-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, JQxBI3iBWCHf9FRnvTNI6ihEMX3wMyG2VC94VJNVkDqd++ji8DuWhetZsc7ZJCw1 YTwQlICzaYf44otKJZZmZA== 0000950147-97-000184.txt : 19970329 0000950147-97-000184.hdr.sgml : 19970329 ACCESSION NUMBER: 0000950147-97-000184 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 13 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970328 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: ARIZONA PUBLIC SERVICE CO CENTRAL INDEX KEY: 0000007286 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 860011170 STATE OF INCORPORATION: AZ FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-04473 FILM NUMBER: 97567425 BUSINESS ADDRESS: STREET 1: 400 N FIFTH ST STREET 2: P O BOX 53999 CITY: PHOENIX STATE: AZ ZIP: 85004 BUSINESS PHONE: 6022501000 10-K405 1 FORM 10-K405 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ----------------- FORM 10-K (Mark One) |X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1996 OR |_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______ to ______ Commission File Number 1-4473 Arizona Public Service Company (Exact name of registrant as specified in its charter) ARIZONA 86-0011170 (State or other jurisdiction (I.R.S. Employer Identification No.) of incorporation or organization) 400 North Fifth Street, P.O. Box 53999 Phoenix, Arizona 85072-3999 (602) 250-1000 (Address of principal executive (Registrant's telephone number, offices, including area code) including zip code) - ------------------------------------------------------------------------------ -------------------------------------- Securities registered pursuant to Section 12(b) of the Act: Name of each exchange on Title of each class which registered - ------------------------------------------------------------------------------ -------------------------------------- Adjustable Rate Cumulative Preferred Stock, Series Q, $100 Par Value.............................................. New York Stock Exchange $1.8125 Cumulative Preferred Stock, Series W, $25 Par Value............................................... New York Stock Exchange 10% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2025........................................ New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: Cumulative Preferred Stock (Title of class) (See Note 3 of Notes to Financial Statements in Item 8 for dividend rates, series designations (if any), and par values) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ X ]
Aggregate Market Value of Voting Stock Held by Non-affiliates of the Title of Each Class Shares Outstanding registrant as of of Voting Stock as of February 26, 1997 February 26, 1997 - --------------------------------------- -------------------------------------- -------------------------------------- Cumulative Preferred Stock........ 4,095,373 $198,000,000(a) - --------------------------------------- -------------------------------------- -------------------------------------- (a) Computed, with respect to shares listed on the New York Stock Exchange, by reference to the closing price on the composite tape on February 26, 1997, as reported by The Wall Street Journal, and with respect to non-listed shares, by determining the yield on listed shares and assuming a market value for non-listed shares which would result in that same yield. As of February 26, 1997, there were issued and outstanding 71,264,947 shares of the registrant's common stock, $2.50 par value, all of which were held beneficially and of record by Pinnacle West Capital Corporation. Documents Incorporated by Reference Portions of the registrant's definitive proxy statement relating to its annual meeting of shareholders to be held on May 20, 1997, are incorporated by reference into Part III hereof.
TABLE OF CONTENTS
Page ---- GLOSSARY ....................................................................................... 1 PART I Item 1. Business............................................................................... 2 Item 2. Properties............................................................................. 11 Item 3. Legal Proceedings...................................................................... 14 Item 4. Submission of Matters to a Vote of Security Holders.................................... 14 Supplemental Item. Executive Officers of the Registrant................................................... 15 PART II Item 5. Market for Registrant's Common Stock and Related Security Holder Matters............... 16 Item 6. Selected Financial Data................................................................ 17 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.............................................................. 18 Item 8. Financial Statements and Supplementary Data............................................ 21 Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure............................................................... 46 PART III Item 10. Directors and Executive Officers of the Registrant..................................... 46 Item 11. Executive Compensation................................................................. 46 Item 12. Security Ownership of Certain Beneficial Owners and Management......................... 46 Item 13. Certain Relationships and Related Transactions......................................... 46 PART IV Item 14. Exhibits, Financial Statements, Financial Statement Schedules, and Reports on Form 8-K................................................................ 47 SIGNATURES ..........................................................................................65
i GLOSSARY ACC --- Arizona Corporation Commission ACC Staff --- Staff of the Arizona Corporation Commission AFUDC --- Allowance for Funds Used During Construction Amendments --- Clean Air Act Amendments of 1990 ANPP --- Arizona Nuclear Power Project, also known as Palo Verde APB Opinion No. 25 --- Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" APS --- Arizona Public Service Company CC&N --- Certificate of convenience and necessity Cholla --- Cholla Power Plant Cholla 4 --- Unit 4 of the Cholla Power Plant Company --- Arizona Public Service Company CUC --- Citizens Utilities Company DOE --- United States Department of Energy EPA --- United States Environmental Protection Agency Energy Act --- National Energy Policy Act of 1992 FASB --- Financial Accounting Standards Board FERC --- Federal Energy Regulatory Commission Four Corners --- Four Corners Power Plant GAAP --- Generally accepted accounting principles ITC --- Investment tax credit kW --- Kilowatt, one thousand watts kWh --- Kilowatt-hour, one thousand watts per hour Mortgage --- Mortgage and Deed of Trust, dated as of July 1, 1946, as supplemented and amended MWh --- Megawatt hours, one million watts per hour 1935 Act --- Public Utility Holding Company Act of 1935 NGS --- Navajo Generating Station NRC --- Nuclear Regulatory Commission PacifiCorp --- An Oregon-based utility company Palo Verde --- Palo Verde Nuclear Generating Station Pinnacle West --- Pinnacle West Capital Corporation, an Arizona corporation, the Company's parent SEC --- Securities and Exchange Commission SFAS No. 34 --- Statement of Financial Accounting Standards No. 34, "Capitalization of Interest Cost" SFAS No. 71 --- Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" SFAS No. 123 --- Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" SRP --- Salt River Project Agricultural Improvement and Power District USEC --- United States Enrichment Corporation Waste Act --- Nuclear Waste Policy Act of 1982, as amended 1 PART I ITEM 1. BUSINESS The Company The Company was incorporated in 1920 under the laws of Arizona and is engaged principally in serving electricity in the State of Arizona. The principal executive offices of the Company are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000). Pinnacle West owns all of the outstanding shares of the Company's common stock. The Company is Arizona's largest electric utility, with 738,000 customers, and provides wholesale or retail electric service to the entire state of Arizona with the exception of Tucson and about one-half of the Phoenix area. During 1996, no single purchaser or user of energy accounted for more than 3% of total electric revenues. At December 31, 1996, the Company employed 6,365 people, which includes employees assigned to joint projects where the Company is project manager. This document may contain "forward-looking statements" that involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in such forward-looking statements. The following factors are among the factors that could cause actual results to differ materially from the forward-looking statements: regulatory developments; competitive developments; regional economic conditions; the cost of debt and equity capital; regulatory, tax and environmental legislation; weather variations affecting customer usage; and technological developments in the electricity industry. See "Competition" in this Item for a discussion of some of these factors. Any forward-looking statements should be considered in light of these factors. Competition Retail General. Under current law, the Company is not in direct competition with any other regulated electric utility for electric service in the Company's retail service territory. Nevertheless, the Company is subject to varying degrees of competition in certain territories adjacent to or within areas that it serves that are also currently served by other utilities in its region (such as Tucson Electric Power Company, Southwest Gas Corporation, and Citizens Utility Company) as well as cooperatives, municipalities, electrical districts and similar types of governmental organizations (principally SRP). The Company faces competitive challenges from low-cost hydroelectric power and natural gas fuel, as well as the access of some utilities to preferential low-priced federal power and other subsidies. In addition, some customers, particularly industrial and large commercial, may own and operate facilities to generate their own electric energy requirements. Such facilities may be operated by the customers themselves or by other entities engaged for such purpose. The legislatures and/or the regulatory commissions in most states have considered or are considering "retail wheeling." This requirement to transmit directly to retail customers could have the result of allowing retail customers to choose to purchase electric capacity and energy from the electric utility in whose service area they are located or from other electric utilities or independent power producers or power marketers. ACC Rules Regarding Arizona Electric Industry Restructuring. The ACC Staff has been conducting an ongoing investigation into the restructuring of the Arizona electric industry in an open competition docket involving many parties. In December 1996, the ACC adopted rules for introduction of retail electric competition in Arizona in phases from 1999 through 2003. The Rules establish a framework for introducing competition; however, with respect to certain matters, they also contain requirements for further workshops and ACC consideration prior to implementation. Recommendations to the ACC from the workshops are expected in late 1997. The Rules indicate that the ACC will allow recovery of unmitigated stranded costs, but do not set forth the mechanisms for determining or recovering such costs. The Company believes that state legislation will ultimately be 2 required before significant implementation of retail electric competition can lawfully occur in Arizona. See Note 2 of Notes to Financial Statements in Item 8 for further discussion of these Rules and of the lawsuits filed by the Company challenging certain provisions of the Rules. Wholesale General. The Company competes with other utilities, power marketers, and independent power producers in the sale of electric capacity and energy in the wholesale market. The Company expects that competition to sell capacity will remain vigorous, and that wholesale prices will remain depressed for at least the next several years due to increased competition and surplus capacity in the western United States. The Company's rates for wholesale power sales and transmission services are subject to regulation by the FERC. During 1996, approximately 6% of the Company's electric operating revenues resulted from such sales and charges. The National Energy Policy Act of 1992 (the "Energy Act") has promoted increased competition in the wholesale electric power markets. The Energy Act reformed provisions of the Public Utility Holding Company Act of 1935 (the "1935 Act") and the Federal Power Act to remove certain barriers to competition for the supply of electricity. For example, the Energy Act permits the FERC to order transmission access for third parties to transmission facilities owned by another entity so that independent suppliers and other third parties can sell at wholesale to customers wherever located. The Energy Act does not, however, permit the FERC to issue an order requiring transmission access to retail customers. Effective July 9, 1996, a FERC decision requires all electric utilities subject to the FERC's jurisdiction to file transmission tariffs which provide competitors with access to transmission facilities comparable to the transmission owners' facilities for wholesale transactions, establishes information requirements and provides recovery for certain wholesale stranded costs. Retail stranded costs resulting from a state-authorized retail direct-access program are the responsibility of the states, unless a state lacks authority to impose rates to recover such costs in which case FERC will consider doing so. The Company has filed its revised open access tariff in accordance with this decision. The Company does not believe that this decision will have a material adverse impact on its results of operations or financial position. Federal Regulation Several electric utility reform bills have been introduced during the current legislative session, which as currently written, would allow consumers to choose their electric supplier by 2000 or 2003. 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 substantial restructuring of the electric utility industry can occur. Regulatory Assets The Company's major regulatory assets are rate synchronization cost deferrals and deferred taxes. These items, combined with miscellaneous regulatory assets and liabilities, amounted to approximately $1.1 billion at December 31, 1996. In accordance with a 1996 regulatory agreement between the Company and the ACC Staff, the ACC accelerated the amortization of substantially all of the Company's regulatory assets to an eight-year period beginning July 1, 1996. The Company's existing regulatory orders and current regulatory environment support its accounting practices related to regulatory assets. If rate recovery of these assets is no longer probable, whether due to competition or regulatory action, the Company would no longer be able to apply the provisions of SFAS No. 71 to all or some part of its operations which could have a material impact on the Company's financial statements. See Notes 1, 2, and 9 of Notes to Financial Statements in Item 8 for additional information. 3 Competitive Strategies The Company is pursuing strategies to maintain and enhance its competitive position. These strategies include (i) cost management, with an emphasis on the reduction of variable costs (fuel, operations, and maintenance expenses) and on increased productivity through technological efficiencies; (ii) a focus on the Company's core business through customer service, distribution system reliability, business segmentation and the anticipation of market opportunities; (iii) an emphasis on good regulatory relationships; (iv) asset maximization (e.g., higher capacity factors and lower forced outage rates); (v) strengthening the Company's capital structure and financial condition; (vi) leveraging core competencies into related areas, such as energy management products and services; and (vii) building a trading floor and implementing a risk management program to provide for more stability of prices and the ability to retain or grow incremental margin through more competitive pricing and risk management. Underpinning the Company's competitive strategies are the strong growth characteristics of the Company's service territory. As competition in the electric utility industry continues to evolve, the Company will continue to pursue strategies to enhance its competitive position. Generating Fuel and Purchased Power Generating Fuel and Purchased Power Costs Fuel and purchased power costs were approximately $326 million during 1996, a 20.7% increase over 1995. See "Management's Discussion and Analysis of Financial Condition and Results of Operations ___ Results of Operations" in Item 7 for a discussion of the factors contributing to this increase. 1996 Energy Mix The Company's sources of energy during 1996 were: purchased power - 17.1%; coal - 43.9%; nuclear - 35.4%; and other - 3.6%. Generating Fuel Mix Coal, nuclear, gas and other contributions to total net generation of electricity by the Company in 1996, 1995 and 1994, and the average cost to the Company of those fuels (in dollars per MWh), were as follows:
Coal Nuclear Gas Other All Fuels ------------------- -------------------- ------------------- ------------------- --------- Percent of Average Percent of Average Percent of Average Percent of Average Average Generation Cost Generation Cost Generation Cost Generation Cost Cost ---------- ---- ---------- ---- ---------- ---- ---------- ---- ---- 1996 (estimate). 52.5% $14.83 42.7% $5.20 4.3% $38.43 0.5% $11.46 $11.72 1995............ 54.7 13.83 40.1 5.21 5.0 19.52 0.2 11.84 10.66 1994............ 59.7 13.84 33.8 6.09 6.3 24.64 0.2 16.26 11.90
Other includes oil and hydro generation. Coal Supply The Company believes that Cholla has sufficient reserves of low sulfur coal committed to that plant for the next four years, the term of the existing coal contract. Sufficient reserves of low sulfur coal are available to continue operating Cholla for its useful life. The Company also believes that Four Corners and NGS have sufficient reserves of low sulfur coal available for use by those plants to continue operating them for their useful lives. The current sulfur content of coal being used at Four Corners, NGS and Cholla is approximately 0.73%, 0.60% and 0.44%, respectively. In 1996, average prices paid for coal supplied from reserves dedicated under the 4 existing contracts increased as a result of power market conditions that changed the mix of coal. In addition, major price adjustments can occur from time to time as a result of contract renegotiation. NGS and Four Corners are located on the Navajo Reservation and held under easements granted by the federal government as well as leases from the Navajo Nation. See "Properties ___ Plant Sites Leased from Navajo Nation" in Item 2. The Company purchases all of the coal which fuels Four Corners from a coal supplier with a long-term lease of coal reserves owned by the Navajo Nation and for NGS from a coal supplier with a long-term lease with the Navajo Nation and the Hopi Tribe. The Company purchases all of the coal which fuels Cholla from a coal supplier who mines all of the coal under a long-term lease of coal reserves owned by the Navajo Nation, the federal government, and private landholders. See Note 11 of Notes to Financial Statements in Item 8 for information regarding the Company's obligation for coal mine reclamation. Natural Gas Supply The Company is a party to contracts with forty natural gas operators and marketers which allow the Company to purchase natural gas in the method it determines to be most economic. During 1996, the principal sources of the Company's natural gas generating fuel were twenty of these companies. The Company is currently purchasing the majority of its natural gas requirements from fifteen companies pursuant to contracts. During 1996 the price of natural gas increased primarily due to a significant increase in the transportation costs as well as increased natural gas prices. The Company's natural gas supply is transported pursuant to a firm transportation service contract between the Company and El Paso Natural Gas Company. The Company continues to analyze the market to determine the source and method of meeting its natural gas requirements. Nuclear Fuel Supply The fuel cycle for Palo Verde is comprised of the following stages: (1) the mining and milling of uranium ore to produce uranium concentrates, (2) the conversion of uranium concentrates to uranium hexafluoride, (3) the enrichment of uranium hexafluoride, (4) the fabrication of fuel assemblies, (5) the utilization of fuel assemblies in reactors and (6) the storage of spent fuel and the disposal thereof. The Palo Verde participants have made arrangements through contract flexibilities to obtain quantities of uranium concentrates anticipated to be sufficient to meet operational requirements through 2000. Existing contracts and options could be utilized to meet approximately 80% of requirements in 2001 and 2002 and 50% of requirements from 2003 through 2007. Spot purchases in the uranium market will be made, as appropriate, in lieu of any uranium that might be obtained through contract flexibilities and options. The Palo Verde participants have contracted for all conversion services required through 2000 and with options for up to 70% through 2002. The Palo Verde participants, including the Company, have an enrichment services contract with USEC which obligates USEC to furnish enrichment services required for the operation of the three Palo Verde units over a term expiring in September 2002, with options to continue through September 2007. In addition, existing contracts will provide fuel assembly fabrication services until at least 2003 for each Palo Verde unit, and through contract options, approximately fifteen additional years are available. Spent Nuclear Fuel and Waste Disposal. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "Waste Act"), DOE is obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by all domestic power reactors. The NRC, pursuant to the Waste Act, requires operators of nuclear power reactors to enter into spent fuel disposal contracts with DOE, and the Company, on its own behalf and on behalf of the other Palo Verde participants, has done so. Under the Waste Act, DOE was to develop the facilities necessary for the storage and disposal of spent nuclear fuel and to have the first such facility in operation by 1998. That facility was to be a permanent repository, but DOE has announced that such a repository now cannot be completed before 2010. In July 1996, the United States Court of Appeals for the District of Columbia Circuit ruled that the DOE has an obligation to start disposing of spent nuclear fuel no later than January 31, 1998. By way of letter dated December 17, 1996, DOE informed contract holders, including the Company, that DOE anticipates that it will be unable to begin acceptance of spent nuclear fuel for disposal in a 5 repository or interim storage facility by January 31, 1998. Several bills have been introduced in Congress contemplating the construction of a central interim storage facility which could be available in the latter part of the current decade; however, there is resistance to certain features of these bills both in Congress and the Administration. Facility funding is a further complication. While all nuclear utilities pay into a so-called nuclear waste fund an amount calculated on the basis of the output of their respective plants, the annual Congressional appropriations for the permanent repository have been for amounts less than the amounts paid into the waste fund (the balance of which is being used for other purposes) and, according to DOE spokespersons, may now be at a level less than needed to achieve a 2010 operational date for a permanent repository. No funding will be available for a central interim facility until one is authorized by Congress. The Company has storage capacity in existing fuel storage pools at Palo Verde which, with certain modifications, could accommodate all fuel expected to be discharged from normal operation of Palo Verde through about 2002, and believes it could augment that wet storage with new facilities for on-site dry storage of spent fuel for an indeterminate period of operation beyond 2002, subject to obtaining any required governmental approvals. One way or another, the Company currently believes that spent fuel storage or disposal methods will be available for use by Palo Verde to allow its continued operation beyond 2002. A new low-level waste facility was built in 1995 on-site which could store an amount of waste equivalent to ten years of normal operation at Palo Verde. Although some low-level waste has been stored on-site, the Company is currently shipping low-level waste to off-site facilities. The Company currently believes that 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. While believing that scientific and financial aspects of the issues of spent fuel and low-level waste storage and disposal can be resolved satisfactorily, the Company acknowledges that their ultimate resolution in a timely fashion will require political resolve and action on national and regional scales which it is less able to predict. Purchased Power Agreements In addition to that available from its own generating capacity (see "Properties" in Item 2), the Company purchases electricity from other utilities under various arrangements. One of the most important of these is a long-term contract with SRP which may be canceled by SRP on three years' notice and which requires SRP to make available, and the Company to pay for, certain amounts of electricity that are based in large part on customer demand within certain areas now served by the Company pursuant to a related territorial agreement. The generating capacity available to the Company pursuant to the contract was 305 MW through May 1996, at which time the capacity decreased to 297 MW. In 1996, the Company received approximately 557,998 MWh of energy under the contract and paid approximately $35 million for capacity availability and energy received. In September 1990, the Company and PacifiCorp entered into certain agreements relating principally to sales and purchases of electric power and electric utility assets, and in July 1991 the Company sold Cholla 4 to PacifiCorp. As part of the transaction, PacifiCorp agreed to make a firm system sale to the Company for thirty years during the Company's summer peak season in the amount of 175 megawatts for the first five years, increasing thereafter, at the Company's option, up to a maximum amount equal to the rated capacity of Cholla 4 (380 megawatts). The Company also had the option to convert these firm system sales to one-for-one seasonal capacity exchanges with PacifiCorp. The Company's agreements with PacifiCorp currently provide for the following Company purchases and one-for-one seasonal capacity exchanges during the indicated years: 1997 (175 megawatt firm capacity purchase; and 100 megawatt capacity exchange effective May 15, 1997); 1998 (175 megawatt firm capacity purchase, converting to capacity exchange in the summer of 1998; and 100 megawatt capacity exchange); 1999 and beyond (275 megawatt capacity exchange; and 205 megawatt capacity exchange beginning in the summer of 1999). In 1996, the generating capacity available to the Company from PacifiCorp 6 was 175 MW. The Company received approximately 404,000 MWh of energy and paid approximately $18.5 million for capacity availability and the energy received. During 1996, the Company entered into an agreement with Citizens Utilities Company to build, own, operate and maintain a combustion turbine in northwest Arizona. Pursuant to a twenty-year purchase power agreement, the Company will recover the cost of the turbine and CUC will pay for the output requested by CUC. The Company has the right to secondary use of the output for cost of fuel and variable operations and maintenance. The Company expects that the combustion turbine will be in service during the first quarter of 1999. Construction Program During the years 1994 through 1996, the Company incurred approximately $824 million in capitalized expenditures. Utility capitalized expenditures for the years 1997 through 1999 are expected to be primarily for expanding transmission and distribution capabilities to meet customer growth, upgrading existing facilities, and for environmental purposes. Capitalized expenditures, including expenditures for environmental control facilities, for the years 1997 through 1999 have been estimated as follows: (Millions of Dollars) By Year By Major Facilities - -------------------------------- ------------------------------- 1997 $296 Electric generation $267 1998 283 Electric transmission 64 1999 262 Electric distribution 412 ---- General facilities 98 $841 ---- ==== $841 ==== The amounts for 1997 through 1999 exclude capitalized interest costs and include capitalized property taxes and about $30 million each year for nuclear fuel. The Company conducts a continuing review of its construction program. Mortgage Replacement Fund Requirements So long as any of the Company's first mortgage bonds are outstanding, the Company is required for each calendar year to deposit with the trustee under its Mortgage, cash in a formularized amount related to net additions to the Company's mortgaged utility plant; however, the Company may satisfy all or any part of this "replacement fund" requirement by utilizing redeemed or retired bonds, net property additions, or property retirements. For 1996, the replacement fund requirement amounted to approximately $129 million. All of the bonds issued by the Company under the Mortgage which are callable prior to maturity are redeemable at their par value plus accrued interest with cash deposited by the Company in the replacement fund, subject in many cases to a period of time after the original issuance of the bonds during which they may not be so redeemed and/or to other restrictions on any such redemption. Environmental Matters EPA Environmental Regulation Clean Air Act. Pursuant to the Clean Air Act, the EPA has adopted regulations that address visibility impairment in certain federally-protected areas which can be reasonably attributed to specific sources. In September 1991, the EPA issued a final rule that would limit sulfur dioxide emissions at NGS. Compliance with the emission limitation becomes applicable to NGS Units 3, 2, and 1 in 1997, 1998 and 1999, respectively. SRP, the NGS operating agent, has estimated a capital cost of $470 million, most of which will be incurred through 1998, and annual operations and maintenance costs of approximately $14 million for all three units, for NGS to meet these requirements. The Company is required to fund 14% of these expenditures. 7 The Clean Air Act Amendments of 1990 (the "Amendments") address, among other things, "acid rain," visibility in certain specified areas, toxic air pollutants and the nonattainment of national ambient air quality standards. With respect to "acid rain," the Amendments establish a system of sulfur dioxide emissions "allowances." Each existing utility unit is granted a certain number of "allowances." On March 5, 1993, the EPA promulgated rules listing allowance allocations applicable to Company-owned plants, which allocations will begin in the year 2000. Based on those allocations, the Company will have sufficient allowances to permit continued operation of its plants at current levels without installing additional equipment. In addition, the Amendments require the EPA to set nitrogen oxides emissions limitations which would require certain plants to install additional pollution control equipment. In December 1996, the EPA issued rules for nitrogen oxides emissions limitations, which may require the Company to install additional pollution control equipment at Four Corners by January 1, 2000. Based on its initial evaluation, the Company currently estimates its capital cost of complying with the rules may be approximately $4 million. On February 14, 1997, the Company filed a Petition for Review in the United States Court of Appeals for the District of Columbia challenging the classification of Four Corners Unit 4 in these rules. Arizona Public Service Company v. United States Environmental Protection Agency, No. 97-1091. With respect to protection of visibility in certain specified areas, the Amendments require the EPA to conduct a study concerning visibility impairment in those areas and identification of sources contributing to such impairment. Interim findings of this study have indicated that any beneficial effect on visibility as a result of the Amendments would be offset by expected population and industry growth. The EPA has established a "Grand Canyon Visibility Transport Commission" to complete a study on visibility impairment in the "Golden Circle of National Parks" in the Colorado Plateau. NGS, Cholla and Four Corners are located near the "Golden Circle of National Parks." The Commission completed its study and on June 10, 1996 submitted its final recommendations to the EPA. The Commission recommended that, beginning in 2000 and every 5 years thereafter, if actual sulfur dioxide emissions from all stationary sources in an eight-state region (including Arizona, New Mexico, Utah, Nevada and California) exceed the projected emissions, which are projected to decline under the current regulatory scheme, the projected total emissions will be changed to a "regional emissions cap" and an emissions trading program would be implemented to limit total sulfur dioxide emissions in the region. The EPA will consider these recommendations before promulgating final requirements on a regional haze regulatory program which is under EPA review (see "Air Quality Standards" below), which is expected by December 1997. If such a program were implemented, industry, including the Company's coal plants, could be subject to further emissions limits. The Company cannot currently estimate the capital expenditures, if any, which may be required as a result of the EPA studies and the Commission's recommendations. With respect to hazardous air pollutants emitted by electric utility steam generating units, the Amendments require two studies. The results of the first study indicated an impact from mercury emissions from such units in certain unspecified areas; however, the EPA has not yet stated whether or not emissions limitations will be imposed. Next, the EPA will complete a general study by 1999 concerning the necessity of regulating such units under the Amendments. Due to the lack of historical data, and because the Company cannot speculate as to the ultimate requirements by the EPA, the Company cannot currently estimate the capital expenditures, if any, which may be required as a result of these studies. Certain aspects of the Amendments may require related expenditures by the Company, such as permit fees, none of which the Company expects to have a material impact on its financial position or results of operations. Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act ("Superfund") establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are potentially responsible parties ("PRP's") and may be each strictly, and often jointly and severally, liable for the cost of any necessary remediation of the substances. The EPA had previously advised the Company that the EPA considers the Company to be a PRP in the Indian Bend Wash Superfund Site, South Area, where the Company's 8 Ocotillo Power Plant is located. The Company is in the process of conducting a voluntary investigation to determine the extent and scope of contamination at the plant site. Based on the information to date, the Company does not expect this matter to have a material impact on its financial position or results of operations. Air Quality Standards. In December 1996, the EPA proposed revised National Ambient Air Quality Standards ("NAAQS") for ozone and particulate matter, and related implementing regulations. The comment period for the proposed NAAQS rules ended on March 12, 1997, and the final rules are expected by July 1997. The EPA is also expected to propose rules to deal with regional haze by June 1997, and final rules are expected by December 1997. Due to these standards the Company could be required to install additional pollution control equipment at certain of its plants. The Company cannot currently estimate the capital expenditures, if any, which may be required as a result of the final rules. MGP Sites. The Company currently is investigating properties, either presently or previously owned by the Company, which were at one time sites of, or sites associated with, manufactured gas plants. The purpose of this investigation is to determine if waste materials are present, if such materials constitute an environmental or health risk, and if the Company has any responsibility for remedial action. Where appropriate, the Company has begun remediation of certain of these sites. The Company does not expect these matters to have a material adverse effect on its financial position or results of operations. Purported Navajo Environmental Regulation Four Corners and NGS are located on the Navajo Reservation and are held under easements granted by the federal government as well as leases from the Navajo Nation. The Company is the Four Corners operating agent and owns a 100% interest in Four Corners Units 1, 2 and 3, and a 15% interest in Four Corners Units 4 and 5. The Company owns a 14% interest in NGS Units 1, 2 and 3. In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act, and the Navajo Nation Pesticide Act (collectively, the "Acts"). Pursuant to the Acts, the Navajo Nation Environmental Protection Agency is authorized to promulgate regulations covering air quality, drinking water and pesticide activities, including those that occur at Four Corners and NGS. By separate letters dated October 12 and October 13, 1995, the Four Corners participants and the NGS participants requested the United States Secretary of the Interior to resolve their dispute with the Navajo Nation regarding whether or not the Acts apply to operations of Four Corners and NGS. On October 17, 1995, the Four Corners participants and the NGS participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, seeking, among other things, a declaratory judgment that (i) their respective leases and federal easements preclude the application of the Acts to the operations of Four Corners and NGS, and (ii) the Navajo Nation and its agencies and courts lack adjudicatory jurisdiction to determine the enforceability of the Acts as applied to Four Corners and NGS. On October 18, 1995, the Navajo Nation and the Four Corners and NGS participants agreed to indefinitely stay the proceedings referenced in the preceding two sentences so that the parties may attempt to resolve the dispute without litigation, and the Secretary and the Court have stayed these proceedings pursuant to a request by the parties. The Company cannot currently predict the outcome of this matter. Water Supply Assured supplies of water are important both to the Company (for its generating plants) and to its customers and, at the present time, the Company has adequate water to meet its needs. However, conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions in recent years. Both groundwater and surface water in areas important to the Company's operations have been the subject of inquiries, claims and legal proceedings which will require a number of years to resolve. The Company is one of a number of parties in a proceeding before a state court in New Mexico to adjudicate rights to a stream system from 9 which water for Four Corners is derived. (State of New Mexico, in the relation of S.E. Reynolds, State Engineer vs. United States of America, City of Farmington, Utah International, Inc., et al., San Juan County, New Mexico, District Court No. 75-184). An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for a then-agreed upon cost, sufficient water from its allocation to offset the loss. A summons served on the Company in early 1986 required all water claimants in the Lower Gila River Watershed in Arizona to assert any claims to water on or before January 20, 1987, in an action pending in Maricopa County Superior Court. (In re The General Adjudication of All Rights to Use Water in the Gila River System and Source, Supreme Court Nos. WC-79-0001 through WC 79-0004 (Consolidated) [WC-1, WC-2, WC-3 and WC-4 (Consolidated)], Maricopa County Nos. W-1, W-2, W-3 and W-4 (Consolidated)). Palo Verde is located within the geographic area subject to the summons, and the rights of the Palo Verde participants, including the Company, to the use of groundwater and effluent at Palo Verde is potentially at issue in this action. The Company, as project manager of Palo Verde, filed claims that dispute the court's jurisdiction over the Palo Verde participants' groundwater rights and their contractual rights to effluent relating to Palo Verde and, alternatively, seek confirmation of such rights. Three of the Company's less-utilized power plants are also located within the geographic area subject to the summons. The Company's claims dispute the court's jurisdiction over the Company's groundwater rights with respect to these plants and, alternatively, seek confirmation of such rights. On December 10, 1992, the Arizona Supreme Court heard oral argument on certain issues in this matter which are pending on interlocutory appeal. Issues important to the Company's claims were remanded to the trial court for further action and the trial court certified its decision for interlocutory appeal to the Arizona Supreme Court. On September 28, 1994, the Arizona Supreme Court granted review of the trial court decision. No trial date concerning the water rights claims of the Company has been set in this matter. The Company has also filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County Superior Court. (In re The General Adjudication of All Rights to Use Water in the Little Colorado River System and Source, Supreme Court No. WC-79-0006 WC-6, Apache County No. 6417). The Company's groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and is therefore potentially at issue in the case. The Company's claims dispute the court's jurisdiction over the Company's groundwater rights and, alternatively, seek confirmation of such rights. The parties are in the process of settlement negotiations with respect to this matter. No trial date concerning the water rights claims of the Company has been set in this matter. Although the foregoing matters remain subject to further evaluation, the Company expects that the described litigation will not have a material adverse impact on its financial position or results of operations. 10 ITEM 2. PROPERTIES Accredited Capacity The Company's present generating facilities have an accredited capacity aggregating 4,026,700 kW, comprised as follows:
Capacity(kW) ------------ Coal: Units 1, 2 and 3 at Four Corners, aggregating............................................... 560,000 15% owned Units 4 and 5 at Four Corners, representing....................................... 222,000 Units 1, 2 and 3 at Cholla Plant, aggregating............................................... 615,000 14% owned Units 1, 2 and 3 at the Navajo Plant, representing................................ 315,000 --------- 1,712,000 ========= Gas or Oil: Two steam units at Ocotillo, two steam units at Saguaro, and one steam unit at Yucca, aggregating.......................................................... 463,400(1) Eleven combustion turbine units, aggregating................................................ 500,600 Three combined cycle units, aggregating..................................................... 253,500 --------- 1,217,500 ========= Nuclear: 29.1% owned or leased Units 1, 2 and 3 at Palo Verde, representing.......................... 1,091,600 ========= Other............................................................................................ 5,600 =========
- --------------- (1) West Phoenix steam units (108,300 kW) are currently mothballed. ----------------------------------------------------- Reserve Margin The Company's peak one-hour demand on its electric system was recorded on July 31, 1996 at 4,574,700 kW, compared to the 1995 peak of 4,420,400 kW recorded on July 28. Taking into account additional capacity then available to it under purchase power contracts as well as its own generating capacity, the Company's capability of meeting system demand on July 31, 1996, computed in accordance with accepted industry practices, amounted to 4,680,300 kW, for an installed reserve margin of 2.7%. The power actually available to the Company from its resources fluctuates from time to time due in part to planned outages, technical problems and short-term purchases. The available capacity from sources actually operable at the time of the 1996 peak amounted to 4,909,300 kW, for a margin of 8.5%. Firm purchases from neighboring utilities totaling 650,000 kW were in place at the time of the peak ensuring the ability to meet the load requirement. Plant Sites Leased from Navajo Nation NGS and Four Corners are located on land held under easements from the federal government and also under leases from the Navajo Nation. The risk with respect to enforcement of these easements and leases is not deemed by the Company to be material. The lease for Four Corners contains a waiver until 2001 of the requirement that the Company pay certain taxes to the Navajo Nation. The Company and the Navajo Nation are currently negotiating an agreement that would settle certain issues regarding this waiver and other matters, including the computation of royalties due on the sales of coal and possessory interest taxes paid by the fuel supplier to Four Corners. If this settlement is consummated, the fuel supplier, the Navajo Nation and the Four Corners participants 11 would agree as a part of their settlement to restructure their relationships in an effort to permit the power and energy generated at Four Corners to be priced competitively. The Company cannot currently predict the outcome of these settlement negotiations. Certain of the Company's transmission lines and almost all of its contracted coal sources are also located on Indian reservations. See "Generating Fuel and Purchased Power --- Coal Supply" in Item 1. Palo Verde Nuclear Generating Station Palo Verde Leases On August 18, 1986 and December 19, 1986, the Company entered into a total of three sale and leaseback transactions under which it sold and leased back approximately 42% of its 29.1% ownership interest in Palo Verde Unit 2. The leases under each of the sale and leaseback transactions have initial lease terms expiring on December 31, 2015. Each of the leases also allows the Company to extend the term of the lease and/or to repurchase the leased Unit 2 interest under certain circumstances at fair market value. The leases in the aggregate require annual payments of approximately $40 million through 1999, approximately $46 million in 2000 and approximately $49 million through 2015 (see Note 8 of Notes to Financial Statements in Item 8). Regulatory Operation of each of the three Palo Verde units requires an operating license from the NRC. Full power operating licenses for Units 1, 2 and 3 were issued by the NRC in June 1985, April 1986 and November 1987, respectively. The full power operating licenses, each valid for a period of approximately 40 years, authorize the Company, as operating agent for Palo Verde, to operate the three Palo Verde units at full power. Nuclear Decommissioning Costs See Note 12 of Notes to Financial Statements in Item 8 for a discussion of the Company's nuclear decommissioning costs. Steam Generators See "Palo Verde Nuclear Generating Station" in Note 11 of Notes to Financial Statements in Item 8 for a discussion of issues relating to the Palo Verde steam generators. Palo Verde Liability and Insurance Matters See "Palo Verde Nuclear Generating Station" in Note 11 of Notes to Financial Statements in Item 8 for a discussion of the insurance maintained by the Palo Verde participants, including the Company, for Palo Verde. Other Information Regarding the Company's Properties See "Environmental Matters" and "Water Supply" in Item 1 with respect to matters having possible impact on the operation of certain of the Company's power plants. See "Construction Program" in Item 1 and "Management's Discussion and Analysis of Financial Condition and Results of Operations ___ Capital Needs and Resources" in Item 7 for a discussion of the Company's construction plans. See Notes 4, 7 and 8 of Notes to Financial Statements in Item 8 with respect to property of the Company not held in fee or held subject to any major encumbrance. 12 [MAP PAGE] In accordance with Item 304 of Regulation S-T of the Securities Exchange Act of 1934, the Company's Service Territory map contained in this Form 10-K is a map of the State of Arizona showing the Company's service area, the location of its major power plants and principal transmission lines, and the location of transmission lines operated by the Company for others. The major power plants shown on such map are the Navajo Generating Station located in Coconino County, Arizona; the Four Corners Power Plant located near Farmington, New Mexico; the Cholla Power Plant, located in Navajo County, Arizona; the Yucca Power Plant, located near Yuma, Arizona; and the Palo Verde Nuclear Generating Station, located about 55 miles west of Phoenix, Arizona (each of which plants is reflected on such map as being jointly owned with other utilities), as well as the Ocotillo Power Plant and West Phoenix Power Plant, each located near Phoenix, Arizona, and the Saguaro Power Plant, located near Tucson, Arizona. The Company's major transmission lines shown on such map are reflected as running between the power plants named above and certain major cities in the State of Arizona. The transmission lines operated for others shown on such map are reflected as running from the Four Corners Plant through a portion of northern Arizona to the California border. 13 ITEM 3. LEGAL PROCEEDINGS Property Taxes On June 29, 1990, a new Arizona state property tax law was enacted, effective as of December 31, 1989, which adversely impacted the Company's earnings before income taxes in tax years 1990 through 1995 by an aggregate amount of approximately $21 million per year. On December 20, 1990, the Palo Verde participants, including the Company, filed a lawsuit in the Arizona Tax Court, a division of the Maricopa County Superior Court, against the Arizona Department of Revenue, the Treasurer of the State of Arizona, and various Arizona counties, claiming, among other things, that portions of the new tax law are unconstitutional. (Arizona Public Service Company, et al. v. Apache County, et al., No. TX 90-01686 (Consol.), Maricopa County Superior Court). On April 23, 1996, the parties reached an agreement to settle the litigation and on July 18, 1996, the Governor signed a new Arizona property tax law that reduced the aggregate property tax of the Company by approximately $18 million (before income taxes) in 1996, with slightly lower amounts expected in future years. Under the formula for potential future rate reduction pursuant to the 1996 regulatory agreement (see "1996 Regulatory Agreement" in Note 2 of Notes to Financial Statements in Item 8 of this report), the property tax reduction is expected to reduce future retail rates. The parties to the litigation have reached a settlement pursuant to which the Company will relinquish its claims for retrospective relief provided that the prospective relief provided by the new law is not changed (other than by changes in law affecting taxpayers generally) for a period of three years. See "Environmental Matters" and "Water Supply" in Item 1 in regard to pending or threatened litigation and other disputes. See "Regulatory Matters" in Note 2 of Notes to Financial Statements in Item 8 for information regarding lawsuits filed by the Company challenging certain provisions of rules adopted by the ACC for the phased-in introduction of retail electric competition in Arizona (Arizona Public Service Company v. The Arizona Corporation Commission, in the Superior Court of the State of Arizona in and for the County of Maricopa, No. CV97-03753, and Arizona Public Service Company v. The Arizona Corporation Commission, in the Court of Appeals, State of Arizona, Division One, No. 1 CA-CC-97-0002, ACC Docket No. R-0000-94-165). ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matter was submitted to a vote of security holders during the fourth quarter of the fiscal year covered by this report, through the solicitation of proxies or otherwise. 14 SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS OF THE REGISTRANT The Company's executive officers are as follows:
Age At Name March 1, 1997 Position(s) At March 1, 1997 - ---- ------------- ---------------------------- Richard Snell 66 Chairman of the Board of Directors(1) William J. Post 46 President and Chief Executive Officer(1) Jack E. Davis 50 Executive Vice President, Commercial Operations George A. Schreiber, Jr. 48 Executive Vice President and Chief Financial Officer(1) William L. Stewart 53 Executive Vice President, Generation Armando B. Flores 53 Senior Vice President, Human Resources and Corporate Services James M. Levine 47 Senior Vice President, Nuclear Jan H. Bennett 49 Vice President, Customer Service Edward Z. Fox 43 Vice President, Environmental, Health and Safety William E. Ide 50 Vice President, Nuclear Engineering Nancy C. Loftin 43 Vice President, Chief Legal Counsel and Secretary Leslie M. Mesh 50 Vice President, Marketing and Economic Development Gregg R. Overbeck 50 Vice President, Nuclear Production Nancy E. Felker 45 Treasurer William J. Hemelt 43 Controller
- --------------- (1) Member of the Board of Directors. The executive officers of the Company are elected no less often than annually and may be removed by the Board of Directors at any time. The terms served by the named officers in their current positions and the principal occupations (in addition to those stated in the table and exclusive of directorships) of such officers for the past five years have been as follows: Mr. Snell was elected to his present position as of February 1990. He was also elected Chairman of the Board, President and Chief Executive Officer of Pinnacle West at that time, and he retired as President in February 1997. Previously, he was Chairman of the Board (1989-1992) and Chief Executive Officer (1989-1990) of Aztar Corporation. Mr. Post assumed his present position in February 1997. Prior to that time he was Senior Vice President and Chief Operating Officer (since September 1994), Senior Vice President, Planning, Information and Financial Services (since June 1993), and Vice President, Finance & Rates (since April 1987). In February 1997, Mr. Post became President of Pinnacle West. Mr. Davis was elected to his present position in September 1996. Prior to that time he was Vice President, Generation and Transmission (June 1993-September 1996); Director, Transmission Systems (January 1993-June 1993); Director, Fossil Generation (June 1992-December 1992); and Director, System Development and Power Operations (May 1990-May 1992). Mr. Schreiber was elected to his present position in February 1997. Prior to that time he was Managing Director at PaineWebber, Inc. (since February 1990). Mr. Stewart was elected to his present position in September 1996. Prior to that time he was Executive Vice President, Nuclear (since May 1994) and Senior Vice President --- Nuclear for Virginia Power (since 1989). 15 Mr. Flores was elected to his present position in September 1996. Prior to that time, he was Vice President, Human Resources (1991-1996) of the Company. Mr. Levine was elected to his present position in September 1996. Prior to that time he was Vice President, Nuclear Production (since September 1989). Mr. Bennett was elected to his present position in May 1991. Mr. Fox was elected to his present position in October 1995. Prior to that time he was Director, Arizona Department of Environmental Quality and Chairman, Wastewater Management Authority of Arizona (July 1991-September 1995). Mr. Ide was elected to his present position in September 1996. Prior to that time he was Director, Palo Verde Operations (1994-1996) and Palo Verde Unit 1 Plant Manager (1988-1994). Ms. Loftin was elected to the positions of Vice President and Chief Legal Counsel in September 1996 and has been Secretary since April 1987. Prior to that time, in addition to Secretary, she was Corporate Counsel (since February 1989). Mr. Mesh was elected to his current position in October 1995. Prior to that time he was Vice President, Marketing and Business Development, Electronic Data Systems (November 1993-October 1995) and Vice President, Northern Telecom, Inc. (April 1984-October 1993). Mr. Overbeck was elected to his current position in July 1995. Prior to that time he was Assistant to Vice President of the Company (January 1994-July 1995) and Director, Nuclear Production Site Technical Support of the Company (January 1991-January 1994). Ms. Felker was elected to her present position in June 1993. Prior to that time she was Assistant Treasurer (since October 1992). She is also Treasurer (since June 1990) and Vice President (since February 1994) of Pinnacle West. Mr. Hemelt was elected to his present position in June 1993. Prior to that time he was Treasurer and Assistant Secretary (since April 1987). PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER MATTERS The Company's common stock is wholly-owned by Pinnacle West and is not listed for trading on any stock exchange. As a result, there is no established public trading market for the Company's common stock. 16 The chart below sets forth the dividends declared on the Company's common stock for each of the four quarters for 1996 and 1995. Common Stock Dividends (Thousands of Dollars)
- --------------------------------------- -------------------------------------- -------------------------------------- Quarter 1996 1995 - --------------------------------------- -------------------------------------- -------------------------------------- 1st Quarter $42,500 $42,500 2nd Quarter 42,500 42,500 3rd Quarter 42,500 42,500 4th Quarter 42,500 42,500 - --------------------------------------- -------------------------------------- --------------------------------------
After payment or setting aside for payment of cumulative dividends and mandatory sinking fund requirements, where applicable, on all outstanding issues of preferred stock, the holders of common stock are entitled to dividends when and as declared out of funds legally available therefor. See Notes 3 and 4 of Notes to Financial Statements in Item 8 for restrictions on retained earnings available for the payment of common stock dividends. ITEM 6. SELECTED FINANCIAL DATA
1996 1995 1994 1993 1992 ---------- ---------- ---------- ---------- ---------- (Thousands of Dollars) Electric Operating Revenues.................. $1,718,272 $1,614,952 $1,626,168 $1,602,413 $1,587,582 Fuel and Purchased Power..................... 325,523 269,798 300,689 300,546 287,201 Operating Expenses........................... 1,027,541 963,400 957,046 929,379 908,123 ---------- ---------- ---------- ---------- ---------- Operating Income.......................... 365,208 381,754 368,433 372,488 392,258 Other Income................................. 35,217 25,548 44,510 54,220 48,801 Interest Deductions --- Net.................. 156,954 167,732 169,457 176,322 194,254 ---------- ---------- ---------- ---------- ---------- Net Income................................ 243,471 239,570 243,486 250,386 246,805 Preferred Dividends....................... 17,092 19,134 25,274 30,840 32,452 ---------- ---------- ---------- ---------- ---------- Earnings for Common Stock................. $ 226,379 $ 220,436 $ 218,212 $ 219,546 $ 214,353 ========== ========== ========== ========== ========== Total Assets................................. $6,423,222 $6,418,262 $6,348,261 $6,357,262 $5,629,432 ========== ========== ========== ========== ========== Capital Structure: Common Stock Equity....................... $1,729,390 $1,621,555 $1,571,120 $1,522,941 $1,476,390 Non-Redeemable Preferred Stock............ 165,673 193,561 193,561 193,561 168,561 Redeemable Preferred Stock................ 53,000 75,000 75,000 197,610 225,635 Long-Term Debt Less Current Maturities.... 2,029,482 2,132,021 2,181,832 2,124,654 2,052,763 ---------- ---------- ---------- ---------- ---------- Total Capitalization.................... 3,977,545 4,022,137 4,021,513 4,038,766 3,923,349 Current Maturities of Long-Term Debt...... 153,780 3,512 3,428 3,179 94,217 Short-Term Debt........................... 16,900 177,800 131,500 148,000 195,000 ---------- ---------- ---------- ---------- ---------- Total................................... $4,148,225 $4,203,449 $4,156,441 $4,189,945 $4,212,566 ========== ========== ========== ========== ==========
- --------------- See "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7 for a discussion of certain information in the foregoing table. 17 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Results of Operations 1996 Compared with 1995 Earnings in 1996 were $226.4 million compared with $220.4 million in 1995. Earnings increased primarily due to increased operating revenues, lower property taxes, the recognition of $12 million of income tax benefits associated with capital loss carryforwards and lower interest expense. The comparison of 1996 to 1995 was also positively impacted by asset write-downs of $21 million before income taxes in 1995. Operating revenues were higher due to increased sales resulting from customer growth, warmer weather in 1996 and higher usage, particularly by residential customers. Property taxes decreased primarily due to a change in tax law. Interest expense was lower due to lower average interest rates and lower amounts of debt outstanding. Partially offsetting these positive factors were $60 million of accelerated regulatory asset amortization, higher fuel expenses, a pretax charge of $31.7 million for a voluntary severance program and a retail rate reduction. Also negatively affecting the comparison of 1996 with 1995 was a gain on the sale of a small subsidiary in 1995. The accelerated regulatory asset amortization and the rate reduction were part of a regulatory agreement which became effective July 1, 1996 (see Note 2 of Notes to Financial Statements). Fuel expenses were up primarily due to higher natural gas costs, increased retail sales and higher coal prices. The Company does not have a fuel adjustment clause as part of its retail rate structure; therefore, changes in fuel and purchased power expenses are reflected currently in earnings. 1995 Compared with 1994 Earnings in 1995 were $220.4 million compared with $218.2 million in 1994. Earnings increased primarily due to customer growth, lower fuel expenses, accelerated amortization of investment tax credits, lower operations and maintenance expenses, lower preferred stock dividends and a gain recognized on the sale of a small subsidiary. Fuel expenses decreased due to lower fuel prices and a more favorable mix resulting from increased nuclear generation. The accelerated amortization of investment tax credits was a result of a 1994 rate settlement (see Note 2 of Notes to Financial Statements) and is reflected as a $21 million decrease in income tax expense. Operations and maintenance expense decreased as a result of lower fossil plant overhaul costs, improved nuclear operations and severance costs incurred in 1994. Preferred stock dividends decreased due to less preferred stock outstanding. Substantially offsetting these positive factors were the absence of non-cash income related to a 1991 rate settlement, milder weather, the reversal in 1994 of certain previously recorded depreciation, a retail rate reduction which became effective June 1, 1994 and in 1995 a $13 million pretax write-down of an office building and an $8 million pretax write-down of certain inventory. Operating Revenues Operating revenues reflect changes in both the volume of units sold and price per kilowatt-hour of electric sales. An analysis of the increases (decreases) in 1996 and 1995 electric operating revenues compared with the prior year follows (in millions of dollars): 1996 1995 ---- ---- Volume variance: Customer growth and usage $ 75.1 $ 57.9 Weather 40.1 (42.0) Other --- (1.7) Rate reductions (29.7) (11.4) Interchange sales 8.5 (7.2) Other 9.3 (6.8) ------ ------ Total change $103.3 $(11.2) 18 Other Income Net income reflects accounting practices required for regulated public utilities and represents a composite of cash and non-cash items, including AFUDC and accretion income on Palo Verde Unit 3 (see Statements of Cash Flows and Note 1 of Notes to Financial Statements). The after-tax accretion income recorded in 1994 was $20.3 million. Also in 1994 was a one-time depreciation reversal of $15 million, after income taxes, which was included in "Other ___ net" in the Statements of Income (see Note 2 of Notes to Financial Statements). Capital Needs and Resources During 1996, the Company redeemed approximately $223 million of long-term debt and preferred stock. Required and optional redemptions of preferred stock and repayments of long-term debt, including premiums thereon, and payments for a capitalized lease obligation are expected to total approximately $222 million, $114 million and $114 million for the years 1997, 1998 and 1999, respectively. The Company's capital requirements consist primarily of capital expenditures and optional and mandatory repayments of long-term debt and preferred stock. The resources available to meet these requirements include funds provided by operations, external financings and annual equity infusions from the parent company of $50 million from 1997 through 1999 (see Note 2 of Notes to Financial Statements). Present construction plans through the year 2006 do not include any major baseload generating plants. In general, most of the capital expenditures are for expanding transmission and distribution capabilities to meet customer growth, for upgrading existing facilities and for environmental purposes. Capital expenditures are anticipated to be approximately $296 million, $283 million and $262 million for 1997, 1998 and 1999, respectively. These amounts include about $30 million each year for nuclear fuel. During the period 1994 through 1996, the Company funded all capital expenditures with funds from operations. The Company expects to have adequate resources to meet its capital requirements for the period 1997 through 1999. Although provisions in the Company's bond indenture, articles of incorporation, and ACC financing orders establish maximum amounts of additional first mortgage bonds and preferred stock that the Company may issue, management does not expect any of these provisions to limit the Company's ability to meet its capital requirements. As of December 31, 1996, the Company had credit commitments from various banks totaling approximately $400 million, which were available either to support the issuance of commercial paper or to be used as bank borrowings. At the end of 1996, there were $16.9 million of commercial paper and $100 million of bank borrowings outstanding. Accounting Matters See Note 12 of Notes to Financial Statements for a description of a proposed standard on accounting for certain liabilities related to closure or removal of long-lived assets. Current Issues The Company's ability to maintain and improve its current level of earnings will depend on several factors. As the electric industry becomes more competitive, the Company's ability to reduce costs and increase productivity and asset utilization will be an important factor in maintaining a price structure that is both attractive to customers and profitable to the Company. Other important factors that could affect the Company's future earnings levels and any forward-looking statements contained in this "Management's Discussion and Analysis of Financial Condition and Results of Operations" include regulatory developments; competitive developments; regional economic conditions; 19 the cost of debt and equity capital; regulatory, tax and environmental legislation; weather variations affecting customer usage; and technological developments in the electricity industry. Competition Competition continues to evolve in the electric utility industry. In December 1996, the ACC adopted rules for the introduction of retail electric competition in Arizona in phases from 1999 through 2003. The Rules establish a framework for introducing competition; however, with respect to certain matters, they also contain requirements for further workshops and ACC consideration prior to implementation. Recommendations to the ACC from the workshops are expected in late 1997. The Rules indicate that the ACC will allow recovery of unmitigated stranded costs, but do not set forth the mechanisms for determining or recovering such costs. Separately, the Arizona legislature established a joint legislative committee to study retail electric competition and to report to the legislature by the end of 1997. The Company believes that state legislation will ultimately be required before significant implementation of retail electric competition can lawfully occur in Arizona. Additionally, legislation related to electric competition has been proposed in the U.S. Congress. See Note 2 of Notes to Financial Statements for further discussion of competitive developments. Until it has been determined how competition will be implemented in Arizona, the Company cannot accurately predict the impact of full retail electric competition on its financial position or results of operations. The Company prepares its financial statements in accordance with the provisions of 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. The Company's existing regulatory orders and current regulatory environment support its accounting practices related to regulatory assets which amounted to approximately $1.1 billion at December 31, 1996. In accordance with the 1996 regulatory agreement, the ACC accelerated the amortization of substantially all of the Company's regulatory assets over an eight-year period. If rate recovery of these assets is no longer probable, whether due to competition or regulatory action, the Company would no longer be able to apply the provisions of SFAS No. 71 to all or some part of its operations which could have a material impact on the Company's financial statements. See Note 1 of Notes to Financial Statements for additional information on regulatory accounting. Rate Matters Pursuant to the price reduction formula in the 1996 regulatory agreement (see Note 2 of Notes to Financial Statements), in March 1997, the Company filed with the ACC its calculation of an annual retail rate reduction of approximately $18 million ($11 million after income taxes) or 1.2%,to become effective July 1, 1997. The amount and timing of the rate decrease is subject to ACC approval. 20 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS
Page ---- Report of Management.......................................................................................... 22 Independent Auditors' Report.................................................................................. 23 Statements of Income for each of the three years in the period ended December 31, 1996........................ 25 Balance Sheets --- December 31, 1996 and 1995................................................................. 26 Statements of Cash Flows for each of the three years in the period ended December 31, 1996.................... 28 Statements of Retained Earnings for each of the three years in the period ended December 31, 1996............. 29 Notes to Financial Statements................................................................................. 29
See Note 13 of Notes to Financial Statements for the selected quarterly financial data required to be presented in this Item. 21 REPORT OF MANAGEMENT The primary responsibility for the integrity of the Company's financial information rests with management, which has prepared the accompanying financial statements and related information. Such information was prepared in accordance with generally accepted accounting principles appropriate in the circumstances, based on management's best estimates and judgments and giving due consideration to materiality. These financial statements have been audited by independent auditors and their report is included. Management maintains and relies upon systems of internal accounting controls. A limiting factor in all systems of internal accounting control is that the cost of the system should not exceed the benefits to be derived. Management believes that the Company's system provides the appropriate balance between such costs and benefits. Periodically the internal accounting control system is reviewed by both the Company's internal auditors and its independent auditors to test for compliance. Reports issued by the internal auditors are released to management, and such reports or summaries thereof are transmitted to the Audit Review Committee of the Board of Directors and the independent auditors on a timely basis. The Audit Review Committee, composed solely of outside directors, meets periodically with the internal auditors and independent auditors (as well as management) to review the work of each. The internal auditors and independent auditors have free access to the Audit Review Committee, without management present, to discuss the results of their audit work. Management believes that the Company's systems, policies and procedures provide reasonable assurance that operations are conducted in conformity with the law and with management's commitment to a high standard of business conduct. William J. Post George A. Schreiber, Jr. William J. Post George A. Schreiber, Jr. President and Executive Vice President Chief Executive Officer and Chief Financial Officer 22 INDEPENDENT AUDITORS' REPORT We have audited the accompanying balance sheets of Arizona Public Service Company as of December 31, 1996 and 1995 and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1996. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. 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 financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1996 and 1995 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles. Deloitte & Touche LLP Deloitte & Touche LLP Phoenix, Arizona February 28, 1997 23 [THIS PAGE INTENTIONALLY LEFT BLANK] 24 ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF INCOME
Year Ended December 31, ------------------------------------------------------------ 1996 1995 1994 ----------- ----------- ----------- (Thousands of Dollars) Electric Operating Revenues......................... $ 1,718,272 $ 1,614,952 $ 1,626,168 ----------- ----------- ----------- Fuel Expenses: Fuel for electric generation..................... 230,393 208,928 237,103 Purchased power.................................. 95,130 60,870 63,586 ----------- ----------- ----------- Total.......................................... 325,523 269,798 300,689 ----------- ----------- ----------- Operating Revenues Less Fuel Expenses............... 1,392,749 1,345,154 1,325,479 ----------- ----------- ----------- Other Operating Expenses: Operations excluding fuel expenses............... 321,959 284,842 292,292 Maintenance...................................... 108,755 115,972 119,629 Depreciation and amortization (Note 1)........... 297,210 242,098 236,108 Income taxes (Note 9)............................ 178,513 178,865 168,202 Other taxes...................................... 121,104 141,623 140,815 ----------- ----------- ----------- Total.......................................... 1,027,541 963,400 957,046 ----------- ----------- ----------- Operating Income.................................... 365,208 381,754 368,433 ----------- ----------- ----------- Other Income (Deductions): Allowance for equity funds used during construction................................... 5,209 4,982 3,941 Income taxes (Note 9)............................ 45,552 37,598 (9,042) Palo Verde accretion income (Note 1)............. --- --- 33,596 Other --- net.................................... (15,544) (17,032) 16,015 ----------- ----------- ----------- Total.......................................... 35,217 25,548 44,510 ----------- ----------- ----------- Income Before Interest Deductions................... 400,425 407,302 412,943 ----------- ----------- ----------- Interest Deductions: Interest on long-term debt....................... 147,666 160,032 159,840 Interest on short-term borrowings................ 10,621 8,143 6,205 Debt discount, premium and expense............... 8,176 8,622 8,854 Allowance for borrowed funds used during construction................................... (9,509) (9,065) (5,442) ----------- ----------- ----------- Total.......................................... 156,954 167,732 169,457 ----------- ----------- ----------- Net Income.......................................... 243,471 239,570 243,486 Preferred Stock Dividend Requirements............... 17,092 19,134 25,274 ----------- ----------- ----------- Earnings for Common Stock........................... $ 226,379 $ 220,436 $ 218,212 ============ ============ ============
See Notes to Financial Statements. 25 ARIZONA PUBLIC SERVICE COMPANY BALANCE SHEETS ASSETS
December 31, ------------------------------------ 1996 1995 ----------- ----------- (Thousands of Dollars) Utility Plant (Notes 4, 7 and 8): Electric plant in service and held for future use........................ $ 6,803,211 $ 6,544,860 Less accumulated depreciation and amortization........................... 2,426,143 2,231,614 ----------- ----------- Total.................................................................. 4,377,068 4,313,246 Construction work in progress............................................ 226,935 281,757 Nuclear fuel, net of amortization of $63,892 and $68,275............................................................ 51,137 52,084 ----------- ----------- Utility Plant --- net.................................................. 4,655,140 4,647,087 ----------- ----------- Investments and Other Assets (Note 12)...................................... 113,666 97,742 ----------- ----------- Current Assets: Cash and cash equivalents................................................ 12,521 18,389 Accounts receivable: Service customers...................................................... 111,715 100,433 Other.................................................................. 49,898 28,107 Allowance for doubtful accounts........................................ (1,685) (1,656) Accrued utility revenues (Note 1)........................................... 55,470 53,519 Materials and supplies (at average cost).................................... 74,120 78,271 Fossil fuel (at average cost)............................................... 13,928 21,722 Deferred income taxes (Note 9).............................................. 8,424 5,653 Other....................................................................... 22,767 17,839 ----------- ----------- Total Current Assets..................................................... 347,158 322,277 ----------- ----------- Deferred Debits: Regulatory asset for income taxes (Note 9)............................... 516,722 548,464 Rate synchronization cost deferral (Note 1).............................. 414,082 449,299 Unamortized costs of reacquired debt..................................... 69,554 63,518 Unamortized debt issue costs............................................. 16,692 17,772 Other.................................................................... 290,208 272,103 ----------- ----------- Total Deferred Debits.................................................. 1,307,258 1,351,156 ----------- ----------- Total.................................................................. $ 6,423,222 $ 6,418,262 =========== ===========
See Notes to Financial Statements. 26 ARIZONA PUBLIC SERVICE COMPANY BALANCE SHEETS LIABILITIES
December 31, ------------------------------------ 1996 1995 ----------- ----------- (Thousands of Dollars) Capitalization (Notes 3 and 4): Common stock............................................................. $ 178,162 $ 178,162 Premiums and expenses --- net............................................ 1,091,122 1,039,550 Retained earnings........................................................ 460,106 403,843 ------------ ------------ Common stock equity.................................................... 1,729,390 1,621,555 Non-redeemable preferred stock........................................... 165,673 193,561 Redeemable preferred stock............................................... 53,000 75,000 Long-term debt less current maturities................................... 2,029,482 2,132,021 ------------ ------------ Total Capitalization................................................... 3,977,545 4,022,137 ------------ ------------ Current Liabilities: Commercial paper (Note 5)................................................ 16,900 177,800 Current maturities of long-term debt (Note 4)............................ 153,780 3,512 Accounts payable......................................................... 174,394 106,583 Accrued taxes............................................................ 86,327 82,827 Accrued interest......................................................... 39,115 41,549 Customer deposits........................................................ 32,137 32,746 Other.................................................................... 21,150 21,134 ------------ ------------ Total Current Liabilities.............................................. 523,803 466,151 ------------ ------------ Deferred Credits and Other: Deferred income taxes (Note 9)........................................... 1,414,242 1,429,482 Deferred investment tax credit (Note 9).................................. 87,723 115,353 Unamortized gain ___ sale of utility plant (Note 8)...................... 86,939 91,514 Customer advances for construction....................................... 24,044 19,846 Other.................................................................... 308,926 273,779 ------------ ------------ Total Deferred Credits and Other....................................... 1,921,874 1,929,974 ------------ ------------ Commitments and Contingencies (Note 11) Total.................................................................... $ 6,423,222 $ 6,418,262 =========== ===========
27 ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF CASH FLOWS
Year Ended December 31, -------------------------------------------- 1996 1995 1994 --------- ---------- --------- (Thousands of Dollars) Cash Flows from Operations: Net income...................................................... $ 243,471 $ 239,570 $ 243,486 Items not requiring cash: Depreciation and amortization................................. 297,210 242,098 236,108 Nuclear fuel amortization..................................... 33,566 31,587 32,564 Allowance for equity funds used during construction........... (5,209) (4,982) (3,941) Deferred income taxes --- net................................. (12,717) 15,344 83,249 Deferred investment tax credit --- net........................ (27,630) (27,641) (6,825) Rate refund reversal.......................................... --- --- (9,308) Palo Verde accretion income................................... --- --- (33,596) Changes in certain current assets and liabilities: Accounts receivable --- net................................... (33,044) 1,659 (7,276) Accrued utility revenues...................................... (1,951) 1,913 4,924 Materials, supplies and fossil fuel........................... 11,945 25,606 4,795 Other current assets.......................................... (4,928) (3,677) (1,509) Accounts payable.............................................. 68,788 6,333 21,666 Accrued taxes................................................. 3,500 (6,585) (22,881) Accrued interest.............................................. (2,565) (3,621) (577) Other current liabilities..................................... (522) 3,393 (9) Other --- net................................................... 17,216 21,328 (418) --------- --------- --------- Net cash provided............................................. 587,130 542,325 540,452 --------- --------- --------- Cash Flows from Investing: Capital expenditures............................................ (258,598) (295,772) (245,925) Allowance for borrowed funds used during construction........... (9,509) (9,065) (5,442) Other........................................................... (9,702) (22,645) (7,251) --------- --------- --------- Net cash used................................................. (277,809) (327,482) (258,618) --------- --------- --------- Cash Flows from Financing: Long-term debt.................................................. 205,830 87,130 516,612 Short-term borrowings --- net................................... (160,900) 46,300 (16,500) Equity infusion................................................. 50,000 --- --- Dividends paid on common stock.................................. (170,000) (170,000) (170,000) Dividends paid on preferred stock............................... (17,416) (19,134) (26,232) Repayment of preferred stock.................................... (50,360) --- (124,096) Repayment and reacquisition of long-term debt................... (172,343) (147,282) (462,643) --------- --------- --------- Net cash used................................................. (315,189) (202,986) (282,859) --------- --------- --------- Net increase (decrease) in cash and cash equivalents............... (5,868) 11,857 (1,025) Cash and cash equivalents at beginning of year..................... 18,389 6,532 7,557 --------- --------- --------- Cash and cash equivalents at end of year........................... $ 12,521 $ 18,389 $ 6,532 ========== ========== =========== Supplemental Disclosure of Cash Flow Information: Cash paid during the year for: Interest (excluding capitalized interest)..................... $ 150,603 $ 163,592 $ 161,294 Income taxes.................................................. $ 158,553 $ 164,261 $ 121,578
See Notes to Financial Statements. 28 ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF RETAINED EARNINGS
Year Ended December 31, -------------------------------------------- 1996 1995 1994 --------- ---------- --------- (Thousands of Dollars) Retained earnings at beginning of year............................. $ 403,843 $ 353,655 $ 307,098 Add: Net income................................................... 243,471 239,570 243,486 --------- --------- --------- Total........................................................... 647,314 593,225 550,584 --------- --------- --------- Deduct: Dividends: Common stock (Notes 3 and 4).................................. 170,000 170,000 170,000 Preferred stock (at required rates) (Note 3).................. 17,092 19,134 25,274 Other........................................................... 116 248 1,655 --------- --------- --------- Total deductions.............................................. 187,208 189,382 196,929 --------- --------- --------- Retained earnings at end of year................................... $ 460,106 $ 403,843 $ 353,655 ========= ========= =========
See Notes to Financial Statements. APS NOTES TO FINANCIAL STATEMENTS 1. Summary of Significant Accounting Policies Nature of Operations The Company is Arizona's largest electric utility, with 738,000 customers, and provides wholesale or retail electric service to the entire state of Arizona with the exception of Tucson and about one-half of the Phoenix area. Accounting Records The accounting records are maintained in accordance with generally accepted accounting principles (GAAP). The preparation of financial statements in accordance with GAAP requires the use of estimates by management. Actual results could differ from those estimates. Regulatory Accounting The Company is regulated by the ACC and the FERC and the accompanying financial statements reflect the rate-making policies of these commissions. The Company prepares its financial statements in accordance with the provisions of 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. The Company's major regulatory assets are rate synchronization cost deferrals (see "Rate Synchronization Cost Deferrals" in this note) and deferred taxes (see Note 9). These items, combined with miscellaneous regulatory assets and liabilities, amounted to approximately $1.1 billion and $1.2 billion at December 31, 1996 and 1995, respectively, most of which are included in "Deferred Debits" on the Balance Sheets. In accordance with the 1996 regulatory agreement (see Note 2), the ACC accelerated the amortization of substantially all of the Company's regulatory assets to an eight-year period beginning July 1, 1996. The accelerated portion of the regulatory asset amortization, approximately $60 million pretax in 1996, is included in depreciation and amortization expense on the Statements of Income. The Company's existing regulatory orders and current regulatory environment support its accounting practices related to regulatory assets. If rate recovery of these assets is no longer probable, whether due to competition or 29 APS NOTES TO FINANCIAL STATEMENTS regulatory action, the Company would no longer be able to apply the provisions of SFAS No. 71 to all or some part of its operations which could have a material impact on the Company's financial statements. Common Stock All of the outstanding shares of common stock of the Company are owned by Pinnacle West. See Note 3. Utility Plant and Depreciation Utility plant represents the buildings, equipment and other facilities used to provide electric service. The cost of utility plant includes labor, materials, contract services, other related items and an allowance for funds used during construction. The cost of retired depreciable utility plant, plus removal costs less salvage realized, is charged to accumulated depreciation. See Note 12 for information on a proposed accounting standard which impacts accounting for removal costs. Depreciation on utility property is recorded on a straight-line basis. The applicable rates for 1994 through 1996 ranged from 1.51% to 20%, which resulted in an annual composite rate of 3.32% for 1996. Allowance for Funds Used During Construction AFUDC represents the cost of debt and equity funds used to finance construction of utility plant. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation. AFUDC does not represent current cash earnings. AFUDC has been calculated using composite rates of 7.75% for 1996; 8.52% for 1995; and 7.70% for 1994. The Company compounds AFUDC semiannually and ceases to accrue AFUDC when construction is completed and the property is placed in service. Effective in 1997, the Company will no longer accrue AFUDC. In place of AFUDC, the Company will capitalize interest in accordance with SFAS No. 34, "Capitalization of Interest Cost." Revenues Operating revenues are recognized on the accrual basis and include estimated amounts for service rendered but unbilled at the end of each accounting period. Palo Verde Accretion Income In 1991, the carrying value of Palo Verde Unit 3 was discounted to reflect the present value of lost cash flows resulting from a 1991 rate settlement agreement deeming a portion of the unit to temporarily be excess capacity. In accordance with generally accepted accounting principles, accretion income was recorded over a thirty-month period ended May 1994 in the aggregate amount of the original discount. The after-tax accretion income recorded in 1994 was $20.3 million. 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 date (September 1986 and January 1988, respectively) until the date the units were included in a rate order (April 1988 and December 1991, respectively). Beginning July 1, 1996, the deferrals are being amortized over an eight-year period in accordance with the 1996 regulatory agreement (see Note 2). Prior to July 1, the deferrals were amortized over thirty-five year periods. Amortization of the deferrals is included in depreciation and amortization expense on the Statements of Income. Nuclear Fuel Nuclear fuel is charged to fuel expense using the unit-of-production method under which the number of units of thermal energy produced in the current period is related to the total thermal units expected to be produced over the remaining life of the fuel. 30 APS NOTES TO FINANCIAL STATEMENTS Under federal law, the DOE is responsible for the permanent disposal of spent nuclear fuel and assesses $0.001 per kWh of nuclear generation. This amount is charged to nuclear fuel expense. See Note 11 for information on spent fuel disposal and Note 12 for information on nuclear decommissioning costs. Reacquired Debt Costs The Company amortizes gains and losses on reacquired debt over the remaining life of the original debt, consistent with ratemaking. In accordance with the 1996 regulatory agreement (see Note 2), the ACC accelerated the Company's amortization of the regulatory asset for reacquired debt costs to an eight-year period beginning July 1, 1996. The accelerated portion of the regulatory asset amortization is included in depreciation and amortization expense on the Statements of Income. Stock-Based Compensation The FASB issued a new statement on "Accounting for Stock-Based Compensation" which was effective for 1996. The statement encourages but does not require companies to recognize compensation expense based on the fair value method. The Company continues to recognize expense based on APB Opinion No. 25. The effects on net income of applying the fair value method would not be material. Cash and Cash Equivalents For purposes of the statements of cash flows, the Company considers all highly liquid debt instruments purchased with an initial maturity of three months or less to be cash equivalents. Reclassifications Certain prior year balances have been restated to conform to the 1996 presentation. 2. Regulatory Matters Electric Industry Restructuring State The ACC has been conducting an ongoing investigation into the restructuring of the Arizona electric industry in an open competition docket involving many parties. In December 1996, the ACC adopted rules that provide a framework for the introduction of retail electric competition. The ACC has ordered that reliability, stranded cost recovery, the phase-in process, and bundled, unbundled and metering services, as well as legal issues, will require additional consideration and will be addressed through workshops and working groups which will issue recommendations to the ACC during 1997. The rules include the following major provisions: o The Rules are intended to apply to virtually all of the Arizona electric utilities regulated by the ACC, including the Company. o Each affected utility would be required to make available at least 20 percent of its 1995 system retail peak demand for competitive generation supply to all customer classes not later than January 1, 1999; at least 50 percent not later than January 1, 2001; and all of its retail demand not later than January 1, 2003. o Electric service providers that obtain a Certificate of Convenience and Necessity (CC&N) from the ACC would be allowed to supply, market, and/or broker specified electric services at retail. These services would include electric generation but exclude electric transmission and distribution. o On or before December 31, 1997, each affected utility is required to file with the ACC proposed tariffs for bundled service and unbundled service. Bundled service means electric service elements (i.e., generation, transmission, distribution, and ancillary services) provided as a package to consumers within an affected utility's current service area. Unbundled service means electric service elements provided and priced 31 APS NOTES TO FINANCIAL STATEMENTS separately. Affected utilities would be required to provide bundled service, as well as unbundled transmission, distribution and miscellaneous other services, at regulated, cost-based rates. o The Rules indicate that the ACC will allow recovery of unmitigated stranded costs. Each affected utility would be required to file with the ACC estimates of unmitigated stranded costs. The ACC would then, after hearing and consideration of various factors, determine the magnitude of stranded cost and appropriate stranded cost recovery mechanisms and charges. The Company continues to focus on working with the ACC to bring competitive benefits to Arizona but believes that certain provisions of the Rules are deficient. In February 1997, the Company filed lawsuits to protect its legal rights regarding the Rules. A joint legislative committee has been appointed to study electric utility industry restructuring issues and report back to the legislature by the end of 1997. The Company believes that legislation will ultimately be required before significant implementation of the Rules can lawfully occur. Until it has been further determined how competition will be implemented in Arizona, the Company cannot accurately predict the impact of full retail competition on its financial position or results of operations. Federal The Energy Policy Act of 1992 and recent rulemakings by FERC have promoted increased competition in the wholesale electric power markets. The Company does not expect these rules to have a material impact on its financial statements. Several electric utility reform bills have been introduced during the current legislative session, which as currently written, would allow consumers to choose their electric supplier by 2000 or 2003. 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 substantial restructuring of the electric utility industry can occur. 1996 Regulatory Agreement In April 1996, the ACC approved a regulatory agreement between the Company and the ACC Staff. The major provisions of this agreement are: o An annual rate reduction of approximately $48.5 million ($29 million after income taxes), or 3.4% on average for all customers except certain contract customers, effective July 1, 1996. o Recovery of substantially all of the Company's present regulatory assets through accelerated amortization over an eight-year period beginning July 1, 1996, increasing annual amortization by approximately $120 million ($72 million after income taxes). See Note 1. o A formula for sharing future cost savings between customers and shareholders (price reduction formula) referencing a return on equity (as defined) of 11.25%. o A moratorium on filing for permanent rate changes prior to July 2, 1999, except under the price reduction formula and under certain other limited circumstances. 32 APS NOTES TO FINANCIAL STATEMENTS o Infusion of $200 million of common equity into the Company by Pinnacle West, in annual payments of $50 million starting in 1996. Pursuant to the price reduction formula, in March 1997 the Company filed with the ACC its calculation of an annual retail rate reduction of approximately $18 million ($11 million after income taxes), or 1.2%, to become effective July 1, 1997. The amount and timing of the rate decrease is subject to ACC approval. 1994 Settlement Agreement In May 1994, the ACC approved a retail rate settlement agreement which provided for a net annual retail rate reduction of 2.2% on average, or approximately $32 million ($19 million after income taxes), effective June 1, 1994. As part of the settlement, in 1994 the Company reversed approximately $20 million of depreciation ($15 million after income taxes) related to a 1991 Palo Verde write-off. It also provided for the accelerated amortization of substantially all deferred investment tax credits over a five-year period beginning in 1995. 33 APS NOTES TO FINANCIAL STATEMENTS 3. Common and Preferred Stocks Non-redeemable preferred stock is not redeemable except at the option of the Company. Redeemable preferred stock is redeemable through sinking fund obligations. In addition, Series V redeemable preferred stock is callable by the Company. Common and preferred stock balances at December 31 are shown below:
Number of Shares Par Par Value Call Outstanding Value Outstanding Price ----------- Per ----------- Per Authorized 1996 1995 Share 1996 1995 Share(a) ----------- ---------- ---------- -------- --------- --------- --------- (Thousands of Dollars) Common Stock................. 100,000,000 71,264,947 71,264,947 $ 2.50 $ 178,162 $ 178,162 --- ========== ========== ========= ========= Preferred Stock: Non-Redeemable: $1.10..................... 160,000 152,740 155,945 $ 25.00 $ 3,818 $ 3,898 $ 27.50 $2.50..................... 105,000 102,532 103,254 50.00 5,127 5,163 51.00 $2.36..................... 120,000 40,000 40,000 50.00 2,000 2,000 51.00 $4.35..................... 150,000 75,000 75,000 100.00 7,500 7,500 102.00 Serial preferred.......... 1,000,000 $2.40 Series A.......... 239,900 240,000 50.00 11,995 12,000 50.50 $2.625 Series C......... 240,000 240,000 50.00 12,000 12,000 51.00 $2.275 Series D......... 199,655 200,000 50.00 9,983 10,000 50.50 $3.25 Series E.......... 320,000 320,000 50.00 16,000 16,000 51.00 Serial preferred.......... 4,000,000(b) Adjustable rate --- Series Q.............. 372,851 500,000 100.00 37,285 50,000 (c) Serial preferred.......... 10,000,000 $1.8125 Series W........ 2,398,615 3,000,000 25.00 59,965 75,000 (d) ---------- ---------- --------- -------- Total................. 4,141,293 4,874,199 $ 165,673 $ 193,561 ========== ========== ========= ========= Redeemable: Serial preferred: $10.00 Series U......... 410,000 500,000 $100.00 $ 41,000 $ 50,000 --- $7.875 Series V......... 120,000 250,000 100.00 12,000 25,000 (e) ---------- ---------- --------- -------- Total................. 530,000 750,000 $ 53,000 $ 75,000 ========== ========== ========= =========
- --------------- (a) In each case plus accrued dividends. (b) This authorization also covers all outstanding redeemable preferred stock. (c) Dividend rate adjusted quarterly to 2% below that of certain United States Treasury securities, but in no event less than 6% or greater than 12% per annum. Redeemable at par. (d) Redeemable at par after December 1, 1998. (e) Redeemable at $104.73 through May 31, 1997, and thereafter declining by a predetermined amount each year to par after May 31, 2002. 34 APS NOTES TO FINANCIAL STATEMENTS If there were to be any arrearage in dividends on any of its preferred stock or in the sinking fund requirements applicable to any of its redeemable preferred stock, the Company could not pay dividends on its common stock or acquire any shares thereof for consideration. The redemption requirements for the above issues for the next five years are: $10.0 million in each of the years 1997 through 2000, and $1.0 million in 2001. Redeemable preferred stock transactions during each of the three years in the period ended December 31 are as follows:
Number of Shares Par Value Outstanding Outstanding ----------------------------------- ----------------------------------- (Thousands of Dollars) Description 1996 1995 1994 1996 1995 1994 - -------------------------------- -------- ------- --------- -------- ------- --------- Balance, January 1.............. 750,000 750,000 1,976,100 $75,000 $75,000 $ 197,610 Retirements: $8.80 Series K............. --- --- (142,100) --- --- (14,210) $11.50 Series R............ --- --- (284,000) --- --- (28,400) $8.48 Series S............. --- --- (300,000) --- --- (30,000) $8.50 Series T............. --- --- (500,000) --- --- (50,000) $10.00 Series U............ (90,000) --- --- (9,000) --- --- $7.875 Series V............ (130,000) --- --- (13,000) --- --- -------- ------- --------- -------- ------- --------- Balance, December 31............ 530,000 750,000 750,000 $53,000 $75,000 $ 75,000 ======= ======= ======= ======= ======= =========
4. Long-Term Debt The following table presents long-term debt outstanding:
December 31, ------------------------ Maturity Dates Interest Rates 1996 1995 -------------- -------------- ---------- ---------- (Thousands of Dollars) First mortgage bonds 1997-2028 5.5%-10.25% (a) $1,448,848 $1,604,317 Pollution control indebtedness 2024-2031 Adjustable (b) 439,990 433,280 Senior notes 2006 6.75% 100,000 --- Debentures 2025 10% 75,000 75,000 Bank loans 2001 Adjustable (c) 100,000 --- Capitalized lease obligation (d) 1996-2001 7.48% 19,424 22,936 ---------- ---------- Total long-term debt 2,183,262 2,135,533 Less current maturities 153,780 3,512 ---------- ---------- Total long-term debt less current maturities $2,029,482 $2,132,021 ========== ==========
- --------------- (a) The weighted-average rate at December 31, 1996 and 1995 was 7.66% and 7.79%, respectively. The weighted-average years to maturity at December 31, 1996 and 1995 was 18 years and 19 years, respectively. (b) The weighted-average rates for the years ended December 31, 1996 and 1995 were 3.40% and 4.31%, respectively. Changes in short-term interest rates would affect the costs associated with this debt. (c) The weighted-average rate for the year ended December 31, 1996 was 5.76%. Changes in short-term interest rates would affect the costs associated with this debt. (d) Represents the present value of future lease payments (discounted at an interest rate of 7.48%) on a combined cycle plant sold and leased back from the independent owner-trustee formed to own the facility (see Note 8). 35 APS NOTES TO FINANCIAL STATEMENTS Aggregate annual principal payments due on long-term debt and for sinking fund requirements through 2001 are as follows: 1997, $153.8 million; 1998, $104.1 million; 1999, $104.4 million; 2000, $104.7 million; and 2001, $102.5 million. See Note 3 for redemption and sinking fund requirements of redeemable preferred stock of the Company. Substantially all utility plant (other than nuclear fuel, transportation equipment and the combined cycle plant) is subject to the lien of the mortgage bond indenture. The mortgage bond indenture includes provisions which would restrict the payment of common stock dividends under certain conditions which did not exist at December 31, 1996. 5. Lines of Credit The Company had committed lines of credit with various banks of $400 million at December 31, 1996 and $300 million at December 31, 1995, which were available either to support the issuance of commercial paper or to be used for bank borrowings. The commitment fees at December 31, 1996 and 1995 for these lines of credit ranged from .10% to .15% per annum. The Company had long-term bank borrowings of $100 million outstanding at December 31, 1996 and commercial paper borrowings outstanding of $16.9 million and $177.8 million at December 31, 1996 and 1995, respectively, under these lines of credit. The weighted average interest rate on commercial paper borrowings was 6.40% and 6.06% on December 31, 1996 and 1995, respectively. By Arizona statute, the Company's short-term borrowings cannot exceed 7% of its total capitalization without the consent of the ACC. 6. Fair Value of Financial Instruments The Company estimates that the carrying amounts of its cash equivalents and commercial paper are reasonable estimates of their fair values at December 31, 1996 and 1995 due to their short maturities. Investments in debt and equity securities are held for purposes other than trading. The December 31, 1996 and 1995 fair values of such investments, determined by using quoted market values or by discounting cash flows at rates equal to the Company's cost of capital, approximate their carrying amounts. The carrying value of long-term debt (excluding a capitalized lease obligation) on December 31, 1996 and 1995 was $2.16 billion and $2.11 billion, respectively, and the estimated fair value was $2.13 billion and $2.14 billion, respectively. The fair value estimates are based on quoted market prices of the same or similar issues. 36 APS NOTES TO FINANCIAL STATEMENTS 7. Jointly-Owned Facilities At December 31, 1996, the Company owned interests in the following jointly-owned electric generating and transmission facilities. The Company's share of related operating and maintenance expenses is included in operating expenses.
Percent Construction Owned by Plant in Accumulated Work in Company Service Depreciation Progress ----------- ----------- ------------ ------------ (Thousands of Dollars) Generating Facilities: Palo Verde Nuclear Generating Station Units 1 and 3 29.1% $1,825,459 $547,750 $15,130 Palo Verde Nuclear Generating Station Unit 2 (see Note 8) 17.0% 568,647 175,926 7,109 Four Corners Steam Generating Station Units 4 and 5 15.0% 144,080 58,447 674 Navajo Steam Generating Station Units 1, 2 and 3 14.0% 141,178 82,430 61,289(a) Cholla Steam Generating Station Common Facilities (b) 62.8%(c) 71,154 37,962 549 Transmission Facilities: ANPP 500KV System 35.8%(c) 62,593 17,848 1,469 Navajo Southern System 31.4%(c) 27,113 16,135 46 Palo Verde-Yuma 500KV System 23.9%(c) 11,376 3,727 --- Four Corners Switchyards 27.5%(c) 3,068 1,634 3 Phoenix-Mead System 17.1%(c) 36,089 (876) 325
- --------------- (a) The construction costs at Navajo are primarily related to the installation of scrubbers required by recent environmental legislation. (b) The Company is the operating agent for Cholla Unit 4, which is owned by PacifiCorp. The common facilities at the Cholla Plant are jointly-owned. (c) Weighted average of interests. 8. Leases In 1986, the Company entered into sale and leaseback transactions under which it sold approximately 42% of its share of Palo Verde Unit 2 and certain common facilities. The gain of approximately $140.2 million has been deferred and is being amortized to operations expense over the original lease term. The leases are being accounted for as operating leases. The amounts to be paid each year approximate $40.1 million through 1999, $46.3 million in 2000 and $49.0 million through 2015. Options to renew for two additional years and to purchase the property at fair market value at the end of the lease terms are also included. Consistent with the ratemaking treatment, an amount equal to the annual lease payments is included in rent expense. A regulatory asset is recognized for the 37 APS NOTES TO FINANCIAL STATEMENTS difference between lease payments and rent expense calculated on a straight-line basis. In accordance with the 1996 regulatory agreement (see Note 2), the ACC accelerated the Company's amortization of the regulatory asset for leases to an eight-year period beginning July 1, 1996. The accelerated amortization is included in depreciation and amortization expense on the Statements of Income. The balance of this regulatory asset at December 31, 1996 was $57.3 million. Lease expense for 1996, 1995 and 1994 was $41.8 million, $41.7 million and $42.2 million, respectively. The Company has a capital lease on a combined cycle plant which it sold and leased back. The lease requires semiannual payments of $2.6 million through June 2001, and includes renewal and purchase options based on fair market value. This plant is included in plant in service at its original cost of $54.4 million; accumulated amortization at December 31, 1996 was $44.6 million. In addition, the Company leases certain land, buildings, equipment and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates. Rent expense for 1996, 1995 and 1994 was approximately $9.7 million, $9.9 million and $10.1 million, respectively. Annual future minimum rental commitments, excluding the Palo Verde and combined cycle leases, for the period 1997 through 2001 range between $12 million and $13 million. Total rental commitments after the year 2001 are estimated at $107 million. 9. Income Taxes The Company is included in the consolidated income tax returns of Pinnacle West. Income taxes are allocated to the Company based on its separate company taxable income or loss. Beginning in 1995, substantially all ITCs are being amortized over a five-year period in accordance with the 1994 rate settlement agreement (see Note 2). Prior to 1995, ITCs were deferred and amortized to other income over the estimated lives of the related assets as directed by the ACC. The Company follows the liability method of accounting for income taxes which requires that deferred income taxes be recorded for all temporary differences between the tax bases of assets and liabilities and the amounts recognized for financial reporting. Deferred taxes are recorded using currently enacted tax rates. In accordance with SFAS No. 71, a regulatory asset has been established for certain temporary differences, primarily AFUDC equity, to reflect the ratemaking treatment. This regulatory asset is being amortized as the related differences reverse. In accordance with the 1996 regulatory agreement (see Note 2), the ACC accelerated the Company's amortization of the regulatory asset for income taxes to an eight-year period beginning July 1, 1996. The accelerated portion of the regulatory asset amortization is included in depreciation and amortization expense on the Statements of Income. 38 APS NOTES TO FINANCIAL STATEMENTS The components of income tax expense are as follows:
Year Ended December 31, -------------------------------------------- 1996 1995 1994 --------- ---------- --------- (Thousands of Dollars) Current: Federal......................................................... $137,531 $120,196 $ 74,272 State........................................................... 35,777 33,368 26,447 -------- -------- --------- Total current................................................. 173,308 153,564 100,719 Deferred........................................................... (869) 17,933 83,350 Change in valuation allowance...................................... (11,848) (2,589) --- Investment tax credit amortization................................. (27,630) (27,641) (6,825) -------- -------- --------- Total expense................................................. $132,961 $141,267 $177,244 ======== ======== ========
Income tax expense differed from the amount computed by multiplying income before income taxes by the statutory federal income tax rate due to the following:
Year Ended December 31, -------------------------------------------- 1996 1995 1994 --------- ---------- --------- (Thousands of Dollars) Federal income tax expense at statutory rate, 35%.................. $131,751 $133,293 $147,256 Increases (reductions) in tax expense resulting from: Tax under book depreciation..................................... 19,229 18,186 17,236 ITC amortization................................................ (27,630) (27,641) (6,825) State income tax ___ net of federal income tax benefit.......... 20,790 21,770 24,947 Change in valuation allowance................................... (10,269) (2,245) --- Other........................................................... (910) (2,096) (5,370) -------- -------- --------- Income tax expense............................................ $132,961 $141,267 $177,244 ======== ======== ========
39 APS NOTES TO FINANCIAL STATEMENTS The components of the net deferred income tax liability were as follows:
December 31, ----------------------------- 1996 1995 ----------- ----------- (Thousands of Dollars) Deferred tax assets: Deferred gain on Palo Verde Unit 2 sale/leaseback................................ $ 35,105 $ 36,945 Other............................................................................ 71,725 77,539 Valuation allowance.............................................................. --- (12,483) ----------- ----------- Total deferred tax assets...................................................... 106,830 102,001 ----------- ----------- Deferred tax liabilities: Plant related.................................................................... 1,104,902 1,081,290 Income taxes recoverable through future rates --- net............................ 208,647 221,418 Rate synchronization deferrals................................................... 167,202 181,384 Other............................................................................ 31,897 41,738 ----------- ----------- Total deferred tax liabilities................................................. 1,512,648 1,525,830 ----------- ----------- Accumulated deferred income taxes --- net........................................... $1,405,818 $1,423,829 ========== ==========
10. Retirement Plans and Other Benefits Voluntary Severance Plan The Company sponsored a voluntary severance plan in 1996 which resulted in a before income tax charge of $31.7 million (including pension and postretirement benefit expense) recorded primarily as operations and maintenance expense. Employees participating in the plan were credited with an additional year of age and service for purposes of calculating pension and postretirement benefits. The total additional pension and postretirement benefit expense recorded for this program was $2.3 million and $5.4 million, respectively. Pension Plan The Company sponsors a defined benefit pension plan covering substantially all employees. Benefits are based on years of service and compensation utilizing a final average pay benefit formula. Company policy is to fund not less than the minimum required contribution nor greater than the maximum tax-deductible contribution. Plan assets consist primarily of domestic and international common stocks and bonds and real estate. Pension expense, including administrative and severance costs, for 1996, 1995 and 1994 was approximately $14.9 million, $9.6 million and $11.9 million, respectively. 40 APS NOTES TO FINANCIAL STATEMENTS The components of net periodic pension costs before consideration of amounts capitalized or billed to others and excluding severance costs of $2.9 million in 1996 and $1.4 million in 1994 are as follows:
1996 1995 1994 --------- ---------- --------- (Thousands of Dollars) Service cost --- benefits earned during the period................. $22,861 $16,038 $20,345 Interest cost on projected benefit obligation...................... 44,602 39,328 39,377 Return on plan assets.............................................. (62,460) (82,209) 6,105 Net amortization and deferral...................................... 19,734 45,976 (44,000) ------- ------- ------- Net periodic pension cost.......................................... $24,737 $19,133 $21,827 ======= ======= =======
A reconciliation of the funded status of the plan to the amounts recognized in the balance sheets is presented below:
1996 1995 ----------- ----------- (Thousands of Dollars) Plan assets at fair value........................................................... $ 533,444 $ 469,820 --------- --------- Less: Accumulated benefit obligation, including vested benefits of $413,004 and $396,138 in 1996 and 1995, respectively........................ 467,037 428,258 Effect of projected future compensation increases................................ 134,057 149,836 --------- --------- Total projected benefit obligation.................................................. 601,094 578,094 --------- --------- Plan assets less than projected benefit obligation.................................. (67,650) (108,274) Plus: Unrecognized net loss from past experience different from that assumed.................................................... 2,818 44,614 Unrecognized prior service cost.................................................. 20,478 23,800 Unrecognized net transition asset................................................ (29,593) (32,809) --------- --------- Accrued pension liability........................................................... $ (73,947) $ (72,669) ========= ========= Principal actuarial assumptions used were: Discount rate.................................................................... 7.75% 7.25% Rate of increase in compensation levels.......................................... 4.50% 4.50% Expected long-term rate of return on assets...................................... 9.00% 9.00%
In addition to the defined benefit pension plan, the Company also sponsors qualified defined contribution plans. Collectively, these plans cover substantially all employees. The plans provide for employee contributions and partial employer matching contributions after certain eligibility requirements are met. Expenses related to these plans for 1996, 1995 and 1994 were $3.4 million, $3.1 million and $3.2 million, respectively. Postretirement Plans The Company provides medical and life insurance benefits to its retired employees. Employees must retire to become eligible for these retirement benefits which are based on years of service and age. The retiree medical insurance plans are contributory; the retiree life insurance plans are noncontributory. In accordance with the governing plan documents, the Company retains the right to change or eliminate these benefits. 41 APS NOTES TO FINANCIAL STATEMENTS Funding is based upon actuarially determined contributions that take tax consequences into account. Plan assets consist primarily of domestic stocks and bonds. The postretirement benefit expense for 1996, 1995 and 1994 was approximately $16 million, $13 million and $13 million, respectively. The components of net periodic postretirement benefit costs before consideration of amounts capitalized or billed to others and excluding severance costs of $9.6 million in 1996 are as follows:
1996 1995 1994 --------- ---------- --------- (Thousands of Dollars) Service cost --- benefits earned during the period................. $ 7,974 $ 6,735 $ 8,785 Interest cost on accumulated benefit obligation.................... 13,395 13,743 14,026 Return on plan assets.............................................. (12,550) (15,133) (6,459) Net amortization and deferral...................................... 12,733 17,142 11,619 -------- -------- -------- Net periodic postretirement benefit cost........................... $ 21,552 $ 22,487 $ 27,971 ======== ======== ========
A reconciliation of the funded status of the plan to the amounts recognized in the balance sheet is presented below:
1996 1995 ----------- ----------- (Thousands of Dollars) Plan assets at fair value........................................................... $109,763 $ 81,309 -------- --------- Less accumulated postretirement benefit obligation: Retirees......................................................................... 86,747 90,222 Fully eligible plan participants................................................. 3,351 15,497 Other active plan participants................................................... 89,452 106,568 -------- --------- Total accumulated postretirement benefit obligation............................ 179,550 212,287 -------- --------- Plan assets less than accumulated benefit obligation................................ (69,787) (130,978) Plus: Unrecognized transition obligation............................................... 122,439 155,481 Unrecognized net gain from past experience different from that assumed........................................................................ (62,299) (24,561) -------- --------- Accrued postretirement liability.................................................... $ (9,647) $ (58) ======== ========= Principal actuarial assumptions used were: Discount rate.................................................................... 7.75% 7.25% Annual salary increases for life insurance obligation............................ 4.50% 4.50% Expected long-term rate of return on assets ___ after tax........................ 7.75% 7.64% Initial health care cost trend rate ___ under age 65............................. 9.00% 9.50% Initial health care cost trend rate ___ age 65 and over.......................... 8.00% 8.50% Ultimate health care cost trend rate (reached in the year 2002).................. 5.50% 5.50%
Assuming a one percent increase in the health care cost trend rate, the 1996 cost of postretirement benefits other than pensions would increase by approximately $5 million and the accumulated benefit obligation as of December 31, 1996 would increase by approximately $31 million. 42 APS NOTES TO FINANCIAL STATEMENTS 11. Commitments and Contingencies Litigation The Company is a party to various claims, legal actions and complaints arising in the ordinary course of business. In the opinion of management, the ultimate resolution of these matters will not have a material adverse effect on the Company's financial statements. Palo Verde Nuclear Generating Station The Company has encountered tube cracking in steam generators and has taken, and will continue to take, remedial actions that it believes have slowed the rate of tube degradation. The projected service life of the steam generators is reassessed periodically and these analyses indicate that it will be economically desirable for the Company to replace the Unit 2 steam generators between 2003 and 2008. The Company estimates that its share of the replacement costs (in 1996 dollars and including installation and replacement power costs) will be approximately $50 million, most of which will be incurred after the year 2000. Based on the latest available data, the Company estimates that the Unit 1 and Unit 3 steam generators should operate for the license periods (until 2025 and 2027, respectively), although the Company will continue its normal periodic assessment of these steam generators. Under the Nuclear Waste Policy Act, DOE was to develop the facilities necessary for the storage and disposal of spent fuel and to have the first such facility in operation by 1998. That facility was to be a permanent repository, but DOE has announced that such a repository now cannot be completed before 2010. The Company has capacity in existing fuel storage pools at Palo Verde which, with certain modifications, could accommodate all fuel expected to be discharged from normal operation of Palo Verde through about 2002, and believes it could augment that wet storage with new facilities for on-site dry storage of spent fuel for an indeterminate period of operation beyond 2002, subject to obtaining any required governmental approvals. The Company currently believes that spent fuel storage or disposal methods will be available for use by Palo Verde to allow its continued operation beyond 2002. 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 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, the Company could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $79 million, subject to an annual limit of $10 million per incident. Based upon the Company's 29.1% interest in the three Palo Verde units, the Company's maximum potential assessment per incident for all three units is approximately $69 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. The Company 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. Fuel and Purchased Power Commitments The Company is a party to various fuel and purchased power contracts with terms expiring from 1997 through 2020 that include required purchase provisions. The Company estimates its 1997 contract requirements to be approximately $120 million. However, this amount may vary significantly 43 APS NOTES TO FINANCIAL STATEMENTS pursuant to certain provisions in such contracts which permit the Company to decrease its required purchases under certain circumstances. The Company is contractually obligated to reimburse certain coal providers for amounts incurred for coal mine reclamation. The Company's share of the total obligation is estimated at $114 million. The portion of the coal mine reclamation obligation related to coal already burned is approximately $68 million at December 31, 1996 and is included in "Deferred Credits ___ Other" in the Balance Sheet. A regulatory asset has been established for amounts not yet recovered from ratepayers. In accordance with the 1996 regulatory agreement (see Note 2), the ACC began accelerated amortization of the Company's regulatory asset for coal mine reclamation costs over an eight-year period beginning July 1, 1996. Amortization is included in depreciation and amortization expense on the Statements of Income. The balance of the regulatory asset at December 31, 1996 was approximately $69 million. Construction Program Total capital expenditures in 1997 are estimated at $296 million. 12. Nuclear Decommissioning Costs In 1996, the Company recorded $11.4 million for decommissioning expense. The Company estimates it will cost approximately $2.0 billion ($440 million in 1996 dollars), over a fourteen year period beginning in 2024, to decommission its 29.1% interest in the three Palo Verde units. Decommissioning costs are charged to expense over the respective unit's operating license term and are included in the accumulated depreciation balance until each unit is retired. Nuclear decommissioning costs are currently recovered in rates. The Company is utilizing a 1995 site-specific study for Palo Verde, prepared for the Company by an independent consultant, that assumes the prompt removal/dismantlement method of decommissioning. The Company is required to update the study every three years. As required by regulation, the Company has established external trust accounts into which quarterly deposits are made for decommissioning. As of December 31, 1996, the Company had deposited a total of $68.1 million. The trust accounts are included in "Investments and Other Assets" on the Balance Sheets at a market value of $95.5 million on December 31, 1996. The trust funds are invested primarily in fixed-income securities and domestic stock and are classified as available for sale. Realized and unrealized gains and losses are reflected in accumulated depreciation. In February 1996, the FASB issued an exposure draft "Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets" which would require the estimated present value of the cost of decommissioning and certain other removal costs to be recorded as a liability, along with an offsetting plant asset when a decommissioning or other removal obligation is incurred. The FASB has indicated a revised exposure draft or a final statement will be issued in the second quarter of 1997. 44 APS NOTES TO FINANCIAL STATEMENTS 13. Selected Quarterly Financial Data (Unaudited) Quarterly financial information for 1996 and 1995 is as follows:
Electric Operating Operating Net Earnings for Quarter Revenues Income(a) Income Common Stock - ------- -------- --------- ------ ------------ (Thousands of Dollars) 1996 First $345,261 $ 77,522 $ 45,606 $ 41,129 Second 426,658 102,978 70,440 66,114 Third 566,899 152,307 128,484 124,331 Fourth (b) 379,454 32,401 (1,059) (5,195) 1995 First $336,968 $ 73,214 $ 37,832 $ 33,025 Second 380,178 88,719 53,452 48,676 Third 549,082 162,602 128,345 123,570 Fourth 348,724 57,219 19,941 15,165
- --------------- (a) The Company's operations are subject to seasonal fluctuations primarily as a result of weather conditions. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. (b) Net income for the fourth quarter of 1996 includes an after-tax charge of $18.9 million for a voluntary severance program. 45 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Reference is hereby made to "Election of Directors" in the Company's Proxy Statement relating to the annual meeting of shareholders to be held on May 20, 1997 (the "1997 Proxy Statement") and to the Supplemental Item --- "Executive Officers of the Registrant" in Part I of this report. ITEM 11. EXECUTIVE COMPENSATION Reference is hereby made to the fourth, fifth and sixth paragraphs under the heading "The Board and its Committees," to "Executive Compensation," to "Report of the Human Resources Committee," to "Performance Graph" and to "Executive Benefit Plans" in the 1997 Proxy Statement. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Reference is hereby made to "Principal Holders of Voting Securities" and "Ownership of Pinnacle West Securities by Management" in the 1997 Proxy Statement. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Reference is hereby made to the last paragraph under the heading "The Board and its Committees" and to "Executive Benefit Plans --- Employment and Severance Agreements" in the 1997 Proxy Statement. 46 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K Financial Statements See the Index to Financial Statements in Part II, Item 8 on page 21. Exhibits Filed Exhibit No. Description - ----------- ----------- 10.1(a) --- 1997 Senior Management Variable Pay Plan 10.2(a) --- 1997 Officers Variable Pay Plan 10.3(a) --- Fifth Amendment to the Arizona Public Service Company Deferred Compensation Plan 10.4 --- Amendment No. 2 to Decommissioning Trust Agreement (PVNGS Unit 1) dated as of July 1, 1991 10.5 --- Amendment No. 4 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992 10.6 --- Amendment No. 2 to Decommissioning Trust Agreement (PVNGS Unit 3) dated as of July 1, 1991 10.7 --- Letter Agreement dated October 9, 1996 between the Company and Jaron B. Norberg 10.8 --- Letter Agreement dated August 16, 1996 between the Company and William L. Stewart 10.9 --- Letter Agreement dated November 27, 1996 between the Company and George A. Schreiber, Jr. 23.1 --- Consent of Deloitte & Touche LLP 27.1 --- Financial Data Schedule 99.1 --- Arizona Corporation Commission Order, Decision No. 59943, dated December 26, 1996, including the Rules regarding the introduction of retail competition in Arizona In addition to those Exhibits shown above, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation ss.229.10(d) by reference to the filings set forth below:
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 3.1 Bylaws, amended as of 3.1 to 1995 Form 10-K 1-4473 3-29-96 February 20, 1996 Report 3.2 Resolution of Board of 3.2 to 1994 Form 10-K 1-4473 3-30-95 Directors temporarily Report suspending Bylaws in part
47
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 3.3 Articles of Incorporation, 4.2 to Form S-3 1-4473 9-29-93 restated as of May 25, 1988 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report 3.4 Certificates pursuant to 4.3 to Form S-3 1-4473 9-29-93 Sections 10-152.01 and Registration Nos. 10-016, Arizona Revised 33-33910 and 33-55248 by Statutes, establishing Series A means of September 24, through V of the Company's 1993 Form 8-K Report Serial Preferred Stock 3.5 Certificate pursuant to 4.4 to Form S-3 1-4473 9-29-93 Section 10-016, Arizona Registration Nos. Revised Statutes, establishing 33-33910 and 33-55248 by Series W of the Company's means of September 24, Serial Preferred Stock 1993 Form 8-K Report 4.1 Mortgage and Deed of Trust 4.1 to September 1992 1-4473 11-9-92 Relating to the Company's Form 10-Q Report First Mortgage Bonds, together with forty-eight indentures supplemental thereto 4.2 Forty-ninth Supplemental 4.1 to 1992 Form 10-K 1-4473 3-30-93 Indenture Report 4.3 Fiftieth Supplemental 4.2 to 1993 Form 10-K 1-4473 3-30-94 Indenture Report 4.4 Fifty-first Supplemental 4.1 to August 1, 1993 Indenture Form 8-K Report 1-4473 9-27-93 4.5 Fifty-second Supplemental 4.1 to September 30, 1993 1-4473 11-15-93 Indenture Form 10-Q Report 4.6 Fifty-third Supplemental 4.5 to Registration 1-4473 3-1-94 Indenture Statement No. 33-61228 by means of February 23, 1994 Form 8-K Report 4.7 Fifty-fourth Supplemental 4.1 to Registration 1-4473 11-22-96 Indenture Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report
48
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 4.8 Agreement, dated March 21, 4.1 to 1993 Form 10-K 1-4473 3-30-94 1994, relating to the filing of Report instruments defining the rights of holders of long-term debt not in excess of 10% of the Company's total assets 4.9 Indenture dated as of January 4.6 to Registration 1-4473 1-11-95 1, 1995 among the Company Statement Nos. 33-61228 and The Bank of New York, and 33-55473 by means of as Trustee January 1, 1995 Form 8-K Report 4.10 First Supplemental Indenture 4.4 to Registration 1-4473 1-11-95 dated as of January 1, 1995 Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report 4.11 Indenture dated as of 4.5 to Registration 1-4473 11-22-96 November 15, 1996 among Statements Nos. 33-61228, the Company and The Bank 33-55473, 33-64455 and of New York, as Trustee 333-15379 by means of November 19, 1996 Form 8-K Report 4.12 First Supplemental Indenture 4.6 to Registration 1-4473 11-22-96 Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report 4.13 Agreement of Resignation, 4.1 to September 25, 1995 Appointment, Acceptance and Form 8-K Report 1-4473 10-24-95 Assignment dated as of August 18, 1995 by and among the Company, Bank of America National Trust and Savings Association and The Bank of New York 10.10 Two separate 10.2 to September 1991 1-4473 11-14-91 Decommissioning Trust Form 10-Q Agreements (relating to PVNGS Units 1 and 3, respectively), each dated July 1, 1991, between the Company and Mellon Bank, N.A., as Decommissioning Trustee
49
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.11 Amendment No. 1 to 10.1 to 1994 Form 10-K 1-4473 3-30-95 Decommissioning Trust Report Agreement (PVNGS Unit 1) dated as of December 1, 1994 10.12 Amendment No. 1 to 10.2 to 1994 Form 10-K 1-4473 3-30-95 Decommissioning Trust Report Agreement (PVNGS Unit 3) dated as of December 1, 1994 10.13 Amended and Restated 10.1 to Pinnacle West 1-8962 3-26-92 Decommissioning Trust 1991 Form 10-K Report Agreement (PVNGS Unit 2) dated as of January 31, 1992, among the Company, Mellon Bank, N.A., as Decommissioning Trustee, and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee under two separate Trust Agreements, each with a separate Equity Participant, and as Lessor under two separate Facility Leases, each relating to an undivided interest in PVNGS Unit 2 10.14 First Amendment to Amended 10.2 to 1992 Form 10-K 1-4473 3-30-93 and Restated Report Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1992 10.15 Amendment No. 2 to Amended 10.3 to 1994 Form 10-K 1-4473 3-30-95 and Restated Report Decommissioning Trust Agreement (PVNGS Unit 2) dated as of November 1, 1994 10.16 Amendment No. 3 to Amended 10.1 to June 1996 Form 1-4473 8-9-96 and Restated 10-Q Report Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992
50
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.17 Asset Purchase and Power 10.1 to June 1991 Form 1-4473 8-8-91 Exchange Agreement dated 10-Q Report September 21, 1990 between the Company and PacifiCorp, as amended as of October 11, 1990 and as of July 18, 1991 10.18 Long-Term Power 10.2 to June 1991 Form 1-4473 8-8-91 Transactions Agreement dated 10-Q Report September 21, 1990 between the Company and PacifiCorp, as amended as of October 11, 1990 and as of July 8, 1991 10.19 Contract, dated July 21, 1984, 10.31 to Pinnacle West's 2-96386 3-13-85 with DOE providing for the Form S-14 Registration disposal of nuclear fuel and/or Statement high-level radioactive waste, ANPP 10.20 Amendment No. 1 dated 10.3 to 1995 Form 10-K 1-4473 3-29-96 April 5, 1995 to the Long-Term Report Power Transactions Agreement and Asset Purchase and Power Exchange Agreement between PacifiCorp and the Company 10.21 Restated Transmission 10.4 to 1995 Form 10-K 1-4473 3-29-96 Agreement between PacifiCorp Report and the Company dated April 5, 1995 10.22 Contract among PacifiCorp, 10.5 to 1995 Form 10-K 1-4473 3-29-96 the Company and United Report States Department of Energy Western Area Power Administration, Salt Lake Area Integrated Projects for Firm Transmission Service dated May 5, 1995 10.23 Reciprocal Transmission 10.6 to 1995 Form 10-K 1-4473 3-29-96 Service Agreement between Report the Company and PacifiCorp dated as of March 2, 1994 10.24 Indenture of Lease with 5.01 to Form S-7 2-59644 9-1-77 Navajo Tribe of Indians, Four Registration Statement Corners Plant
51
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.25 Supplemental and Additional 5.02 to Form S-7 2-59644 9-1-77 Indenture of Lease, including Registration Statement amendments and supplements to original lease with Navajo Tribe of Indians, Four Corners Plant 10.26 Amendment and Supplement 10.36 to Registration 1-8962 7-25-85 No. 1 to Supplemental and Statement on Form 8-B of Additional Indenture of Lease, Pinnacle West Four Corners, dated April 25, 1985 10.27 Application and Grant of 5.04 to Form S-7 2-59644 9-1-77 multi-party rights-of-way and Registration Statement easements, Four Corners Plant Site 10.28 Application and Amendment 10.37 to Registration 1-8962 7-25-85 No. 1 to Grant of multi-party Statement on Form 8-B of rights-of-way and easements, Pinnacle West Four Corners Power Plant Site, dated April 25, 1985 10.29 Application and Grant of 5.05 to Form S-7 2-59644 9-1-77 Arizona Public Service Registration Statement Company rights-of-way and easements, Four Corners Plant Site 10.30 Application and Amendment 10.38 to Registration 1-8962 7-25-85 No. 1 to Grant of Arizona Statement on Form 8-B of Public Service Company Pinnacle West rights-of-way and easements, Four Corners Power Plant Site, dated April 25, 1985 10.31 Indenture of Lease, Navajo 5(g) to Form S-7 2-36505 3-23-70 Units 1, 2, and 3 Registration Statement 10.32 Application and Grant of 5(h) to Form S-7 2-36505 3-23-70 rights-of-way and easements, Registration Statement Navajo Plant 10.33 Water Service Contract 5(l) to Form S-7 2-39442 3-16-71 Assignment with the United Registration Statement States Department of Interior, Bureau of Reclamation, Navajo Plant
52
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.34 Arizona Nuclear Power 10.1 to 1988 Form 10-K 1-4473 3-8-89 Project Participation Report Agreement, dated August 23, 1973, among the Company, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles, and amendments 1-12 thereto 10.35 Amendment No. 13 dated as 10.1 to March 1991 Form 1-4473 5-15-91 of April 22, 1991, to Arizona 10-Q Report Nuclear Power Project Participation Agreement, dated August 23, 1973, among the Company, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles 10.36(c) Facility Lease, dated as of 4.3 to Form S-3 33-9480 10-24-86 August 1, 1986, between Registration Statement State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and the Company, as Lessee
53
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.37(c) Amendment No. 1, dated as of 10.5 to September 1986 1-4473 12-4-86 November 1, 1986, to Facility Form 10-Q Report by Lease, dated as of August 1, means of Amendment No. 1986, between State Street 1 on December 3, 1986 Bank and Trust Company, as Form 8 successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and the Company, as Lessee 10.38(c) Amendment No. 2 dated as of 10.3 to 1988 Form 10-K 1-4473 3-8-89 June 1, 1987 to Facility Lease Report dated as of August 1, 1986 between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee 10.39(c) Amendment No. 3, dated as of 10.3 to 1992 Form 10-K 1-4473 3-30-93 March 17, 1993, to Facility Report Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and the Company, as Lessee 10.40 Facility Lease, dated as of 10.1 to November 18, 1986 1-4473 1-20-87 December 15, 1986, between Form 8-K Report State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and the Company, as Lessee 10.41 Amendment No. 1, dated as of 4.13 to Form S-3 1-4473 8-24-87 August 1, 1987, to Facility Registration Statement Lease, dated as of December No. 33-9480 by means of 15, 1986, between State Street August 1, 1987 Form 8-K Bank and Trust Company, as Report successor to The First National Bank of Boston, as Lessor, and the Company, as Lessee
54
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.42 Amendment No. 2, dated as of 10.4 to 1992 Form 10-K 1-4473 3-30-93 March 17, 1993, to Facility Report Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and the Company, as Lessee 10.43(a) Directors' Deferred 10.1 to June 1986 Form 1-4473 8-13-86 Compensation Plan, as 10-Q Report restated, effective January 1, 1986 10.44(a) Second Amendment to the 10.2 to 1993 Form 10-K 1-4473 3-30-94 Arizona Public Service Report Company Directors' Deferred Compensation Plan, effective as of January 1, 1993 10.45(a) Third Amendment to the 10.1 to September 1994 1-4473 11-10-94 Arizona Public Service Form 10-Q Company Directors' Deferred Compensation Plan effective as of May 1, 1993 10.46(a) Arizona Public Service 10.4 to 1988 Form 10-K 1-4473 3-8-89 Company Deferred Report Compensation Plan, as restated, effective January 1, 1984, and the second and third amendments thereto, dated December 22, 1986, and December 23, 1987, respectively 10.47(a) Third Amendment to the 10.3 to 1993 Form 10-K 1-4473 3-30-94 Arizona Public Service Report Company Deferred Compensation Plan, effective as of January 1, 1993 10.48(a) Fourth Amendment to the 10.2 to September 1994 1-4473 11-10-94 Arizona Public Service Form 10-Q Report Company Deferred Compensation Plan effective as of May 1, 1993
55
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.49(a) Pinnacle West Capital 10.10 to 1995 Form 10-K 1-4473 3-29-96 Corporation, Arizona Public Report Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan as amended and restated effective January 1, 1996 10.50(a) Arizona Public Service 10.11 to 1995 Form 10-K 1-4473 3-29-96 Company Supplemental Report Excess Benefit Retirement Plan as amended and restated on December 20, 1995 10.51(a) Pinnacle West Capital 10.7 to 1994 Form 10-K 1-4473 3-30-95 Corporation and Arizona Report Public Service Company Directors' Retirement Plan effective as of January 1, 1995 10.52(a) Letter Agreement dated 10.6 to 1994 Form 10-K 1-4473 3-30-95 December 21, 1993, between Report the Company and William L. Stewart 10.53(a) Agreement for Utility 10.6 to 1988 Form 10-K 1-4473 3-8-89 Consulting Services, dated Report March 1, 1985, between the Company and Thomas G. Woods, Jr., and Amendment No. 1 thereto, dated January 6, 1986 10.54(a) Letter Agreement, dated April 10.7 to 1988 Form 10-K 1-4473 3-8-89 3, 1978, between the Company Report and O. Mark DeMichele, regarding certain retirement benefits granted to Mr. DeMichele 10.55(a) Letter Agreement dated July 10.1 to September 1995 1-4473 11-14-95 28, 1995, between the 10-Q Report Company and Jaron B. Norberg regarding certain of Mr. Norberg's retirement benefits
56
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.56(a) Letter Agreement dated as 10.8 to 1995 Form 10-K 1-4473 3-29-96 of January 1, 1996 between Report the Company and Robert G. Matlock & Associates, Inc. for consulting services 10.57(a)(d) Key Executive Employment 10.3 to 1989 Form 10-K 1-4473 3-8-90 and Severance Agreement Report between the Company and certain executive officers of the Company 10.58(a)(d) Revised form of Key Executive 10.5 to 1993 Form 10-K 1-4473 3-30-94 Employment and Severance Report Agreement between the Company and certain executive officers of the Company 10.59(a)(d) Second revised form of Key 10.9 to 1994 Form 10-K 1-4473 3-30-95 Executive Employment and Report Severance Agreement between the Company and certain executive officers of the Company 10.60(a)(d) Key Executive Employment 10.4 to 1989 Form 10-K 1-4473 3-8-90 and Severance Agreement Report between the Company and certain managers of the Company 10.61(a)(d) Revised form of Key Executive 10.4 to 1993 Form 10-K 1-4473 3-30-94 Employment and Severance Report Agreement between the Company and certain key employees of the Company 10.62(a)(d) Second revised form of Key 10.8 to 1994 Form 10-K 1-4473 3-30-95 Executive Employment and Report Severance Agreement between the Company and certain key employees of the Company 10.63(a) Pinnacle West Capital 10.1 to 1992 Form 10-K 1-4473 3-30-93 Corporation Stock Option and Report Incentive Plan
57
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.64(a) Pinnacle West Capital A to the Proxy Statement 1-8962 4-16-94 Corporation 1994 Long-Term for the Plan Report Incentive Plan effective as of Pinnacle West 1994 March 23, 1994 Annual Meeting of Shareholders 10.65 Agreement No. 13904 (Option 10.3 to 1991 Form 10-K 1-4473 3-19-92 and Purchase of Effluent) Report with Cities of Phoenix, Glendale, Mesa, Scottsdale, Tempe, Town of Youngtown, and Salt River Project Agricultural Improvement and Power District, dated April 23, 1973 10.66 Agreement for the Sale and 10.4 to 1991 Form 10-K 1-4473 3-19-92 Purchase of Wastewater Report Effluent with City of Tolleson and Salt River Agricultural Improvement and Power District, dated June 12, 1981, including Amendment No. 1 dated as of November 12, 1981 and Amendment No. 2 dated as of June 4, 1986 99.2 Collateral Trust Indenture 4.2 to 1992 Form 10-K 1-4473 3-30-93 among PVNGS II Funding Report Corp., Inc., the Company and Chemical Bank, as Trustee 99.3 Supplemental Indenture to 4.3 to 1992 Form 10-K 1-4473 3-30-93 Collateral Trust Indenture Report among PVNGS II Funding Corp., Inc., the Company and Chemical Bank, as Trustee 99.4(c) Participation Agreement, 28.1 to September 1992 1-4473 11-9-92 dated as of August 1, 1986, Form 10-Q Report among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, the Company, and the Equity Participant named therein
58
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 99.5(c) Amendment No. 1 dated as of 10.8 to September 1986 1-4473 12-4-86 November 1, 1986, to Form 10-Q Report by Participation Agreement, means of Amendment No. dated as of August 1,1986, 1, on December 3, 1986 among PVNGS Funding Form 8 Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, the Company, and the Equity Participant named therein 99.6(c) Amendment No. 2, dated as of 28.4 to 1992 Form 10-K 1-4473 3-30-93 March 17, 1993, to Report Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, the Company, and the Equity Participant named therein 99.7(c) Trust Indenture, Mortgage, 4.5 to Form S-3 33-9480 10-24-86 Security Agreement and Registration Statement Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee
59
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 99.8(c) Supplemental Indenture No. 10.6 to September 1986 1-4473 12-4-86 1, dated as of November 1, Form 10-Q Report by 1986 to Trust Indenture, means of Amendment No. Mortgage, Security Agreement 1 on December 3, 1986 and Assignment of Facility Form 8 Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee 99.9(c) Supplemental Indenture No. 2 4.4 to 1992 Form 10-K 1-4473 3-30-93 to Trust Indenture, Mortgage, Report Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee 99.10(c) Assignment, Assumption and 28.3 to Form S-3 33-9480 10-24-86 Further Agreement, dated as Registration Statement of August 1, 1986, between the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee 99.11(c) Amendment No. 1, dated as of 10.10 to September 1986 1-4473 12-4-86 November 1, 1986, to Form 10-Q Report by Assignment, Assumption and means of Amendment No. Further Agreement, dated as 1 on December 3, 1986 of August 1, 1986, between Form 8 the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee
60
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 99.12(c) Amendment No. 2, dated as of 28.6 to 1992 Form 10-K 1-4473 3-30-93 March 17, 1993, to Report Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee 99.13 Participation Agreement, 28.2 to September 1992 1-4473 11-9-92 dated as of December 15, Form 10-Q Report 1986, among PVNGS Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee under a Trust Indenture, the Company, and the Owner Participant named therein 99.14 Amendment No. 1, dated as of 28.20 to Form S-3 1-4473 8-10-87 August 1, 1987, to Registration Statement Participation Agreement, No. 33-9480 by means of a dated as of December 15, November 6, 1986 Form 1986, among PVNGS Funding 8-K Report Corp., Inc. as Funding Corporation, State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, Chemical Bank, as Indenture Trustee, the Company, and the Owner Participant named therein
61
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 99.15 Amendment No. 2, dated as of 28.5 to 1992 Form 10-K 1-4473 3-30-93 March 17, 1993, to Report Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, the Company, and the Owner Participant named therein 99.16 Trust Indenture, Mortgage, 10.2 to November 18, 1986 1-4473 1-20-87 Security Agreement and Form 8-K Report Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee 99.17 Supplemental Indenture No. 4.13 to Form S-3 1-4473 8-24-87 1, dated as of August 1, 1987, Registration Statement to Trust Indenture, Mortgage, No. 33-9480 by means of Security Agreement and August 1, 1987 Form 8-K Assignment of Facility Lease, Report dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee
62
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 99.18 Supplemental Indenture No. 2 4.5 to 1992 Form 10-K 1-4473 3-30-93 to Trust Indenture, Mortgage, Report Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee 99.19 Assignment, Assumption and 10.5 to November 18, 1986 1-4473 1-20-87 Further Agreement, dated as Form 8-K Report of December 15, 1986, between the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee 99.20 Amendment No. 1, dated as of 28.7 to 1992 Form 10-K 1-4473 3-30-93 March 17, 1993, to Report Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee 99.21(c) Indemnity Agreement dated 28.3 to 1992 Form 10-K 1-4473 3-30-93 as of March 17, 1993 by the Report Company 99.22 Extension Letter, dated as of 28.20 to Form S-3 1-4473 8-10-87 August 13, 1987, from the Registration Statement signatories of the No. 33-9480 by means of a Participation Agreement to November 6, 1986 Form Chemical Bank 8-K Report 99.23 Arizona Corporation 28.1 to 1991 Form 10-K 1-4473 3-19-92 Commission Order dated Report December 6, 1991 99.24 Arizona Corporation 10.1 to June Form 10-Q 1-4473 8-12-94 Commission Order dated Report June 1, 1994
63
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 99.25 Rate Reduction Agreement 10.1 to December 4, 1995 1-4473 12-14-95 dated December 4, 1995 Form 8-K Report between the Company and the ACC Staff 99.26 Arizona Corporation Commission 10.1 to March 1996 Form 1-4473 5-14-96 Order dated April 24, 1996 10-Q Report
- --------------- (a)Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 14(c) of Form 10-K. (b)Reports filed under File No. 1-4473 were filed in the office of the Securities and Exchange Commission located in Washington, D.C. (c)An additional document, substantially identical in all material respects to this Exhibit, has been entered into, relating to an additional Equity Participant. Although such additional document may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates of execution), there are no material details in which such document differs from this Exhibit. (d)Additional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional officers and key employees of the Company. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit. Reports on Form 8-K During the quarter ended December 31, 1996, and the period ended March 27, 1997, the Company did not file any Reports on Form 8-K. 64 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. ARIZONA PUBLIC SERVICE COMPANY (Registrant) Date: March 27, 1997 William J. Post ------------------------------ (William J. Post, President and Chief Executive Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature Title Date --------- ----- ---- William J. Post Principal Executive Officer March 27, 1997 - -------------------------------------------------- and Director (William J. Post, President and Chief Executive Officer) George A. Schreiber, Jr. Principal Accounting Officer, March 27, 1997 - -------------------------------------------------- Principal Financial Officer (George A. Schreiber, Jr.) and Director O. Mark DeMichele Director March 27, 1997 - -------------------------------------------------- (O. Mark DeMichele) Martha O. Hesse Director March 27, 1997 - -------------------------------------------------- (Martha O. Hesse) Marianne Moody Jennings Director March 27, 1997 - -------------------------------------------------- (Marianne Moody Jennings) Robert G. Matlock Director March 27, 1997 - -------------------------------------------------- (Robert G. Matlock) Jaron B. Norberg Director March 27, 1997 - -------------------------------------------------- (Jaron B. Norberg)
65
Signature Title Date --------- ----- ---- John R. Norton III Director March 27, 1997 - -------------------------------------------------- (John R. Norton III) Donald M. Riley Director March 27, 1997 - -------------------------------------------------- (Donald M. Riley) Wilma W. Schwada Director March 27, 1997 - -------------------------------------------------- (Wilma W. Schwada) Richard Snell Director March 27, 1997 - -------------------------------------------------- (Richard Snell) Dianne C. Walker Director March 27, 1997 - -------------------------------------------------- (Dianne C. Walker) Ben F. Williams, Jr. Director March 27, 1997 - -------------------------------------------------- (Ben F. Williams, Jr.) Thomas G. Woods, Jr. Director March 27, 1997 - -------------------------------------------------- (Thomas G. Woods, Jr.)
66 Commission File Number 1-4473 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ----------------- EXHIBITS TO FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1996 ----------------- Arizona Public Service Company (Exact name of registrant as specified in charter) - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- INDEX TO EXHIBITS Exhibit No. Description - ----------- ----------- 10.1(a) --- 1997 Senior Management Variable Pay Plan 10.2(a) --- 1997 Officers Variable Pay Plan 10.3(a) --- Fifth Amendment to the Arizona Public Service Company Deferred Compensation Plan 10.4 --- Amendment No. 2 to Decommissioning Trust Agreement (PVNGS Unit 1) dated as of July 1, 1991 10.5 --- Amendment No. 4 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992 10.6 --- Amendment No. 2 to Decommissioning Trust Agreement (PVNGS Unit 3) dated as of July 1, 1991 10.7 --- Letter Agreement dated October 9, 1996 between the Company and Jaron B. Norberg 10.8 --- Letter Agreement dated August 16, 1996 between the Company and William L. Stewart 10.9 --- Letter Agreement dated November 27, 1996 between the Company and George A. Schreiber, Jr. 23.1 --- Consent of Deloitte & Touche LLP 27.1 --- Financial Data Schedule 99.1 --- Arizona Corporation Commission Order, Decision No. 59943, dated December 26, 1996, including the Rules regarding the introduction of retail competition in Arizona - --------------- (a)Management contract or compensatory plan or arrangement required to be filed as an exhibit pursuant to Item 14(c) of Form 10-K. For a description of the Exhibits incorporated in this filing by reference, see Part IV, Item 14. EX-10.1A 2 1997 SENIOR MANAGEMENT VARIABLE PAY PLAN Exhibit 10.1a Under the Company's 1997 Senior Management Variable Pay Plan, the President of the Company, with the approval of the Human Resources Committee of the Board of Directors, annually designates employees to participate in the program, establishes their participation level, and establishes certain financial and operational goals for the Company which must be satisfied in order for variable pay awards to be made. The impact, if any, of each employee's performance on his or her variable pay award is determined by his or her officer. Subject to final approval by the Human Resources Committee of the Board of Directors, the President of the Company also determines at year-end the degree to which those goals have been satisfied and the amount of variable pay to be awarded to participating employees, if any. EX-10.2.A 3 1997 OFFICERS VARIABLE PAY PLAN Exhibit 10.2a Under the Company's 1997 Officers Variable Pay Plan, the President of the Company, with the approval of the Human Resources Committee of the Board of Directors, annually designates the officers who will participate in the program, establishes their participation level, and establishes certain financial and operational goals for the Company which must be satisfied in order for variable pay awards to be made. The impact, if any, of each officer's performance on his or her variable pay award is determined by the President of the Company, with the approval of the Human Resources Committee. Subject to final approval by the Human Resources Committee of the Board of Directors, the President also determines at year-end the degree to which those goals have been satisfied and the amount of variable pay to be awarded to participating officers, if any. EX-10.3.A 4 FIFTH AMENDMENT TO THE APS COMPANY Exhibit 10.3.a FIFTH AMENDMENT TO THE ARIZONA PUBLIC SERVICE COMPANY DEFERRED COMPENSATION PLAN Effective January 1, 1978, ARIZONA PUBLIC SERVICE COMPANY (the "Company") adopted the ARIZONA PUBLIC SERVICE COMPANY DEFERRED COMPENSATION PLAN (the "Plan"). The Plan was subsequently amended and restated several times and was the most recent amendment and restatement becoming effective January 1, 1984. The Plan was thereafter amended on December 22, 1986, December 23, 1987, April 4, 1993, and August 1, 1994. By this instrument, the Company desires to amend the Plan to change the retirement date on which participants may retire and receive benefits. 1. This Amendment shall amend only the provisions of the Plan as set forth herein, and those provisions not expressly amended hereby shall be considered in full force and effect. 2. Section IV.A.2 is hereby amended to read as follows: 2. Separation from employment after attainment by the Participant of the age of fifty-five (55) years if such Participant has been credited with ten (10) Years of Service (as defined below); for purposes of this Section, "Years of Service" shall have the same meaning as that given it in the Arizona Public Service Company Employees' Retirement Plan, as amended (which definition is incorporated herein by this reference); 3. The provisions of this Amendment shall be effective as of January 1, 1997. Except as amended and supplemented by this instrument, the Company hereby ratifies the Plan as restated effective January 1, 1984, and thereafter amended. DATED: December 18, 1996 ARIZONA PUBLIC SERVICE COMPANY By: Nancy C. Loftin --------------------------------- Its: Vice President, Chief Legal Counsel and Secretary ---------------------------------------------------- EX-10.4 5 AMENTMENT NO. 2 TO DECOMMISSIONING TRUST AGREEMENT Exhibit 10.4 AMENDMENT NO. 2 Decommissioning Trust Agreement (PVNGS Unit 1) Dated as of July 1, 1991, as Amended by Amendment No. 1 Dated as of December 1, 1994 between Arizona Public Service Company and Mellon Bank, N.A. as Decommissioning Trustee This Amendment No. 2, dated as of December 16, 1996, to the Decommissioning Trust Agreement (PVNGS Unit 1) dated as of July 1, 1991 as amended by Amendment No. 1 thereto dated as of December 1, 1994 (the "Decommissioning Trust Agreement"; terms used herein as therein defined), is entered into between Arizona Public Service Company ("APS") and Mellon Bank, N.A., as Decommissioning Trustee ("Decommissioning Trustee"). R E C I T A L S - - - - - - - - WHEREAS, the parties hereto wish to amend the limitations of the parties' ability to modify the Decommissioning Trust Agreement under certain circumstances; NOW THEREFORE, in consideration of the premises and of other good and valuable consideration, receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows: A G R E E M E N T S: - - - - - - - - - - SECTION 1. Amendments. The Decommissioning Trust Agreement is hereby amended by adding the following as the last sentence of Section 13: "Notwithstanding the foregoing, this Agreement may not be amended or modified in violation of Section 468A of the Code or the regulations thereunder." SECTION 2. Effectiveness. This Amendment No. 2 shall become effective as of the date hereof upon the execution and delivery of a counterpart of this Amendment No. 2 by each of the parties hereto. SECTION 3. Miscellaneous. (a) Full Force and Effect. Except as expressly provided herein, the Decommissioning Trust Agreement shall remain unchanged and in full force and effect. Each reference in the Decommissioning Trust Agreement and in any exhibit or schedule thereto to "this Agreement," "hereto," "hereof" and terms of similar import shall be deemed to refer to the Decommissioning Trust Agreement as amended hereby. (b) Counterparts. This Amendment No. 2 may be executed in any number of counterparts, all of which taken together shall constitute the same instrument, and any of the parties hereto may execute this Amendment No. 2 by signing any such counterpart. (c) Arizona Law. This Amendment No. 2 shall be construed in accordance with and governed by the law of the State of Arizona. IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 2 to the Decommissioning Trust Agreement to be duly executed as the day and year first above written. ARIZONA PUBLIC SERVICE COMPANY By NANCY E. NEWQUIST ------------------------------ Title Treasurer ------------------------------ -2- MELLON BANK, N.A., as Decommissioning Trustee By EARL G. KLECKNER ------------------------------ Earl G. Kleckner Title Vice President ------------------------------ STATE OF ARIZONA ) ) ss. County of Maricopa ) The foregoing instrument was acknowledged before me this 16th day of December, 1996, by Nancy E. Newquist, the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, on behalf of said corporation. [Official Seal] MARIA R. MARRS --------------------------------- Notary Public My commission expires: July 21, 1998 STATE OF PENNSYLVANIA ) ) ss. County of Allegheny ) The foregoing instrument was acknowledged before me this 16th day of October, 1996, by Earl Kleckner, a Trust Officer of MELLON BANK, N.A., a corporation having trust powers, as Decommissioning Trustee, on behalf of said corporation. [Official Seal] STEPHANIE RIEGER --------------------------------- Notary Public My commission expires: May 12, 1997 -3- EX-10.5 6 AMENDMENT NO. 4 TO AMENDED AND RESTATED Exhibit 10.5 This Amendment No. 4, dated as of December 16, 1996, to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of January 31, 1992, as amended by Amendment No. 1 thereto dated as of November 1, 1992, Amendment No. 2 thereto dated as of November 1, 1994, and Amendment No. 3 thereto dated as of June 20, 1996 (the "Decommissioning Trust Agreement"; terms used herein as therein defined), is entered into between Arizona Public Service Company ("APS"), State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee and as Lessor, and Mellon Bank, N.A., as Decommissioning Trustee ("Decommissioning Trustee"). R E C I T A L S: - - - - - - - - WHEREAS, the parties hereto wish to amend the limitations of the parties' ability to modify the Decommissioning Trust Agreement under certain circumstances; NOW, THEREFORE, in consideration of the premises and of other good and valuable consideration, receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows: A G R E E M E N T S: - - - - - - - - - - SECTION 1. Amendments. The Decommissioning Trust Agreement is hereby amended by adding the following as the last sentence of Section 15: "Notwithstanding the foregoing, this Agreement may not be amended or modified in violation of Section 468A of the Code or the regulations thereunder." SECTION 2. Effectiveness. This Amendment No. 4 shall become effective as of the date hereof upon the execution and delivery of a counterpart of this Amendment No. 4 by each of the parties hereto. SECTION 3. Miscellaneous. (a) Full Force and Effect. Except as expressly provided herein, the Decommissioning Trust Agreement shall remain unchanged and in full force and effect. Each reference in the Decommissioning Trust Agreement and in any exhibit or schedule thereto to "this Agreement," "hereto," "hereof" and terms of similar import shall be deemed to refer to the Decommissioning Trust Agreement as amended hereby. (b) Counterparts. This Amendment No. 4 may be executed in any number of counterparts, all of which taken together shall constitute one and the same instrument, and any of the parties hereto may execute this Amendment No. 4 by signing any such counterpart. (c) Arizona Law. This Amendment No. 4 shall be construed in accordance with and governed by the law of the State of Arizona. IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 4 to the Decommissioning Trust Agreement to be duly executed as of the day and year first above written. ARIZONA PUBLIC SERVICE COMPANY By NANCY E. NEWQUIST ------------------------------------- Title Treasurer ----------------------------------- MELLON BANK, N.A., as Decommissioning Trustee By EARL G. KLECKNER ------------------------------------- Earl G. Kleckner Title Vice President ----------------------------------- STATE STREET BANK AND TRUST COMPANY, as Owner Trustee under a Trust Agreement with Security Pacific Capital Leasing Corporation and as Lessor under a Facility Lease with Arizona Public Service Company By ERIC DONAGHEY ------------------------------------- Title Assistant Vice President ----------------------------------- -2- STATE STREET BANK AND TRUST COMPANY, as Owner Trustee under a Trust Agreement with Emerson Finance Co. and as Lessor under a Facility Lease with Arizona Public Service Company By ERIC DONAGHEY ------------------------------------- Title Assistant Vice President ----------------------------------- STATE OF ARIZONA ) ) ss. County of Maricopa ) The foregoing instrument was acknowledged before me this 16th day of December, 1996, by Nancy E. Newquist, the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, on behalf of said corporation. [Official Seal] MARIA R. MARRS ------------------------------- Notary Public My commission expires: July 21, 1998 STATE OF PENNSYLVANIA ) ) ss. County of Allegheny ) The foregoing instrument was acknowledged before me this 16th day of October, 1996, by Earl Kleckner, a Trust Officer of MELLON BANK, N.A., a corporation having trust powers, as Decommissioning Trustee, on behalf of said corporation. [Official Seal] STEPHANIE RIEGER --------------------------------- Notary Public My commission expires: May 12, 1997 -3- Commonwealth of Massachusetts ) ) ss. County of Suffolk ) The foregoing instrument was acknowledged before me this 13th day of December, 1996, by Eric Donaghey, the Assistant Vice President of STATE STREET BANK AND TRUST COMPANY, a Massachusetts trust company, in its capacity as Owner Trustee under a Trust Agreement with Security Pacific Capital Leasing Corporation, and as Lessor under a Facility Lease with Arizona Public Service Company, on behalf of said association in such capacities. [Official Seal] SCOTT KNOX --------------------------------- Notary Public My commission expires: July 12, 2002 Commonwealth of Massachusetts ) ) ss. County of Suffolk ) The foregoing instrument was acknowledged before me this 13th day of December, 1996, by Eric Donaghey, the Assistant Vice President of STATE STREET BANK AND TRUST COMPANY, a Massachusetts trust company, in its capacity as Owner Trustee under a Trust Agreement with Emerson Finance Co., and as Lessor under a Facility Lease with Arizona Public Service Company, on behalf of said association in such capacities. [Official Seal] SCOTT KNOX --------------------------------- Notary Public My commission expires: July 12, 2002 -4- EX-10.6 7 AMENDMENT NO. 2 TO DECOMMISSIONING TRUST AGREEMENT Exhibit 10.6 AMENDMENT NO. 2 Decommissioning Trust Agreement (PVNGS Unit 3) Dated as of July 1, 1991, as Amended by Amendment No. 1 Dated as of December 1, 1994 between Arizona Public Service Company and Mellon Bank, N.A. as Decommissioning Trustee This Amendment No. 2, dated as of December 16, 1996, to the Decommissioning Trust Agreement (PVNGS Unit 3) dated as of July 1, 1991 as amended by Amendment No. 1 thereto dated as of December 1, 1994 (the "Decommissioning Trust Agreement"; terms used herein as therein defined), is entered into between Arizona Public Service Company ("APS") and Mellon Bank, N.A., as Decommissioning Trustee ("Decommissioning Trustee"). R E C I T A L S - - - - - - - - WHEREAS, the parties hereto wish to amend the limitations of the parties' ability to modify the Decommissioning Trust Agreement under certain circumstances; NOW THEREFORE, in consideration of the premises and of other good and valuable consideration, receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows: A G R E E M E N T S: - - - - - - - - - - SECTION 1. Amendments. The Decommissioning Trust Agreement is hereby amended by adding the following as the last sentence of Section 13: "Notwithstanding the foregoing, this Agreement may not be amended or modified in violation of Section 468A of the Code or the regulations thereunder." SECTION 2. Effectiveness. This Amendment No. 2 shall become effective as of the date hereof upon the execution and delivery of a counterpart of this Amendment No. 2 by each of the parties hereto. SECTION 3. Miscellaneous. (a) Full Force and Effect. Except as expressly provided herein, the Decommissioning Trust Agreement shall remain unchanged and in full force and effect. Each reference in the Decommissioning Trust Agreement and in any exhibit or schedule thereto to "this Agreement," "hereto," "hereof" and terms of similar import shall be deemed to refer to the Decommissioning Trust Agreement as amended hereby. (b) Counterparts. This Amendment No. 2 may be executed in any number of counterparts, all of which taken together shall constitute the same instrument, and any of the parties hereto may execute this Amendment No. 2 by signing any such counterpart. (c) Arizona Law. This Amendment No. 2 shall be construed in accordance with and governed by the law of the State of Arizona. IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 2 to the Decommissioning Trust Agreement to be duly executed as the day and year first above written. ARIZONA PUBLIC SERVICE COMPANY By NANCY E. NEWQUIST -------------------------------- Title Treasurer ---------------------------- -2- MELLON BANK, N.A., as Decommissioning Trustee By EARL G. KLECKNER -------------------------------- Earl G. Kleckner Title Vice President ---------------------------- STATE OF ARIZONA ) ) ss. County of Maricopa ) The foregoing instrument was acknowledged before me this 16th day of December, 1996, by Nancy E. Newquist, the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, on behalf of said corporation. [Official Seal] MARIA R. MARRS ------------------------- Notary Public My commission expires: July 21, 1998 STATE OF PENNSYLVANIA ) ) ss. County of Allegheny ) The foregoing instrument was acknowledged before me this 16th day of October, 1996, by Earl Kleckner, a Trust Officer of MELLON BANK, N.A., a corporation having trust powers, as Decommissioning Trustee, on behalf of said corporation. [Official Seal] STEPHANIE RIEGER ------------------------- Notary Public My commission expires: May 12, 1997 -3- EX-10.7 8 LETTER AGREEMENT DATED OCTOBER 9, 1996 Exhibit 10.7 October 9, 1996 Jaron Norberg Tempe, Az 85282 Dear Jaron, As a follow-up to our recent discussion in which you expressed your intent to retire from APS effective December 31st of this year, I am providing you with a written summary of those benefit enhancements that we have agreed upon. Retirement - ---------- A. The cash equivalent for stock options and restricted stock awarded under the Pinnacle West Stock Option and Restricted Stock Program that would have vested with one additional year credited. B. In recognition for your service on the APS Board of Directors you will receive an additional four years of credited service for the purpose of calculating your pension benefit. C. Your pension benefit will be calculated on base compensation paid in 1994, 1995 and 1996. Additionally, any incentive bonus earned in 1994, 1995 and 1996 will also be included in your pension calculation. Severance - --------- A. You will receive severance pay equal to one year of base salary. B. You will be credited with one additional year of age and service for purposes of calculating your pension and SEBRP benefits. C. You will receive continued dental coverage for a period of one year beginning January 1, 1997 to December 31, 1997 provided that you continue to pay your respective share of the premium. At the end of this one year period, you will be eligible to elect continued coverage in accordance with COBRA. Consulting Services - ------------------- At the discretion of the Chief Executive Officer you will provide up to six hundred hours of consulting services to APS in each of the two years following your retirement at the rate of two hundred dollars per hour. Miscellaneous - ------------- We are awarding you the computers you have been using at APS, as well as the Country Club membership at Phoenix Country Club. Further, at the discretion of the CEO every effort will be made to accommodate you with parking at the Corporate Headquarters building subject to availability. If you have questions regarding any of the preceding information let me know, otherwise indicate your acknowledgment and agreement by providing your signature below. Sincerely, WILLIAM J. POST - -------------------------------- William J. Post Chief Operating Officer Arizona Public Service The foregoing is agreed to and accepted: JARON B. NORBERG - -------------------------------- Jaron Norberg EX-10.8 9 LETTER AGREEMENT DATED AUGUST 16, 1996 Exhibit 10.8 August 16, 1996 Mr. William L. Stewart Paradise Valley, AZ 85253 Dear Bill, As a result of our meeting on Tuesday, July 23, 1996, I am pleased to provide you with a summary of the compensation and retirement benefit enhancements that we agreed upon. Base Salary: - ------------ Your base salary will be increased by $100,000 effective July 23, 1996. Your new base salary will be $410,026. Incentive Pay Plan: - ------------------- You will continue to be a participant in the Officers Incentive Plan as an Executive Vice President, with an incentive opportunity ranging from 0% - 52% of base pay. Retirement: - ----------- Your retirement benefit will be calculated by adding a base amount of 20% of your average monthly wage (as determined by the highest 36 consecutive months) and 10% of your average monthly wage for each year of service. You will become vested in this benefit when you have accrued four years and 1000 hours of service (November 1998). The maximum benefit you can accrue is 100% of your average monthly wage. Under this schedule, you will qualify for the maximum benefit in November 2001. Please note, this retirement benefit replaces our previous agreement outlined in your offer letter dated December 21, 1993. Restricted Stock: - ----------------- You will receive two thousand shares of restricted stock for each calendar year you are actively employed at APS retroactive to 1994. This results in an award of four thousand shares to be issued as soon as possible. Each subsequent years award will be made in the last quarter of each year and will be provided in addition to any other stock award you receive under the Pinnacle West Stock Option and Restricted Stock Program. Home Purchase: - -------------- The Company will purchase your home at its market value and you may live there for the remainder of your employment at APS. You will be responsible for any personal income taxes due to this arrangement. Should you have any questions regarding any of the above information, please feel free to contact Armando Flores who will implement all of the above actions. Sincerely, WILLIAM J. POST - ----------------------------------- William J. Post Chief Operating Officer Arizona Public Service Company The foregoing is agreed to and accepted: WILLIAM L. STEWART - ---------------------------------- William L. Stewart EX-10.9 10 LETTER AGREEMENT DATED NOVEMBER 27, 1996 Exhibit 10.9 November 27, 1996 Mr. George Schreiber New York, NY 10021 Dear George: I am delighted to provide you with this offer of employment as Chief Financial Officer of Arizona Public Service Company and Pinnacle West Capital Corporation. This is an exciting and challenging time both in the Companies as well as the industry. Your experience will have a direct impact on our efforts. The information outlined below covers the major items regarding our offer of employment. This offer of employment is for a three-year term and renewable by mutual agreement after the completion of the second year. As you know this offer is for the position of Executive Vice President and Chief Financial Officer of Arizona Public Service Company (APS), and Executive Vice President and Chief Financial Officer of Pinnacle West Capital Corporation (PNW), with a 50/50 split of your time and efforts directed to each. You will report directly to me in both Companies and your responsibilities will include Corporate Finance, Accounting, Treasury, Investor Relations and Risk Management. Changes in responsibility may occur during the contract term at the discretion of the Company. The base salary of $375,000 is effective on your first day of employment, February 3, 1997. In addition to your base salary, you will participate in the APS Officer Incentive Program which has a maximum target opportunity of 52% of annual base salary in 1996. Incentive dollars are generally paid during the first quarter of the subsequent year. The targets and payout thresholds are reviewed each year. In 1997, your minimum incentive payment will be $125,000. In addition to the base and incentive compensation referenced above, you will also receive a semi-monthly auto allowance totaling $7,200 per year. You will also be able to utilize a corporate club membership contingent upon your acceptance. You will be responsible for all monthly dues. As an additional incentive and contingent upon your acceptance of the position, the Pinnacle West Board has granted you 1,200 shares of Restricted Stock as well as 6,000 stock options. The description of these grants is attached. These grants occur annually in November and are at the levels at which you would normally participate in the Pinnacle West Capital Corporation Long-Term Incentive Program. The 1996 grants were determined as if you had been an employee of the Company at your proposed salary and responsibility levels. Regarding pension, the Company will credit you with ten years of service which will allow you to reach the maximum level of pension benefits at age 65. During 1997, you will be provided with four weeks vacation. For purposes of vacation, you will be eligible for five weeks vacation after five years of service. Mr. George Schreiber November 27, 1996 Page 2 I have enclosed copies of our Employee Benefits and a schedule outlining the employee premiums. Also enclosed is a description of our Employee Savings Plan in which you will be eligible to participate 31 days after employment. Please note that the Employee Savings Plan is a pre-tax savings plan and takes advantage of Section 401(k) of the Code. Also, please note that the premiums that apply to our medical and dental plan are done on a pre-tax basis. We will also provide you with a relocation service for the disposition of your real estate. We have a contract with Western Relocation Management Company. Briefly, the procedure is that Western will select two independent real estate appraisers. The two appraisers will appraise the property based on the normal resale period for your area. Provided that both appraisals are within five percent of one another, the two will be averaged. That average will be considered the fair market value of the property. You will be given a written offer in the amount of the fair value. You have sixty days within which to decide to accept or reject that offer. If you sell the property to another buyer for a higher price during the sixty day period, you can then assign the property over to Western. You will receive a check in the amount of your equity based on the fair market value assigned by Western, and you will then receive a check after the closing of the property with the buyer to whom you sold the property for the difference. APS will pay all of the relocation company fees, as well as any maintenance of the property during the period of time it is held for resale. We will also pay normal closing costs and provide the relocation of all household effects to Phoenix. I have also included a copy of the change of control agreement, the Pinnacle West Capital Corporation Long-Term Incentive Program and the executive insurance program. On behalf of APS, I look forward to having you join our team. In the event you have any questions, feel free to contact me or Armando Flores who will ultimately coordinate the details of your employment and relocation. Sincerely, WILLIAM J. POST William J. Post Executive Vice President Pinnacle West Capital Corporation and Senior Vice President and Chief Operating Officer Arizona Public Service Company Enclosures The foregoing is agreed to and accepted GEORGE A. SCHREIBER, JR. - --------------------------------------------- George Schreiber Date: 12/3/96 ---------------------------------------- EX-23.1 11 CONSENT OF DELOITTE & TOUCHE L.L.P. Exhibit 23.1 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 33-51085, 33-57822, 33-61228, 33-55473, 33-64455 and 333-15379 on Form S-3, of our report dated February 28, 1997 appearing in this Annual Report on Form 10-K of Arizona Public Service Company for the year ended December 31, 1996. DELOITTE & TOUCHE LLP DELOITTE & TOUCHE LLP Phoenix, Arizona March 27, 1997 EX-27.1 12 FDS
UT PUBLIC UTILITY COMPANIES AND PUBLIC UTILITY HOLDING COMPANIES (THOUSANDS OF DOLLARS) FISCAL YEAR ENDED DECEMBER 31, 1996 FOR PERIOD JANUARY 1, 1996 THROUGH DECEMBER 31, 1996 TWELVE MONTHS ENDED 1000 U.S. DOLLARS 12-MOS DEC-31-1996 JAN-01-1996 DEC-31-1996 1 PER-BOOK 4655140 113666 347158 1307258 0 6423222 178162 1091122 460106 1729390 53000 165673 2029482 0 0 16900 153780 0 0 0 2274997 6423222 1718272 178513 1174551 1353064 365208 35217 400425 156954 243471 17092 226379 170000 139699 587130 0 0
EX-99.1 13 ARIZONA CORP. COMMISSION ORDER-DECISION NO. 59943 Arizona Corporation Commission DOCKETED DEC 26 1996 DOCKETED BY CM BEFORE THE ARIZONA CORPORATION COMMISSION RENZ D. JENNINGS Chairman MARCIA WEEKS Commissioner CARL J. KUNASEK Commissioner IN THE MATTER OF THE COMPETITION ) DOCKET NO. U-0000-94-165 IN THE PROVISION OF ELECTRIC ) SERVICES THROUGHOUT THE STATE ) OF ARIZONA. ) DECISION NO. 59943 ) ) ____________________________________) OPINION AND ORDER ----------------- DATES OF HEARING: December 2, 3 and 4, 1996 PLACES OF PUBLIC Phoenix, Tucson, Yuma, Flagstaff, and COMMENT: Kingman, Arizona PRESIDING OFFICERS: Jerry L. Rudibaugh, Jane Rodda, Scott Wakefield IN ATTENDANCE: Renz D. Jennings, Chairman Marcia Weeks, Commissioner Carl J. Kunasek, Commissioner APPEARANCES: Mr. Bradford A. Borman, and Mr. Peter Breen, Staff Attorneys, Legal Division, on behalf of the Utilities Division of the Arizona Corporation Commission. BY THE COMMISSION: On October 1, 1996, the Utilities Division Staff ("Staff") of the Arizona Corporation Commission ("Commission") forwarded to the Commission proposed new rules A.A.C. R14-2-1601 through A.A.C. R14-2-1616 ("Rules" or "Electric Competition Rules") regarding competitive electric services. By Decision No. 59870 (October 10, 1996), the Commission directed the Hearing Division to schedule Public Comment regarding the proposed Rules in Phoenix, Tucson, Yuma, Flagstaff, and Kingman, Arizona. Our October 11, 1996 Procedural Order scheduled public comment proceedings on the above-captioned matter on December 2 in Phoenix, December 3 in Tucson and Yuma, and December 4 in Flagstaff and Kingman. Decision No. 59870 also ordered Staff to forward a Notice of Proposed Rulemaking ("Notice") to the Office of the Secretary of State for publication. The Notice was published in the Arizona Administrative Register on November 1, 1996. DISCUSSION ---------- The proposed Competitive Electric Rules set forth a framework for the inevitable transition from a non-competitive to a competitive environment. It has been a process that has evolved since May 1994 as Staff has held numerous workshops prior to bringing forth the proposed Rules. Based on the amount of comments filed and the attendance at each of the public comment proceedings held, the interest in the proposed Rules is as great as it has been for as any rules the Commission has promulgated. Based on the overall comments, we must conclude that all of the parties have expressed a desire for a more competitive electric market in Arizona. Some parties, including Arizona Public Service ("APS"), Tucson Electric Power ("TEP"), Citizens Utilities Company ("Citizens"), Salt River Project ("SRP") and the cooperatives were not as receptive to the proposed Rules as other parties. That is certainly understandable since, under the proposed Rules, their status as monopoly providers of electric service will change. The parties were generally in agreement that competition will provide the benefit of reduced costs, at least for some consumers. However, there were concerns raised regarding the quality of service, as well as concerns that not all customers, particularly residential customers, will receive the benefits of competition as quickly as some large industrial customers. And of course, the incumbent utilities were greatly concerned regarding the recoverability of stranded costs. While there was general agreement as to the need and inevitability of competition in the electric field, there were major disagreements over the implementation of these Rules. The parties identified complex problems such as the recoverability of stranded investment, intra-state and inter-state reciprocity, the status of the new Certificates of Convenience and Necessity ("CC&Ns"), and other issues, for which the parties assert the Rules provide insufficient guidance. Several parties have suggested holding evidentiary hearings on these issues in order to resolve them before going forward with these Rules. Other parties, including Staff, have warned against delay in promulgating these rules, indicating that the competitive electric market is rapidly approaching whether these Rules are promulgated or not. We conclude that these gaps, to the extent that they exist, can be filled in later with workshops, working groups, subsequent evidentiary hearings, and perhaps subsequent rulemaking proceedings; while competition is approaching rapidly, the transition to competition will allow time to address these issues and resolve them in a timely fashion. * * * * * * * * * * Having considered the entire record herein and being fully advised in the premises, the Commission finds, concludes, and orders that: FINDINGS OF FACT ---------------- 1. On October 1, 1996, Staff filed the proposed Rules regarding competitive electric services. 2. On October 10, 1996, the Commission issued Decision No. 59870 which directed the Hearing Division to schedule hearings on the proposed Rules in Phoenix, Tucson, Yuma, Flagstaff, and Kingman, Arizona. 3. The purpose of the proposed Rules is to provide the Commission with a framework to open the retail electric market to competition, and to streamline the regulatory process for setting rates for competitive electric services. 4. The proposed amendments to the Rules are set forth in Appendix A, attached hereto and incorporated by reference. 5. In accordance with A.R.S. Section 41-1027, a Concise Explanatory Statement for the proposed Rules is set forth in Appendix B, attached hereto and incorporated by reference. 6. The economic impact of the proposed Rules is set forth in Appendix C, attached hereto and incorporated by reference. 7. The Notice of Rulemaking was filed with the Secretary of State and was published in the Arizona Administrative Register on November 1, 1996. 8. Public Comment sessions were held on December 2, 1996, in Phoenix, December 3, 1996 in Tucson and Yuma, and December 4, 1996 in Flagstaff and Kingman, Arizona. CONCLUSIONS OF LAW ------------------ 1. The Commission has authority for the proposed Rules pursuant to the Arizona Constitution, Article XV, under A.R.S. Sections 40-202, -203, -250, - -321, -322, -331, -332, -336, 361, -365, -367, and under the Arizona Revised Statutes, Title 40, generally. 2. Notice of the proceeding has been given in the manner prescribed by law. 3. Adoption of the proposed Rules is in the public interest. 4. The Concise Explanatory Statement set forth in Appendix B should be adopted. ORDER IT IS THEREFORE ORDERED that the proposed Rules A.A.C. R14-2-1601, R14-2-1602, R14-2-1603, R14-2-1604, R14-2-1605, R14-2-1606, R14-2-1607, R14-2-1608, R14-2-1609, R14-2-1610, R14-2-1611, R14-2-1612, R14-2-1613, R14-2-1614, R14-2-1615, and R14-2-1616, as set forth in Appendix A, and the Concise Explanatory Statement, as set forth in Appendix B, are hereby adopted. IT IS FURTHER ORDERED that the Commission=s Utilities Division shall immediately forward the new Rules A.A.C. R14-2-1601, R14-2-1602, R14-2-1603, R14-2-1604, R14-2-1605, R14-2-1606, R14-2-1607, R14-2-1608, R14-2-1609, R14-2-1610, R14-2-1611, R14-2-1612, R14-2-1613, R14-2-1614, R14-2-1615, and R14-2-1616, to the Secretary of State. IT IS FURTHER ORDERED that this Decision shall become effective immediately. BY ORDER OF THE ARIZONA CORPORATION COMMISSION Renz D. Jennings Marcia Weeks Carl J. Kunasek - -------------------------------------------------------------------------------- CHAIRMAN COMMISSIONER COMMISSIONER IN WITNESS WHEREOF, I, JAMES MATTHEWS, Executive Secretary of the Arizona Corporation Commission, have hereunto, set my hand and caused the official seal of this Commission to be affixed at the Capitol, in the City of Phoenix, this 26th day of December , 1996. Phillip R. Moulton, Deputy --------------------------------------- for JAMES MATTHEWS Executive Secretary DISSENT __________________ GY:DB:KEC: RTW:BAB:mmc TITLE 14. PUBLIC SERVICE CORPORATIONS; CORPORATIONS AND ASSOCIATIONS; SECURITIES REGULATIONS CHAPTER 2. CORPORATION COMMISSION - FIXED UTILITIES ARTICLE 16. RETAIL ELECTRIC COMPETITION Section R14-2-1601. Definitions R14-2-1602. Filing of Tariffs by Affected Utilities R14-2-1603. Certificates of Convenience and Necessity R14-2-1604. Competitive Phases R14-2-1605. Competitive Services R14-2-1606. Services Required To Be Made Available by Affected Utilities R14-2-1607. Recovery of Stranded Cost of Affected Utilities R14-2-1608. System Benefits Charges R14-2-1609. Solar Portfolio Standard R14-2-1610. Spot Markets and Independent System Operation R14-2-1611. In-State Reciprocity R14-2-1612. Rates R14-2-1613. Service Quality, Consumer Protection, Safety, and Billing Requirements R14-2-1614. Reporting Requirements R14-2-1615. Administrative Requirements R14-2-1616. Legal Issues ARTICLE 16. RETAIL ELECTRIC COMPETITION R14-2-1601. Definitions In this Article, unless the context otherwise requires: 1. "Affected Utilities" means the following public service corporations providing electric service: Tucson Electric Power Company, Arizona Public Service Company, Citizens Utilities Company, Arizona Electric Power Cooperative, Trico Electric Cooperative, Duncan Valley Electric Cooperative, Graham County Electric Cooperative, Mohave Electric Cooperative, Sulphur Springs Valley Electric Cooperative, Navopache Electric Cooperative, Ajo Improvement Company, and Morenci Water and Electric Company. #In the event that modifications are made to existing law that would allow the application of this Article to the Salt River Project Agricultural Improvement and Power District ("SRP") then Affected Utilities shall also include SRP.# 2. "Bundled Service" means electric service provided as a package to the consumer including all generation, transmission, distribution, ancillary and other services necessary to deliver and measure useful electric energy and power to consumers. 3. "Buy-through" refers to a purchase of electricity by an Affected Utility at wholesale for a particular retail consumer or aggregate of consumers or at the direction of a particular retail consumer or aggregate of consumers. 4. "Distribution Service" means the delivery of electricity to a retail consumer through wires, transformers, and other devices that are not classified as transmission services subject to the jurisdiction of the Federal Energy Regulatory Commission; Distribution Service excludes meters and meter reading. 5. "Electric Service Provider" means a company supplying, marketing, or brokering at retail any of the services described in R14-2-1605 or R14-2-1606. 6. "Eligible Demand" means the total consumer kilowatts of demand which an Affected Utility must make available to competitive generation under the terms of this Article or the consumer kilowatts of demand provided competitively in an Affected Utility's distribution territory, whichever is greater. 7. "Standard Offer" means Bundled Service offered to all consumers in a designated area at regulated rates. 8. "Stranded Cost" means the verifiable net difference between: a. The value of all the prudent jurisdictional assets and obligations necessary to furnish electricity (such as generating plants, purchased power contracts, fuel contracts, and regulatory assets), acquired or entered into prior to the adoption of this Article, under traditional regulation of Affected Utilities; and b. The market value of those assets and obligations directly attributable to the introduction of competition under this Article. 9. "System Benefits" means Commission-approved utility low income, demand side management, environmental, renewables, and nuclear power plant decommissioning programs. 10. "Unbundled Service" means electric service elements provided and priced separately, including, but not limited to, such service elements as generation, transmission, distribution, and ancillary services. Unbundled Service may be sold to consumers or to other Electric Service Providers. Text between # indicates strikethrough R14-2-1602. Filing of Tariffs by Affected Utilities Each Affected Utility shall file tariffs consistent with this Article by December 31, 1997. R14-2-1603. Certificates of Convenience and Necessity A. Any Electric Service Provider intending to supply services described in R14- 2-1605 or R-14-2-1606, other than services subject to federal jurisdiction, shall obtain a Certificate of Convenience and Necessity from the Commission pursuant to this Article; however, a Certificate is not required to offer information services or billing and collection services. An Affected Utility does not need to apply for a Certificate of Convenience and Necessity for any service provided as of the date of adoption of this Article within its distribution service territory. B. Any company desiring such a Certificate of Convenience and Necessity shall file with the Docket Control Center the required number of copies of an application. Such Certificates shall be restricted to geographical areas served by the Affected Utilities as of the date this Article is adopted and to service areas added under the provisions of R14-2-1611. In support of the request for a Certificate of Convenience and Necessity, the following information must be provided: 1. A description of the electric services which the applicant intends to offer; 2. The proper name and correct address of the applicant, and a. The full name of the owner if a sole proprietorship, b. The full name of each partner if a partnership, c. A full list of officers and directors if a corporation, or d. A full list of the members if a limited liability corporation; 3. A tariff for each service to be provided that states the maximum rate and terms and conditions that will apply to the provision of the service; 4. A description of the applicant's technical ability to obtain and deliver electricity and provide any other proposed services; 5. Documentation of the financial capability of the applicant to provide the proposed services, including the most recent income statement and balance sheet, the most recent projected income statement, and other pertinent financial information. Audited information shall be provided if available; 6. A description of the form of ownership (e.g., partnership, corporation); 7. Such other information as the Commission or the Staff may request. C. At the time of filing for a Certificate of Convenience and Necessity, each applicant shall notify the Affected Utilities in whose service territories it wishes to offer service of the application by serving a complete copy of the application on the Affected Utilities. D. The Commission may deny certification to any applicant who: 1. Does not provide the information required by this Article; 2. Does not possess adequate technical or financial capabilities to provide the proposed services; 3. Fails to provide a performance bond, if required. E. Every Electric Service Provider obtaining a Certificate of Convenience and Necessity under this Article shall obtain certification subject to the following conditions: 1. The Electric Service Provider shall comply with all Commission rules, orders, and other requirements relevant to the provision of electric service and relevant to resource planning; 2. The Electric Service Provider shall maintain accounts and records as required by the Commission; 3. The Electric Service Provider shall file with the Director of the Utilities Division all financial and other reports that the Commission may require and in a form and at such times as the Commission may designate; 4. The Electric Service Provider shall maintain on file with the Commission all current tariffs and any service standards that the Commission shall require; 5. The Electric Service Provider shall cooperate with any Commission investigation of customer complaints; 6. The Electric Service Provider shall obtain all necessary permits and licenses; 7. Failure to comply with any of the above conditions may result in recision of the Electric Service Provider's Certificate of Convenience and Necessity. F. In appropriate circumstances, the Commission may require, as a precondition to certification, the procurement of a performance bond sufficient to cover any advances or deposits the applicant may collect from its customers, or order that such advances or deposits be held in escrow or trust. R14-2-1604. Competitive Phases A. Each Affected Utility shall make available at least 20 percent of its 1995 system retail peak demand for competitive generation supply to all customer classes (including residential and small commercial consumers) not later than January 1, 1999. If data permit, coincident annual peak demand shall be used; otherwise noncoincident peak data may be used. 1. No more than 1/2 of the Eligible Demand may be procured by consumers, each of whose total competitive contract demand is greater than 3 MW. 2. At least 15% of the Eligible Demand shall be reserved for residential consumers. 3. Aggregation of loads of multiple consumers shall be permitted. B. Each Affected Utility shall make available at least 50% of its 1995 system retail peak demand for competitive generation supply to all customer classes (including residential and small commercial consumers) not later than January 1, 2001. If data permit, coincident peak annual demand shall be used; otherwise noncoincident peak data may be used. 1. No more than 1/2 of the Eligible Demand may be procured by consumers, each of whose total competitive contract demand is greater than 3 MW. 2. At least 30 % of the Eligible Demand shall be reserved for residential consumers. 3. Aggregation of loads of multiple consumers shall be permitted. C. Prior to 2001, no single consumer shall receive more than 20% of the Eligible Demand in a given year in an Affected Utility's service territory. D. Each Affected Utility shall make available all of its retail demand for competitive generation supply not later than January 1, 2003. E. By the date indicated in R14-2-1602, Affected Utilities shall propose for Commission review and approval how customers will be selected for participation in the competitive market prior to 2003. 1. Possible selection methods are first-come, first-served; random selection via a lottery among volunteering consumers; or designation of geographic areas. 2. The method for selecting customers to participate in the competitive market must fairly allow participation by a wide variety of customers of all sizes of loads. 3. All customers who produce or purchase at least 10% of their annual electricity consumption from photovoltaic or solar thermal resources installed in Arizona after January 1, 1997 shall be selected for participation in the competitive market if those customers apply for participation in the competitive market. Such participants count toward the minimum requirements in R14-2- 1604(A) and R14-2-1604(B). 4. The Commission Staff shall commence a series of workshops on selection issues within 45 days of the adoption of this Article and Staff shall submit a report to the Commission discussing the activities and recommendations of participants in the workshops. The report shall be due not later than 90 days prior to the date indicated in R14-2-1602. F. Retail consumers served under existing contracts are eligible to participate in the competitive market prior to expiration of the existing contract only if the Affected Utility and the consumer agree that the retail consumer may participate in the competitive market. G. An Affected Utility may engage in Buy-throughs with individual or aggregated consumers. Any contract for a Buy-through effective prior to the date indicated in R14-2-1604(A) must be approved by the Commission. H. Schedule Modifications for Cooperatives 1. An electric cooperative may request that the Commission modify the schedule described in R14-2-1604(A) through R14-2-1604(D) so as to preserve the tax exempt status of the cooperative or to allow time to modify contractual arrangements pertaining to delivery of power supplies and associated loans. 2. As part of the request, the cooperative shall propose methods to enhance consumer choice among generation resources. 3. The Commission shall consider whether the benefits of modifying the schedule exceed the costs of modifying the schedule. R14-2-1605. Competitive Services A properly certificated Electric Service Provider may offer any of the following services under bilateral or multilateral contracts with retail consumers: A. Generation of electricity from generators at any location whether owned by the Electric Service Provider or purchased from another generator or wholesaler of electric generation. B. Any service described in R14-2-1606, except Distribution Service and except services required by the Federal Energy Regulatory Commission to be monopoly services. Billing and collection services and information services do not require a Certificate of Convenience and Necessity. R14-2-1606. Services Required To Be Made Available by Affected Utilities A. Until the Commission determines that competition has been substantially implemented for a particular class of consumers (residential, commercial, industrial) so that all consumers in that class have an opportunity to participate in the competitive market, and until all Stranded Costs pertaining to that class of customers have been recovered, each Affected Utility shall make available to all consumers in that class in its service area, as defined on the date indicated in R14-2-1602, Standard Offer bundled generation, transmission, ancillary, distribution, and other necessary services at regulated rates. 1. An Affected Utility may request that the Commission determine that competition has been substantially implemented to allow discontinuation of Standard Offer service and shall provide sufficient documentation to support its request. 2. The Commission may, on its own motion, investigate whether competition has been substantially implemented and whether Standard Offer service may be discontinued. B. Standard Offer Tariffs 1. By the date indicated in R14-2-1602, each Affected Utility may file proposed tariffs to provide Standard Offer Bundled Service and such rates shall not become effective until approved by the Commission. If no such tariffs are filed, rates and services in existence as of the date in R14-2-1602 shall constitute the Standard Offer. 2. Affected Utilities may file proposed revisions to such rates. It is the expectation of the Commission that the rates for Standard Offer service will not increase, relative to existing rates, as a result of allowing competition. Any rate increase proposed by an Affected Utility for Standard Offer service must be fully justified through a rate case proceeding. 3. Such rates shall reflect the costs of providing the service. 4. Consumers receiving Standard Offer service are eligible for future rate reductions authorized by the Commission, such as reductions authorized in Decision No. 59601. C. By the date indicated in R14-2-1602, each Affected Utility shall file Unbundled Service tariffs to provide the services listed below to all eligible purchasers on a nondiscriminatory basis: 1. Distribution Service; 2. Metering and meter reading services; 3. Billing and collection services; 4. Open access transmission service (as approved by the Federal Energy Regulatory Commission, if applicable); 5. Ancillary services in accordance with Federal Energy Regulatory Commission Order 888 (III FERC Stats. & Regs. P. 31,036, 1996) incorporated herein by reference; 6. Information services such as provision of customer information to other Electric Service Providers; 7. Other ancillary services necessary for safe and reliable system operation. D. To manage its risks, an Affected Utility may include in its tariffs deposit requirements and advance payment requirements for Unbundled Services. E. The Affected Utilities must provide transmission and ancillary services according to the following guidelines: 1. Services must be provided consistent with applicable tariffs filed with the Federal Energy Regulatory Commission. 2. Unless otherwise required by federal regulation, Affected Utilities must accept power and energy delivered to their transmission systems by others and offer transmission and related services comparable to services they provide to themselves. F. Customer Data 1. Upon authorization by the customer, an Electric Service Provider shall release in a timely and useful manner that customer's demand and energy data for the most recent 12 month period to a customer-specified Electric Service Provider. 2. The Electric Service Provider requesting such customer data shall provide an accurate account number for the customer. 3. The form of data shall be mutually agreed upon by the parties and such data shall not be unreasonably withheld. G. Rates for Unbundled Services 1. The Commission shall review and approve rates for services listed in R14-2-1606(C) and requirements listed in R14-2-1606(D), where it has jurisdiction, before such services can be offered. 2. Such rates shall reflect the costs of providing the services. 3. Such rates may be downwardly flexible if approved by the Commission. H. Electric Service Providers offering services under this R14-2-1606 shall provide adequate supporting documentation for their proposed rates. Where rates are approved by another jurisdiction, such as the Federal Energy Regulatory Commission, those rates shall be provided to this Commission. I. Within 90 days of the adoption of this Article, the Commission Staff shall commence a series of workshops to explore issues in the provision of Unbundled Service and Standard Offer service. 1. Parties to be invited to participate in the workshops shall include utilities, consumers, organizations promoting energy efficiency, and other Electric Service Providers. 2. Among the issues to be reviewed in the workshops are: metering requirements; metering protocols; designation of appropriate test years; the nature of adjustments to test year data; de-averaging of rates; service characteristics such as voltage levels; revenue uncertainty; line extension policies; and the need for performance bonds. 3. A report shall be submitted to the Commission by the Staff on the activities and recommendations of the participants in the workshops not later than 60 days prior to the date indicated in R14-2-1602. The Commission shall consider any recommendations regarding Unbundled Service and Standard Offer service tariffs. R14-2-1607. Recovery of Stranded Cost of Affected Utilities A. The Affected Utilities shall take every feasible, cost-effective measure to mitigate or offset Stranded Cost by means such as expanding wholesale or retail markets, or offering a wider scope of services for profit, among others. B. The Commission shall allow recovery of unmitigated Stranded Cost by Affected Utilities. C. A working group to develop reccomendations for the analysis and recovery of Stranded Cost shall be established. 1. The working group shall commence activities within 15 days of the date of adoption of this Article. 2. Members of the working group shall include representatives of Staff, the Residential Utility Consumer Office, consumers, utilities, and other Electric Service Providers. In addition, the Executive and Legislative Branches shall be invited to send representatives to be members of the working group. 3. The working group shall be coordinated by the Director of the Utilities Division of the Commission or by his or her designee. D. In developing its recommendations, the working group shall consider at least the following factors: 1. The impact of Stranded Cost recovery on the effectiveness of competition; 2. The impact of Stranded Cost recovery on customers of the Affected Utility who do not participate in the competitive market; 3. The impact, if any, on the Affected Utility's ability to meet debt obligations; 4. The impact of Stranded Cost recovery on prices paid by consumers who participate in the competitive market; 5. The degree to which the Affected Utility has mitigated or offset Stranded Cost; 6. The degree to which some assets have values in excess of their book values; 7. Appropriate treatment of negative Stranded Cost; 8. The time period over which such Stranded Cost charges may be recovered. The Commission shall limit the application of such changes to a specified time period; 9. The ease of determining the amount of Stranded Cost; 10. The applicability of Stranded Cost to interruptible customers; 11. The amount of electricity generated by renewable generating resources owned by the Affected Utility. E. The working group shall submit to the Commission a report on the activities and recommendations of the working group no later than 90 days prior to the date indicated in R14-2-1602. F. The Commision shall consider the recommendations and decide what actions, if any, to take based on the recommendations. G. The Affected Utilities shall file estimates of unmitigated Stranded Cost. Such estimates shall be fully supported by analyses and by records of market transactions undertaken by willing buyers and willing sellers. H. An Affected Utility shall request Commission approval of distribution charges or other means of recovering unmitigated Stranded Cost from customers who reduce or terminate service from the Affected Utility as a direct result of competition governed by this Article, or who obtain lower rates from the Affected Utility as a direct result of the competition governed by this Article. I. The Commission shall, after hearing and consideration of analyses and recommendations presented by the Affected Utilities, Staff, and intervenors, determine for each Affected Utility the magnitude of Stranded Cost, and appropriate Stranded Cost recovery mechanisms and charges. In making its determination of mechanisms and charges, the Commission shall consider at least the following factors: 1. The impact of Stranded Cost recovery on the effectiveness of competition; 2. The impact of Stranded Cost recovery on customers of the Affected Utility who do not participate in the competitive market; 3. The impact, if any, on the Affected Utility's ability to meet debt obligations; 4. The impact of Stranded Cost recovery on prices paid by consumers who participate in the competitive market; 5. The degree to which the Affected Utility has mitigated or offset Stranded Cost; 6. The degree to which some assets have values in excess of their book values; 7. Appropriate treatment of negative Stranded Cost; 8. The time period over which such Stranded Cost charges may be recovered. The Commission shall limit the application of such charges to a specified time period; 9. The ease of determining the amount of Stranded Cost; 10. The applicability of Stranded Cost to interruptible customers; 11. The amount of electricity generated by renewable generating resources owned by the Affected Utility. J. Stranded Cost may only be recovered from customer purchases made in the competitive market using the provisions of this Article. Any reduction in electricity purchases from an Affected Utility resulting from self-generation, demand side management, or other demand reduction attributable to any cause other than the retail access provisions of this Article shall not be used to calculate or recover any Stranded Cost from a consumer. K. The Commission may order an Affected Utility to file estimates of Stranded Cost and mechanisms to recover or, if negative, to refund Stranded Cost. L. The Commission may order regular revisions to estimates of the magnitude of Stranded Cost. R14-2-1608. System Benefits Charges A. By the date indicated in R14-2-1602, each Affected Utility shall file for Commission review non-bypassable rates or related mechanisms to recover the applicable pro-rata costs of System Benefits from all consumers located in the Affected Utility's service area who participate in the competitive market. In addition, the Affected Utility may file for a change in the System Benefits charge at any time. The amount collected annually through the System Benefits charge shall be sufficient to fund the Affected Utilities' present Commission-approved low income, demand side management, environmental, renewables, and nuclear power plant decommissioning programs. B. Each Affected Utility shall provide adequate supporting documentation for its proposed rates for System Benefits. C. An Affected Utility shall recover the costs of System Benefits only upon hearing and approval by the Commission of the recovery charge and mechanism. The Commission may combine its review of System Benefits charges with its review of filings pursuant to R14-2-1606. D. Methods of calculating System Benefits charges shall be included in the workshops described in R14-2-1606(I). R14-2-1609. Solar Portfolio Standard A. Starting on January 1, 1999, any Electric Service Provider selling electricity under the provisions of this Article must derive at least 1/2 of 1% of the total retail energy sold competitively from new solar resources, whether that solar energy is purchased or generated by the seller. Solar resources include photovoltaic resources and solar thermal resources that generate electricity. New solar resources are those installed on or after January 1, 1997. B. Solar portfolio standard after December 31, 2001: 1. Starting on January 1, 2002, any Electric Service Provider selling electricity under the provisions of this Article must derive at least 1% of the total retail energy sold competitively from new solar resources, whether that solar energy is purchased or generated by the seller. Solar resources include photovoltaic resources and solar thermal resources that generate electricity. New solar resources are those installed on or after January 1, 1997. 2. The Commission may change the solar portfolio percentage applicable after December 31, 2001, taking into account, among other factors, the costs of producing solar electricity and the costs of fossil fuel for conventional power plants. C. Any Electric Service Provider certificated under the provisions of this Article shall be able to credit 2 times the electric energy it generated, or caused to be generated under contract, before January 1, 1999 using photovoltaics or solar thermal resources installed on or after January 1, 1997 in Arizona to the electric energy requirements of R14-2-1609(A) or R14-2-1609(B). D. Electric Service Providers selling electricity under the provisions of this Article shall provide reports on sales and solar power as required in this Article, clearly demonstrating the output of solar resources, the installation date of solar resources, and the transmission of energy from those solar resources to Arizona consumers. The Commission may conduct necessary monitoring to ensure the accuracy of these data. E. If an Electric Service Provider selling electricity under the provisions of this Article fails to meet the requirement in R14-2-1609(A) or R14-2-1609(B) in any year, the Commission may impose a penalty on that Electric Service Provider up to $0.30 per kWh for deficiencies in the provision of solar energy. In addition, if the provision of solar energy is consistently deficient, the Commission may void an Electric Service Provider's contracts negotiated under this Article. F. Photovoltaic or solar thermal resources that are located on the consumer's premises shall count toward the solar portfolio standard applicable to the current Electric Service Provider serving that consumer. G. The solar portfolio standard described in this section is in addition to renewable resource goals for Affected Utilities established in Decision No. 58643. R14-2-1610. Spot Markets and Independent System Operation A. The Commission shall conduct an inquiry into spot market development and independent system operation for the transmission system. B. The Commission may support development of a spot market or independent system operator(s) for the transmission system. C. The Commission may work with other entities to help establish spot markets and independent system operators. R14-2-1611. In-State Reciprocity A. The service territories of Arizona electric utilities which are not Affected Utilities shall not be open to competition under the provisions of this Article, nor shall Arizona electric utilities which are not Affected Utilities be able to compete for sales in the service territories of the Affected Utilities. B. An Arizona electric utility, subject to the jurisdiction of the Commission, which is not an Affected Utility may voluntarily participate under the provisions of this Article if it makes its service territory available for competing sellers, if it agrees to all of the requirements of this Article, and if it obtains an appropriate Certificate of Convenience and Necessity. #C. The Commission shall pursue, on its own or in cooperation whith the Joint Legislative Study Committe on Electric Industry Competition established by House Bill 2504 (1996), legislation to address the role of electric utilities of Arizona political subdivisions or municipal corporations in a competitive market. The Commission shall further make available, as appropriate, Staff assistance to the Legislature if the Legislature requests such assistance for the purpose of determining the proper role of electric utilities of Arizona political subdivisions or municipal corporations in a competitive market. D. An Arizona electic utility, not subject to the jurisdiction of the Commission, which is not an Affected Utility, may voluntarily participate under the provisions of this Article if it makes its service territory available for competing sellers, if it agrees to all of the requirements of this Article other than any requirement to obtain a Certificate of Convenience and Necessity, if adequate enforcement mechanisms can be established, and if all other Affected Utilities consent in writing.# C. An Arizona electric utility, not subject to the jurisdiction of the --------------------------------------------------------------------------- Commission, may submit a statement to the Commission that it voluntarily --------------------------------------------------------------------------- opens its service territory for competing sellers in a manner similar to --------------------------------------------------------------------------- the provisions of this Article. Such statement shall be accompanied by the --------------------------------------------------------------------------- electric utility's nondiscriminatory Standard Offer Tariff, electric supply --------------------------------------------------------------------------- tariffs, Unbundled Services rates, Stranded Cost charges, System Benefits --------------------------------------------------------------------------- charges, Distribution Services charges and any other applicable tariffs and --------------------------------------------------------------------------- policies for services the electric utility offers for which these Rules --------------------------------------------------------------------------- otherwise require compliance by Affected Utilities or Electric Service --------------------------------------------------------------------------- Providers. Such filings shall serve as authorization for such electric --------------------------------------------------------------------------- utility to utilize the Commission's Rules of Practice and Procedure and --------------------------------------------------------------------------- other applicable Rules concerning any complaint that an Affected Utility or --------------------------------------------------------------------------- #Text between # indicates strikethrough Electric Service Provider is violating any provision of this Article or is --------------------------------------------------------------------------- otherwise discriminating against the filing electric utility or failing to --------------------------------------------------------------------------- provide just and reasonable rates in tariffs filed under this Article. --------------------------------------------------------------------------- D. If an electric utility is an Arizona political subdivision or municipal --------------------------------------------------------------------------- corporation, then the existing service territory of such electric utility --------------------------------------------------------------------------- shall be deemed open to competition if the political subdivision or --------------------------------------------------------------------------- municipality has entered into an intergovernmental agreement with the --------------------------------------------------------------------------- Commission that establishes nondiscriminatory terms and conditions for --------------------------------------------------------------------------- Distribution Services and other Unbundled Services, provides a procedure --------------------------------------------------------------------------- for complaints arising therefrom, and provides for reciprocity with --------------------------------------------------------------------------- Affected Utilities. The Commission shall conduct a hearing to consider any --------------------------------------------------------------------------- such intergovernmental agreement. R14-2-1612. Rates A. Market determined rates for competitively provided services as defined in R14-2-1605 shall be deemed to be just and reasonable. B. Each Electric Service Provider selling services under this Article shall have on file with the Commission tariffs describing such services and maximum rates for those services, but the services may not be provided until the Commission has approved the tariffs. C. Prior to the date indicated in R14-2-1604(D), competitively negotiated contracts governed by this Article customized to individual customers which comply with approved tariffs do not require further Commission approval. However, all such contracts whose term is one year or more and for service of 1 MW or more must be filed with the Director of the Utilities Division as soon as practicable. If a contract does not comply with the provisions of this Article it shall not become effective without a Commission order. D. Contracts entered into on or after the date indicated in R14-2-1604(D) which comply with approved tariffs need not be filed with the Director of the Utilities Division. If a contract does not comply with the provisions of this Article it shall not become effective without a Commission order. E. An Electric Service Provider holding a Certificate pursuant to this Article may price its competitive services, as defined in R14-2-1605, at or below the maximum rates specified in its filed tariff, provided that the price is not less than the marginal cost of providing the service. F. Requests for changes in maximum rates or changes in terms and conditions of previously approved tariffs may be filed. Such changes become effective only upon Commission approval. R14-2-1613. Service Quality, Consumer Protection, Safety, and Billing Requirements A. Except as indicated elsewhere in this Article, R14-2-201 through R14-2-212, inclusive, are adopted in this Article by reference. However, where the term "utility" is used in R14-2-201 through R14-2-212, the term "utility" shall pertain to Electric Service Providers providing the services described in each paragraph of R14-2-201 through R14-2-212. R14-2-212(G)(2) shall pertain only to Affected Utilities. R14-2-212(G)(4) shall apply only to Affected Utilities. R14-2-212(H) shall pertain only to Electric Service Providers who provide distribution service. B. The following shall not apply to this Article: 1. R14-2-202 in its entirety, 2. R14-2-212(F)(1), 3. R14-2-213. C. No consumer shall be deemed to have changed suppliers of any service authorized in this Article (including changes from supply by the Affected Utility to another supplier) without written authorization by the consumer for service from the new supplier. If a consumer is switched to a different ("new") supplier without such written authorization, the new supplier shall cause service by the previous supplier to be resumed and the new supplier shall bear all costs associated with switching the consumer back to the previous supplier. D. Each Electric Service Provider providing service governed by this Article shall be responsible for meeting applicable reliability standards and shall work cooperatively with other companies with whom it has interconnections, directly or indirectly, to ensure safe, reliable electric service. E. Each Electric Service Provider shall provide at least 30 days notice to all of its affected consumers if it is no longer obtaining generation, transmission, distribution, or ancillary services necessitating that the consumer obtain service from another supplier of generation, transmission, distribution, or ancillary services. F. All Electric Service Providers rendering service under this Article shall submit accident reports as required in R14-2-101. G. An Electric Service Provider providing firm electric service governed by this Article shall make reasonable efforts to reestablish service within the shortest possible time when service interruptions occur and shall work cooperatively with other companies to ensure timely restoration of service where facilities are not under the control of the Electric Service Provider H. Each Electric Service Provider shall ensure that bills rendered on its behalf include the toll free telephone numbers for billing, service, and safety inquiries and the telephone number of the Consumer Services Section of the Arizona Corporation Commission Utilities Division. Each Electric Service Provider shall ensure that billing and collection services rendered on its behalf comply with R14-2-1613(A) and R14-2- 1613(B). I. Additional Provisions for Metering and Meter Reading Services 1. An Electric Service Provider who provides metering or meter reading services pertaining to a particular consumer shall provide access to meter readings to other Electric Service Providers serving that same consumer. 2. A consumer or an Electric Service Provider relying on metering information provided by another Electric Service Provider may request a meter test according to the tariff on file and approved by the Commission. However, if the meter is found to be in error by more than 3%, no meter testing fee will be charged. 3. Protocols for metering shall be developed subsequent to the workshops described in R14-2-1606(I). J. Working Group on System Reliability and Safety: 1. If it has not already done so, the Commission shall establish, by separate order, a working group to monitor and review system reliability and safety. a. The working group may establish technical advisory panels to assist it. b. The working group shall commence activities within 15 days of the date of adoption of this Article. c. Members of the working group shall include representatives of Staff, consumers, the Residential Utility Comsumer Office, utilities, other Electric Service Providers and organizations promoting energy efficiency. In addition, the Executive and Legislative Branches shall be invited to send representatives to be members of the working group. d. The working group shall be coordinated by the Director of the Utilities Division of the Commission or by his or her designee. 2. All Electric Service Providers governed by this Article shall cooperate and participate in any investigation conducted by the working group, including provision of data reasonably related to system reliability or safety. 3. The working group shall report to the Commission on system reliability and safety regularly, and shall make recommendations to the Commission regarding improvements to reliability or safety. K. Electric Service Providers shall comply with applicable reliability standards and practices established by the Western Systems Coordinating Council and the North American Electric Reliability Council or successor organizations. L. Electric Service Providers shall provide notification and informational materials to consumers about competition and consumer choices, such as a standardized description of services, as ordered by the Commission. R14-2-1614. Reporting Requirements A. Reports covering the following items shall be submitted to the Director of the Utilities Division by Affected Utilities and all Electric Service Providers granted a Certificate of Convenience and Necessity pursuant to this Article. These reports shall include the following information pertaining to competitive service offerings, Unbundled Services, and Standard Offer services in Arizona: 1. Type of services offered; 2. kW and kWh sales to consumers, disaggregated by customer class (e.g., residential, commercial, industrial); 3. Solar energy sales (kWh) and sources for grid connected solar resources; kW capacity for off-grid solar resources; 4. Revenues from sales by customer class (e.g., residential, commercial, industrial); 5. Number of retail customers disaggregated as follows: aggregators, residential, commercial under 100 kW, commercial 100 kW to 2999 kW, commercial 3000 kW or more, industrial less than 3000 kW, industrial 3000 kW or more, agricultural (if not included in commercial), and other; 6. Retail kWh sales and revenues disaggregated by term of the contract (less than 1 year, 1 to 4 years, longer than 4 years), and by type of service (for example, firm, interruptible, other); 7. Amount of and revenues from each service provided under R14-2- 1605, and, if applicable, R14-2-1606; 8. Value of all Arizona specific assets and accumulated depreciation; 9. Tabulation of Arizona electric generation plants owned by the Electric Service Provider broken down by generation technology, fuel type, and generation capacity; 10. Other data requested by Staff or the Commission; 11. In addition, prior to the date indicated in R14-2-1604(D), Affected Utilities shall provide data demonstrating compliance with the requirements of R14-2-1604; B. Reporting Schedule 1. For the period through December 31, 2003, semi-annual reports shall be due on April 15 (covering the previous period of July through December) and October 15 (covering the previous period of January through June). The first such report shall cover the period January 1 through June 30, 1999. 2. For the period after December 31, 2003, annual reports shall be due on April 15 (covering the previous period of January through December). The first such report shall cover the period January 1 through December 31, 2004. C. The information listed above may be provided on a confidential basis. However, Staff or the Commission may issue reports with aggregate statistics based on confidential information that do not disclose data pertaining to a particular seller or purchases by a particular buyer. D. Any Electric Service Provider governed by this Article which fails to file the above data in a timely manner may be subject to a penalty imposed by the Commission or may have its Certificate rescinded by the Commission. E. Any Electric Service Provider holding a Certificate pursuant to this Article shall report to the Director of the Utilities Division the discontinuation of any competitive tariff as soon as practicable after the decision to discontinue offering service is made. F. In addition to the above reporting requirements, Electric Service Providers governed by this Article shall participate in Commission workshops or other forums whose purpose is to evaluate competition or assess market issues. G. Reports filed under the provisions of this section shall be submitted in written format and in electronic format. Electric Service Providers shall coordinate with the Commission Staff on formats. R14-2-1615. Administrative Requirements A. Any Electric Service Provider certificated under this Article may propose additional electric services at any time by filing a proposed tariff with the Commission describing the service, maximum rates, terms and conditions. The proposed new electrical service may not be provided until the Commission has approved the tariff. B. Contracts filed pursuant to this Article shall not be open to public inspection or made public except on order of the Commission, or by the Commission or a Commissioner in the course of a hearing or proceeding. C. The Commission may consider variations or exemptions from the terms or requirements of any of the rules in this Article upon the application of an affected party. The application must set forth the reasons why the public interest will be served by the variation or exemption from the Commission rules and regulations. Any variation or exemption granted shall require an order of the Commission. Where a conflict exists between these rules and an approved tariff or order of the Commission, the provisions of the approved tariff or order of the Commission shall apply. D. The Commission may develop procedures for resolving disputes regarding implementation of retail electric competition. R14-2-1616. Legal Issues A. A working group to identify, analyze and provide recommendations to the Commission on legal issues relevant to this Article shall be established. 1. The working group shall commence activities within 15 days of the date of adoption of this Article. 2. Members of the working group shall include representatives of Staff, the Residential Utility Consumer Office, consumers, utilities, and other Electric Service Providers. In addition, the Executive and Legislative Branches and the Attorney General shall be invited to send representatives to be members of the working group. 3. The working group shall be coordinated by the Director of the Legal Division of the Commission or by his or her designee. B. The working group shall submit to the Commission a report on the activities and recommendations of the working group no later than 90 days prior to the date indicated in R14-2-1602. C. The Commission shall consider the recommendations and decide what actions, if any, to take based on the recommendations. APPENDIX B ---------- CONCISE EXPLANATORY STATEMENT ----------------------------- This explanatory statement is provided to comply with A.R.S. Section 41-1036. I. REASONS FOR ADOPTING THE PROPOSED AMENDMENTS. The Arizona Corporation Commission has promulgated proposed Rules to govern the provision of competitive electric services in the State of Arizona. R14-2-1601. Definitions. This section contains all the definitions necessary to interpret and follow the provisions set forth in the proposed Rules. R14-2-1602. Filing of Tariffs by Affected Utilities. This section requires all Affected Utilities (defined in R14-2-1601) to file tariffs required by this Article by December 31, 1997. R14-2-1603. Certificates of Convenience and Necessity. This section requires all Electric Services Providers (defined in R14-2-1601) intending to supply electric services under this Article to obtain a Certificate of Convenience and Necessity from the Commission. Affected Utilities already have Certificates for their existing service area, and thus need not obtain a Certificate in order to continue to provide service therein. This section sets up the process for obtaining such Certificates, as well as grounds for denial and conditions under which they may be granted. R14-2-1604. Competitive Phases. This section outlines the time frames for the introduction of competition in Arizona. In the first phase, to begin in 1999, Affected Utilities are required to open up 20 percent of their base year (1995) markets (as measured by kW demand) to competition. In the second phase, to begin in 2001, this is enlarged to at least 50 percent of the incumbent utilities' base year markets. Full competition for generation, the third phase, begins in 2003. At least 15 percent of the eligible demand must be reserved for residential consumers in the competitive marketplace in the first phase, and at least 30 percent of the eligible demand must be reserved for residential consumers in the competitive marketplace in the second phase. In addition, prior to 2001, no single consumer may receive more than 20 percent of the total service available in the competitive market in an Affected Utility's service territory. The Affected Utilities must propose how customers will be selected for participation in the competitive market. Consumers who use photovoltaics or solar thermal resources (built after January 1, 1997 and installed in Arizona) for at least 10 percent of their annual electricity consumption are automatically included in the list of eligible customers for participation in the competitive market if they wish to participate in the competitive market. To assist the Affected Utilities and the Commission in understanding selection issues, a workshop will be conducted on selection issues prior to the date when selection filings are due. Customers served under existing contracts are eligible to participate in the competitive market prior to expiration of the existing contract only if the affected utility and customer agree to early revision of the contract. Buy-throughs are permitted on a voluntary basis. These mechanisms, which enable the incumbent utility to purchase specific sources of energy at wholesale for the use of a specific consumer, may enable some consumers to obtain some of the benefits of competition prior to the start of the first competitive phase, if the Commission approves. Electric cooperatives may request a modification to the schedule. Any such requests must include proposals on enhancing consumer choice among generation resources. The Commission will have to consider the costs and benefits of modifying the schedule in making a determination on the proposed modifications. R14-2-1605. Competitive Services. This section describes services which can be provided competitively. These include generation at any location (including distributed generation) plus other services except distribution service and except services required by the federal government to be provided on a monopoly basis. R14-2-1606. Services Required To Be Made Available by Affected Utilities. This section deals with utilities' obligations to provide unbundled services and standard offer services. Incumbent utilities must offer "Standard Offer" service in their service territories until the Commission determines that competition has been substantially implemented. Standard offer service consists of bundled service at regulated rates for consumers who do not or cannot participate in the competitive market. In addition, by December 31, 1997, Affected Utilities will have to file unbundled tariffs to provide to all eligible purchasers on a nondiscriminatory basis the following services: Distribution service, metering and meter reading, billing and collection, open access transmission service, and ancillary services. Such transmission and ancillary service tariffs must be consistent with applicable tariffs filed with the Federal Energy Regulatory Commission ("FERC"). This section also sets up guidelines and practices for the authorization and release of customer demand and energy data, sets up a process for the review of rates for unbundled services, and sets up a series of workshops to explore various issues involved in the provision of unbundled services and Standard Offer services. R14-2-1607. Recovery of Stranded Cost of Affected Utilities. This section discusses the process by which Affected Utilities may seek to recover their unmitigated Stranded Costs (defined in R14-2-1601). The section sets up a working group to develop recommendations for the analysis and recovery of such Stranded Costs, and sets forth several factors to be considered in allowing this recovery. Stranded Costs can only be recovered from customers in the competitive marketplace, and estimates of Stranded Costs must be updated periodically to allow the Commission to monitor the magnitude of such costs, and to grant refunds where such estimates may be overstated. R14-2-1608. System Benefits Charges. This section recognizes the availability of the recovery of costs of Commission-approved utility low income, demand side management, environmental, renewables, and nuclear power plant decommissioning programs. Affected Utilities are to propose the necessary charges on competitive consumers (to continue existing programs) for Commission review and approval. R14-2-1609. Solar Portfolio Standard. This section requires any Electric Service Provider selling electricity under the provisions of the Rules to derive at least 1/2 of 1% of the total retail energy sold competitively from new solar resources. As of January 1, 2001, this standard becomes 1%, unless the Commission decides otherwise. New solar resources are those installed on or after January 1, 1997. Electric Service Providers selling electricity derived from new solar resources prior to January 1, 1999 are allowed to claim credit toward the Solar Portfolio Standard for twice the electric energy generated by such solar resources prior to 1999. Periodic reports of such sales of solar energy are required; Electric Services Providers who fail to meet the standard in the Rules may be subject to penalties imposed by the Commission. R14-2-1610. Spot Markets and Independent System Operators. This section requires the Commission to conduct an inquiry into spot market development and independent system operation for the transmission system; the Commission is authorized to support the development of either, and may work with other entities to help establish them. R14-2-1611. In-State Reciprocity. This section recognizes that electric utilities which are not subject to the Commission's jurisdiction are not allowed to participate in the competitive electric market unless certain legislative changes are made, or these electric utilities either voluntarily submit to the Commission=s jurisdiction for purposes of such participation, or they enter into some form of agreement with the Commission to allow for their participation under mutually agreeable terms. R14-2-1612. Rates. This section sets forth the Commission's determination that rates determined by the competitive market are just and reasonable. Electric Service Providers selling services under these Rules are required to file with the Commission tariffs describing such services along with the maximum rates of those services, subject to Commission approval. Pricing for competitive services may be at or below the maximum rates specified in the tariff, provided the price is not less than the marginal cost of the service. Changes in maximum rates or in terms and conditions of previously approved tariffs may be filed, and are effective upon Commission approval. R14-2-1613. Service Quality, Consumer Protection, Safety, and Billing Requirements. This section explicitly recognizes that the Commission's existing rules for electric service apply in the competitive arena, except in specific instances. "Slamming" by suppliers of electric service is explicitly prohibited. Electric Service Providers supplying service under these Rules are responsible for meeting applicable reliability standards, are required to provide customer notice if it is unable to continue providing customers with any service, shall submit accident reports, shall make reasonable efforts to reestablish service in the shortest possible time in the event of service interruptions, and shall ensure that bills rendered on their behalf include toll free telephone numbers for customer inquiries. In addition, Electric Service Providers supplying metering or meter reading services shall provide access to meter readings to other Electric Service Providers serving the same customer. Meter tests may be requested by a consumer or an Electric Service Provider relying on meter information provided by another Electric Service Provider; such test shall be without charge if an error of more than 3% is found. A working group on System Reliability and Safety is set up to monitor and review such issues and make regular reports to the Commission on these issues. All Electric Service Providers are required to comply with applicable reliability standards and practices set forth by the Western Systems Coordinating Council and the North American Electric Reliability Council or successor organizations. R14-2-1614. Reporting Requirements. This section requires regular reporting of market information so the Commission is able to monitor developments in competitive markets. R14-2-1615. Administrative Requirements. This section indicates that Electric Service Providers may file to offer new services and that contracts are not public documents. It further states the Commission may grant variation s or exemptions from portions of the Rules. The Commission may also adopt procedures to resolve disputes. R14-2-1616. Legal Issues. This section sets up a working group to identify, analyze and provide recommendations to the Commission on legal issues relative to these Rules. The Commission shall consider the recommendations and decide the appropriate actions to take thereon. II. CHANGES IN THE TEXT OF THE PROPOSED AMENDMENT FROM THAT CONTAINED IN THE NOTICE OF RULEMAKING FILED WITH THE SECRETARY OF STATE. A.A.C. R14-2-1601 Definitions The last sentence has been deleted from R14-2-1601.1. The deleted language stated that "In the event that modifications are made to exisiting law that would allow the application of this Article to the Salt River Project Agricultural Improvement and Power District ("SRP"), then Affected Utilities shall also include SRP." A.A.C. R14-2-1603 Certificates of Convenience and Necessity The second sentence of R14-2-1603(B) has been amended to read: "Such Certificates shall be restricted to geographical areas served by the Affected Utilities as of the date this Article is adopted and to service areas added under the provisions of R14-2-1611." A.A.C. R14-2-1611 In-State Reciprocity R14-2-1611(C) has been deleted. The remaining subsections have been renumbered and relettered accordingly. R14-2-1611D (now C) has been amended to read: C. An Arizona electric utility, not subject to the jurisdiction of the Commission, may submit a statement to the Commission that it voluntarily opens its service territory for competing sellers in a manner similar to the provisions of this Article. Such statement shall be accompanied by the electric utility's nondiscriminatory Standard Offer tariff, electric supply tariffs, Unbundled Services rates, Stranded Cost charges, System Benefits charges, Distribution Services charges and any other applicable tariffs and policies for services the electric utility offers, for which these Rules otherwise require compliance by Affected Utilities or Electric Service Providers. Such filings shall serve as authorization for such electric utility to utilize the Commission's Rules of Practice and Procedure and other applicable Rules concerning any complaint that an Affected Utility or Electric Service Provider is violating any provision of this Article or is otherwise discriminating against the filing electric utility or failing to provide just and reasonable rates in tariffs filed under this Article. R14-2-1611D has been added to read: D. If an electric utility is an Arizona political subdivision or municipal corporation, then the existing service territory of such electric utility shall be deemed open to competition if the political subdivision or municipality has entered into an intergovernmental agreement with the Commission that establishes nondiscriminatory terms and conditions for Distribution Services and other Unbundled Services, provides a procedure for complaints arising therefrom, and provides for reciprocity with Affected Utilities. The Commission shall conduct a hearing to consider any such intergovernmental agreement. III. EVALUATION OF THE ARGUMENTS FOR AND AGAINST THE PROPOSED AMENDMENTS. A. General Legal Arguments Against The Rules. 1. The Commission Has the Legal Right to Promulgate These Rules. One primary overriding comment made by the parties is that the Commission has no legal right to adopt these Rules. This argument follows several lines of reasoning, the three primary ones being that the rules modify or abrogate the regulatory compact; the rules are in violation of the Arizona Administrative Procedures Act; and that the Commission does not have the authority to issue, modify or delete a Certificate of Convenience and Necessity without some legislative change. Issue: The Rules Are an Unlawful Modification or Abrogation of the Regulatory Compact. The basic argument made by the parties regarding the regulatory compact is that there is some sort of "contract" between the state and the incumbent monopoly electric utility, wherein the utility is obligated to supply electricity to all customers who require it at a reasonable cost, and in return, the state agrees to provide the utility with the exclusive right to serve all customers within a defined territory. The argument goes on to assert that since the Proposed Rules would change the exclusive nature of electric service, the rules unilaterally abrogate or at least modify this contract, and thus the Proposed Rules cannot be passed. Staff argues that no such contract has been formed. Generally, a party asserting the formation of a contract by statute must overcome a presumption against such formation, and courts will be cautious both in identifying a contract within the language of a regulatory statute, and in defining the outlines of any contractual obligation. Nat'l R.R. Passenger Corp. v. Atchison, Topeka, and Santa Fe Ry. Co., 470 U.S. 451, 466, 105 S.Ct. 1441, 1452 (1985). "[A]bsent some clear indication that the legislature intends to bind itself contractually, the presumption is that 'a law is not intended to create private contractual or vested rights but merely declares a policy to be pursued until the legislature shall ordain otherwise.'" Id. at 465-66, 105 S.Ct. at 1451 (quoting Dodge v. Bd. Educ. of City of Chicago, 302 U.S. 74, 79, 58 S.Ct. 98, 100 (1937)). In promulgating these Proposed Rules, the Commission is exercising the legislative discretion flowing from its plenary ratemaking authority. See Simms v. Round Valley Light & Power, 80 Ariz. 145, 294 P.2d 378 (1956). The question as to whether particular legislation creates a contractual right begins with an examination of the statute itself. Nat'l R.R. Corp., 470 U.S. at 465-66, 105 S.Ct. at 1451. However, a search of the Arizona Constitution reveals no such intent on the part of the State to bind itself. Indeed, the Constitution expressly disfavors monopolies: "[m]onopolies and trusts shall never be allowed in this State . . . ." Ariz. Const. Art. XIV, section 15. Staff further notes that, while the parties cite Application of Trico Electric Co-operative, Inc., 92 Ariz. 373, 377 P.2d 309 (1962) for the proposition that "the state in effect contracts" with a monopoly utility, that language in Trico is clearly dicta. Additionally, other cases refer to regulated monopoly as public policy rather than a contractual relationship. See Ariz. Corp. Comm'n v. Super. Ct., 105 Ariz. 56, 59, 459 P.2d 489 (1969) (regulated monopoly held to be public policy of Arizona); Winslow Gas Co. v. Southern Union Gas Co., 76 Ariz. 373, 385, 265 P.2d 442, 443 (1954)(referring to Arizona=s public policy of controlled monopoly); James P. Paul Water Co. v. Ariz. Corp. Comm'n, 137 Ariz 426, 429, 671 P.2d 404, 407 (1983)("It is well established that Arizona's public policy respecting public service corporations . . . is one of regulated monopoly over freewheeling competition."). In addition, Staff points out that it is well established that any alleged contract is subject to modifications in the law. The parties seem to find the source of the regulatory compact in both the Arizona Constitution and the statutes concerning public service corporations. The Constitution clearly provides for changes in the law concerning public service corporations; see Ariz. Const Art. XV, section 3. Further, any statutes concerning public service corporations may be changed at any time as well. If indeed the Constitution and the statutes have created a contract such as the parties claim, then this possibility for changes in the law must also be a part of that contract. Analysis: We are not convinced that the regulatory policy of the state has formed any sort of contract with the Affected Utilities. It appears that the former "policy" of regulated monopoly was just that- a policy, made with no intent to bind the state or the Commission. Finally, we recognize, as should the utilities, that such regulatory policies are always subject to change as the economics and technologies of the time also change. Resolution: There is no reason to delay the promulgation of these Rules. Issue: The Rules Violate the Administrative Procedures Act. The next argument made by the parties is that the Commission in adopting the Proposed Rules in this manner is violating the Arizona Administrative Procedures Act ("APA"), A.R.S. section 41-1001 et seq. There are two prongs to this argument, one being that the rules will clearly not be certified by the Attorney General's office, and the other being that because the Economic Impact Statement ("EIS") accompanying the Proposed Rules are somehow inadequate, interested persons are not given an adequate opportunity for notice and comment as required in the APA. Both prongs are without merit. Staff believes that the rules are not subject to Attorney General certification, as they are quite plainly a manifestation of the Commission's ratemaking authority. Clearly, the adoption of the Proposed Rules will have an impact on rates, something even all the commentators seem to recognize. Such an impact on rates has been recognized as grounds for the Commission's authority to exercise its plenary ratemaking authority through the adoption of rules. Ariz. Corp. Comm'n v. State ex rel. Woods, 171 Ariz. 286, 295, 830 P.2d 807, 816 (1992). Where rules, such as these, are an exercise of that ratemaking authority, the Attorney General does not have the authority to review and reject them. State ex rel. Corbin v. Ariz. Corp. Comm'n, 174 Ariz. 216, 219, 848 P.2d 301 (Ct.App. 1992). Further, Staff notes that the Commission is expressly exempted pursuant to A.R.S. section 41-1057 from the requirement of submitting an EIS as set forth in section 41-1055. Under section 41-1057, the Commission is merely required to adopt substantially similar review procedures for its rules. This is what Staff has done in this case in preparing the EIS forwarded to the Secretary of State as part of the rulemaking package. Staff thus believes its EIS thus meets the requirements of the APA. Analysis: We have previously litigated the issue of whether Commission rules involving ratemaking are subject to review and certification by the Attorney general=s office. The Courts have been clear in deciding that they are not. Further, we are satisfied that the EIS prepared by Staff meets the statutory requirements set forth in A.R.S. section 41-1057. Resolution: There is no reason to delay the promulgation of these Rules. Issue: The Adoption of These Rules Modifies Existing CC&Ns. Another argument raised by various parties in this proceeding is that the Commission has no authority to enact the Rules because the legislature has not afforded the Commission the authority to issue competitive CC&Ns as is contemplated by the Rules. According to this argument, the Commission has no authority to promulgate the Rules until the legislature grants to the Commission the authority to grant competitive CC&Ns. Staff urges that the adoption of these Rules does not grant to any potential competitor the right to provide electric service. Pursuant to the Rules, CC&Ns may be granted to applicants after going through an application process which includes public notice of the application and an opportunity for a hearing. See A.A.C. R14-2-1603. No CC&N is granted merely by the adoption of the Rules, and any CC&N granted under these Rules is expressly conditional upon numerous factors set forth in the rules. Therefore no additional legislative authority is required for the Commission to promulgate the Rules. Furthermore, Staff points out that courts have recognized that the Commission does have the authority to determine when competition is in the public interest and to issue competitive CC&Ns. Arizona v. People's Freight Line, 41 Ariz. 158, 166-67, 16 P.2d 420, 423 (1932); Winslow Gas Co. v. Southern Union Gas Co., 76 Ariz. 383, 385, 265 P.2d 442, 443 (1954). Thus, while Staff welcomes a role for the legislature in clarifying this authority, Staff believes such authority already exists. Analysis: The Rules as drafted set forth a framework for the introduction of competition into the electric services market in Arizona. As they are merely a framework, the Rules do not grant, modify, or delete any new or existing CC&N. The Rules do set up a process that must be followed before any such event occurs. All of the objecting parties are anticipated and expected to participate in such process. We are also persuaded by Staff's argument that we already have the authority to grant competitive CC&Ns, when the public interest demands it. However, that is an issue that we expect to address again before any competitive CC&Ns are issued. Resolution: There is no reason to delay the promulgation of these Rules. 2. The Adoption of the Proposed Rules Does Not Violate Due Process. Issue: Several parties in their comments have observed that the Proposed Rules as written violate due process because they are impermissibly vague. They argue that the Proposed Rules defer resolution of too many issues, such as stranded cost and the nature of CC&Ns under the rules, and do not give the affected parties fair warning as to how these and other aspects of the rules will be determined by the Commission. Staff acknowledges that a statute or rule is impermissibly vague in violation of due process if a) it fails to give a person of ordinary intelligence a reasonable opportunity to know what the law is in order to plan accordingly, or b) it allows arbitrary or discriminatory enforcement by failing to provide an objective standard. Bird v. State, 184 Ariz. 198, 908 P.2d 12 (Ct.App. 1995). However, Staff believes the Rules as written do not violate this standard. First, in regard to stranded cost recovery, the Rules set up a process for utilities claiming to have incurred stranded costs to seek recovery of those costs. The Rules set forth several factors for the Commission to consider in determining a utility's stranded cost, and allow the requesting utility to recover the appropriate amount. The Rules thus give the utility an opportunity to know what the law is so it can plan ahead, and sets forth an objective standard which the Commission must follow in doing so. As for CC&Ns, once again it is clear to a person of ordinary intelligence that under the Rules, all new CC&Ns will be competitive CC&Ns, and that under the rules there is a clear standard for granting such CC&Ns. Analysis: The Rules as written give the parties a great deal of guidance in terms of what is expected in the new competitive environment. Precise specificity is of course impossible; neither we nor anyone else has the prescience to know exactly what will happen in the future. However, the Rules do set adequate standards and processes for dealing with these future uncertainties. We thus do not agree that the Rules are impermissibly vague in violation of due process. Resolution: There is no reason to delay the promulgation of these Rules. 3. The Proposed Rules Do Not Violate Equal Protection. Issue: Some parties argue that the rules as proposed do not allow for equal treatment of all members of a recognized class, that class being all entities that provide electric services. The claim is made that the Proposed Rules treat incumbent monopoly public service corporations differently than they treat such potential competitors as the Salt River Project, municipal corporations, tribal authorities and non-utility generators. According to these comments, these other entities are not subject to any of the obligations of the Proposed Rules, but are still allowed to reap the benefits of the rules. Such unequal treatment, it is claimed, violates equal protection. Staff notes that there are serious differences between the incumbent monopoly providers and other potential entrants. Equal protection is satisfied if all persons in a class are treated alike. Baseball Liquors v. Circle K Corp., 129 Ariz. 215, 630 P.2d 38 (Ct.App. 1981), cert den. 454 U.S. 969, 102 S.Ct. 515. Legislation which applies to members of a class, but not to nonmembers of that class, will be upheld under equal protection if the classification is not arbitrary and there is a substantial difference between those within the class and those without. Farmer v. Killingsworth, 102 Ariz. 44, 424 P.2d 172 (1967). In this instance, there is one clear difference between the incumbent monopoly providers, and all others: the incumbents' monopoly status. To treat all parties identically under the rules would fail to recognize the incumbents' ability to use their current monopoly status to inhibit the competition these rules are designed to encourage. These Proposed Rules recognize that electric competition is not a race that begins with all entrants beginning at the starting gate; rather, the incumbents have a significant head start and a full head of steam. The Proposed Rules treat the incumbents differently because they ARE different. This does not violate equal protection. Analysis: As pointed out by Staff, there are clear reasons why Affected Utilities are treated differently than other entities under these Rules. Indeed, it would make no sense to make their treatment identical, because of their differing circumstances. The Rules identify those differences and treat the classes fairly based on those differences. Resolution: There is no reason to delay the promulgation of these Rules. 4. Passage of the Proposed Rules Does Not Constitute an Unconstitutional Taking. Issue: Another argument put forth by several parties is that the property rights of regulated utilities enjoy constitutional protection, and therefore the Rules constitute an unconstitutional taking of this property. The primary focus of these comments s that because under the Rules the Commission possibly may not allow recovery of a utility's entire stranded cost claim, this constitutes a regulatory taking of the utility's property without compensation. Another argument is that the rules confiscate the exclusive rights inherent in existing CC&Ns without compensation Staff believes such claims are premature at this time. The Rules as written do not take anything; they do not deny any utility recovery of any stranded cost, nor do they grant any new CC&N. What the rules do is set forth a framework wherein a regulated entity claiming to have stranded costs may come before the Commission and seek recovery of those costs. The rules also establish a process wherein potential new entrants may apply for and receive a CC&N. Mere adoption of the Rules will not result in any property being taken. Furthermore, Staff argues that in order for a taking to be unconstitutional, it must be done without compensation. The law is well-settled that takings claims are not ripe until the plaintiff has been denied compensation. Pub. Serv. Comm'n of New Mexico v. City of Albuquerque, 755 F.Supp. 1494, 1498 (D.N.M. 1991). If a state provides an adequate procedure for seeking just compensation, the property owner cannot claim a violation until it has used the procedure and been denied just compensation. Williamson Co. Regional Planning Comm'n v. Hamilton Bank, 473 U.S. 172, 195, 105 S.Ct. 3108, 3121 (1985). Any property that a utility believes has been taken once competition has been implemented under the Rules is essentially a stranded cost. The Rules allow for stranded cost recovery, and set forth a process wherein utilities can seek recovery of these costs. Analysis: Mere adoption of these Rules does not constitute a taking. Thus claims by parties that the Rules constitute an unlawful taking are clearly premature. Losses in value of utility assets as a result of competition would appear to be stranded costs; as the Rules set forth a process to allow for the recovery of stranded costs, it seems clear that the Rules do not constitute an unconstitutional taking of any utility property. Resolution: There is no reason to delay the promulgation of these Rules. B. A.A.C. R14-2-1601: Definitions Issue: Trico proposes that cooperatives be deleted from the definition of affected utilities (R14-2-1601(1)). Staff disagrees. The consumers located in the service areas of the cooperatives should be able to benefit from competition. Analysis: The Commission agrees that all customers should be able to benefit from competition, including those located in the service areas of cooperatives. Resolution: No amendment to R14-2-1601(1) is necessary. Issue: APS wants to delete the word "net" and to delete the term "value" and substitute "recorded costs of the assets and obligations" from the definition of stranded costs in R14-2-1601(8). Further, APS wants to substitute "used and useful" for "necessary," pertaining to furnishing electricity. APS is also concerned that stranded costs refers only to assets and obligations created prior to the adoption of the article. TEP is concerned that the proposed definition of stranded cost would result in reconsideration of the prudence of past investment decisions. TEP states that it is unclear what specific assets and obligations are included in stranded cost and whether the definition is limited to balance sheet accounts. TEP states that stranded cost is not limited to generation assets and may include regulatory assets and operating expenses. In response to Arizona Public Service Company's concerns, Staff believes that the word "net" is essential -- it reflects the fact that some assets will have market values greater than regulated values and that some assets will have market values less than regulated value. Further, Staff believes the rule should be general so as to permit stranded cost calculations reflecting the individual circumstances of a given utility. Staff expects that, in general, reconsideration such as concerns TEP would not be undertaken, but cannot rule out reconsideration of the prudence of past investments in every circumstance. Further, Staff believes that the definition is clear on these points: the calculation of stranded cost will not consider only generation assets, and can include purchased power contracts, regulatory assets, fuel contracts, etc. Evaluation: The Commission should not just allow a utility to recover stranded costs only for those assets whose value has decreased without offsetting that gross stranded cost with increases in the value of other assets. Substituting "recorded costs of the assets and obligations" for "value" is not necessary. APS' point can be dealt with in the stranded cost working group to obtain input from other parties; this may be an issue on which consensus can be reached. Resolution: No amendment to R14-2-1601(8) is necessary. C. R14-2-1604: Competitive Phases Issue: Several cooperatives (Arizona Electric Power Cooperative, Duncan Valley Electric Cooperative, Inc., Graham County Electric Cooperative, Inc., and Sulphur Springs Valley Electric Cooperative), would substitute for R14-2-1604(H), which allows for modifications of the implementation schedule for cooperatives, a requirement that the cooperatives file a report describing the status of the efforts to address and resolve tax exemption and contractual and federal financing issues. Phelps Dodge Morenci, Inc. (Phelps Dodge) disagrees with the contention that cooperatives should be exempted from competition. To do so, Phelps Dodge says, would mean that rural customers will be prevented from receiving the lowest possible price of electricity. Staff disagrees with the cooperatives, and agrees with Phelps Dodge, because this proposal will exclude consumers served by cooperatives from the benefits of competition and dilute incentives for the cooperatives to introduce competition. The cooperatives propose that a new definition be added for available transmission capability ("the meaning accorded it by Federal Energy Regulatory Commission Order 888 ...). The phrase "subject to Available Transmission Capability" would then be added to the beginning of R14-2-1604(A), (B), and (D). FERC Order 888 requires transmission providers to describe their method for determining available transmission capability posted on the transmission provider's OASIS (Open Access Same time Information Systems). If sufficient transmission capability may not exist to accommodate a service request, the transmission provider will respond by performing a system impact study (Section 15.2 of the pro-forma tariff). System impact studies are described in Section 32 of the pro-forma tariff. If transmission upgrades are needed to supply a service request, the customer must reimburse the transmission provider for the facilities study and, if the customer wants the facilities, he or she will have to pay for them. Staff believes that the cooperative's proposal incorrectly gives the impression that the transmission provider is not obligated to conduct system impact studies or facilities studies as required by the FERC. Therefore, Staff recommends that the wording of the proposed rule not be changed as suggested by the cooperatives. The cooperatives also propose to add language to R14-2-1604 that states that "Any consumer which elects to participate in the competitive market shall pay all costs attributable to such election including but not limited to special metering costs and any costs required to relieve transmission or distribution constraints." Staff argues that these costs should be covered by rates charged for unbundled services; no change in the rule is needed. Analysis: As with Trico's objection to R14-2-1601(1), the Commission agrees that all customers should be able to benefit from competition, including those located in the service areas of cooperatives. Further, it appears to the Commission that the cooperatives' proposed language regarding transmission service gives the misleading impression that transmission providers have no obligation regarding the stated studies. Finally, the proposed language regarding competitive customers paying special metering costs and other costs is not necessary. Resolution: No amendment to R14-2-1604 is necessary. Issue: Timing of the introduction to competition. TEP proposes that unbundling of distribution services be postponed until 2002 to allow operational issues with generation competition to be sorted out first and to allow time to prepare for "complete competitive product and service unbundling." Nordic Power of Southpoint I, Limited Partnership (Nordic Power) "supports market-based rates with customer choice in the most expeditious manner reasonably feasible." Nordic Power proposes that the phase-in begin no later than January 1, 1998. Enron Capital & Trade Resources (ECT) agrees that competition should begin in 1998, rather than in 1999. Staff believes that two years offers a practical, but aggressive schedule, in which to address all of the unanswered questions that need to be resolved. Two years will allow for evidentiary hearings, working group deliberations, and time to review successful programs as well as problems in other state restructuring efforts. Analysis: The time line in the Rule as written for the introduction of competition in these services is both reasonable and feasible. It allows time for the Commission, Staff and other parties to come up to speed on competition quickly, yet is not so hasty as to ignore lessons that can be learned through the procedures in the rules and the experiences of other states. Resolution: No amendment to R14-2-1604 is necessary. D. R14-2-1606: Services Required To Be Made Available by Affected Utilities Issue: Obligation to provide service. APS wants clarification that an Affected Utility has an obligation to provide service and plan for generation resources during the phase-in period for those customers not eligible for access. Staff notes that R14-2-1606(A) indicates that Affected Utilities have an obligation to provide standard offer service until the Commission determines otherwise. Analysis: R14-2-1606(A) is clear on this subject: an Affected Utility has an obligation to provide Standard Offer service until otherwise ordered by this Commission. Resolution: No amendment to R14-2-1606 is necessary. E. R14-2-1607: Recovery of Stranded Cost of Affected Utilities Issue: R14-2-1607(A) requires Affected Utilities to take every feasible, cost-effective measure to mitigate Stranded Costs. APS wants to replace in R14-2-1607(A),"every feasible, cost effective [mitigation] measure" with "reasonable [mitigation] measures..." Staff believes this proposed change may be more workable than the initial wording and would not object to such a change if it were clear that the Commission is serious about having utilities actively work to offset stranded costs through mitigation measures. APS further proposes deletion of the examples of types of mitigation. Staff believes that the examples provide additional clarity to the intent. TEP states that it is unclear whether mitigation of stranded costs includes only energy related activities or is all-encompassing, covering any business activity the utility and its affiliates may pursue. TEP believes that profits from activities that are unrelated to the provision of electricity in Arizona and that do not require use of assets acquired to serve electric customers in Arizona, and that are potentially strandable, should not be considered as a source of funds to offset stranded cost. Further, TEP fears that costs of mitigation activities could become stranded. Staff interprets the rule as including all activities, including non-energy-related activities, as part of mitigation. An Affected Utility's losses due to stranded cost are to be offset by that company's gains in other activities. Further, there cannot be any recoverable stranded costs associated with mitigation since those costs would not be necessary to furnish electricity to consumers in the utility's service territory and be incurred prior to the adoption of the Article. RUCO wants greater emphasis on mitigation of stranded costs. Analysis: This Commission is serious about having utilities actively pursue mitigation measure to offset stranded costs. Because of that, we believe it is important to retain the current language requiring Affected Utilities to take "every feasible, cost-effective measure to mitigate or offset Stranded Cost." We further agree with Staff that the inclusion of examples of mitigation or offset are helpful to parties in understanding what we are expecting. We interpret the rule in a manner similar to Staff, in that it envisions Affected Utilities utilizing a wide variety of methods to mitigate or offset Stranded Cost, including methods unrelated to energy activities. We also agree with Staff that there are no recoverable Stranded Costs associated with mitigation, since those costs cannot be both necessary to furnish electricity to consumers in its service territory, and be incurred prior to the adoption of these Rules. So far as RUCO's comments are concerned, we believe the Rule as written adequately emphasizes the importance of mitigation. Further, RUCO never indicates how this additional emphasis is to be provided. Resolution: No amendment to R14-2-1607(A) is necessary. Issue: Guarantee of recovery of Stranded Costs. RUCO wants the rule to indicate that there is no guarantee of recovery of stranded costs and that the Commission should make a determination regarding the amount of stranded costs that should be recoverable by each utility. The rule allows recovery of unmitigated stranded cost (R14-2-1607(B)) and for the determination of the magnitude of stranded cost (R14-2-1607(I)). Destec is concerned that the Commission has determined the efficacy of stranded cost recovery before considering the issue. Staff expects that the Commission will ultimately consider a wide range of estimates of the magnitude of stranded cost offered by Affected Utilities, Staff, RUCO, consumer groups, and other intervenors. The Commission must also consider several factors regarding mechanisms and charges for recovery of stranded costs (R14-2-1607(I)). Staff believes that no change in the rule is needed on this matter. Analysis: The Rule does guarantee recovery of unmitigated Stranded Cost, but also provides a process for determining the magnitude of Stranded Cost, and recovery mechanisms and charges. Input from various parties as to that magnitude is provided and encouraged. Resolution: No amendment to the Rule is necessary. Issue: R14-2-1607(I) lists various factors to be considered by the Commission in determining the mechanisms for the recovery of Stranded Cost. APS wants the rule to indicate that the factors listed in R14-2-1607(I) pertain only to recovery mechanisms and not to the recoverability of stranded costs. APS wants to remove R14-2-1607(I)(8) pertaining to the period over which stranded cost charges may be recovered. Further, APS desires prompt review of Stranded Cost recovery proposals. TEP states that a specific time period over which stranded costs are computed should not be ordered. The proposed rule does not specify a standard time period, but leaves this to be determined on a case by base basis. AEPCO and other cooperatives propose deleting some of the factors in R14-2-1607(I) because they believe that stranded cost recovery is required by law. Trico also indicates that some of these should not be considered because, in Trico's view, all stranded costs are recoverable. Staff believes that changes proposed by APS to R14-2-1607(I) are unnecessary. As written, R14-2-1607(I) states that the list of factors is to be considered by the Commission in determining mechanisms and charges for recovery of stranded cost, but not the magnitude of stranded cost. The Commission cannot consider stranded cost recovery mechanisms and charges in a vacuum as proposed by APS. Staff further believes that the Commission will give prompt attention to requests for stranded cost recovery. However, not knowing the nature of the utilities' filings or the nature of other parties' analyses, no specific time limit should be imposed now. The inclusion of R14-2- 1607(I)(8) is necessary to indicate that a stranded cost recovery charge is for a fixed time period to be determined by the Commission after having reviewed data provided by utilities and other parties. Stranded cost recovery for an indefinite time period is precluded. Staff disagrees with the cooperatives and Trico; the effects of stranded cost recovery on competition and on consumers are important factors in stranded cost recovery mechanisms and should not be ignored by the Commission. Staff believes that the Commission must consider all the factors listed so as to take into account impacts of stranded cost recovery mechanisms on consumers and on the market in general. Analysis: We believe that the Rule is clear in that R14-2-1607(I) identifies factors to be considered in setting the mechanisms and charges for Stranded Cost recovery, not for the issue of the magnitude of Stranded Cost. Further, as regards R14-2-1607(I)(8), utilities will be free to propose specific methods for stranded cost recovery that are compatible with their circumstances. Further, the factors identified in the Rule are necessary in order for the Commission to determine the appropriate mechanisms for Stranded Cost recovery. Resolution: No amendment to R14-2-1607(I) is necessary. Issue: R14-2-1607(J) allows Stranded Cost recovery only from those customers participating in the competitive market. RUCO indicates that stranded costs should be recovered from all customers. TEP argues that consumers who self generate should pay for stranded costs. Staff notes that costs are only stranded when competitive market prices are below traditionally regulated rates. Consumers served in non-competitive markets will pay for all prudently incurred costs in their regulated rates and so, in that case, there is no stranded cost. Thus, RUCO's proposed objectives are already incorporated in the rule. As for TEP's recommendation, self generation has been available to consumers for years and no stranded cost recovery has been imposed on such customers. Analysis: The Commission agrees that consumers who will not be participating in the competitive market will be paying for Stranded Costs through the regulated Standard Offer rates. We also agree that there is no compelling reason to impose Stranded Cost responsibility on self generators under these Rules, when none has been imposed in the past. Resolution: No amendment to R14-2-1607(J) is necessary. F. R14-2-1609: Solar Portfolio Standard Issue: The Solar Portfolio Standard may not result in increased solar capacity in Arizona. APS suggests that the solar portfolio standard might not result in any increased solar capacity in Arizona. Staff agrees that there is a possibility that no new solar capacity will be built in Arizona, but notes that the purpose of the standard is to promote solar power regardless of the location of generation facilities. Staff believes that economics favor Arizona locations for new solar facilities serving Arizona consumers. Because out-of-state solar resources would need to acquire transmission rights to transmit solar electricity into Arizona for use by the competitive customers in the phased-in competition program, out-of-state resources would probably be more expensive. In addition, since Arizona has the most plentiful supply of sunshine resources in the nation, it is unlikely that an Electricity Service Provider would want to build a solar plant elsewhere. The double credit provision for early solar electricity generation is designed to encourage the installation of the solar facilities in Arizona. Analysis: While the Rule does not specifically require the building of solar resource in Arizona, we believe that the prevailing environmental and economic conditions will result in much of the solar requirement being met by Arizona resources. Resolution: No amendment to R14-2-1609 is necessary. Issue: The Rules may not require that solar resources be used to serve Arizona customers. APS suggests that the proposed rules do not require that the solar resources "even be used to serve Arizona consumers." Staff notes that R14-2-1609(A) defines the solar portfolio standard as a percentage "of the total retail energy sold competitively..." The obvious reference is for electricity sold competitively in Arizona to Arizona consumers as part of the phased-in competition program. However, if there is a need for clarification, Staff would not object to the addition of the phrase "to Arizona consumers" after the phrase "sold competitively." Analysis: These rules pertain to the provision of electric services in the State of Arizona. While Staff's proposed language may be useful, it is not necessary, in that all electricity sold competitively under these Rules is sold in Arizona. Resolution: No amendment to R14-2-1609(A) is necessary. Issue: APS' alternative solar proposal. APS made an alternative proposal in its September 12, 1996 comments that it claims would be far less costly, guarantee between 25 and 50 MW of new solar generation, and not serve as a market barrier. The proposal would have the Commission levy a fixed fee on all kWh delivered to customers in Arizona starting in June 1997. The money would be placed in an interest bearing account and, starting in 1998, the money would be used to "buy down" the uneconomic portion of the cost of newly installed solar systems in Arizona. The money would be disbursed on a competitive-bid basis. Staff does not believe that APS' proposal will accomplish what APS claims it will. The proposal appears to contemplate the need for the establishment of a new bureaucracy to collect fees, determine winning bidders, oversee solar plant construction and start-up. At a time where competition should be encouraging the reduction of bureaucracies in the regulation of electric service and the provision of those services, this proposal would seem to offer just the opposite. Analysis: The APS proposal, contrary to APS' assertions, would not guarantee that any solar facilities are built. It would offer an opportunity, certain incentives, and a favorable environment for solar projects, but certainly no guarantees. The Staff proposal, in contrast, offers a good chance that solar projects will be built because of the potentially high penalties for not meeting the standard. Further, we are not convinced that APS' proposal will be less costly. The costs of buying and installing solar should be about the same. In fact, there is a distinct possibility, under the solar portfolio standard, that utilities or other large electricity suppliers, by buying solar equipment in large volume purchases, will be able to obtain significant price reductions from solar manufacturers anxious for increased market share. Resolution: No amendment to R14-2-1609 is necessary. Issue: The Solar Portfolio Standard is too expensive compared to wind power. RUCO is concerned about the cost of the solar portfolio standard. RUCO states that wind power would be cheaper than solar power. Staff notes that the purpose of the solar portfolio standard, however, is to promote a specific type of renewable resource and not renewables in general, some of which are already cost effective in a wide range of applications. Further, Arizona has mostly Class 3 wind regions, which are not currently cost effective resources, and Arizona wind resources are best in the winter when their value is less than it would be during peak summer demand. Analysis: The Solar Portfolio Standard as written serves properly serves its intended purpose of encouraging the development of solar resources. Solar resources more accurately match the electric demand needs of Arizona consumers than do wind resources, improving their cost effectiveness. Resolution: No amendment to R14-2-1609 is necessary. Issue: R14-2-1609 should be deleted to make the Rules fuel and resource neutral. The Center for Energy and Economic Development (CEED) believes that restructuring should be fuel and resource neutral. Staff disagrees that restructuring should be resource and fuel neutral. The Commission, over the last few years has encouraged the utilities it regulates to diversify their energy portfolios to include renewable energy resources Analysis: Diversification of resource portfolios benefits Arizona. We believe it particularly appropriate to encourage solar because of its natural advantages in the state. Resolution: No amendment to R14-2-1609 is necessary. Issue: The Solar Portfolio Standard is too modest. The Environmental Group is concerned that the solar portfolio standard's percentage rate is too low. The group quotes two National Renewable Energy Laboratory ("NREL") reports that claim that solar thermal technologies produce electricity today at 10.5 cents/kWh and that the current cost of photovoltaic generated electricity is 21.8 cents/kWh. This is in contrast to Staff's estimates of 30 cents/kWh. The group therefore suggests that section R14-2-1609(B)(2) be modified to show that only an increase in the solar portfolio be allowed when the standard is re-evaluated in 2001. Staff disagrees with the proposal to change the solar portfolio standard. There is insufficient information at this time to set future policy, and R14-2-1609(B) should not be altered in the absence of this information. Staff agrees that NREL's estimated solar electricity cost numbers are probably appropriate for large solar installations. However, since the early solar portfolio projects will be modest in size, Staff feels that it is important to be conservative in estimates. This has resulted in the modest and conservative 1/2 of 1 percent initial solar portfolio standard. Staff agrees with the Environmental Group and NREL that solar costs in the 1999-2003 time frame will be significantly lower than current costs. If this cost reduction occurs as projected, there will be a natural tendency to increase the solar standard in 2001. If not, it may be appropriate to freeze the standard at 1/2 of 1 percent for a few years. Analysis: While the Environmental Group may be right in regard to the information it has provided from NREL, we believe it is too premature to increase the standard beyond the levels set forth in the Rule. Resolution: No amendment to R14-2-1609(B) is necessary. Issue: Several commentators at the Public Comment session encouraged the Commission to expand the Solar Portfolio Standard to include solar water heaters and other solar demand reduction technologies. It was argued that many of these technologies are cost effective and reliable methods to reduce the demand for electricity from the grid. Analysis: While the suggestions of these commentators has some merit, we do not believe it appropriate to modify the Solar Portfolio Standard at this time. As noted earlier, the purpose of the Solar Portfolio Standard is to promote a specific type of renewable resource. Resolution: No amendment to R14-2-1609 is necessary. G. R14-2-1611: In-State Reciprocity Issue: R14-2-1611 precludes Salt River Project and other quasi-governmental entities and municipalities from participating in the competitive marketplace. SRP states that the Rules do not give all Arizona customers the right to choose their Electric Service Provider. SRP further states that the Rules= proposed regulation of political subdivisions and municipal corporations is unconstitutional. SRP expressed concern about having to obtain consent from the Affected Utilities. A concern is that some utilities will bar SRP's entrance by refusing to agree to allow SRP to participate. Consequently, SRP proposed the use of intergovernmental agreements to allow it to participate in competition under this Article. The Irrigation and Electrical Districts' Association of Arizona (IEDA) suggests current wording in the Rules may embroil jurisdictional fights and proposed rewording R14-2-1611 subsection D. The rewording would allow non-jurisdictional utilities to voluntarily file unbundled and standard offer service tariffs and to voluntarily open its service territory to competing sellers. These filings would serve as authorization for such service providers to utilize the Commission's rules concerning complaints related to their participation in the competitive market. Staff believes that the rules as proposed do not make provisions for competition in the service territories of utilities not regulated by the Commission. The rules do provide a framework for implementing competition in the service territories of utilities regulated by the Commission and several means by which nonjurisdictional utilities may participate. Staff further notes that the Rules do not propose regulation of nonjurisdictional utilities in their service territories. They apply to affected utilities and energy service providers authorized to do business in currently regulated service areas. The rules also explicitly state that SRP would not be considered an Affected Utility unless existing law changes (R14-2-1601(1)). Nordic Power is concerned that the intergovernmental agreement recommended by SRP may allow major utilities to carve out service territories if customers and competitive power service providers are left out of the process. Staff believes SRP's proposed use of intergovernmental agreements has merit and may be a means of establishing adequate enforcement of nondiscriminatory rates. The concerns of other utilities over level playing field issues must be considered in any resolution of SRP's status. Further, there must be an objective party who can resolve disputes over whether electric service providers have fair, nondiscriminatory access to SRP's distribution system. If the Commission does not have this authority, some other party must take on this responsibility; other electric service providers may also want to be involved in the creation of this independent party. Staff agrees with Nordic Power that other parties should have the opportunity to provide input into intergovernmental agreements and expects that if such an agreement is being entertained, the Commission will seek that input. Analysis: SRP's status as the second largest electric provider in the state, coupled with its status as a political subdivision of Arizona, has vexed the Commission in the formation of Rules designed to allow competition to benefit all electric consumers in the state. SRP's and IEDA's proposals have merit. Resolution: R14-2-1611 should be amended as follows: Initially, based on SRP's arguments and the analysis set forth above, it is clear that R14-2-1611(C) is simply unnecessary. Therefore, R14-2-1611(C) as previously proposed is deleted. The remaining subsections have been relettered to conform. Therefore. R14-2-1611D has been relettered as (C) and amended to read: C. An Arizona electric utility, not subject to the jurisdiction of the Commission, may submit a statement to the Commission that it voluntarily opens its service territory for competing sellers in a manner similar to the provisions of this Article. Such statement shall be accompanied by the electric utility's nondiscriminatory Standard Offer tariff, electric supply tariffs, Unbundled Services rates, Stranded Cost charges, System Benefits charges, Distribution Services charges and any other applicable tariffs and policies for services the electric utility offers, for which these Rules otherwise require compliance by Affected Utilities or Electric Service Providers. Such filings shall serve as authorization for such electric utility to utilize the Commission's Rules of Practice and Procedure and other applicable Rules concerning any complaint that an Affected Utility or Electric Service Provider is violating any provision of this Article or is otherwise discriminating against the filing electric utility or failing to provide just and reasonable rates in tariffs filed under this Article. R14-2-1611D has been added to read: E. If an electric utility is an Arizona political subdivision or municipal corporation, then the existing service territory of such electric utility shall be deemed open to competition if the political subdivision or municipality has entered into an intergovernmental agreement with the Commission that establishes nondiscriminatory terms and conditions for Distribution Services and other Unbundled Services, provides a procedure for complaints arising therefrom, and provides for reciprocity with Affected Utilities. The Commission shall conduct a hearing to consider any such intergovernmental agreement. In addition, several other conforming changes are necessary. First, because the adopted changes to the rules make it redundant, the last sentence of R14-2-1601.1 should be deleted. The deleted sentence stated that "In the event that modifications are made to existing law that would allow the application of this Article to the Salt River Project Agricultural Improvement and Power District ("SRP"), then Affected Utilities shall also include SRP." Also, the second sentence of R14-2-1603(B) should be amended to read: "Such Certificates shall be restricted to geographical areas served by the Affected Utilities as of the date this Article is adopted and to service areas added under the provisions of R14-2-1611." APPENDIX C ---------- ECONOMIC IMPACT STATEMENT PROPOSED RULE --RETAIL ELECTRIC COMPETITION R14-2-1601 et seq. A. Summary of economic, small business and consumer impacts. 1. Identification of the proposed rulemaking. The proposed rule (Article 16) provides procedures and schedules for introducing competition into the provision of electric service. 2. Brief summary of the economic, small business and consumer impact statement. Increased competition in the electric industry is expected to produce several benefits: (1) Consumer choice among energy suppliers. (2) Greater customization of energy services, especially for larger consumers, regarding time of use rates, interruptible service, contract duration, pricing arrangements, risk management, and so on. (3) Greater innovation in technology and greater applications of technological innovations, especially in distributed generation, as a result of incentives in the competitive marketplace. (4) Greater application of energy efficiency measures as energy service companies offer packages of electric energy, demand side management measures, and possibly other services such as building maintenance services. (5) Lower prices for electricity due to competitive pressures and to technological, marketing, and organizational innovations that would not occur as rapidly, if at all, in a regulated monopoly environment. The costs of participating in a competitive market generally involve risk management and information. Examples of possible costs include: the costs of searching out and evaluating alternatives; additional record keeping and billing costs associated with deliveries of electricity from suppliers; additional costs of executing, monitoring, and enforcing contracts; and additional costs of maintaining power quality and transmission and generation system reliability. A competitive market in electricity will benefit small businesses because it increases their choices and tends to lower prices of electric service. However, small businesses must be informed about their choices. The rule indicates that the Commission may undertake educational activities to lower the costs of participating in the competitive market. Probable costs to the Commission include costs associated with new tasks, such as reviewing applications for competitive Certificates of Convenience and Necessity, and engaging in evidentiary hearings for stranded investment and unbundled tariff filings. However, Commission review of tariff filings should be reduced eventually and costly rate cases will be avoided for competitive services. Employment opportunities could be enhanced as new energy related companies move into the area or as a result of new business start-ups. However, employees at public utilities could lose their positions through cost cutting measures as the utilities strive to become more cost competitive. Implementation of the proposed rule should result in no increased costs to political subdivisions. As an end user of competitive electricity services, a political subdivision may benefit from greater choices of service options and affordable rates. Those political subdivisions which have their own municipal electric utilities may feel pressure to allow competitive electric service. The restructuring policy proposed is preferred to alternatives considered because it: minimizes administrative complexity; requires minimal information and planning needs a priori; is relatively flexible so that policy could be adjusted in mid-course; uses existing institutions; minimizes utility organizational disruption; allows buyers and sellers to enter the market freely; limits market power of incumbent utilities; and minimizes public confusion. 3. The name and address of agency employees to contact regarding this statement. Gary Yaquinto or Bradford Borman at the Arizona Corporation Commission, 1200 West Washington Street, Phoenix, Arizona 85007. B. Economic, small business and consumer impact statement. 1. Identification of the proposed rulemaking. The proposed rule (Article 16) provides procedures and schedules for introducing competition into the provision of electric service. 2. Persons who will be directly affected by, bear the costs of, or directly benefit from the proposed rulemaking. a. The public at large who are consumers of electricity throughout the State of Arizona. b. Furnishers of electricity (serving Arizona and elsewhere), including Investor Owned Utilities, consumer owned utilities/power authorities, self generators, and Independent Power Producers. c. Power aggregators/marketers. d. Industry organizations (e.g., Regional Transmission Groups). e. Transmission utilities. f. Employees of furnishers of electricity. g. Suppliers to furnishers of electricity. h. Investors in Investor Owned Utilities and Independent Power Producers and holders of bonds of consumer owned utilities and cooperatives. i. Financial Organizations. j. Government agencies such as the Arizona Corporation Commission, siting authorities, Federal agencies (including the Federal Energy Regulatory Commission), and consumer advocates such as the Residential Utility Consumers Organization. 3. Cost-benefit analysis. a. Probable costs and benefits to the implementing agency and other agencies directly affected by the implementation and enforcement of the proposed rulemaking. Probable costs to the Commission include costs associated with new tasks, such as reviewing applications for competitive Certificates of Convenience and Necessity, and engaging in evidentiary hearings for stranded costs, standard offer service, and unbundled tariff filings. The proposed rule allows competitive power and energy suppliers to change rates by applying for streamlined rate treatment. Filing requirements for rate increases may be reduced. Thus, Commission review of tariff filings should be reduced eventually and costly rate cases will be avoided for competitive services. b. Probable costs and benefits to a political subdivision of this state directly affected by the implementation and enforcement of the proposed rulemaking. Implementation of the proposed rules should result in no increased costs to political subdivisions relative to cost changes that may otherwise occur. As an end user of competitive electricity services, a political subdivision may benefit from greater choices of service options and affordable rates. Those political subdivisions which have their own municipal electric utilities may feel pressure to allow competitive electric service. c. Probable costs and benefits to businesses directly affected by the proposed rulemaking, including any anticipated effect on the revenues or payroll expenditure of employers who are subject to the proposed rulemaking. Greater efficiency under competition should arise from lower cost electricity generation, efficient operation and maintenance, development of low cost new resources, and greater stimuli to innovation in electric generation technology. These benefits are achievable while limiting adverse financial impacts of competition on incumbent utilities; maintaining transmission and generation system reliability; countering the market power of vertically integrated utilities; and promoting solar resources. Possible costs include: additional record keeping and billing costs associated with deliveries of electricity; transmission access costs; costs of interconnection arrangements such as disconnection switches to ensure that interruptible consumers are properly interrupted; additional costs of maintaining power quality and transmission and generation system reliability; additional costs of scheduling power deliveries to meet contract requirements; additional costs of executing, monitoring, and enforcing contracts; and costs of complying with legal requirements. 4. Probable impacts on private and public employment in business, agencies and political subdivisions of this state directly affected by the proposed rulemaking. Employment opportunities could be enhanced as new energy related companies move into the area or as a result of new business start-ups. However, employees at public utilities could lose their positions through cost cutting measures as the utilities strive to become more cost competitive. 5. Probable impact of the proposed rulemaking on small business. a. Identification of the small businesses subject to the proposed rulemaking. Businesses subject to the proposed rulemaking are furnishers of electricity (serving Arizona and elsewhere), including Investor Owned Utilities, consumer owned utilities/power authorities, self generators, Independent Power Producers, and power aggregators/marketers. Some of these businesses are small, but some are also large regional, national, or international firms. b. Administrative and other costs required for compliance with the proposed rulemaking. Administrative costs to providers of competitive retail electric service would include costs associated with filing requests with the Commission for approval of Competitive Certificates of Convenience and Necessity; filing unbundled tariffs for approval; filing semi-annual reports to inform the Commission about the progress of competition during the phase-in period and annual reports when competition is fully established; and requests for stranded cost recovery. Sellers may be required to provide notification and informational materials to consumers about competition and their choices. c. A description of the methods that the agency may use to reduce the impact on small businesses. A competitive market in electricity will benefit small businesses because it increases their choices and tends to lower prices of electric service. However, small businesses must be informed about their choices. The rule indicates that the Commission may undertake educational activities to lower the costs of participating in the competitive market. A possible alternative to reduce the impact on small businesses is to reduce the frequency of filings during the phase-in period. As a consequence, however, the Commission may not become aware of implementation problems quickly enough to offer timely solutions. Another alternative would be to allow competitive service providers to engage in market competition by simply registering the company with the Commission rather than requiring the company to apply for a Certificate of Convenience and Necessity. However, the outcome of this alternative may be undesirable if an electric service provider does not have the technical or financial capability of providing reliable energy services, and if the industry becomes more prone to companies that engage in fraudulent activities. A third alternative is to dispense with tariff filings. However, the Commission could not fulfill its Constitutional responsibilities and consumers would have less information about businesses who supply electric service. d. The probable cost and benefit to private persons and consumers who are directly affected by the proposed rulemaking. Costs of participating in the market generally involve information and risk management. Possible costs include: the costs of searching out and evaluating alternatives; the cost of interruptions, whether the power was intended to be interruptible or firm; costs of backup and maintenance service provided by a utility or another party to deal with forced or scheduled outages at the supplier's generation plant or transmission lines; and additional costs of executing, monitoring, and enforcing contracts. Also, consumers of competitive energy services may be assessed a stranded investment charge for sunk costs incurred by the utility from which they previously received service. The proposed rule will benefit Arizona consumers by creating consumer choice among energy suppliers; customizing energy services to consumer needs; stimulating innovation in technology; encouraging energy efficiency; and lowering prices relative to regulated rates. Important public programs, such as low income programs, will be protected and consumers who do not participate in competition will be shielded from adverse effects during the early phases via Commission-approved standard offer service from incumbent utilities. 6. A statement of the probable effect on state revenues. The proposed rule could reduce state revenues received from public utilities as rates and, therefore, utility revenues are reduced. However, to the degree that consumers respond to lower prices by increasing their demand for electricity, the reduction in utility revenues would be offset by additional revenues from increased electricity demand. 7. A description of any less intrusive or less costly alternative methods of achieving the purpose of the proposed rulemaking. A Working Group on Retail Electric Competition met in 1995 to discuss restructuring options, including retail wheeling and maintaining the status quo. The Working Group was comprised of individuals from utilities, alternative power providers, consumer groups, and other interested parties. Several restructuring options were considered: (1) maintaining the status quo, (2) introducing retail competition and requiring divestiture of utility assets, (3) introducing retail competition and requiring an exclusive poolco, and (4) introducing retail competition and allowing bilateral contracts for power supplies (similar to the proposed rule). The first alternative is to maintain the status quo, utilizing traditional cost-plus rate-making, incentive rate-making (e.g., bench-marking prices, quality and reliability standards), and flexible pricing. No new institutions would be required and disruptions in utility operations would be minimized. However, the effectiveness of incentives (if any) and flexible pricing are unknown. Also, the circumstances which once warranted classifying utilities as "natural monopolies" are no longer applicable. The economies of scale of large central station generation plants are not nearly as large as they once were. Further, regulated monopolies cannot produce prices that are as low as would occur in a competitive market and regulated monopolies cannot stimulate technological, marketing, and organizational innovations as would occur in a competitive market. A second alternative is to establish retail competition with an "exclusive poolco," which is an independent system operator that controls all power transactions. All generators would sell to the neutral system operator and all purchasers would buy from the system operator. With an exclusive poolco, all consumers or their agents would know the market price at each hour. In addition, power would be dispatched in a least cost order, subject to restrictions on transmission. A major disadvantage of an exclusive poolco is that it forces all transactions to be spot market transactions, thereby increasing the risk to investors of investing in new power plant capacity without long term contracts to purchase the output from new plants. Further, with only spot market transactions, it becomes more difficult to customize contracts to suit the circumstances of a wide variety of buyers and sellers. Another disadvantage of retail competition with an exclusive poolco is the unknown cost to implement the poolco. Also bidders in the poolco may game their bids, especially if some have an advantage because of their location or large size relative to the market. A third option is to introduce retail competition and require utilities to divest their generation and possibly transmission facilities. The market would become segmented by function and generation companies would be expected to operate in a competitive environment. A principal reason for divestiture is that any incentive for utilities to impede access to their transmission systems to inhibit competition in generation could be eliminated. In addition, incentives for efficiency gains could be created by unbundling services into profit centers. However, the Commission's regulatory authority to require divesture of utility assets may be questioned and result in a protracted legal dispute. Further, utilities, utility shareholders, and utility debt holders may strongly resist divesture. Divestiture could be costly due to expensive debt re-financing. In addition, inefficiencies could result from the loss of traditional coordination of generation, transmission, and distribution services. The restructuring policy proposed is preferred to the alternatives described above because it: minimizes administrative complexity; requires minimal information and planning needs a priori; is relatively flexible so that policy could be adjusted in mid-course; uses existing institutions; minimizes utility organizational disruption; allows buyers and sellers to enter the market freely; limits market power of incumbent utilities; and minimizes public confusion. The proposed rule was synthesized from comments received from interested parties on electric industry restructuring and it represents a middle ground of proposals submitted by utilities, potential energy service competitors, consumer groups, and others. C. If for any reason adequate data are not reasonably available to comply with the requirements of subsection B of this section, the agency shall explain the limitations of the data and the methods that were employed in the attempt to obtain the data and shall characterize the probable impacts in qualitative terms. The Commission conducted a series of workshops and task forces to obtain useful information to assess the costs and benefits of electric industry competition. It is not possible to quantify future market prices, technological innovations, organization changes, and the like. Therefore, we have described impacts in qualitative terms. Among the information gathering activities were: * An introductory workshop held on September 7, 1994. One hundred eighteen representatives from utilities, consumer organizations, other power suppliers, and others attended the workshop. The workshop was summarized in a Staff Report dated October 1994. * A series of nine working group and task force meetings held in 1995 which addressed restructuring options, implementation of the options, and advantages and disadvantages of the options. Fifty-one groups were represented on task forces which focused on systems and markets, regulatory issues, and energy efficiency and environmental issues. Members of the task forces included representatives from utilities, consumer organizations, other power suppliers, and others. This work was summarized in a "Report of the Working Group on Retail Electric Competition," dated October 5, 1995. The report contains an extensive bibliography on electric industry restructuring. * A request for comments on electric industry restructuring issued in February 1996. Comments were filed by 31 parties on June 28, 1996. Commenters included consumer groups, Arizona utilities, other suppliers, and other parties. Staff prepared a summary of the comments in July 1996. * A workshop held on August 12, 1996 to explore and obtain feedback on a small number of options for introducing retail electric competition. One hundred thirty workshop participants included representatives from utilities, consumer organizations, other power suppliers, and others. Staff summarized the workshop in a report dated August 19, 1996. * Requests for comments on a draft rule to phase-in retail electric competition. The requests were sent out on August 28, 1996 and comments were due September 12, 1996. Comments were provided by a total of 30 utilities, consumer organizations, other power suppliers, and others. * A workshop to discuss a revised draft rule held on September 18, 1996. Ninety individuals attended the workshop, including representatives from utilities, consumer organizations, other power suppliers, and others. In addition, to better understand possible impacts of restructuring, the Commission Staff reviewed activities in other jurisdictions, including: New Hampshire, Massachusetts, Illinois, Rhode Island, Texas, Alberta, and New York. -----END PRIVACY-ENHANCED MESSAGE-----