transfer to such affiliate(s) its competitive electric assets and services at book value as of the date of transfer, and will complete the transfers no later than December 31, 2002. APS will be allowed to defer and later collect, beginning July 1, 2004, 67% of its costs to accomplish the required transfer of generation assets to an affiliate.

However, as noted above and discussed in greater detail below, in 2002 the ACC unilaterally modified this aspect of the 1999 Settlement Agreement by issuing an order preventing APS from transferring its generation assets.

Retail Electric Competition Rules The Rules approved by the ACC included the following major provisions:

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

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

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

Affected utilities must file ACC tariffs that unbundle rates for noncom-petitive services.

The ACC shall allow a reasonable opportunity for recovery of unmiti-gated stranded costs.

Absent an ACC waiver, prior to January 1, 2001, each affected utility (except certain electric cooperatives) must transfer all competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates. Under the 1999 Settlement Agreement, APS received a waiver to allow transfer of its competitive electric assets and services to affiliates no later than December 31, 2002. However, as noted above and discussed in greater detail below, in 2002 the ACC reversed its decision, as reflected in the Rules, to require APS to transfer its generation assets.

Under the 1999 Settlement Agreement, the Rules are to be interpreted and applied, to the greatest extent possible, in a manner consistent with the 1999 Settlement Agreement. If the two cannot be reconciled, APS must seek, and the other parties to the 1999 Settlement Agreement must support, a waiver of the Rules in favor of the 1999 Settlement Agreement.

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

Provider of Last Resort Obligation Although the Rules allow retail cus-tomers to have access to competitive providers of energy and energy services, APS is the provider of last resort for standard-offer, full-service customers under rates that have been approved by the ACC. These rates are established until at least July 1, 2004. The 1999 Settlement Agreement allows APS to seek adjustment of these rates in the event of emergency conditions or circumstances, such as the inability to secure financing on reasonable terms; material changes in APS cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders. Energy prices in the western wholesale market vary and, during the course of the last two years, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount included in APS current retail rates. In the event of shortfalls due to unforeseen increases in load demand or generation or transmission outages, APS may need to purchase additional supple-mental power in the wholesale spot market. Unless APS is able to

51 2002 PNW 51 obtain an adjustment of its rates under the emergency provisions of the 1999 Settlement Agreement, there can be no assurance that APS would be able to fully recover the costs of this power.

Generic Docket In January 2002, the ACC opened a generic docket to determine if changed circumstances require the [ACC] to take another look at electric restructuring in Arizona. In February 2002, the ACC docket relating to APS October 2001 filing was consolidated with several other pending ACC dockets, including the generic docket. On May 2, 2002, the ACC issued a procedural order stating that hearings would begin on June 17, 2002 on various issues, including APS planned divestiture of generation assets to Pinnacle West Energy and associated market and affiliate issues. The procedural order also stated that consideration of the competitive bidding process required by the Rules would proceed concurrently with the Track A issues.

Track A Order On September 10, 2002, the ACC issued the Track A Order, which documents decisions made by the ACC at an open meeting on August 27, 2002. The major provisions of the Track A Order include, among other things:

Provisions related to the reversal of the generation asset transfer requirement:

The ACC reversed its decision, as reflected in the Rules, to require APS to transfer its generation assets either to an unrelated third party or to a separate corporate affiliate; and the ACC unilaterally modified the 1999 Settlement Agreement, which authorized APS transfer of its generating assets, and directed APS to cancel its activities to transfer its generation assets to Pinnacle West Energy.

Provisions related to the wholesale competitive energy procurement process (Track B issues):

The ACC stayed indefinitely the requirement of the Rules that APS acquire 100% of its energy needs for its standard offer customers from the competitive market, with at least 50% obtained through a competitive bid process; the ACC established a requirement that APS competitively procure, at a minimum, any required power that it cannot produce from its existing assets in accordance with the ultimate outcome of the Track B proceedings; the ACC directed the parties to develop a competitive procurement (bidding) process that can begin by March 1, 2003; and the ACC stated that the [Pinnacle West Energy] generating assets that APS may acquire from [Pinnacle West Energy] shall not be counted as APS assets in determining the amount, timing and manner of the competitive solicitation for Track B purposes, thereby bifurcating the regulatory treatment of the existing APS assets and the Pinnacle West Energy assets.

On November 15, 2002, APS filed appeals of the Track A Order in the Maricopa County, Arizona Superior Court and in the Arizona Court of Appeals. Arizona Public Service Company vs. Arizona Corporation Commission, CV 2002-0222 32. Arizona Public Service Company vs.

Arizona Corporation Commission, 1CA CC 02-0002. On December 13, 2002, APS and the ACC staff agreed to principles for resolving certain issues raised by APS in its appeals of the Track A Order. APS and the ACC are the only parties to the Track A Order appeals. The major provisions of this document include, among other things, the following:

The parties agreed that it would be appropriate for the ACC to consider the following matters in APS upcoming general rate case, anticipated to be filed before June 30, 2003:

the generating assets to be included in APS rate base, including the question of whether certain power plants currently owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5, and Saguaro Unit 3) should be included in APS rate base; the appropriate treatment of the $234 million pretax asset write-off agreed to by APS as part of a 1999 settlement agreement approved by the ACC among APS and various parties related to the implementation of retail competition in Arizona; and the appropriate treatment of costs incurred by APS in preparation for the previously anticipated transfer of generation assets to Pinnacle West Energy.

Upon the ACCs issuance of a final decision that is no longer subject to appeal approving the Financing Application, with appropriate conditions, APS appeals of the Track A Order would be limited to the issues described in the preceding bullet points, each of which would be pre-sented to the ACC for consideration prior to any final judicial resolution.

On February 21, 2003, a Notice of Claim was filed with the ACC and the Arizona Attorney General on behalf of APS, Pinnacle West and Pinnacle West Energy to preserve their and our rights relating to the Track A Order.

Track B Order The ACC Staff has conducted workshops on the Track B issues with various parties to determine and define the appropriate process to be used for competitive power procurement. On September 10, 2002, the ACC issued an order that, among other things, estab-lished a requirement that APS competitively procure certain power requirements. On March 14, 2003, the ACC issued the Track B Order which documented the decision made by the ACC at its open meeting on February 27, 2003 addressing this requirement. The order adopted most of the provisions of an ACC ALJs recommendation that was issued on January 30, 2003. Under the ACCs Track B Order, APS will be required to solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. For 2003, APS will be required to solicit competitive bids for about 2,500 megawatts of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of APS total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in APS retail load and APS retail energy sales. The Track B Order also confirmed that it was not intended to change the current rate base status of [APS] existing assets.

52 52 PNW 2002 The order recognizes APS right to reject any bids that are unreason-able, uneconomical or unreliable. The Track B procurement process will involve the ACC Staff and an independent monitor. The Track B Order also contains requirements relating to standards of conduct between APS and any affiliate of APS that may participate in the competitive solicitation, requires that APS treat bidders in a non-discriminatory manner and requires APS to file a protocol regarding short-term and emergency procurements. The order permits the provision of corporate oversight, support and governance as long as such activities do not favor Pinnacle West Energy in the procurement process or provide Pinnacle West Energy with confidential APS bidding information that is not available to other bidders. The order directs APS to evaluate bids on cost, reliability and reasonableness. The decision requires bidders to allow the ACC to inspect their plants and requires assurances of appro-priate competitive market conduct from senior officers of such bidders.

Following the solicitation, APS will prepare a report evaluating environ-mental issues relating to the procurement and a series of workshops on environmental risk management will be commenced thereafter.

APS expects to issue requests for proposals in March 2003 and to complete the selection process by June 1, 2003. Pinnacle West Energy will be eligible to bid to supply APS electricity requirements.

ACC Applications On September 16, 2002, APS filed a Financing Application requesting the ACC to allow APS to borrow up to $500 million and to lend the proceeds to Pinnacle West Energy or the Company; to guarantee up to $500 million of Pinnacle West Energys or the Companys debt; or a combination of both, not to exceed $500 million in the aggregate.

The loan and/or the guarantee would be used to refinance debt incurred to fund the construction of Pinnacle West Energy generation assets.

The Financing Application addressed, among other things, the following matters:

APS noted that its April 19, 2002 filing with the ACC had sought unifi-cation of [Pinnacle West Energy] Assets (West Phoenix Units 4 and 5, Redhawk Units 1 and 2 and Saguaro Unit 3) and APS generation assets under a common financial and regulatory regime. APS further noted that the Track A Orders language regarding the treatment of the Pinnacle West Energy Assets for Track B purposes appears to post-pone a decision regarding the inclusion of the Pinnacle West Energy Assets in APS rate base, thereby effectively precluding the consolida-tion of the Pinnacle West Energy Assets at APS under a common financial and regulatory regime at the present time.

APS stated that it did not intend or desire to foreclose the possibility that it would acquire all or part of the Pinnacle West Energy Assets or that it may propose that the Pinnacle West Energy Assets be included in APS rate base or afforded cost-of-service regulatory treatment to the extent the Pinnacle West Energy Assets are used by APS cus-tomers. APS stated that these issues would be appropriate topics in APS 2003 general rate case and noted that the Track A Order specifi-cally stated that the ACC would not pre-judge the eventual rate treat-ment of the Pinnacle West Energy Assets.

APS stated that the Track A Orders reversal of the generation asset transfer requirement and the resulting bifurcation of generation assets between APS and Pinnacle West Energy under different regulatory regimes result in Pinnacle West Energy being unable to attain investment-grade credit ratings. This, in turn, precludes Pinnacle West Energy from accessing capital markets to refinance the bridge financ-ing provided by the Company to fund the construction of the Pinnacle West Energy Assets or from effectively competing in the wholesale markets. APS noted that Pinnacle West Energy had previously received investment-grade credit ratings contingent upon its receipt of APS generation assets and that the Companys credit ratings could be adversely affected if Pinnacle West Energy is unable to finance its cap-ital requirements. On November 4, 2002, Standard & Poors lowered the Companys senior unsecured debt rating from BBB to BBB-.

APS stated that the amount of the requested loan and/or guarantee is APS present estimate of the amount of credit support necessary through APS to restore Pinnacle West Energy and the Company to their credit status prior to the ACCs issuance of the Track A Order.

APS further stated that if the requested amount proves to be inade-quate, APS reserves the right to submit a second financing application seeking additional credit support.

On March 27, 2003, the ACC approved the Financing Application, subject to the following principal conditions:

any debt issued by APS pursuant to the order must be unsecured; APS will be permitted to loan up to $500 million to Pinnacle West Energy (the APS Loan), guarantee up to $500 million of Pinnacle West Energy debt, or a combination of both, not to exceed

$500 million in the aggregate; the APS Loan must be callable and secured by certain Pinnacle West Energy assets; the APS Loan must bear interest at a rate equal to 264 basis points above the interest rate on APS debt that could be issued and sold on equivalent terms (including, but not limited to, maturity and security);

the 264 basis points referred to in the previous bullet point will be cap-italized as a deferred credit and used to offset retail rates in the future, with the deferred credit balance bearing an interest rate of six percent per annum; the APS Loan must have a maturity date of not more than four years, unless otherwise ordered by the ACC; any demonstrable increase in APS cost of capital as a result of the transaction (such as from a decline in bond rating) will be excluded from future rate cases; APS must maintain a common equity ratio of at least forty percent and may not pay common dividends if such payment would reduce its com-mon equity below that threshold, unless otherwise waived by the ACC.

The ACC will process any waiver request within sixty days, and for this

53 2002 PNW 53 sixty-day period this condition will be suspended. However, this condi-tion, which will continue indefinitely, will not be permanently waived without an order of the ACC; and certain waivers of the ACCs affiliated interest rules previously granted to APS and its affiliates will be withdrawn and, during the term of the APS Loan, neither Pinnacle West nor Pinnacle West Energy may reorganize or restructure, acquire or divest assets, or form, buy or sell affiliates (each a Covered Transaction), or pledge or otherwise encumber the Pinnacle West Energy assets without prior ACC approval, expect that the foregoing restrictions will not apply to the following categories of Covered Transactions:

Covered Transactions less than $100 million, measured on a cumu-lative basis over the calendar year in which the Covered Transac-tions are made; Covered Transactions by SunCor of less than $300 million through 2005, consistent with SunCors anticipated accelerated asset sales activity during those years; Covered Transactions related to the payment of ongoing construc-tion costs for Pinnacle West Energys (a) West Phoenix Unit 5, located in Phoenix, with an expected commercial operation date in mid-2003, and (b) Silverhawk plant, located near Las Vegas, with an expected commercial operation date in mid-2004; and Covered Transactions related to the sale of 25% of the Silverhawk plant to SNWA if SNWA exercises its existing purchase option to do so.

The ACC also ordered the ACC staff to conduct an inquiry into our and our affiliates compliance with the retail electric competition and related rules and decisions.

In mid-2003, the Company will need to refinance approximately $475 million of parent company indebtedness. We expect that this indebted-ness will be repaid through funds borrowed by Pinnacle West Energy from APS under the APS Loan.

On November 22, 2002, the ACC approved APS request to permit APS to (a) make short-term advances to Pinnacle West in the form of an inter-affiliate line of credit in the amount of $125 million, or (b) guarantee $125 million of Pinnacle Wests short-term debt, subject to certain conditions.

See Note 5.

Federal In July 2002, the FERC adopted a price mitigation plan that constrains the price of electricity in the wholesale spot electricity market in the west-ern United States. The FERC has adopted a price cap of $250 per MWh for the period subsequent to October 31, 2002. Sales at prices above the cap must be justified and are subject to potential refund.

On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking for Standard Market Design for wholesale electric markets. Voluminous comments and reply comments were filed on virtually every aspect of the proposed rule, and the FERC has announced that it will issue an additional white paper on the proposed Standard Market Design in April 2003. We are reviewing the proposed rulemaking and cannot currently predict what, if any, impact there may be to the Company if the FERC adopts the proposed rule or any modifications proposed in the comments.

General The regulatory developments and legal challenges to the Rules discussed in this Note have raised considerable uncertainty about the status and pace of retail electric competition in Arizona. Although some very limited retail competition existed in APS service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS customers.

As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS service territory. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete in the new regulatory environment.

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

APS has recorded a regulatory asset related to income taxes on its Balance Sheets in accordance with SFAS No. 71. This regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. APS amortizes this amount as the differences reverse. In accordance with ACC settlement agreements, APS is continuing to accelerate amortization of a regulatory asset related to income taxes over an eight-year period that will end June 30, 2004 (see Note 1). Accordingly, we are including this accelerated amortization in depreciation and amortization expense on our Consolidated Statements of Income.

As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on the 2001 federal consolidated income tax return. The accelerated deduction has resulted in a $200 million reduction in the current income tax liability and a corre-sponding increase in the plant-related deferred tax liability. In 2002, we received an income tax refund of approximately $115 million related to our 2001 federal consolidated income tax return.

The components of income tax expense for income before accounting change are (dollars in thousands):

year ended December 31, 2002 2001 2000 Current:

Federal

$ (43,492)

$184,893

$ 189,779 State (14,732) 45,845 42,306 Total current (58,224) 230,738 232,085 Deferred 196,324 (17,203)

(37,885)

Total income tax expense

$ 138,100

$213,535

$ 194,200

December 31, 2002 2001 Current asset/(liability) 4,094 (3,244)

Long term liability (1,209,074)

(1,064,993)

Accumulated deferred income taxes - net

$ (1,204,980)

$(1,068,237)

December 31, 2002 2001 DEFERRED TAX ASSETS Pension liability 72,835 19,422 Risk management and trading activities 43,542 73,043 Deferred gain on Palo Verde Unit 2 sale-leaseback 23,562 25,374 Other 99,054 90,580 Total deferred tax assets 238,993 208,419 DEFERRED TAX LIABILITIES Plant-related (1,316,636)

(1,069,207)

Regulatory asset for income taxes (80,635)

(121,757)

Risk management and trading activities (46,702)

(85,692)

Total deferred tax liabilities (1,443,973)

(1,276,656)

Accumulated deferred income taxes - net

$ (1,204,980)

$(1,068,237) year ended December 31, 2002 2001 2000 Federal income tax expense at 35% statutory rate

$ 123,639

$189,316

$ 173,786 Increases (reductions) in tax expense resulting from:

State income tax net of federal income tax benefit 16,478 23,353 19,848 Other (2,017) 866 566 Income tax expense

$ 138,100

$213,535

$ 194,200 54 54 PNW 2002 The following table sets forth the net deferred income tax liability recog-nized on the Consolidated Balance Sheets at December 31, 2002 and 2001 (dollars in thousands):

The components of the net deferred income tax liability were as follows (dollars in thousands):

5. LINES OF CREDIT AND SHORT-TERM BORROWINGS APS had committed lines of credit with various banks of $250 million at December 31, 2002 and 2001, which were available either to support the issuance of commercial paper or to be used for bank borrowings.

These lines of credit mature in June 2003. The commitment fees at December 31, 2002 and 2001 for these lines of credit were 0.09% per annum. APS had no bank borrowings outstanding under these lines of credit at December 31, 2002 and 2001.

APS had no commercial paper borrowings outstanding at December 31, 2002 and $171 million at December 31, 2001. The weighted average interest rate on commercial paper borrowings was 2.47% for the year ended December 31, 2002 and 4.72% for the year ended December 31, 2001. By Arizona statute, APS short-term borrowings cannot exceed 7%

of its total capitalization unless approved by the ACC.

Pinnacle West had committed lines of credit of $475 million at December 31, 2002 and $250 million at December 31, 2001, which were available either to support the issuance of commercial paper or to be used for bank borrowings. Outstanding amounts at December 31, 2002 were $72 million, and there were no short-term bank borrowings outstanding at December 31, 2001. The commitment fees ranged from 0.10% to 0.15% in 2002 and 2001. Pinnacle West commercial paper borrowings outstanding were $24 million at December 31, 2002 and

$235 million at December 31, 2001. The weighted average interest rate on commercial paper borrowings was 2.06% for the year ended December 31, 2002 and 3.50% for the year ended December 31, 2001.

On July 31, 2002, Pinnacle West completed a $300 million bank credit facility, which was subsequently reduced to $225 million by applying

$75 million of the proceeds from the equity offering in December 2002 (see Note 7). The borrowings are LIBOR-based, can be drawn upon as needed and are expected to be used primarily to fund Pinnacle West Energy capital requirements. The facility matures in July 2003. The majority of these borrowings were used to fund Pinnacle West Energy capital expenditures. At December 31, 2002, Pinnacle West had borrowed $67 million under the credit facility.

On November 22, 2002, the ACC approved APS request to permit APS to (a) make short-term advances to Pinnacle West in the form of an inter-affiliate line of credit in the amount of $125 million, or (b) guar-antee $125 million of Pinnacle Wests short-term debt, subject to certain conditions. This interim loan matures in December 2003. There have been no borrowings on this line.

SunCor had revolving lines of credit totaling $140 million at December 31, 2002 and 2001. The commitment fees were 0.125% in 2002 and 2001.

SunCor had $126 million outstanding at December 31, 2002 and $128 million outstanding at December 31, 2001. The balance is included in long-term debt on the Consolidated Balance Sheets (see Note 6). SunCor had short-term loans in the amount of $6 million at December 31, 2002 and no short-term loans outstanding at December 31, 2001.

The following chart compares pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):

Maturity Interest December 31, December 31, Dates (a)

Rates 2002 2001 APS First mortgage bonds 2002 8.125% (b) 125,000 2004 6.625%

80,000 80,000 2023 7.25%

54,150 54,150 2024 8.75% (c) 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 (6,337)

(5,266)

Pollution control bonds 2024-2034 (d) 386,860 386,860 Pollution control bonds 2029 3.30% (e) 90,000 Pollution control bonds with senior notes (f) 2029 5.05%

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%

400,000 400,000 Unsecured notes 2012 6.50%

375,000 Senior notes (g) 2006 6.75%

83,695 83,695 Capitalized lease obligations 2003-2012 5.78%

20,400 1,343 Subtotal 2,220,843 2,074,525 SUNCOR Revolving credit 2003-2004 (h) 125,500 128,000 Notes payable 2003-2008 (i) 7,646 7,912 Bonds payable 2024 5.95%

5,090 5,215 Bonds payable 2026 6.75%

7,500 7,500 Capitalized lease obligations 2003-2007 8.91%

1,299 Subtotal 147,035 148,627 PINNACLE WEST Senior notes 2003-2006 (j) 540,000 325,000 Unamortized discount and premium (530)

Floating rate notes 2003 (k) 250,000 250,000 Capitalized lease obligations 2004-2007 5.48%

1,999 1,066 Subtotal 791,469 576,066 EL DORADO Construction loan 2005 1.77%

2,600 Capitalized lease obligations 2004-2005 7.04%

771 Subtotal 3,371 Total long-term debt 3,162,718 2,799,218 Less current maturities 281,023 126,140 TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES

$ 2,881,695

$ 2,673,078 (a) This schedule does not reflect the timing of redemptions that may occur prior to maturity.

(b) On March 15, 2002, APS redeemed at maturity $125 million of its First Mortgage Bonds, 8.125% Series due 2002.

(c) On April 15, 2002, APS redeemed $122 million of its First Mortgage Bonds, 8.75% Series due 2024.

(d) The weighted-average rate was 1.94% at December 31, 2002 and 2.55% at December 31, 2001. Changes in short-term interest rates would affect the costs associated with this debt.

(e) 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%.

(f) On November 1, 2002, Maricopa County, Arizona Pollution Control Corporation issued $90 million of 5.05% Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project) 2002 Series A, due 2029, and loaned the proceeds to APS pursuant to a loan agreement. The bonds were issued to refinance $90 million of outstanding pollution control bonds. The bondholders were issued $90 million of first mortgage bonds (senior note mortgage bonds) as collateral.

55 2002 PNW 55

6. LONG-TERM DEBT Borrowings under the APS mortgage bond indenture are secured by substantially all utility plant. APS also has unsecured debt. SunCors debt is collateralized by interests in certain real property and Pinnacle Wests debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2002 and 2001 (dollars in thousands):

56 56 PNW 2002 (g) 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, as well as the

$90 million issue discussed in footnote (f) above. 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.

(h) The weighted-average rate was 3.75% at December 31, 2002 and was 5.31% at December 31, 2001. Interest for 2002 and 2001 was based on LIBOR plus 2% or prime plus 0.5%.

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

( j ) Includes three series of notes: $25 million at 6.87% due in 2003, $300 million at 6.4% due in 2006 and $215 million at 4.5% due in 2004 as of December 31, 2002.

(k) The weighted average rate was 2.85% at December 31, 2002 and was 4.65% at December 31, 2001. Interest for 2002 and 2001 was based on LIBOR plus 0.98%.

Pinnacle Wests and APS significant debt covenants related to their respective financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test. Pinnacle West and APS are in compliance with such covenants and each anticipates it will continue to meet all the significant covenant requirement levels. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants.

Neither Pinnacle Wests nor APS financing agreements contain ratings triggers that would result in an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a ratings downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.

All of Pinnacle Wests bank agreements contain cross-default provisions under which a default by it or APS in a specified amount under another agreement would result in a default and the potential acceleration of payment under the agreements. All of APS bank agree-ments contain cross-default provisions under which a default by APS in a specified amount under another agreement would result in a default and the potential acceleration of payment under the agreements.

Pinnacle Wests and APS credit agreements generally contain provi-sions under which the lenders could refuse to advance loans in the event of a material adverse change in the borrowers financial condition or financial prospects.

The following is a list of payments due on total long-term debt and capitalized lease requirements through 2007:

$281 million in 2003;

$552 million in 2004;

$405 million in 2005;

$390 million in 2006;

$3 million in 2007; and

$1,539 million, thereafter.

APS first mortgage bondholders share a lien on substantially all utility plant assets (other than nuclear fuel and transportation equipment and other excluded assets). The mortgage bond indenture restricts the pay-ment of common stock dividends under certain conditions. APS may pay dividends on its common stock if there is a sufficient amount avail-able from retained earnings and the excess of cumulative book depre-ciation (since the mortgages inception) over mortgage depreciation, which is the cumulative amount of additional property pledged each year to address collateral depreciation. As of December 31, 2002, the amount available under the mortgage would have allowed APS to pay approximately $3 billion of dividends compared to APS current annual common stock dividends of $170 million.

7. COMMON STOCK AND TREASURY STOCK Our common stock and treasury stock activity during each of the three years 2002, 2001 and 2000 is as follows (dollars in thousands, except shares):

Common Stock Common Stock Treasury Stock Treasury Stock Shares Amount Shares Amount Balance at December 31, 1999 84,824,947

$ 1,540,197 (74,844)

(2,748)

Purchase of treasury stock (300,800)

(12,968)

Reissuance of treasury stock for stock compensation (net) 266,006 10,627 Other (2,277)

Balance at December 31, 2000 84,824,947 1,537,920 (109,638)

(5,089)

Purchase of treasury stock (334,600)

(16,393)

Reissuance of treasury stock for stock compensation (net) 342,931 15,596 Other (996)

Balance at December 31, 2001 84,824,947 1,536,924 (101,307)

(5,886)

Common stock issuance - December 23, 2002 6,555,000 199,238 Purchase of treasury stock (150,500)

(5,971)

Reissuance of treasury stock for stock compensation (net) 126,977 7,499 Other 1,096 Balance at December 31, 2002 91,379,947

$ 1,737,258 (124,830)

(4,358)

57 2002 PNW 57 The following table shows a reconciliation of the funded status of the plans to the amounts recognized in the Consolidated Balance Sheets as of December 31, 2002 and 2001 (dollars in thousands):

8. RETIREMENT PLANS AND OTHER BENEFITS Pension Plans Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. Effective January 1, 2003, Pinnacle West sponsored a new account balance pension plan for all new employees in place of the defined benefit plan and, effective April 1, 2003, the new plan will be offered as an alternative to the defined benefit plan for all existing employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all of our employees.

The supplemental excess benefit plan covers officers of the company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans.

Generally, we calculate the benefits based on age, years of service and pay. We fund the qualified plan by contributing at least the minimum amount required under IRS regulations but no more than the maximum tax-deductible amount. The assets in the qualified plan at December 31, 2002 were mostly domestic common stocks and bonds and real estate.

Total pension expense, including administrative costs and after consider-ation of amounts capitalized or billed to electric plant participants, was:

$14 million in 2002;

$11 million in 2001; and

$ 6 million in 2000.

The following table shows the components of net periodic pension cost before consideration of amounts capitalized or billed to electric plant participants for the years ended December 31, 2002, 2001 and 2000 (dollars in thousands):

2002 2001 2000 Service cost - benefits earned during the period $

30,333

$ 27,640

$ 26,040 Interest cost on projected benefit obligation 71,242 66,549 61,625 Expected return on plan assets (75,652)

(77,340)

(77,231)

Amortization of:

Transition asset (3,227)

(3,227)

(3,227)

Prior service cost 2,912 3,008 2,370 Net actuarial loss/(gain) 1,846 907 (1,190)

Net periodic pension cost 27,454

$ 17,537 8,387 2002 2001 Funded status - pension plan assets less than projected benefit obligation

$ (348,770)

$ (166,773)

Unrecognized net transition asset (10,327)

(13,554)

Unrecognized prior service cost 23,148 26,170 Unrecognized net actuarial losses 293,223 108,422 Accrued pension benefit liability recognized in the Consolidated Balance Sheets (42,726)

(45,735) 2002 2001 Projected pension benefit obligation at beginning of year

$ 931,646

$ 840,485 Service cost 30,333 27,640 Interest cost 71,242 66,549 Benefit payments (35,230)

(33,282)

Actuarial losses 71,696 21,632 Plan amendments (110) 8,622 Projected pension benefit obligation at end of year

$1,069,577

$ 931,646 2002 2001 Fair value of pension plan assets at beginning of year

$ 764,873

$ 775,196 Actual loss on plan assets (36,966)

(22,876)

Employer contributions 26,600 44,200 Benefit payments (33,700)

(31,647)

Fair value of pension plan assets at end of year

$ 720,807

$ 764,873 2002 2001 Accrued pension benefit liability (42,726)

(45,735)

Additional minimum liability (141,155)

(3,297)

Intangible asset 23,148 1,697 Accumulated other comprehensive loss - pretax 118,007 1,600 The following table sets forth the defined benefit pension plans change in projected benefit obligation for the plan years 2002 and 2001 (dollars in thousands):

The following table sets forth the qualified defined benefit pension plans change in the fair value of plan assets for the plan years 2002 and 2001 (dollars in thousands):

The following table sets forth the defined benefit pension plans amounts recognized in the Consolidated Balance Sheets at December 31, 2002 and 2001 (dollars in thousands):

2002 2001 2000 Service cost - benefits earned during the period $

12,036 9,438 8,613 Interest cost on accumulated benefit obligation 25,235 21,585 19,315 Expected return on plan assets (21,116)

(21,985)

(22,381)

Amortization of:

Transition obligation 4,001 7,698 7,698 Prior service credit (75)

Net actuarial loss/(gain) 3,072 (4,066)

(7,983)

Net periodic other post-retirement benefit cost 23,153

$ 12,670 5,262 2002 2001 Funded status - other postretirement plan assets less than accumulated other postretirement benefit obligation

$ (186,400)

(80,544)

Unrecognized net obligation at transition 36,489 84,748 Unrecognized prior service credit (1,673)

Unrecognized net actuarial loss/(gain) 148,268 (8,606)

Net other postretirement benefit liability recognized in the Consolidated Balance Sheets (3,316)

(4,402) 2002 2001 Accumulated other postretirement benefit obligation at beginning of year

$ 318,355

$ 264,006 Service cost 12,036 9,438 Interest cost 25,235 21,585 Benefit payments (10,473)

(10,194)

Actuarial losses 108,979 33,520 Plan amendments (44,258) (a)

Accumulated other postretirement benefit obligation at end of year

$ 409,874

$ 318,355 (a) The plan was amended January 1, 2002 to increase the deductibles, out-of-pocket maximums and prescription drug co-pays. The plan was amended in June 2002 to increase the participants portion of premiums.

2002 2001 Projected benefit obligation

$1,069,577

$ 931,646 Accumulated benefit obligation 904,687 752,230 Fair value of plan assets 720,807 764,873 2002 2001 Discount rate 6.75%

7.50%

Rate of increase in compensation levels 4.00%

4.00%

Expected long-term rate of return on assets 9.00%

10.00%

58 58 PNW 2002 Employee Savings Plan Benefits Pinnacle West sponsors a defined contribution savings plan for the employees of Pinnacle West and our subsidiaries. In a defined contribu-tion savings plan, the benefits a participant will receive result from regu-lar contributions they make to a participant account. Under this plan, we make matching contributions in Pinnacle West stock to participant accounts. After a five-year vesting period, participants have a choice to change the employer contribution match to other investments. At December 31, 2002, approximately 25% of total plan assets were in Pinnacle West stock. We recorded expenses for this plan of approxi-mately $5 million for 2002 and 2001 and $4 million for 2000.

Other Postretirement Benefits Pinnacle West sponsors other postretirement benefits for the employees of Pinnacle West and our 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. We retain the right to change or eliminate these benefits.

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

$12 million for 2002;

$6 million for 2001; and

$3 million for 2000.

The following table shows a reconciliation of the funded status of the plan to the amounts recognized in the Consolidated Balance Sheets at December 31, 2002 and 2001 (dollars in thousands):

The following table sets forth the other postretirement benefit plans change in accumulated postretirement benefit obligation for the plan years 2002 and 2001 (dollars in thousands):

The following table shows the accumulated benefit obligation in relation to the fair value of plan assets for the plan years 2002 and 2001 (dollars in thousands):

The following are weighted-average assumptions as of December 31, 2002 and 2001:

The following table shows the components of net periodic other post-retirement benefit costs before consideration of amounts capitalized or billed to electric plant participants for the years ended December 31, 2002, 2001 and 2000 (dollars in thousands):

2002 2001 Discount rate 6.75%

7.50%

Expected long-term rate of return on assets - pretax 9.00%

10.00%

Expected long-term rate of return on assets - after tax 7.84%

8.71%

Initial health care cost trend rate -

under age 65 8.00%

7.00%

Initial health care cost trend rate -

age 65 and over 8.00%

7.00%

Ultimate health care cost trend rate 5.00%

5.00%

Year ultimate health care trend rate is reached 2007 2006 1% Increase 1% Decrease Effect on the 2002 other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants 5

(4)

Effect on the 2002 service and interest cost components of net periodic other postretirement benefit costs 7

(6)

Effect on the accumulated other postretirement benefit obligation at December 31, 2002 54 (43)

Year 2003 70 2004 66 2005 64 2006 63 2007 63 Thereafter 478 Total future lease commitments 804 2002 2001 Fair value of other postretirement benefit plan assets at beginning of year

$ 237,810

$ 249,154 Actual loss on plan assets (27,802)

(12,550)

Employer contributions 23,600 11,400 Benefit payments (10,134)

(10,194)

Fair value of other postretirement benefit plan assets at end of year

$ 223,474

$ 237,810 59 2002 PNW 59 The following are weighted-average assumptions as of December 31, 2002 and 2001:

The following table shows the effect of a 1% increase or decrease in the initial and ultimate health care expense and cost trend rate (dollars in millions):

Severance Charges In July 2002, we implemented a voluntary workforce reduction as part of our cost reduction program. We recorded $36 million before taxes in voluntary severance costs in 2002. No further charges are expected.

9. LEASES In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale-leaseback transactions.

APS accounts for these leases as operating leases. The gain resulting from the transaction of approximately $140 million was deferred and is being amortized to operations and maintenance expense over 29.5 years, the original term of the leases. There are options to renew the leases for two additional years and to purchase the property for fair market value at the end of the lease terms. Consistent with the ratemaking treatment, a regulatory asset is recognized for the difference between lease payments and rent expense calculated on a straight-line basis. See Note 20 for a discussion of VIEs, including the SPEs involved in the Palo Verde sale-leaseback transactions.

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

Total lease expense recognized in the Consolidated Statements of Income was $62 million in 2002, $56 million in 2001 and $58 million in 2000.

The amounts to be paid for the Palo Verde Unit 2 leases are approxi-mately $49 million per year for the years 2003 to 2015.

In accordance with the 1999 Settlement Agreement and previous settle-ment agreements, APS is continuing to accelerate amortization of the regulatory asset for leases over an eight-year period that will end June 30, 2004 (see Note 1). All regulatory asset amortization is included in depreciation and amortization expense in the Consolidated Statements of Income. The balance of this regulatory asset at December 31, 2002 was $14 million.

Estimated future minimum lease payments for our operating leases are approximately as follows (dollars in millions):

The following table sets forth the other postretirement benefit plans change in the fair value of plan assets for the plan years 2002 and 2001 (dollars in thousands):

60 60 PNW 2002

10. JOINTLY-OWNED FACILITIES APS shares ownership of some of its generating and transmission facilities with other companies. The following table shows APS interest in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2002. APS share of operating and maintaining these facili-ties is included in the Consolidated Statements of Income in operations and maintenance expense.

Percent Construction Owned by Plant in Accumulated Work in (dollars in thousands)

APS Service Depreciation Progress Generating Facilities:

Palo Verde Nuclear Generating Station Units 1 and 3 29.1%

$ 1,829,225 (905,278) 17,428 Palo Verde Nuclear Generating Station Unit 2 (see Note 9) 17.0%

574,745 (289,049) 68,475 Four Corners Steam Generating Station Units 4 and 5 15.0%

153,559 (82,434) 500 Navajo Steam Generating Station Units 1, 2, and 3 14.0%

235,743 (110,923) 3,010 Cholla Steam Generating Station Common Facilities (a) 62.8%(b) 76,322 (42,608) 1,733 Transmission Facilities:

ANPP 500KV System 35.8%(b) 68,314 (25,655) 31 Navajo Southern System 31.4%(b) 27,129 (17,405) 664 Palo Verde - Yuma 500KV System 23.9%(b) 9,591 (4,168) 383 Four Corners Switchyards 27.5%(b) 3,071 (1,979)

Phoenix - Mead System 17.1%(b) 36,418 (2,906)

Palo Verde - Estrella 500KV System 50.0%(b) 50,450 (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.

11. COMMITMENTS AND CONTINGENCIES Enron We recorded charges totaling $21 million before income taxes for exposure to Enron and its affiliates in the fourth quarter of 2001. This amount is comprised of a $15 million reserve for the Companys net exposure to Enron and its affiliates and additional expenses of $6 million primarily related to 2002 power contracts with Enron that were canceled. These charges take into consideration our rights of set-off with respect to the Enron related contractual obligations. The APS por-tion of the write-off was $13 million. The basis of the set-offs included, but was not limited to, provisions in the various contractual arrange-ments with Enron and its affiliates, including an International Swaps and Derivative Agreement (ISDA) between APS and Enron North America.

The write-off is also net of the expected recovery based on secondary market quotes from the bond market. The amounts were written-off from the balances of the related assets and liabilities from risk manage-ment and trading activities on the Consolidated Balance Sheets.

Palo Verde Nuclear Generating Station Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before 2010 and it does not intend to begin accepting spent nuclear fuel prior to that date. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOEs delay, a number of utilities filed damages actions against the DOE in the Court of Federal Claims.

In February 2002, the Secretary of Energy recommended to President Bush that the Yucca Mountain, Nevada site be developed as a perma-nent repository for spent nuclear fuel. The President transmitted this recommendation to Congress and the State of Nevada vetoed the Presidents recommendation. Congress approved the Yucca Mountain site, overriding the Nevada veto. It is now expected that the DOE will submit a license application to the NRC in late 2004.

61 2002 PNW 61 APS has existing fuel storage pools at Palo Verde and is in the process of completing construction of a new facility for on-site dry storage of spent nuclear fuel. With the existing storage pools and the addition of the new facility, APS believes spent nuclear fuel storage or disposal methods will be available for use by Palo Verde to allow its continued operation through the term of the operating license for each Palo Verde unit.

Although some low-level waste has been stored on-site in a low-level waste facility, APS is currently shipping low-level waste to off-site facilities.

APS currently believes interim low-level waste storage methods are or will be available for use by Palo Verde to allow its continued operation and to safely store low-level waste until a permanent disposal facility is available.

APS currently estimates it will incur $115 million (in 2002 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. As of December 31, 2002, APS had spent

$2 million and recorded accumulated spent nuclear fuel amortization of

$44 million and a regulatory asset of $46 million for on-site interim spent nuclear fuel storage costs related to nuclear fuel burned to date.

The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law.

This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $200 million ($300 million effective January 1, 2003) and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assess-ment per reactor under the program for each nuclear incident is approx-imately $88 million, subject to an annual limit of $10 million per incident.

Based on APS interest in the three Palo Verde units, APS maximum potential assessment per incident for all three units is approximately $77 million, with an annual payment limitation of approximately $9 million.

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

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

Purchased Power and Fuel Commitments APS and Pinnacle West are parties to various purchased power and fuel contracts with terms expiring from 2003 through 2025 that include required purchase provisions. We estimate the contract requirements to be approximately $173 million in 2003; $82 million in 2004; $28 million in 2005; $31 million in 2006; $17 million in 2007 and $162 million there-Estimated Years ended December 31, 2003 2004 2005 2006 2007 Coal

$ 43

$ 44 9

9 9

Nuclear Fuel 22 Total take-or-pay commitments (a)

$ 65

$ 44 9

9 9

(a) Total take-or-pay commitments are approximately $136 million. The total net present value of these commitments is approximately $119 million.

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

Of the various purchased power and fuel contracts mentioned above some of those contracts have take-or-pay provisions. The contracts APS has for the supply of its coal and nuclear fuel supply have take-or-pay provisions. The current take-or-pay nuclear fuel contracts expire in 2003 and had not been renewed as of December 31, 2002. The current take-or-pay coal contracts have terms that expire in 2007.

The following table summarizes the estimated take-or-pay commitments for the existing terms (dollars in millions):

Coal Mine Reclamation Obligations APS must reimburse certain coal providers for amounts incurred for coal mine reclamation. Our coal mine reclamation obligation is about $59 mil-lion at December 31, 2002 and is included in deferred credits-other in the Consolidated Balance Sheets.

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

California Energy Market Issues and Refunds in the Pacific Northwest In July 2001, the FERC ordered an expedited fact-finding hearing to cal-culate refunds for spot market transactions in California during a specified time frame. This order calls for a hearing, with findings of fact due to the FERC after the ISO and PX provide necessary historical data. The FERC directed an ALJ to make findings of fact with respect to: (1) the mitigated price in each hour of the refund period; (2) the amount of refunds owed by each supplier according to the methodology established in the order; and (3) the amount currently owed to each supplier (with separate quantities due from each entity) by the CAISO, the California Power Exchange, the investor-owned utilities and the State of California.

62 62 PNW 2002 APS was a seller and a purchaser in the California markets at issue, and to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. On December 12, 2002, the ALJ issued Proposed Findings of Fact with respect to the refunds. On March 26, 2003, the FERC adopted the great majority of the proposed findings, revising only the calculation of natural gas prices for the final determina-tion of mitigated prices in the California markets. Sellers who may actu-ally have paid more for natural gas than the proxy prices adopted by the FERC have 40 days in which to submit necessary data to the FERC, after which a technical conference will be held. Finalization of refund amounts is expected in mid-2003. APS does not anticipate material changes in its exposure and still believes, subject to the finalization of the revised proxy prices, that it will be entitled to a net refund.

On November 20, 2002, the FERC reopened discovery in these proceedings pursuant to instructions of the United States Court of Appeals for the Ninth Circuit that the FERC permit parties to offer additional evidence of potential market manipulation for the period January 1, 2000 through June 20, 2001. Parties have submitted additional evidence and proposed findings, which the FERC continues to consider.

The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The FERC required that the record establish the volume of the transactions, the identifica-tion of the net sellers and net buyers, the price and terms and conditions of the sales contracts and the extent of potential refunds.

On September 24, 2001, an ALJ concluded that prices in the Pacific Northwest during the period December 25, 2000 through June 20, 2001 were the result of a number of factors in addition to price signals from the California markets, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances, the ALJ ultimately concluded that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. The FERC is currently reviewing the ALJs report and recommendations.

On December 19, 2002, the FERC opened a new discovery period to permit the parties to offer additional evidence for the period January 1, 2000 through June 20, 2001. Additional evidence has been submitted and a FERC decision on the newly submitted evidence is expected soon.

Based on public comments from the FERC, it is anticipated that this case will be sent back to the ALJ for further proceedings on spot market and balance of month transactions.

Although the FERC has not yet made a final ruling in the Pacific Northwest matter nor calculated the specific refund amounts due in California, we do not expect that the resolution of these issues, as to the amounts alleged in the proceedings, will have a material adverse impact on our financial position, results of operations or liquidity.

On March 26, 2003, FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its Staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the ISO tariff. The report also recommended that the FERC issue an order to show cause why these transactions did not violate the ISO tariff, with potential disgorgement of any unjust profits. Although APS has not yet had an opportunity to review the transactions at issue, it believes that it was not engaged in any such improper transactions.

Based on the information available, it also appears that such transac-tions would not have a material adverse impact on our financial position, results of operations or liquidity.

SCE and PG&E have publicly disclosed that their liquidity has been materially and adversely affected because of, among other things, their inability to pass on to ratepayers the prices each has paid for energy and ancillary services procured through the PX and the ISO. PG&E filed for bankruptcy protection in 2001.

We are closely monitoring developments in the California energy market and the potential impact of these developments on us and our sub-sidiaries. Based on our evaluations, we previously reserved $10 million before income taxes for our credit exposure related to the California energy situation, $5 million of which was recorded in the fourth quarter of 2000 and $5 million of which was recorded in the first quarter of 2001. Our evaluations took into consideration our range of exposure of approximately zero to $38 million before income taxes and review of likely recovery rates in bankruptcy situations.

In the second quarter of 2002, PG&E filed its Modified Second Amended Disclosure Statement and the CPUC filed its Alternative Plan of Reorganization. Both plans generally indicated that PG&E would, at the close of bankruptcy proceedings, be able to pay in full all outstand-ing, undisputed debts. As a result of these developments, the probable range of our total exposure now is approximately zero to $27 million before income taxes, and our best estimate of the probable loss is now approximately $6 million before income taxes. Consequently, we reversed $4 million of the $10 million reserve in the second quarter of 2002. We cannot predict with certainty, however, the impact that any future resolution or attempted resolution, of the California energy market situation may have on us, our subsidiaries or the regional energy market in general.

63 2002 PNW 63 California Energy Market Litigation. On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including the Company, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present. State of California v. British Columbia Power Exchange et.-al., Docket No. EL02-71-000. The complaint requests the FERC to require the wholesale sellers to refund any rates that are found to exceed just and reasonable levels. This complaint has been dis-missed by FERC and the State of California is now appealing the matter to the Ninth Circuit Court of Appeals. In addition, the State of California and others have filed various claims, which have now been consolidat-ed, against several power suppliers to California alleging antitrust viola-tions. Wholesale Electricity Antitrust Cases I and II, Superior Court in and for the County of San Diego, Proceedings Nos. 4204-00005 and 4204-00006. Two of the suppliers who were named as defendants in those matters, Reliant Energy Services, Inc. (and other Reliant entities) and Duke Energy and Trading, LLP (and other Duke entities), filed cross-claims against various other participants in the PX and ISO mar-kets, including APS, attempting to expand those matters to such other participants. APS has not yet filed a responsive pleading in the matter, but APS believes the claims by Reliant and Duke as they relate to APS are without merit.

APS was also named in a lawsuit regarding wholesale contracts in California. James Millar, et al. v. Allegheny Energy Supply, et al., United States District Court in and for the District of Northern California, Case No. C02-2855 EMC. The complaint alleges basically that the contracts entered into were the result of an unfair and unreasonable market. The PX has filed a lawsuit against the State of California regarding the seizure of forward contracts and the State has filed a cross complaint against APS and numerous other PX participants. Cal PX v. The State of California Superior Court in and for the County of Sacramento, JCCP No. 4203. Various preliminary motions are being filed and we cannot currently predict the outcome of this matter. The United States Justice Foundation is suing numerous wholesale energy contract suppliers to California, including us, as well as the California Department of Water Resources, based upon an alleged conflict of interest arising from the activities of a consultant for Edison International who also negotiated long-term contracts for the California Department of Water Resources.

McClintock, et al. v. Yudhraja, Superior Court in and for the County of Los Angeles, Case No. GC 029447. The California Attorney General has indicated that an investigation by his office did not find evidence of improper conduct by the consultant. We believe the claims against APS and us in the lawsuits mentioned in this paragraph are without merit and will have no material adverse impact on our financial position, results of operations or liquidity.

APS 401 Pinnacle West Energy 268 SunCor 64 Other (primarily APS Energy Services and Pinnacle West) 17 Total 750 Power Service Agreement By letter dated March 7, 2001, Citizens, which owns a utility in Arizona, advised APS that it believes APS overcharged Citizens by over $50 million under a power service agreement. APS believes its charges under the agreement were fully in accordance with the terms of the agreement. In addition, in testimony filed with the ACC on March 13, 2002, Citizens acknowledged, based on its review, if Citizens filed a complaint with FERC, it probably would lose the central issue in the contract interpretation dispute. APS and Citizens terminated the power service agreement effective July 15, 2001. In replacement of the power service agreement, the Company and Citizens entered into a power sale agreement under which the Company will supply Citizens with future specified amounts of electricity and ancillary services through May 31, 2008. This new agreement does not address issues previously raised by Citizens with respect to charges under the original power service agreement through June 1, 2001.

Construction Program Consolidated capital expenditures in 2003 are estimated to be (dollars in millions):

64 64 PNW 2002 2002 2001 Trust fund assets - at cost:

Fixed income securities 113 103 Domestic stock 68 61 Total 181 164 Trust fund assets - fair value:

Fixed income securities 117 106 Domestic stock 77 96 Total 194 202 See Note 2 for information on a new accounting standard on accounting for certain liabilities related to closure or removal of long-lived assets.

Pinnacle West Energys Generation Construction Pinnacle West Energys generation construction plan is as follows:

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

The Redhawk Power Plant, two 530 MW combined cycle units, near Palo Verde. Commercial operation began in July 2002. Based on an analysis of the financial situation of the Company and the market as a whole, among other things, Pinnacle West has cancelled plans to construct the additional two 530 MW combined cycle units, Redhawk Units 3 and 4. As a result we recorded a pretax charge of approxi-mately $49 million in December 2002.

The construction of an 80 MW simple-cycle power plant at Saguaro in Southern Arizona. Commercial operation began in July 2002.

Development of the 570 MW Silverhawk combined-cycle plant 20 miles north of Las Vegas, Nevada. Construction of the plant began in August 2002, with an expected commercial operation date of mid-2004. Pinnacle West Energy has signed an agreement with Las Vegas-based SNWA under which SNWA has an option to purchase a 25% interest in the project for approximately $100 million.

A Pinnacle West Energy affiliate is exploring the possibility of creating an underground natural gas storage facility on Company-owned land west of Phoenix. An analysis to determine the feasibility of the project is in progress.

Litigation We are party to various claims, legal actions and complaints arising in the ordinary course of business, including but not limited to environmen-tal matters related to the Clean Air Act, Navajo Nation issues and ADEQ issues. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our consolidated financial statements, results of operations or liquidity.

12. NUCLEAR DECOMMISSIONING COSTS APS recorded $11 million for nuclear decommissioning expense in each of the years 2002, 2001 and 2000. APS estimates it will cost approxi-mately $1.8 billion ($528 million in 2002 dollars) to decommission its share of the three Palo Verde units. The majority of decommissioning costs are expected to be incurred over a 14-year period beginning in 2024. APS charges decommissioning costs to expense over each units operating license term and APS includes them in the accumulated depreciation balance until each unit is retired. Nuclear decommissioning costs are recovered in rates.

APS current estimates are based on a 2001 site-specific study for Palo Verde that assumes the prompt removal/dismantlement method of decommissioning. An independent consultant prepared this study.

APS is required by the ACC to update the study every three years.

To fund the costs APS expects to incur to decommission the plant, APS established external decommissioning trusts in accordance with NRC regulations and ACC orders. APS invests the trust funds primarily in fixed income securities and domestic stock and classifies them as available for sale. Realized and unrealized gains and losses are reflected in accumulated depreciation in accordance with industry practice.

The following table shows the cost and fair value of our nuclear decom-missioning trust fund assets, which were reported in investments and other assets on the Consolidated Balance Sheets at December 31, 2002 and 2001 (dollars in millions):

13. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

Consolidated quarterly financial information for 2002 and 2001 is as follows:

(dollars in thousands, except per share amounts) 2002 QUARTER ENDED March 31 June 30 September 30 December 31(a)

Operating revenues (b)

Regulated electricity segment 380,241 496,837 719,361 416,584 Marketing and trading segment 75,815 49,503 87,258 113,355 Real estate segment 41,185 69,152 45,108 80,943 Other revenues (c) 4,277 2,881 21,224 33,555 Operating income 119,438 166,706 213,025 16,878 Income (loss) before accounting change 53,757 75,365 100,916 (14,885)

Cumulative effect of change in accounting - net of income tax (65,745)

Net income (loss) 53,757 75,365 100,916 (80,630)

Earnings (loss) per weighted average common share outstanding - basic:

Income before accounting change 0.63 0.89 1.19 (0.18)

Cumulative effect of change in accounting (0.77)

Earnings per weighted average common share outstanding - basic 0.63 0.89 1.19 (0.95)

Earnings (loss) per weighted average common share outstanding - diluted:

Income before accounting change 0.63 0.89 1.19 (0.18)

Cumulative effect of change in accounting (0.77)

Earnings per weighted average common share outstanding - diluted 0.63 0.89 1.19 (0.95)

Dividends declared per share 0.40 0.40 0.40 0.425 (dollars in thousands, except per share amounts) 2001 QUARTER ENDED March 31 June 30 September 30 December 31 Operating revenues (b)

Regulated electricity segment 412,807 739,317 973,398 436,569 Marketing and trading segment 258,296 233,841 141,674 17,419 Real estate segment 32,335 32,454 43,024 61,095 Other revenues 1,543 1,653 2,682 5,893 Operating income 136,646 140,010 298,752 100,615 Income before accounting change 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:

Income before accounting change 0.73 0.79 1.92 0.42 Cumulative effect of change in accounting (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:

Income before accounting change 0.73 0.79 1.91 0.42 Cumulative effect of change in accounting (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 (a) The fourth quarter of 2002 included pretax losses of $38 million related to our investment in NAC (see Note 22), a $49 million pretax write-off related to the cancellation of Redhawk Units 3 and 4 and pretax severance costs of approximately $11 million.

(b) 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. We have reclassified certain operating revenues to conform to the current presentation of netting energy trading contracts (see Note 18).

(c) NAC financial statements were fully consolidated starting in third quarter 2002 (see Note 22).

65 2002 PNW 65

66 66 PNW 2002 In May 2002, shareholders approved the 2002 Long-term Incentive Plan (2002 plan), which allows Pinnacle West to grant performance shares, stock ownership incentive awards and non-qualified and perfor-mance-accelerated stock options to key employees. The Company has reserved 6 million shares of common stock for issuance under the 2002 plan. No more than 1.8 million shares may be issued in relation to performance share awards and stock ownership incentive awards. The plan also provides for the granting of new non-qualified stock options at a price per option not less than the fair market value of the common stock at the time of grant. The stock options vest over three years, unless certain performance criteria are met which can accelerate the vesting period. The term of the option cannot be longer than 10 years and the option cannot be repriced during its term.

The 1994 plan provides for the granting of new options (which may be non-qualified stock options or incentive stock options) of up to 3.5 mil-lion shares at a price per option not less than the fair market value on the date the option is granted. The 1985 plan includes outstanding options but no new options will be granted from the plan. Options vest one-third of the grant per year beginning one year after the date the option is granted and expire ten years from the date of the grant. The 1994 plan also provides for the granting of any combination of shares of restricted stock, stock appreciation rights or dividend equivalents.

In the third quarter of 2002, we began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No.

123. The fair value method of accounting is the preferred method. In accordance with the transition requirements of SFAS No. 123, we applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock compensation expense based on the intrinsic value method allowed in APB No. 25. We record-ed approximately $500,000 in stock option expense before income taxes in our Consolidated Statements of Income in 2002. This amount may not be reflective of the stock option expense we will record in future years because stock options typically vest over several years and additional grants are generally made each year.

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure. The standard amends SFAS No. 123 to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based compensation. The standard also amends the disclosure requirements of SFAS No. 123. SFAS No. 148 is effective for fiscal years ending after December 15, 2002. We adopted the disclosure requirements in 2002.

See Note 1 for our pro forma disclosures on stock-based compensation and our weighted-average assumptions used to calculate the fair value of our stock options.

Total stock-based compensation expense, including stock option expense, was $5 million in 2002, $3 million in 2001 and $2 million in 2000.

Dilutive stock options increased average common shares outstanding by 60,975 shares in 2002, 212,491 shares in 2001 and 202,738 shares in 2000. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 84,963,921 shares in 2002, 84,930,140 shares in 2001 and 84,935,282 shares in 2000.

Options to purchase 1,629,958 shares of common stock were out-standing at December 31, 2002 but were not included in the computa-tion of diluted earnings per share because the options exercise price was greater than the average market price of the common shares.

Options to purchase shares of common stock that were not included in the computation of diluted earnings per share were 212,562 at December 31, 2001 and 517,614 at December 31, 2000.

16. STOCK-BASED COMPENSATION Pinnacle West offers stock-based compensation plans for officers and key employees of our company and our subsidiaries.

15. EARNINGS PER SHARE The following table presents earnings per weighted average common share outstanding for the years ended December 31, 2002, 2001 and 2000:

2002 2001 2000 Basic earnings per share:

Income before accounting change 2.53 3.86 3.57 Cumulative effect of change in accounting (0.77)

(0.18)

Earnings per share - basic 1.76 3.68 3.57 Diluted earnings per share:

Income before accounting change 2.53 3.85 3.56 Cumulative effect of change in accounting (0.77)

(0.17)

Earnings per share - diluted $

1.76 3.68 3.56

14. FAIR VALUE OF FINANCIAL INSTRUMENTS We believe that the carrying amounts of our cash equivalents and com-mercial paper are reasonable estimates of their fair values at December 31, 2002 and 2001 due to their short maturities.

We hold investments in debt and equity securities for purposes other than trading. The December 31, 2002 and 2001 fair values of such investments, which we determine by using quoted market prices, approximate their carrying amount.

On December 31, 2002, the carrying value of our long-term debt (excluding capitalized lease obligations) was $3.15 billion, with an estimated fair value of $3.25 billion. The carrying value of our long-term debt (excluding capitalized lease obligations) was $2.80 billion on December 31, 2001, with an estimated fair value of $2.82 billion. The fair value estimates are based on quoted market prices of the same or similar issues.

67 2002 PNW 67 The following table is a summary of the status of our stock option plans as of December 31, 2002, 2001 and 2000 and changes during the years ending on those dates:

2002 Weighted 2001 Weighted 2000 Weighted 2002 Average 2001 Average 2000 Average Shares Exercise Price Shares Exercise Price Shares Exercise Price Outstanding at beginning of year 1,832,725 39.52 1,569,171 37.55 1,441,124 33.45 Granted 603,900 (a) 38.37 444,200 42.55 451,450 43.28 Exercised (163,381) 28.25 (162,229) 28.53 (283,819) 20.90 Forfeited (88,115) 41.54 (18,417) 41.67 (39,584) 39.86 Outstanding at end of year 2,185,129 39.96 1,832,725 39.52 1,569,171 37.55 Options exercisable at year-end 1,155,357 39.66 926,315 37.41 831,537 34.37 Weighted average fair value of options granted during the year 6.16 8.84 11.81 (a) Beginning 2002, we recorded compensation expense related to stock options under SFAS No. 123 (see above discussion).

The following table summarizes information about our stock options at December 31, 2002:

Weighted Average Remaining Exercise Options Weighted-Average Contract Life Options Weighted-Average Prices Per Share Outstanding Exercise Price (Years)

Exercisable Exercise Price

$18.71-23.39 50,584 20.73 1.3 50,584 20.73 23.39-28.07 48,417 27.40 3.4 41,750 27.44 28.07-32.75 46,000 31.44 3.9 46,000 31.44 32.75-37.42 235,160 34.70 6.7 235,160 34.70 37.42-42.10 779,700 38.85 8.3 181,900 40.01 42.10-46.78 1,025,268 43.95 7.7 599,963 44.59 2,185,129 1,155,357 2002 2001 2000 Weighted Weighted Weighted Average Average Average 2002 Grant-Date 2001 Grant-Date 2000 Grant-Date Shares Fair Value Shares Fair Value Shares Fair Value Restricted stock 6,000 38.84 95,450 42.84 86,426 44.03 Performance share awards 115,975 38.37 Stock ownership incentive awards (a) 9,650 38.37 (a) Shares are based on estimated ownership of Pinnacle West common stock.

The following table is a summary of the amount and weighted-average grant date fair value of stock compensation awards granted, other than options, during the years ended December 31, 2002, 2001 and 2000:

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

our regulated electricity segment, which consists of regulated tradi-tional retail and wholesale electricity businesses and related activities, and includes electricity transmission, distribution and generation; our marketing and trading segment, which consists of our competitive business activities, including wholesale marketing and trading and APS Energy Services commodity-related energy services; and our real estate segment, which consists of SunCors real estate development and investment activities.

68 68 PNW 2002 The amounts in our other segment include activity principally related to NAC in 2002 (see Note 22), as well as the parent company and other sub-sidiaries. Financial data for the years ended December 31, 2002, 2001 and 2000 by business segments is provided as follows (dollars in millions):

Business Segments for the Year Ended December 31, 2002 Other Regulated Marketing (principally Electricity and Trading Real Estate NAC)

Total Operating revenues 2,013 326 236 62 2,637 Purchased power and fuel costs 500 194 694 Other operating expenses 659 34 205 105 1,003 Operating margin 854 98 31 (43) 940 Depreciation and amortization 416 2

5 2

425 Interest and other expense 160 (5) 8 163 Pretax margin 278 96 31 (53) 352 Income taxes 108 38 12 (21) 137 Income (loss) before accounting change 170 58 19 (32) 215 Cumulative effect of change in accounting for trading activities - net of income taxes of $43 (66)

(66)

Net income (loss) 170 (8) 19 (32) 149 Total assets 7,589 301 504 32 8,426 Capital expenditures 893 19 72 984 Business Segments for the Year Ended December 31, 2001 Regulated Marketing Electricity and Trading Real Estate Other Total Operating revenues 2,562 651 169 12 3,394 Purchased power and fuel costs 1,161 334 1,495 Other operating expenses 598 33 154 11 796 Operating margin 803 284 15 1

1,103 Depreciation and amortization 423 1

4 428 Interest and other expense 129 6

135 Pretax margin 251 283 5

1 540 Income taxes 99 112 2

213 Income before accounting change 152 171 3

1 327 Cumulative effect of change in accounting for derivatives - net of income taxes of $10 (15)

(15)

Net income 137 171 3

1 312 Total assets 6,862 589 477 11 7,939 Capital expenditures 1,004 23 80 22 1,129 Business Segments for the Year Ended December 31, 2000 Regulated Marketing Electricity and Trading Real Estate Other Total Operating revenues 2,539 418 158 4

3,119 Purchased power and fuel costs 1,066 292 1,358 Other operating expenses 532 18 134 1

685 Operating margin 941 108 24 3

1,076 Depreciation and amortization 426 1

5 432 Interest and other expense 152 (4) 148 Pretax margin 363 107 19 7

496 Income taxes 142 42 8

2 194 Net income 221 65 11 5

302 Total assets 6,213 459 429 22 7,123 Capital expenditures 665 50 715

69 2002 PNW 69

18. DERIVATIVE AND TRADING ACCOUNTING We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps.

As part of our overall risk management program, we enter into derivative transactions to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

Effective January 1, 2001, we adopted SFAS No. 133. SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value.

Changes in the fair value of derivative instruments are either recognized periodically in income or, if hedge criteria is met, in common stock equity (as a component of other comprehensive income). We use cash flow hedges to limit our exposure to cash flow variability on forecasted transactions. Hedge effectiveness is related to the degree to which the derivative contract and the hedged item are correlated. It is measured based on the relative changes in fair value between the derivative con-tract and the hedged item over time. We exclude the time value of cer-tain options from our assessment of hedge effectiveness. Any change in the fair value resulting from ineffectiveness, or the amount by which the derivative contract and the hedged commodity are not directly correlated, is recognized immediately in net income. See Note 1 for further discussion on our derivative instrument accounting policy.

In 2001, we recorded a $15 million after-tax charge in net income and a $72 million after-tax credit in common stock equity (as a compo-nent of other comprehensive income), both as cumulative effects of a change in accounting for derivatives. The charge primarily resulted from electricity option contracts. The credit resulted from unrealized gains on cash flow hedges.

In December 2001, the FASB issued revised guidance on the accounting for electricity contracts with option characteristics and the accounting for contracts that combine a forward contract and a purchased option con-tract. The effective date for the revised guidance was April 1, 2002. The impact of this guidance was immaterial to our financial statements.

During 2002, the EITF discussed EITF 02-3 and reached a consensus on certain issues. EITF 02-3 rescinded EITF 98-10 and was effective October 25, 2002 for any new contracts and on January 1, 2003 for existing contracts, with early adoption permitted. We adopted the EITF 02-3 guidance for all contracts in the fourth quarter of 2002. We record-ed a $66 million after-tax charge in net income as a cumulative effect adjustment for the previously recorded accumulated unrealized mark-to-market on energy trading contracts that did not meet the accounting definition of a derivative. As a result, our energy trading contracts that are derivatives continue to be accounted for at fair value under SFAS No. 133. Contracts that were previously marked-to-market as trading activities under EITF 98-10 that do not meet the definition of a derivative are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received. Additionally, all gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Consolidated Statements of Income on a net basis. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading activities, which continue to be accounted for in accordance with SFAS No. 133.

Both non-trading and trading derivatives are classified as assets and liabilities from risk management and trading activities in the Consolidated Balance Sheets. For non-trading derivative instruments that qualify for cash flow hedge accounting treatment, changes in the fair value of the effective portion are recognized in common stock equity (as a component of accumulated other comprehensive income (loss)).

Non-trading derivatives, or any portion thereof, that are not effective hedges are adjusted to fair value through income. Gains and losses related to non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted transaction will not occur, we discontinue the use of hedge accounting and recognize in income the unrealized gains and losses that were previously recorded in other comprehensive income (loss). In the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain in other comprehensive income (loss), and are recognized in income when the underlying transaction impacts earnings.

Derivatives associated with trading activities are adjusted to fair value through income. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business are exempt from the requirements of SFAS No. 133 under the normal purchase and sales exception and are not reflected on the balance sheet at fair value. Most of our non-trading electricity purchase and sales agreements qualify as normal purchases and sales and are exempted from recognition in the financial statements until the electricity is delivered.

EITF 02-3 requires that derivatives held for trading purposes, whether settled financially or physically, be reported in the income statement on a net basis. Conversely, all non-trading contracts and derivatives are to be reported gross in the income statement. Previous guidance under EITF 98-10 permitted non-financially settled energy trading contracts to be reported either gross or net in the income statement. Beginning in the third quarter of 2002, we netted all of our energy trading activities on the Consolidated Statements of Income and restated prior year

70 70 PNW 2002 The following table summarizes our assets and liabilities from risk management and trading activities related to system and marketing and trading at December 31, 2002 and 2001 (dollars in thousands):

Current Current Other Net December 31, 2002 Assets Investments Liabilities Liabilities Asset/(Liability)

Mark-to-market:

Marketing and Trading 17,640 51,771 (9,848)

(2,583) 56,980 System 41,522 6,971 (60,819)

(36,678)

(49,004)

Emission allowances - at cost 58,067 (14,328) 43,739 Collateral provided (held) 5,527 (22,053)

(16,526)

Total 59,162 122,336 (70,667)

(75,642) 35,189 Current Current Other Net December 31, 2001 Assets Investments Liabilities Liabilities Asset/(Liability)

Mark-to-market:

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

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

(95,159)

(106,902)

Emission allowances - at cost (3,216)

(59,164)

(62,380)

Collateral provided 55,110 55,110 Total 66,973 200,351 (35,994)

(207,576) 23,754 Credit Risk We are exposed to losses in the event of nonperformance or nonpay-ment by counterparties. We have risk management and trading con-tracts with many counterparties, including two counterparties for which a worst case exposure represents approximately 33% of our $181 mil-lion of risk management and trading assets as of December 31, 2002.

We use a risk management process to assess and monitor the financial exposure of those and all other counterparties. Despite the fact that the great majority of trading counterparties are rated as investment grade by the credit rating agencies, including the counterparties noted above, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our coun-terparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. In many contracts, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a 2002 2001 Gains/(losses) on the ineffective portion of derivatives qualifying for hedge accounting (a) 11,198 (6,056)

Losses from the discontinuance of cash flow hedges (8,820)

(4,683)

Losses from non-hedge derivatives (4,324)

(7,157)

Prior period mark-to-market losses realized upon delivery of commodities 8,005 25,948 Total pretax gain 6,059 8,052 (a) Time value component of options excluded from assessment of hedge effectiveness.

amounts for all periods presented. Reclassification of such trading activity to a net basis of reporting resulted in reductions in both rev-enues and purchased power and fuel costs, but did not have any impact on our financial condition, results of operations or cash flows.

Our assets and liabilities from risk management and trading activities are presented in two categories consistent with our business segments:

System - our regulated electricity business segment, which consists of non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for our Native Load requirements; and Marketing and Trading - our non-regulated, competitive business segment, which includes both non-trading and trading derivative instruments.

As of December 31, 2002, the maximum length of time over which we are hedging our exposure to the variability in future cash flows for fore-casted transactions is approximately seven years. During the twelve months ending December 31, 2003, we estimate that a net loss of $26 million before income taxes will be reclassified from accumulated other comprehensive loss as an offset to the effect on earnings of market price changes for the related hedged transactions.

The changes in derivative fair value included in the Consolidated Statements of Income for the years ended December 31, 2002 and 2001 are comprised of the following (dollars in thousands):

71 2002 PNW 71 single counterparty. Credit valuation adjustments are established repre-senting our estimated credit losses on our overall exposure to counter-parties. See Mark-to-Market Accounting in Note 1 for a discussion of our credit valuation adjustment policy.

19. OTHER INCOME AND OTHER EXPENSE The following table provides detail of other income and other expense for the years ended December 31, 2002, 2001 and 2000 (dollars in thousands):

APS is also exposed to losses under the Palo Verde sale-leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2002, APS would have been required to assume approximately $285 million of debt and pay the equity participants approximately $200 million.

21. INTANGIBLE ASSETS On January 1, 2002, we adopted SFAS No. 142, Goodwill and Other Intangible Assets. This statement addresses financial accounting and reporting for acquired goodwill and other intangible assets and super-sedes APB Opinion No. 17, Intangible Assets. We have no goodwill recorded and have separately disclosed other intangible assets on our Consolidated Balance Sheets. The intangible assets continue to be amortized over their finite useful lives. Thus, there was no impact on our financial position as a result of the adoption of SFAS No. 142. The Companys gross intangible assets (which are primarily software) were

$214 million at December 31, 2002 and $175 million at December 31, 2001. The related accumulated amortization was $104 million at December 31, 2002 and $88 million at December 31, 2001.

Amortization expense was $21 million in 2002, $22 million in 2001 and

$20 million in 2000. Estimated amortization expense on existing intangi-ble assets over the next five years is $25 million in 2003, $24 million in 2004, $23 million in 2005, $21 million in 2006 and $15 million in 2007.

22. EL DORADOS INVESTMENT IN NAC Through our unregulated wholly-owned subsidiary, El Dorado, we own a majority interest in NAC, a company that develops, markets and con-tracts for the manufacture of cask designs for spent nuclear fuel storage and transportation. Prior to the third quarter of 2002, our investment in NAC was accounted for under the equity method and our share of NACs earnings and losses was recorded in other income or expense in our Consolidated Statements of Income. Beginning in the third quarter of 2002, we fully consolidated NACs financial statements after acquiring a controlling interest in NAC as a result of increased voting representa-tion on NACs Board of Directors. During the second and third quarters of 2002, we recorded cumulative losses of approximately $21 million before tax ($13 million after tax, $0.15 per share) related to NAC, primarily as a result of expected losses under contracts with two customers, including a contract between NAC and Maine Yankee Atomic Power Company (Maine Yankee).

year ended December 31, 2002 2001 2000 Other income:

Environmental insurance recovery

$ 12,349 Equity earnings - net 6,882 Interest income 4,410 6,763 8,291 SunCor joint venture earnings 7,471 3,687 3,208 Miscellaneous 3,223 3,617 3,451 Total other income 15,104

$ 26,416 21,832 Other expense:

Equity losses - net (a)

$ (10,439)

(5,126)

Non-operating costs -

SunCor (7,000)

Non-operating costs (b)

(19,430)

(16,807)

(16,044)

Miscellaneous (3,786)

(4,644)

(9,285)

Total other expense

$ (33,655)

$ (33,577)

$ (25,329)

(a) Primarily related to El Dorados investment losses in NAC prior to consolidation in the third quarter of 2002 (see Note 22).

(b) As defined by the FERC, includes below-the-line non-operating utility costs (primarily community relations and environmental compliance).

20. VARIABLE INTEREST ENTITIES In January 2003, the FASB issued FIN No. 46, Consolidation of Variable Interest Entities. FIN No. 46 requires that we consolidate a VIE if we have a majority of the risk of loss from the VIEs activities or we are entitled to receive a majority of the VIEs residual returns or both. A VIE is a corporation, partnership, trust or any other legal structure that either does not have equity investors with voting rights or has equity investors that do not provide sufficient financial resources for the entity to support its activities. FIN No. 46 is effective immediately for any VIE created after January 31, 2003 and is effective July 1, 2003 for VIEs created before February 1, 2003.

In 1986, APS entered into agreements with three separate SPE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. See Note 9 for further information about the sale-leaseback transactions. Based on our preliminary assessment of FIN No. 46, we do not believe we will be required to consolidate the Palo Verde SPEs.

However, we continue to evaluate the requirements of the new guidance to determine what impact, if any, it will have on our financial statements.

72 72 PNW 2002 On January 15, 2003, Maine Yankee notified NAC of its intention to terminate its contract with NAC. We recorded additional NAC losses of approximately $38 million before tax ($23 million after tax, or $0.27 per share) in the fourth quarter of 2002, the substantial majority of which relate to the termination of the Maine Yankee contract. As a result, in 2002, we recorded NAC losses of approximately $59 million before tax

($35 million after tax, or $0.42 per share).

NAC Litigation On March 4, 2003, Maine Yankee Atomic Power Co.

filed suit against Pinnacle West, NAC and a surety company in federal court in Portland, Maine. Maine Yankee Atomic Power Company v.

United States Fire Insurance Company, Civil Action Docket No. 03 PC, United States District Court, District of Maine. The lawsuit alleges that NAC failed to meet its contractual obligations with respect to cer-tain of NACs activities relating to the decommissioning of the Maine Yankee nuclear power plant. The lawsuit was filed a few weeks after NAC initiated arbitration against Maine Yankee with respect to matters relating to the same contract. The lawsuit seeks recovery under a parental guarantee signed by Pinnacle West relating to certain of NACs contractual obligations and under performance and payment bonds issued by the surety which are guaranteed (at least in part) by Pinnacle West. Maine Yankee also alleges damages in excess of $1 million. We are currently evaluating the allegations of the lawsuit and expect to vigorously defend our position.

23. GUARANTEES On January 1, 2003, we adopted FIN No. 45, Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guaran-tees of Indebtedness of Others. FIN No. 45 elaborates on the disclo-sures to be made by a guarantor in its financial statements about its obligations under certain guarantees. It also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The disclo-sure provisions are effective for the year ended December 31, 2002.

The initial recognition and measurement provisions of FIN No. 45 are effective on a prospective basis to guarantees issued or modified after December 31, 2002.

We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our unregulated subsidiaries. Our parental guarantees related to Pinnacle West Energy consist of equipment and performance guarantees related to our generation construction pro-gram, transmission service guarantees for West Phoenix Units 4 and 5 and long-term service agreement guarantees for new power plants.

Our credit support instruments enable APS Energy Services to provide commodity energy and energy-related products and enable El Dorado to support the activities of NAC. SunCor has a debt guarantee on behalf of an affiliated joint venture. Non-performance or payment under the original contract by our unregulated subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Consolidated Balance Sheets related to Pinnacle Wests guarantees on behalf of its subsidiaries. Our guarantees have no recourse (except NAC) or collateral provisions to allow us to recover amounts paid under the guarantee.

Surety Surety Letters Letters Guarantees Guarantees Bonds Bonds of Credit of Credit Amount Term (in years)

Amount Term (in years)

Amount Term (in years)

Parental:

Pinnacle West Energy 126 1 to 2 42 1 to 2 APS Energy Services 82 less than 2 43 less than 1 El Dorado (all NAC) 43 1 to 3 SunCor guarantees 33 1

Total 284 43 42 The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at December 31, 2002 are as follows (dollars in millions):

73 2002 PNW 73 At December 31, 2002, we had entered into approximately $42 million of letters of credit which support various construction agreements.

These letters of credit expire in 2003 and 2004. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2002, approximately

$258 million of letters of credit were outstanding to support existing pollution control bonds of approximately $253 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations. These letters of credit have expiration dates in 2003.

APS has also entered into approximately $115 million of letters of credit to support certain equity lessors in the Palo Verde sale-leaseback trans-actions (see Note 9 for further details on the Palo Verde sale-leaseback transactions). These letters of credit expire in 2005. Additionally, APS has approximately $5 million of letters of credit related to counterparty collateral requirements and approximately $5 million of letters of credit related to workers compensation expiring in 2003. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

In conjunction with our financing agreements, including our sale-lease-back transactions, we generally provide indemnifications relating to liabilities arising from or related to the agreements, except with certain limited exceptions depending on the particular agreement. APS has also provided indemnifications to the equity participants and other parties in the Palo Verde sale-leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification and therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnifications is likely and therefore no related liability has been recorded.

24. SUBSEQUENT EVENTS See ACC Applications in Note 3 for information regarding the ACCs approval on March 27, 2003 of a $500 million financing arrangement between APS and Pinnacle West Energy and Track B Order in Note 3 for information regarding the ACC order issued on March 14, 2003, mandating a process by which APS must competitively procure energy.

See California Energy Issues and Refunds in the Pacific Northwest in Note 11 for information regarding the FERCs adoption on March 26, 2003 of an ALJs proposed findings, and issuance on March 26, 2003 of a Final Report on Price Manipulation in Western Markets.

See Note 22 for information related to the March 4, 2003 NAC litigation.

74 74 PNW 2002

1. PAMELA GRANT, (64) 1980* Civic Leader COMMITTEES: Human Resources, Chairman; Audit; Corporate Governance 2. MARTHA O. HESSE, (60) 1991 President, Hesse Gas Company COMMITTEES:

Audit, Chairman; Finance and Operating; Corporate Governance 3. THE REV. BILL JAMIESON, JR., (59) 1991 President, Institute for Servant Leadership of Asheville, North Carolina COMMITTEES: Human Resources; Corporate Governance 4. ROY A. HERBERGER, JR., (60) 1992 President, Thunderbird, The American Graduate School of International Management COMMITTEES: Finance and Operating, Chairman; Human Resources; Corporate Governance 5. ROBERT G. MATLOCK, (69) 1993 Management Consultant, R.G. Matlock & Associates, Inc. COMMITTEES: Human Resources; Corporate Governance 6. WILLIAM J. POST, (52) 1994 Chairman of the Board & Chief Executive Officer COMMITTEE: Finance and Operating 7. HUMBERTO S. LOPEZ, (57) 1995 President, HSL Properties, Inc.

COMMITTEES: Audit; Corporate Governance 8. MICHAEL L. GALLAGHER, (58) 1997 Chairman Emeritus, Gallagher & Kennedy, P.A. COMMITTEES:

Human Resources; Corporate Governance, Presiding Director 9. BRUCE J. NORDSTROM, (53) 1997 Certified Public Accountant, Nordstrom and Associates, P.C. COMMITTEES: Audit; Corporate Governance 10. JACK E. DAVIS, (56) 1998 President COMMITTEE: Finance and Operating

11. WILLIAM L. STEWART, (59) 1998** 12. EDDIE BASHA, (65) 1999 Chairman of the Board, Bashas COMMITTEES: Audit; Corporate Governance

13. KATHRYN L. MUNRO, (54) 1999 Chairman, BridgeWest L.L.C. COMMITTEES: Finance and Operating; Corporate Governance 1.

6.

11.

12.

13.

7.

8.

9.

2.

3.

4.

5.

10.

Board of Directors

• The year in which the individual first joined the Board of a Pinnacle West company.

• • William Stewart announced his retirement from the company effective Dec. 1, 2003. He will be transitioning his duties to other officers in the company until his retirement.

75 2002 PNW 75 PINNACLE WEST William J. Post (52) 1973*

Chairman of the Board

& Chief Executive Officer Jack E. Davis (56) 1973 President Armando B. Flores (59) 1991 Executive Vice President, Corporate Business Services ARIZONA PUBLIC SERVICE William J. Post Chairman of the Board Jack E. Davis President & Chief Executive Officer James M. Levine (53) 1989 Executive Vice President, Generation Donald E. Brandt Senior Vice President

& Chief Financial Officer PINNACLE WEST ENERGY James M. Levine President

& Chief Executive Officer Ajoy K. Banerjee (57) 1999 Vice President, Construction & Operations Warren C. Kotzmann (53) 1989 Vice President, Financial

& Corporate Services

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

Officers Donald E. Brandt (48) 2002 Senior Vice President

& Chief Financial Officer Robert S. Aiken (46) 1986 Vice President, Federal Affairs John G. Bohon (57) 1971 Vice President, Corporate Services & Human Resources Dennis L. Brown (52) 1973 Vice President

& Chief Information Officer Edward Z. Fox (49) 1995 Vice President, Communications, Environment & Safety Nancy C. Loftin (49) 1985 Vice President, General Counsel

& Secretary Martin L. Shultz (58) 1979 Vice President, Government Affairs Barbara M. Gomez (48) 1978 Treasurer Gregg R. Overbeck (56) 1990 Senior Vice President, Nuclear Generation Steven M. Wheeler (54) 2001 Senior Vice President, Regulation, System Planning

& Operations Jan H. Bennett (55) 1967 Vice President, Customer Service Ajit P. Bhatti (57) 1973 Vice President, Resource Planning John R. Denman (60) 1964 Vice President, Fossil Generation Chris N. Froggatt (45) 1986 Vice President & Controller David A. Hansen (43) 1980 Vice President, Power Marketing & Trading Nancy C. Loftin Vice President, General Counsel

& Secretary David Mauldin (53) 1990 Vice President, Nuclear Engineering Donald G. Robinson (49) 1978 Vice President, Finance & Planning Barbara M. Gomez Treasurer SUNCOR DEVELOPMENT William J. Post Chairman of the Board John C. Ogden (57) 1972 President

& Chief Executive Officer Geoffrey L. Appleyard (49) 1987 Vice President

& Chief Financial Officer Duane S. Black (50) 1989 Vice President

& Chief Operating Officer Jay T. Ellingson (54) 1992 Vice President, Development - Palm Valley Steven Gervais (47) 1987 Vice President & General Counsel Margaret E. Kirch (53) 1988 Vice President, Commercial Development Thomas A. Patrick (49) 1995 Vice President, Golf Operations APS ENERGY SERVICES Vicki G. Sandler (46) 1982 President, APS Energy Services EL DORADO INVESTMENT William J. Post Chairman of the Board, President

& Chief Executive Officer

76 76 PNW 2002 Campbell Fisher Design CORPORATE HEADQUARTERS 400 North 5th Street P.O. Box 53999 Phoenix, Arizona 85004 Main telephone number: (602) 250-1000 ANNUAL MEETING OF SHAREHOLDERS Wednesday, May 21, 2003 10:30 a.m.

The Herberger Theatre 222 East Monroe Street Phoenix, Arizona 85004 STOCK LISTING Ticker symbol: PNW on New York Stock Exchange and Pacific Stock Exchange Newspaper financial listings: PinWst FORM 10-K Pinnacle Wests Annual Report to the Securities and Exchange Commission on Form 10-K will be available (after April 1, 2003) to shareholders upon written request, without charge.

Write: Office of the Secretary.

INVESTORS ADVANTAGE PLAN Pinnacle West offers a direct stock purchase plan. Any interested investor may purchase Pinnacle West common stock through the Investors Advantage Plan. Features of the Plan include a variety of options for reinvesting dividends, direct deposit of cash dividends, automatic monthly investment, certificate safekeeping, reduced brokerage commissions and more. An Investors Advantage Plan prospectus and enrollment materials may be obtained by calling the Company at (800) 457-2983, at the corporate Web site -

www.pinnaclewest.com, or by writing to:

Pinnacle West Capital Corporation Shareholder Department P.O. Box 52133 Phoenix, AZ 85072-2133 CORPORATE WEB SITE www.pinnaclewest.com TRANSFER AGENTS AND REGISTRAR Common Stock Pinnacle West Capital Corporation Stock Transfer Department P.O. Box 52134 Phoenix, Arizona 85072-2134 Or:

400 North 5th Street Phoenix, Arizona 85004 Telephone: (602) 250-5506 SHAREHOLDER ACCOUNT AND ADMINISTRATIVE INFORMATION Shareholder Department telephone number (toll-free): (800) 457-2983 STATISTICAL REPORT A detailed Statistical Report for Financial Analysis for 1997-2002 will be available in April on the Companys Web site or by writing to the Investor Relations Department.

INVESTOR RELATIONS CONTACT Rebecca L. Hickman Director, Investor Relations P.O. Box 53999 Station 9998 Phoenix, Arizona 85072-3999 Telephone: (602) 250-5668 Fax: (602) 250-2789 STATEWIDE ASSOCIATION FOR UTILITY INVESTORS The Arizona Utility Investors Association represents the interests of investors in Arizona utilities. If interested, send your name and address to:

Arizona Utility Investors Association P.O. Box 34805 Phoenix, Arizona 85067 (602) 257-9200 www.auia.org ENVIRONMENTAL, HEALTH AND SAFETY REPORT To view the APS Environmental, Health and Safety Report please visit www.aps.com, or to receive a printed summary report, call (602) 250-3282.\\

IMPORTANT NOTICE TO SHAREHOLDERS:

Pinnacle West posts quarterly results and other important information on its Web site (www.pinnaclewest.com). If you would like to receive news by regular mail, fax or e-mail, let us know by mail or phone at the addresses and numbers listed on this page.

Also, let us know if you would like to be kept abreast of legislative and regulatory activities at the state and federal levels that could impact investor-owned utilities.

Shareholder Information

Pinnacle West Capital Corporation 2002 ANNUAL REPORT