NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. The condensed consolidated financial statements include the accounts of Pinnacle West and its subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor, and El Dorado . All significant intercompany balances have been eliminated. We have reclassified certain prior year amounts to conform to the current year presentation.

2. Our unaudited condensed consolidated financial statements reflect all adjustments which we believe are necessary for the fair presentation of our financial position and results of operations for the periods presented. These adjustments are of a normal recurring nature with the exception of the extraordinary charge and the tax benefit from discontinued operations. We suggest that these Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements be read along with the Consolidated Financial Statements and Notes to Consolidated Financial Statements included in our 1999 10-K.

3. Weather conditions and wholesale power marketing and trading activities can have significant impacts on our results for interim periods. El Dorado's earnings are subject to stock market volatility (see Note 12). For these and other reasons, results for interim periods do not necessarily represent results to be expected for the year.

4. See "Liquidity and Capital Resources" in Part I, Item 2 of this report for changes in capitalization for the six months ended June 30, 2000.

5. Regulatory Accounting

For regulated operations, APS prepares its financial statements in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements.

During 1997, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) issued EITF 97-4. EITF 97-4 requires that SFAS No. 71 be discontinued no later than when legislation is passed or a rate order is issued that contains sufficient detail to determine its effect on the portion of the business being deregulated, which could result in write-downs or write-offs of physical and/or regulatory assets. Additionally, the EITF determined that regulatory assets should not be written off if they are to be recovered from a portion of the entity which continues to apply SFAS No. 71.

The Settlement Agreement was approved by the ACC in September 1999 (see Note 6 for a discussion of the agreement). Consequently, APS has discontinued the application of SFAS No. 71 for its generation operations. This means that the generation assets were tested for impairment and the portion of regulatory assets deemed to be unrecoverable through ongoing regulated cash flows was eliminated. APS determined that the generation assets were not impaired. A regulatory disallowance removed $234 million pretax ($183 million net present value) from ongoing regulatory cash flows and was recorded as a net

reduction of regulatory assets. This reduction ($140 million after income taxes) was reported as an extraordinary charge on the income statement during the third quarter of 1999. Prior to the Settlement Agreement, under the 1996 regulatory agreement (see Note 6), the ACC accelerated the amortization of substantially all of APS' regulatory assets to an eight-year period ending June 30, 2004.

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

                                               1/1 - 6/30
1999      2000      2001      2002      2003      2004     Total
----      ----      ----      ----      ----      ----     -----
$164      $158      $145      $115      $86       $18      $686

The majority of APS' regulatory assets relate to deferred income taxes and rate synchronization cost deferrals.

The condensed consolidated balance sheets include the amounts listed below for generation assets not subject to SFAS No. 71 (thousands of dollars):

                                                    June 30,       December 31,
                                                      2000            1999
                                                   -----------     -----------
Electric plant in service & held for future use    $ 3,761,855     $ 3,770,234
Accumulated depreciation and amortization           (1,678,752)     (1,641,855)
Construction work in progress                          140,037          87,819
Nuclear fuel, net of amortization                       47,864          49,114

6. Regulatory Matters -- Electric Industry Restructuring

STATE

SETTLEMENT AGREEMENT. On May 14, 1999, APS entered into a comprehensive Settlement Agreement with various parties, including representatives of major consumer groups, related to the implementation of retail electric competition. On September 23, 1999, the ACC voted to approve the Settlement Agreement, with some modifications. On December 13, 1999, two parties filed lawsuits challenging the ACC's approval of the Settlement Agreement. One of the parties questioned the authority of the ACC to approve the Settlement Agreement and both parties challenged several specific provisions of the Settlement Agreement. A decision on the appeals to the Settlement Agreement is not expected until later this year or next year.

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

* APS will reduce rates for standard offer service for customers with loads less than 3 megawatts in a series of annual retail electric price reductions of 1.5% beginning

July 1, 1999 through July 1, 2003, for a total of 7.5%. The first reduction of approximately $24 million ($14 million after income taxes) included the July 1, 1999 retail price decrease of approximately $11 million annually ($7 million after income taxes) related to the 1996 regulatory agreement. See "1996 Regulatory Agreement" below. Based on the price reduction authorized in the Settlement Agreement, there was a retail price decrease of approximately $28 million ($17 million after taxes), or 1.5%, effective July 1, 2000. For customers having loads 3 megawatts or greater, standard offer rates will be reduced in varying annual increments that total 5% through 2002.

* Unbundled rates being charged by APS for competitive direct access service (for example, distribution services) became effective upon approval of the Settlement Agreement, retroactive to July 1, 1999, and also will be 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 limited circumstances. Neither the ACC nor APS will be prevented from seeking or authorizing rate changes prior to July 1, 2004 in the event of conditions or circumstances that constitute an emergency, such as an inability to finance on reasonable terms, or material changes in APS' cost of service for ACC-regulated services resulting from federal, tribal, state or local laws, regulatory requirements, judicial decisions, actions or orders.

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

* APS' distribution system opened for retail access effective September 24, 1999. Customers will be eligible for retail access in accordance with the phase-in adopted by the ACC under the electric competition rules (see "Retail Electric Competition Rules" below), with an additional 140 megawatts being made available to eligible non-residential customers. Unless subject to judicial or regulatory restraint, APS will open its distribution system to retail access for all customers on January 1, 2001.

* Prior to the Settlement Agreement, APS was recovering substantially all of its regulatory assets through July 1, 2004, pursuant to the 1996 regulatory agreement. In addition, the Settlement Agreement states that APS has demonstrated that its allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value. APS will not be allowed to recover $183 million net present value of the above amounts. The Settlement Agreement provides that APS will have the opportunity to recover $350 million net present value through a competitive transition charge (CTC) that will remain in effect through December 31, 2004, at which time it will terminate. Any over/under-recovery will be

credited/debited against the costs subject to recovery under the adjustment clause described above.

* APS will form a separate corporate affiliate or affiliates and transfer to that affiliate(s) its generating assets and competitive services at book value as of the date of transfer, which transfer shall take place no later than December 31, 2002. APS will be allowed to defer and later collect, beginning July 1, 2004, sixty-seven percent of its costs to accomplish the required transfer of generation assets to an affiliate.

* When the Settlement Agreement approved by the ACC is no longer subject to judicial review, APS will move to dismiss all of its litigation pending against the ACC as of the date it entered into the Settlement Agreement. To protect APS' rights, it has several lawsuits pending on ACC orders relating to stranded cost recovery and the adoption and amendment of the ACC's electric competition rules, which would be voluntarily dismissed at the appropriate time under this provision.

As discussed in Note 5 above, APS has discontinued the application of SFAS No. 71 for its generation operations.

RETAIL ELECTRIC COMPETITION RULES. On September 21, 1999, the ACC voted to approve the rules that provide a framework for the introduction of retail electric competition in Arizona (Rules). If any of the Rules conflict with the Settlement Agreement, the terms of the Settlement Agreement govern. On December 8, 1999, APS filed a lawsuit to protect its legal rights regarding the Rules. This lawsuit is pending, along with several other lawsuits on ACC orders relating to stranded cost recovery and the adoption or amendment of the Rules, but two related cases filed by other utilities have been partially decided in a manner adverse to those utilities' positions.

On July 12, 2000, a Maricopa County Superior Court judge issued a preliminary ruling in favor of the ACC and denied substantive challenges to the Rules that had been made by the electric cooperatives. However, he concluded that some of the Rules were invalid because of procedural deficiencies. Specifically, the judge concluded that several non-ratemaking Rules were required to be presented to the Arizona Attorney General for certification. Additionally, the judge determined that the Arizona Constitution requires the ACC to make findings regarding the fair value of property in Arizona of competitive electric service providers. We do not believe that the ruling affects the Settlement Agreement with the ACC. The Settlement Agreement was not at issue in the consolidated cases before the judge. Further, the ACC made findings related to fair value of APS' property in the order approving the APS Settlement Agreement.

The ruling does not immediately affect the Rules. APS expects that, in the next few weeks, the court will consider proposed forms of judgment which will establish the specific impact of the ruling. Although the ACC has not yet indicated what steps it intends to take after a judgment is issued, the ACC could appeal the ruling to the Court of Appeals or could elect to take corrective action to correct the procedural deficiencies identified in the judge's ruling. The cooperatives may also appeal the ruling. There is authority indicating that if the order is appealed by the ACC, it will be automatically stayed pending further judicial review. Certain

other appeals of the Rules are still pending in the Maricopa County Superior Court. We believe that the court may rule on the remaining appeals later this year or next year.

On January 14, 2000, a special action was filed requesting the Arizona Supreme Court to enjoin implementation of the Rules and decide whether the ACC can allow the competitive marketplace, rather than the ACC, to set just and reasonable rates under the Arizona Constitution. The issue of competitively set rates has been decided by lower Arizona courts in favor of the ACC in four separate lawsuits, two of which relate to telecommunications companies. The Supreme Court denied to hear the case as a special action on March 17, 2000. The lower court litigation will continue.

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

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

* The Rules require each affected utility, including APS, to make available at least 20% of its 1995 system retail peak demand for competitive generation supply beginning when the ACC makes a final decision on each utility's stranded costs and unbundled rates (Final Decision Date) or January 1, 2001, whichever is earlier, and 100% beginning January 1, 2001. Under the Settlement Agreement, APS will provide retail access to customers representing the minimum 20% required by the ACC and an additional 140 megawatts of non-residential load in 1999, and to all customers as of January 1, 2001, or such other dates as approved by the ACC.

* Subject to the 20% requirement, all utility customers with single premise loads of one megawatt or greater will be eligible for competitive electric services on the Final Decision Date, which for APS' customers was the approval of the Settlement Agreement. Customers may also aggregate smaller loads to meet this one megawatt requirement.

* When effective, residential customers will be phased in at 1.25% per quarter calculated beginning on January 1, 1999, subject to the 20% requirement above.

* Electric service providers that get Certificates of Convenience and Necessity (CC&Ns) from the ACC can supply only competitive services, including electric generation, but not electric transmission and distribution.

* Affected utilities must file ACC tariffs that unbundle rates for non-competitive services.

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

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

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

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

 Annual Electric            Percentage
Revenue Decrease             Decrease              Effective Date
----------------             --------              --------------
      $49                      3.4%                July 1, 1996
      $18                      1.2%                July 1, 1997
      $17                      1.1%                July 1, 1998
      $11                      0.7%                July 1, 1999 (a)

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

The regulatory agreement also required the parent company to infuse $200 million of common equity into APS in annual payments of $50 million from 1996 through 1999. All of these equity infusions were made by December 31, 1999.

LEGISLATION. In May 1998, a law was enacted to facilitate implementation of retail electric competition in Arizona. The law includes the following major provisions:

* Arizona's largest government-operated electric utility (Salt River Project) and, at their option, smaller municipal electric systems must (i) make at least 20% of their 1995 retail peak demand available to electric service providers by December 31, 1998 and for all retail customers by December 31, 2000; (ii) decrease rates by at least 10% over a ten-year period beginning as early as January 1, 1991; (iii) implement procedures and public processes comparable to those already applicable to public service corporations for establishing the terms, conditions, and pricing of electric services as well as certain other decisions affecting retail electric competition;

* describes the factors which form the basis of consideration by Salt River Project in determining stranded costs; and

* metering and meter reading services must be provided on a competitive basis during the first two years of competition only for customers having demands in excess of one megawatt (and that are eligible for competitive generation services), and thereafter for all customers receiving competitive electric generation.

GENERAL

We cannot accurately predict the impact of full retail competition on our financial position, cash flows, or results of operations. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position the Company and our subsidiaries to compete in the new regulatory environment.

FEDERAL

The Energy Policy Act of 1992 and recent rulemakings by FERC have promoted increased competition in the wholesale electric power markets. APS does not expect these rules to have a material impact on its financial statements.

Several electric utility industry restructuring bills have been introduced during the current congressional session. Several of these bills are written to allow consumers to choose their electricity suppliers beginning in 2000 and beyond. These bills, other bills that are expected to be introduced, and ongoing discussions at the federal level suggest a wide range of opinion that will need to be narrowed before any comprehensive restructuring of the electric utility industry can occur.

7. Nuclear Insurance

The Palo Verde participants have insurance for public liability payments 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 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 assessment per reactor under the program for each nuclear incident is approximately $88 million, subject to an annual limit of $10 million per incident. Based upon APS' 29.1% interest in the three Palo Verde units, APS' maximum potential assessment per incident is approximately $77 million, with an annual payment limitation of approximately $9 million.

The Palo Verde participants maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and 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.

8. Business Segments

We have two principal business segments (determined by products, services and regulatory environment) which consist of the transmission and distribution of electricity and wholesale power marketing and trading activities (delivery business segment) and the generation of electricity (generation business segment). We plan to move our wholesale power marketing and trading activities from APS to the parent company by the end of 2000. The other amounts include activity relating to the parent company and other subsidiaries including APS Energy Services, SunCor and El Dorado. Eliminations primarily relate to intersegment sales of electricity. Segment information for the three, six and twelve months ended June 30, 2000 and 1999 is as follows (millions of dollars):

                                     3 Months Ended       6 Months Ended        12 Months Ended
                                        June 30,              June 30,              June 30,
                                     --------------       ---------------       ----------------
                                     2000      1999       2000       1999       2000        1999
                                     ----      ----       ----       ----       ----        ----
Operating Revenues:
Delivery                             $ 719     $ 511     $ 1,165     $ 925     $ 2,533     $ 2,110
Generation                             249       220         428       396         886         877
Other                                   38        33          80        58         152         118
Eliminations                          (249)     (220)       (428)     (396)       (886)       (877)
                                     -----     -----     -------     -----     -------     -------
     Total                           $ 757     $ 544     $ 1,245     $ 983     $ 2,685     $ 2,228
                                     =====     =====     =======     =====     =======     =======

Income from Continuing Operations:
Delivery                             $  55     $  34     $    80     $  55     $   172     $   144
Generation                              40        36          48        47         121         125
Other                                   (5)       (1)         16        (3)         21          (7)
                                     -----     -----     -------     -----     -------     -------
     Total                           $  90     $  69     $   144     $  99     $   314     $   262
                                     =====     =====     =======     =====     =======     =======

                                                             As of June 30,     As of December 31,
                                                                  2000                1999
                                                                  ----                ----
Assets:
Delivery                                                         $3,938              $3,796
Generation                                                        2,381               2,342
Other                                                               525                 471
                                                                 ------              ------
     Total                                                       $6,844              $6,609
                                                                 ======              ======

9. Accounting Matters

In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, which is effective for us in 2001. 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. The standard also provides specific guidance for accounting for derivatives designated as hedging instruments. We are currently evaluating what impact this standard will have on our financial statements.

10. Generation Expansion

Pinnacle West Energy has announced plans to build and acquire up to 4,000 MW of generating capacity from 2001-2006 at an estimated cost of about $2 billion, assuming all of the announced plants are built or acquired.

Pinnacle West Energy is also considering additional expansion over the next several years, which may result in additional expenditures. Pinnacle West Energy's expenditures are expected to be funded through debt issued directly by Pinnacle West Energy, as well as capital infusions from the parent company's internally generated cash and debt proceeds.

Pinnacle West Energy is currently planning a 650-megawatt expansion of the West Phoenix Power Plant and the construction of a natural gas-fired electric generating station of up to 2,120 megawatts near Palo Verde, called Redhawk (see discussion in the following paragraph). Construction at West Phoenix began in July 2000, with commercial operation of the first unit expected in the summer of 2001. Pinnacle West Energy also expects that construction will begin on the first two units of Redhawk near the end of 2000, with commercial operation scheduled for the summer of 2002.

Pinnacle West Energy and Reliant have terminated discussions on joint development of the first two Redhawk units and three units in Nevada. Pinnacle West Energy currently plans to keep the first two units (1,060 megawatts) of the Redhawk project on schedule.

Projected capital expenditures for the above expansion plans on the current schedule are estimated to be $277 million in 2000, $392 million in 2001, and $141 million in 2002.

On April 27, 2000, Pinnacle West Energy entered into two separate agreements with SCE to purchase SCE's 15.8% ownership interest in Palo Verde and its 48% ownership interest in Units 4 and 5 of the Four Corners Power Plant (Four Corners). The purchase price is $550 million in cash to be paid at closing, subject to certain adjustments. The interests to be acquired represent 1,310 MW of generating capacity (600 MW associated with SCE's Palo Verde interest, and 710 MW associated with SCE's Four Corners interest). The transactions are expected to close in mid-2001, subject to the approval of various governmental authorities, including the CPUC, the FERC, the Nuclear Regulatory Commission, the Internal Revenue Service, and the Navajo Nation.

The agreements between Pinnacle West Energy and SCE include the following additional terms:

* Prior to and up to 90 days following SCE's filing with the CPUC seeking approval of the transactions, which was made on May 15, 2000, SCE was allowed to solicit offers for, or indications of interest in, (a) its Four Corners interest or (b) its Four Corners interest and its Palo Verde interest. SCE's sale of its interest in Four Corners is also subject to a right of first refusal on the part of the other Four Corners participants, including APS. Pinnacle West Energy had the right to match any offer or indication of interest that SCE

received during this period. This period has expired without Pinnacle West Energy matching an indication of interest.

* The Agreements permit SCE, for a period of up to 120 days (until early December), to engage in further negotiations and discussions with any party who submitted an indication of interest. Subject to CPUC approval, Pinnacle West Energy retains the right under the Agreements to match the terms of any binding agreement that SCE elects to enter into.

* Pinnacle West Energy is not obligated to purchase SCE's Four Corners interest unless SCE also sells its Palo Verde interest to Pinnacle West Energy. SCE is not obligated to sell its Palo Verde interest to Pinnacle West Energy unless Pinnacle West Energy (or some other third party) purchases SCE's Four Corners interest.

* SCE will transfer the assets of its Palo Verde decommissioning fund to Pinnacle West Energy, and Pinnacle West Energy will assume SCE's Palo Verde decommissioning obligations.

* Pinnacle West Energy will assume SCE's obligations and liabilities associated with ownership of its interests in Palo Verde and Four Corners, subject to specified exceptions.

* We guaranteed Pinnacle West Energy's obligations under each of the agreements, including Pinnacle West Energy's purchase price obligations.

The Utility Reform Network, which represents the interests of SCE's residential and small commercial customers, has filed a protest with the CPUC recommending that the CPUC reject the sale and require SCE to retain the generating facilities. The California Office of Ratepayer Advocates has also filed objections regarding various aspects of the proposed transactions. There can be no assurance that other protests will not be filed with the CPUC.

11. Income Tax Benefit

In September 1999, we recorded a tax benefit of $38 million, or $0.45 per basic or diluted share, which stemmed from the resolution of income tax matters related to a former subsidiary, MeraBank, A Federal Savings Bank. This amount is reflected as a tax benefit from discontinued operations in the income statement.

12. El Dorado Partnership Investment Income

Net other income consists primarily of El Dorado's share in the earnings of a venture capital partnership. The partnership adjusts the value of its investment at the end of each fiscal quarter. The value of El Dorado's investment in the partnership is determined by various factors beyond our control, including equity market conditions. Most of the partnership's investments are in technology-related companies whose share prices are highly volatile.

Prior to June 2000, we recorded our share of the earnings from the partnership, as the partnership adjusted the value of its investment, on a one-quarter lag. This was done due to time constraints in obtaining and analyzing such results for inclusion in our consolidated financial statements on a current basis.

During the second quarter of 2000, we requested a distribution of our share of the investments held by the partnership. There is some disagreement with the general partner regarding the distribution of those shares, but we believe we have legal authority to request and receive our share of the investments. We are pursuing that distribution and accordingly have adjusted our investment to reflect the current market value. In the second quarter of 2000, we recognized earnings net of tax of $28 million on the one-quarter lag basis offset by a $31 million decline net of tax in the value of our investment for the fiscal quarter ended June 30, 2000 for a total net loss of $3 million for the quarter.

Upon receipt, we will account for the securities as available for sale with changes in value recorded in other comprehensive income. Gains and losses from the ultimate sale of such securities will be reflected in our net earnings. The book value of El Dorado's investment in the partnership at June 30, 2000 was approximately $38 million.

PINNACLE WEST CAPITAL CORPORATION