-----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, Vpf/MpYlFcjpjxLoO4jzaQkBMdR6NYBnueeg0Ge7vlsGsuwr/aTmkQhxsBT/6qV8 d3dG1zlKPr1aAyt/BqRYaQ== 0000950147-95-000207.txt : 19951215 0000950147-95-000207.hdr.sgml : 19951215 ACCESSION NUMBER: 0000950147-95-000207 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19951204 ITEM INFORMATION: Other events ITEM INFORMATION: Financial statements and exhibits FILED AS OF DATE: 19951214 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: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-04473 FILM NUMBER: 95601694 BUSINESS ADDRESS: STREET 1: 400 N FIFTH ST STREET 2: P O BOX 53999 CITY: PHOENIX STATE: AZ ZIP: 85004 BUSINESS PHONE: 6022501000 8-K 1 FORM 8-K SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report (Date of earliest event reported) December 4, 1995 ---------------- ARIZONA PUBLIC SERVICE COMPANY - -------------------------------------------------------------------------------- (Exact name of registrant as specified in its charter) Arizona 1-4473 86-0011170 - -------------------------------------------------------------------------------- (State or other (Commission (IRS Employer jurisdiction of File Number) Identification incorporation Number) 400 North Fifth Street, P.O. Box 53999, Phoenix, AZ 85004 - -------------------------------------------------------------------------------- (Address of principal executive offices) (Zip code) Registrant's telephone number, including area code (602)250-1000 ------------- NONE - -------------------------------------------------------------------------------- (Former name or former address, if changed since last report) ITEM 5. Other Events - --------------------- Retail Rate Settlement - ---------------------- On December 4, 1995, Arizona Public Service Company (the "Company") and the staff (the "ACC Staff") of the Arizona Corporation Commission (the "ACC") entered into a Rate Reduction Agreement (the "Rate Agreement"). Pursuant to the terms of the Rate Agreement, the Company's annualized retail rates would be reduced by approximately $48 million (approximately $29 million after tax), or 3.25%, based on adjusted kilowatt-hour ("kWh") sales for the twelve months ended June 30, 1995. The rate decrease will be effective on the date the ACC issues a final order approving the Rate Agreement (the "ACC Order"), but in no event will the decrease be effective earlier than July 1, 1996. If the ACC does not issue the ACC Order on or before July 1, 1996, the Rate Agreement will be deemed to be automatically withdrawn. The following description of the Rate Agreement is a summary, and is qualified in its entirety by the Rate Agreement, a copy of which is attached to this filing as an exhibit. Cost Savings Incentives and Potential for Future Retail Rate Changes -------------------------------------------------------------------- To the extent the Company is able to lower its average cost per kWh as compared to the average price per kWh (as defined in Attachment 3 to the Rate Agreement, attached hereto), for each year following the initial rate reduction, through and including July 1, 1999, the Company would reduce its rates as follows: if the average price per kWh exceeds the average cost per kWh based on results of operations for the preceding calendar year, then base rate levels will be adjusted prospectively to reflect fifty-five percent of that difference, effective July 1 of the then-current year. The cost per kWh includes, among other things, the cost of capital, which includes a return on equity of 11.25% applied to the average annual equity balance (including the equity infusion from Pinnacle West Capital Corporation as discussed below), and depreciation and amortization (including the accelerated amortization of regulatory assets discussed below), and does not include the accelerated investment tax credits provided for by the 1994 rate settlement(see Note 5 in Notes to Condensed Financial Statements in Part I, Item 1 of the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 1995 (the "September 10-Q")). Subject to the procedure described above and in Paragraph 2 of the Rate Agreement, which is incorporated herein by reference, neither the Company nor the ACC Staff would file for a permanent change to the Company's retail rates prior to July 2, 1999, except in the event of (i) conditions or circumstances which constitute an emergency, such as the inability to finance on reasonable terms, or (ii) material changes in the Company's cost of service as a result of federal, tribal, state or local laws, regulatory requirements, judicial decisions, actions, or orders. Regulatory Assets ----------------- Substantially all regulatory assets will be recovered by accelerating their amortization over an eight-year period commencing July 1, 1996. As of September 30, 1995, regulatory assets totalled approximately $1.3 billion and included primarily cost deferrals from Palo Verde Nuclear Generating Station ("Palo Verde") Units 2 and 3 and regulatory assets to cover future income tax liabilities recorded as a result of implementing Financial Accounting Standard No. 109 in 1993. This acceleration will increase the annual amortization of regulatory assets by approximately $120 million before income taxes (approximately $72 million after income taxes). Equity Infusion --------------- Pinnacle West Capital Corporation will infuse into the Company $200 million of common equity, in $50 million annual increments, by each year-end beginning in 1996. The Company presently intends to use the additional equity funds primarily to retire outstanding debt and preferred stock. Renewable Resources/Demand Side Management ------------------------------------------ A total of $7 million will be included in base rates for demand side management ("DSM") and renewable resources, of which the Company shall annually undertake on average at least $3 million each of renewable resources programs and DSM. See Paragraph 10 of the Rate Agreement, incorporated by reference herein, for further details regarding the Company's obligation to pursue DSM and renewable resources. Overcollected Property Taxes ---------------------------- As previously reported, in a lawsuit filed by the Palo Verde participants, including the Company, the Company appealed the decision of the Maricopa County Superior Court that an Arizona state tax law, effective December 31, 1989, is constitutional. See "Property Taxes" in Part I, Item 3 of the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994. In November 1995, the Arizona Court of Appeals reversed that decision, holding that the law is unconstitutional. The Arizona Court of Appeals' decision is subject to review by the Arizona Supreme Court. If any overcollected property taxes are refunded to the Company by the State of Arizona as a result of the disposition of this lawsuit, the Company will refund all of the net jurisdictional amount of such refund to its retail customers. Restructuring Issues -------------------- The Company and the ACC Staff recognize the national debate about the electric utility industry and itemized issues which will need to be addressed to enable such competition to take place in Arizona. These issues include electric public service corporations' obligations to serve in a restructured competitive environment; compensation for electric public service corporations moving to a restructured competitive environment, taking into account, among other matters, the estimated magnitude of stranded investment; clarification of federal-state jurisdictional uncertainties; access by Arizona public service corporations to consumers located in other service territories and the terms for access by others to the customers of Arizona public service corporations; and the maintenance of generation, transmission, and distribution system reliability. See Attachment 8 and Attachment 9 to the Rate Agreement, incorporated by reference herein, for further discussion regarding these issues and the Company's proposals with respect to these issues. Pending the satisfactory resolution of the issues raised by the restructuring of the electric utility industry in Arizona, the Company would propose ACC approval of phased access of large retail customers to the broad generation market in the years 2000 to 2004. Access for the remaining customers would be proposed at the appropriate time. The Company anticipates a hearing on the ratemaking portion of the Rate Agreement in the spring of 1996. The Company has suggested that the ACC conduct an independent series of hearings during 1996 (as contemplated by the ACC Staff in its generic competition docket (see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Competition" in Part I, Item 2 of the September 10-Q)) to develop appropriate legislative and regulatory solutions to the identified restructuring issues, which the Company anticipates could be presented to the appropriate legislative bodies in 1997. ITEM 7. Financial Statement, Pro Forma Financial - ------------------------------------------------- Information and Exhibits - ------------------------ (c) Exhibits Exhibit No. Description - ----------- ----------- 10.1 Rate Reduction Agreement dated December 4, 1995 between Arizona Public Service Company and the Staff of the Arizona Corporation Commission SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. ARIZONA PUBLIC SERVICE COMPANY (Registrant) Dated December 14, 1995 By Nancy E. Newquist ------------------------ ----------------------------------- Nancy E. Newquist Treasurer EX-10.1 2 RATE REDUCTION AGREEMENT EXHIBIT 10.1 RATE REDUCTION AGREEMENT ------------------------ Staff of the Arizona Corporation Commission (Staff) and Arizona Public Service Company (APS or Company) agree: 1. APS will implement a first year average 3.25% base rate reduction of $48.3 million, based on retail sales to and revenues from eligible customers for the adjusted test year ended July 1, 1995. See Attachment 1 for details of the calculation. Such rate reduction will become effective July 1, 1996 or immediately upon a Commission order approving the Plan whichever is later. Such rate reduction will be allocated among customers by means of the 0.299(cent)/kWh reduction as shown in Attachment 1 by reducing energy charges for all current APS rate schedules except those set forth in Attachment 2. 2. In order to provide customers with the opportunity for further price reductions, while maintaining its financial stability, the Company must continue to lower its average cost/kWh. To the extent the Company is successful, customers and shareholders will benefit. Each year following the initial rate reduction described in Paragraph 1, through and including July 1, 1999 (the "Moratorium Period"), APS rates would be subject to a reduction in base rates determined as follows: if the average price/kWh exceeds the average cost/kWh, as defined in Attachment 3, based on results of operations for the preceding calendar year, then 55% of the difference will be reflected as a reduction in base rates effective July 1 of the current year. After giving effect to the consolidation, elimination and restructuring of certain existing rate offerings as discussed below, any net revenue decrease would be allocated among customers by means of a uniform(cent)/kWh reduction in the energy charges for all current APS rate schedules, except those set forth in Attachment 2. In any year, if the average cost/kWh is equal to or exceeds the average price/kWh, there would be no further change in base rates (neither a decrease nor an increase in base rates for that year). 3. Under the Plan, certain regulatory assets will be recovered by accelerating their amortization over an eight year period commencing July 1, 1996. These assets are primarily cost deferrals from Palo Verde Units 2 and 3, that were recorded under ACC approved accounting orders, and regulatory assets to cover future income tax liabilities recorded in 1993 as a result of implementing Financial Accounting Standard No. 109 with respect to deferred income taxes. This amortization will be included in the calculation of the average cost/kWh. The accelerated amortization approved in this proceeding is for the purpose of settlement and anticipates the transition period toward a more competitive marketplace. Further, APS agrees that the accelerated amortization of these regulatory assets cannot be used as a separate justification for a net rate increase in any future rate proceeding. Finally, at the end of the Moratorium Period, the accelerated rate of amortization will continue until further order of the Commission. 4. The determination of the reduction to base rates for the succeeding years will be determined pursuant to the Company's calculation of the average price and cost/kWh using data from the prior calendar year. A filing of this calculation will be made on or about March 1 of each year for Staff review and approval. The reduction for the current year will automatically become effective for usage on or after July 1, unless the Commission orders a hearing, which would automatically delay its effective date until a final order is issued. 5. To improve the Company's equity ratio in anticipation of greater competition, Pinnacle West Capital Corporation will infuse $200 million of common equity, in $50 million increments, by each year-end beginning in 1996, into APS with such infusion to be included in calculating each year's average cost/kWh under this Agreement. 6. During the Moratorium Period, no party shall seek to change the rates except as set forth specifically in this Agreement. However, neither APS nor Staff shall be prevented from seeking a change in rates prior to July 2, 1999 in the event of: (a) conditions or circumstances which constitute an emergency, such as the inability to finance on reasonable terms, or (b) material changes in the Company's cost of service as a result of federal, tribal, state or local laws, regulatory requirements, judicial decisions, actions, or orders. 7. The parties agree to the following revisions of current rate schedules and new tariffs: a. Approval of a flexible contracting schedule, Rate E-36, that permits APS to contract with individual customers on price, terms and conditions of service. Contracts negotiated under this tariff would be supplied under strict confidentiality to ACC Staff for their approval within 30 days of submission. This schedule would provide APS the ability to expeditiously and effectively price its services to individual customers to retain and grow its load. Schedule E-36, as shown on Attachment 4, shall also include the following provisions: * The negotiated rate must be commensurate with the costs to the customer of that customer's alternative(s). * APS must file each contract with Staff at least 30 days prior to the effective date of the proposed contract and Staff shall determine whether the contract complies with the tariff prior to the effective date. APS must provide adequate documentation on each element of the tariff (for example, the customer's alternatives) before the 30 day review period commences. * The customer must agree to an energy audit or review unless the customer has recently completed a significant demand side management program or energy audit/review and provides APS with adequate documentation concerning the demand side management activities or audit/review. * For contracts whose terms extend beyond the date when APS will need to add capacity, marginal cost shall mean long run marginal cost. In addition, the last sentence under service billing on Schedule E-36 shall be revised to read: "The revenue from the customer shall exceed the marginal cost of serving that customer." b. The Company shall retain the right to propose for Commission approval during the Moratorium Period new or revised rate designs. Examples of this type of filing might be: i. Revise the time-of-use (TOU) pricing periods and prices (both residential and general service) once advanced meter communications systems are in place. ii. Establish a real-time pricing experiment or operational program. iii. Unbundle retail rates to provide customers alternative service options. 8. The parties agree to the following changes to current rate schedules. These changes are designed to more accurately reflect the costs to serve, promote fairness among similar customer groups, and improve customer understanding and acceptability of the pricing, terms and conditions of the tariffs. a. Revise Schedule #1, General Terms and Conditions of Service, so that credit and collections practices and charges fairly and properly collect costs from customers who impose those costs on APS without subsidies from other customers. The parties also agree to other minor changes to clarify current practices and service specifications. These proposed changes are summarized in Attachment 5. b. Revise partial requirements provisions of the tariff to consistently and fairly charge for services provided. APS has a variety of rates applicable to various types of partial requirements customers and these are proposed to be revised to apply market-based charges for standby, and cost-based charges for supplemental and maintenance service. The proposed tariffs (Schedules E-55 and E-52) are attached as Attachment 6. Schedules E-55 and E-52 shall: * indicate that the customer designates the amount of standby capacity he or she wants in setting the contract standby capacity and that the capacity could be less than the capacity of the self generation facility. In addition, APS shall review whether the potential for lower rates for a customer with a capacity factor consistently below 75 percent (relative to a customer with a higher capacity factor) is in need of correction or clarification. Schedule E-51 shall be frozen to new and reconnecting customers. c. EPR-1, -2, and -3, purchase rates for small qualified cogeneration customers, would be revised to reflect current buy-back rates, current metering technology and establish consistency among the rates. Schedule EPR-4 shall reference schedules for sales to the customer. In addition, Schedule EPR-2 shall offer an option for the incremental cost of the bidirectional meter to be paid in a lump sum or in monthly installments over a specified time period. Schedule EPR-1 will be cancelled. Proposed tariffs (Schedules EPR-2, EPR-3, and EPR-4) are attached as Attachment 7. d. Eliminate extra-small general service Rate E-31 and incorporate E-31 into Schedule E-32 so that the monthly service charge under the new Schedule E-32 is $12.50, and the energy charge (prior to application of the rate decrease) is increased by $0.00024 per kWh for all kWh. 9. The electric base rates proposed to be effective in 1996 include the costs associated with depreciation and decommissioning expense schedules currently being used by APS. The results of any future Palo Verde decommissioning cost or plant depreciation studies completed during the Moratorium Period would be reflected in the average cost/kWh used in the calculation of additional base rate reductions described in Paragraph 2. Any depreciation or decommissioning study would be reviewed by Staff and the new schedules derived therefrom would be authorized and approved in accordance with the procedure established in Section 13.H of Decision No. 58644. 10. APS' commitment to foster investment in DSM and renewables continues and shall be implemented as follows: a. The EEASE fund shall be eliminated. Any over-recovery shall be refunded to customers through a one-time refund within 120 days of the effective date of the Commission's order. b. A total of $7 million will be included in base rates for demand side management (DSM)and renewables. Of the $7 million total, APS shall undertake at least $3 million of renewables programs per year on average and at least $3 million of DSM per year on average. APS shall spend at least $7 million per year on DSM and renewables projects consistent with this Paragraph 10. If APS spends less than $7 million on renewables and DSM per year on average, the Commission, at the next rate case, shall review these expenditures and may order appropriate refunds to ratepayers taking into consideration any sharing that has occurred as a result of paragraph 2. c. APS shall move to phase out consumer rebate DSM programs for customers and instead substitute shareholder-funded, market-based DSM programs for larger customers and, for all customers, develop and implement ratepayer-funded market transformation activities (such as trade ally programs or consumer education programs). However, costs (including incentives and net lost revenues) for existing and approved customer rebate programs shall be included in the calculation of the Company's $7 million obligation under this paragraph until such programs have been phased out. APS shall evaluate the effectiveness of market transformation programs. d. APS shall continue its low income DSM program (at least at current levels), complete current monitoring and evaluation commitments, and fulfill outstanding commitments under existing rebate programs. e. APS shall prepare an administrative and implementation plan for Staff review and approval for its DSM and renewables programs within six months of the effective date of this decision. APS shall prepare proposals for new DSM and renewables programs for Staff review and approval. f. APS shall file detailed semi-annual reports with Staff and in Docket Control on all DSM and renewables activities, although confidential information need not be filed in Docket Control. 11. APS recognizes that the jurisdictional portion of any net refund that it receives as a result of disposition of the property tax lawsuit (Tucson Electric Power v. Apache County, 175 Ariz. 485 (App. 1995)) is -------------------------------------- owed to its customers, since these taxes were collected from and paid by customers to APS through rates. Therefore, APS will refund to its customers the net jurisdictional amount of overcollected property taxes that are refunded to APS by the State of Arizona. APS agrees to work cooperatively with Staff to determine the amount of any refund and method for returning the refund to customers. 12. The rates and charges authorized herein fully include a return on the recorded book original cost of all jurisdictional APS assets (net of depreciation, amortization, and deferred income taxes and other deferred credits) as of June 30, 1995, excepting construction work in progress as of such date. However, nothing in this Agreement shall be construed as prohibiting Staff or any other party from pursuing new issues related to expenditures made or actions taken after June 30, 1995. 13. Staff and APS stipulate to the adoption of the fair value rate base and fair rate of return and agree that the resultant revenue decrease, as reflected in Paragraph 1 above, results in just and reasonable rates for the Company. The determinations made in this Paragraph are made solely for the purpose of the stipulation contained in this Agreement. 14. Each provision of this Agreement is in consideration and support of all the other provisions. This Agreement shall not become effective until the issuance of a final Commission Order approving this Agreement without change or alteration on or before July 1, 1996 in the form of a Proposed Order to be agreed to by the parties. In the event that the Commission fails to adopt this Agreement according to its terms on or before July 1, 1996, this Agreement shall be deemed automatically withdrawn, the rate reduction provisions of this Agreement shall not take effect, and APS and Staff shall be free to pursue their respective positions without prejudice. In addition, if any appeal is taken or other judicial review is sought of a final Commission Order approving this Agreement, then the parties shall no longer be bound by the terms of this Agreement and this Agreement shall automatically become null and void, in which case: (1) the rate reduction specified in Paragraph 1 shall immediately cease; (2) all bills rendered on or after that date shall be at the rates existing immediately prior to the Commission's approval of this Agreement; and (3) the revenue reduction theretofore experienced by APS pursuant to Paragraph 1 shall be recovered through a surcharge mechanism. 15. The terms and provisions of this Agreement apply solely to and are binding only in the context of the purposes and results of this Agreement and none of the positions taken herein by APS may be referred to, cited or relied upon by any other party in any fashion as precedent or otherwise in any other proceeding before this Commission or any other regulatory agency or before any court of law for any purpose except in furtherance of the purposes and results of this Agreement. Nothing in this Agreement shall be construed as imposing a cap on the Company's otherwise reasonable and prudent cost of service for purposes of setting just and reasonable rates. 16. This Agreement represents an attempt to compromise and settle issues regarding the prospective just and reasonable rate levels for APS in a manner consistent with the public interest and applicable legal requirements. Nothing contained in this Agreement is an admission by APS that its current rate levels or rate design are unjust or unreasonable. 17. APS' agreement to the matters contained herein is predicated on a national movement toward competition in the electricity industry. That movement raises a number of policy and legal issues in Arizona which are summarized (not necessarily completely) in the Points of Agreement (Attachment 8). APS has its own views, independent of any the Staff may have, of the proper resolution of certain of the issues presented in the Points of Agreement. Such views are summarized in Attachment 9. Dated at Phoenix, Arizona, this 4th day of December 1995. STAFF OF ARIZONA ARIZONA PUBLIC SERVICE CORPORATION COMMISSION COMPANY By: Gary Yaquinto By: William J. Post -------------------------------- ----------------------------- Title: Director, Utilities Division Title: Senior Vice President & ---------------------------- ------------------------- Chief Operating Officer ------------------------- Attachment 1 Calculation of Base Rate Reduction (Test Year Ended 6/30/95) (1) Adjusted Base Revenues $ 1,485.1 Million (2) 3.25% Base Rate Reduction [(1) x 3.25%] $ 48.3 Million (3) Electric Sales Subject to Decrease 16,152 GWh (4) Base Rate Decrease Factor [(2) / (3)] $ 0.00299 per kWh (5) EEASE Roll-in Factor at $10 Million/year /a/ $ 0.00058 per kWh (6) Net Base Rate Decrease Factor [(4) - (5)] $ 0.00241 per kWh /a/ $10 million divided by the electric sales subject to EEASE (17,143.2 GWh). ATTACHMENT 2 Attachment 2 Rates and Contracts Exempt From General Rate Decreases 1. Rate E-67, Municipal Lighting Service -- City of Phoenix 2. Cyprus Copper Company Contract 3. El Paso Natural Gas (Leupp and Seligman) Contract 4. Magma Copper Company Contract 5. Phelps Dodge Contract 6. Stone Southwest Contract 7. Contracts under proposed Rate E-36 8. Future ACC approved contracts with pricing provisions that exempt them from general rate decreases. These rates and contracts are already discounted or have fixed rate provisions and will not be subject to the general price decreases resulting from the operation of the Plan unless so specified by contract. ATTACHMENT 3 Attachment 3 Unit Cost Ratio and Unit Price Ratio Definitions (The revenues and costs to be utilized in this calculation will be derived from the actual audited financial statements of the Company) Unit Cost Ratio (UCR): Annual cents-per-kilowatt-hour average cost of electric services. UCR = Annual total electric costs (1) ------------------------------------ Annual total Company kwh sales (2) Unit Price Ratio (UPR): Annual cents-per-kilowatt-hour average price of electric services. UPR = Annual electric revenues (3) ------------------------------------ Annual total Company kwh sales (2) 1. Excludes sales taxes (as in the case of the income statement), all ITC amortization (as required by federal tax laws), annual Pinnacle West charges net of costs for shareholder services, fuel expenses for non-traditional and interchange sales (generally defined as opportunity sales which are cost justified on an incremental basis), and non-utility income or deductions and related income tax effects. Includes fuel, operations and maintenance, depreciation and amortization (including the accelerated amortization of regulatory assets), property and other taxes, cost of capital (consisting of long-term interest; debt discount, premium and expense; preferred stock dividend requirements; and a return on equity of 11.25% applied to the average annual equity balance), the gross profit margin on non-traditional and interchange sales, DSM and renewable expenditures (including net lost revenues and incentives), and income taxes on Operating Income including adjustments to income taxes for the above exclusions and inclusions. 2. Excludes kwh sales for non-traditional and interchange sales. 3. Includes miscellaneous revenues. Excludes sales taxes (as in the case of the income statement) and non-traditional and interchange revenues. ATTACHMENT 4 E-36 ELECTRIC RATES -------------- ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5223 Phoenix, Arizona Tariff or Schedule No. E-36 Filed by: Gary J. Volkenant Original Filing Title: Director, Business Financial Services Effective: Original Effective Date: FLEXIBLE CONTRACTING -------------------- APPLICATION - ----------- Qualified customers must: 1. Maintain a single billing account with an annual average metered demand greater than 2,000 kW, or 2. Have single billing accounts with annual average metered demands greater than 50 kW that, when combined, are greater than 2,000 kW, and 3. Agree to an energy audit or review, unless the customer has recently completed a significant demand side management program or energy audit/review and provides APS with adequate documentation concerning demand side management activities or audit/review, and 4. Have or may acquire a competitive alternative to receiving electric service at APS' otherwise effective price, or 5. Have the ability to acquire all or part of their electric service requirements from an alternate supplier, or 6. Desire a long-term contract for electric service. SERVICE BILLING - --------------- Only individual billing accounts meeting the above criteria can be served under Rate E-36. The negotiated price must be commensurate with the costs to the customer of that customer's current or potential alternative(s). Prices may be revised periodically as specified in the service contract to account for changing conditions, costs, and individual customer requirements. The revenue from the customer shall exceed the marginal cost of serving that customer. For contracts whose terms extend beyond the date when APS will need to add capacity, marginal cost shall mean long run marginal cost. SERVICE CONTRACT - ---------------- The contract terms and conditions will be at the Company's option, based on its assessment of the qualified customer's competitive alternative. The contract may be for varying lengths of time as determined by individual customer or Company requirements. Each executed contract will be filed with Commission Staff, on a confidential basis, at least thirty days prior to the effective date of the proposed contract and Staff shall determine whether the contract complies with the tariff prior to the effective date. APS must provide adequate documentation on each element of the tariff (for example, the customer's alternatives) before the thirty day review period commences. If no action is taken within 30 days of the filing, the contract is deemed approved by the Commission. Nothing in this tariff is intended to limit the Arizona Corporation Commission's power to order recovery of costs determined to be attributable to the customer either prior to or after termination of the contract. ATTACHMENT 5 PROPOSED CHANGES TO SCHEDULE #1 2. ESTABLISHMENT OF SERVICE 2.2 Add to first sentence, "or to make a special read without a -------------------------------------- disconnect and calculate a bill for a partial month." --------------------------------------------------- 2.2 Modify last sentence to read "Billing for the service charge will be rendered as part of not later than the second service bill." 2.3 GROUNDS FOR REFUSAL OF SERVICE 2.3.8 Change wording to "Service is requested by an Applicant and a ------------------------------------------- prior customer living with the Applicant owes a delinquent -------------------------------------------------------------- bill." ---- 2.3.9 Change wording to "Applicant is acting as agent for a prior ------------------------------------------- Customer who is deriving benefits of the electric service and -------------------------------------------------------------- who owes a delinquent bill." -------------------------- 2.4 ESTABLISHMENT OF CREDIT OR SECURITY DEPOSIT 2.4.1.3 Delete Letter of Guarantee 2.6 SECURITY DEPOSITS 2.6.3 Add "effective on the first business day of each year." ------------------------------------------------ 2.6.5.1 Change bankruptcy from within the last 6 months to within the last 12 months. 2.6.6 Change to "...Customer's maximum monthly billing as estimated ------------------------------------------------ by the Company." -------------- 4.2 BILLING AND COLLECTION 4.2.1 Change late charge from 12% to "18%." --- 4.4 RETURNED CHECKS 4.4.1 Change $10 to "$15." --- 4.5 Change collection charge to "field charge", change amount from ------------ $9.50 to "$15.00" and add "or terminate the service." For ------ ------------------------ other than termination, premise visit must be requested by customer. 4.5.2 Change acceptable to "satisfactory to Company." ----------------------- 5.3 COMPANY ACCESS TO CUSTOMER PREMISES 5.3 Add requirement of "unassisted" access in two sentences. All ---------- existing conditions shall be grandfathered, i.e., tariff shall apply only to services established after effective date of tariff. 5.3 Expand remedy for inaccessibility. 5.5 Add "a minimum standard is IEEE 519" and simplify language. ------------------------------ 6. METERING AND METERING EQUIPMENT 6.1.1 Add "Electric Service Requirements manual." All updates to this manual shall be provided to Staff in a timely manner. 7. TERMINATION 7.1.5 Add "satisfactory and unassisted." All existing conditions ---------------------------- shall be grandfathered, i.e., tariff shall apply only to services established after effective date of tariff. ATTACHMENT 6 ELECTRIC RATES -------------- ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5215 Phoenix, Arizona Tariff or Schedule No. E-52 Filed by: Gary J. Volkenant Original Filing Title: Director, Business Financial Services Effective Date: Original Effective Date: ELECTRIC SERVICE FOR PARTIAL REQUIREMENTS SERVICE ------------------------------------------------- OF LESS THAN 3,000 KW --------------------- I. AVAILABILITY ------------ In all territory served by Company at all points where facilities of adequate capacity and the required phase and suitable voltage are adjacent to the premises served and when all applicable provisions described herein have been met. II. APPLICATION ----------- Applicable to any non-residential customer requiring Partial Requirements services, Supplemental Power, Standby Power or Maintenance Power with an aggregate Partial Requirements service load of less than 3,000 kW. Customer may elect to take any of the Partial Requirements services offered hereunder, Supplemental Power, Standby Power and Maintenance Power independently of one another or in combination with one another as required. III. TYPE OF SERVICE --------------- Single or three phase, 60 Hertz, at one standard voltage as may be selected by Customer subject to availability at Customer's premise. IV. MONTHLY BILL ------------ The monthly bill shall be the sum of the amounts computed under A., B., C., and D. below, including the applicable Adjustments: A. Basic Service ------------- $ 106.79 per month Basic Service Charge, plus $ 17.06 per month for each Generator Meter B. Supplemental Service -------------------- In accordance with the rate levels contained in General Service Rate Schedule E-32 excluding the monthly Basic Service Charge. C. Standby Service --------------- The monthly charge for Standby Service shall be the sum of the amounts computed in accordance with sections 1 and 2 below: 1. Monthly Reservation Charge of either a, b or c: a. $5.54 per kW of Contract Standby Capacity for Standby Service customers with alternate supply resources demonstrating an aggregate Capacity Factor of 90% or greater during the billing month. b $7.29 per kW of contract Standby Capacity for Standby Service customers with alternate supply resources demonstrating an aggregate Capacity Factor between 80% - 89.9% during the billing month. c. Standby Service customers whose alternate supply resource(s) achieved an aggregate capacity factor of less than 80% during a billing month shall be assessed the same charge as set forth in Section VIII of this rate schedule. 2. Standby Energy Charge: June - October $0.0213 per kWh on-peak Billing Cycles $0.0154 per kWh off-peak (Summer) November - May $0.0187 per kWh on-peak Billing Cycles $0.0135 per kWh off-peak (Winter) The charges for Standby Service contained in Section C herein reflect the Company's costs to serve Standby Service loads. For applications where the charges for Standby Service stated herein are not competitive with customer installed standby resource alternatives, the Company may negotiate alternate Monthly Reservation Charges from those contained in this rate schedule; however, the maximum discount allowed shall not be greater than fifty percent (50%) of the Reservation Charges stated herein; however, such discount shall not result in a reservation charge lower than the Company's long run capacity costs associated with this service. No changes to the Standby Energy Charge rate component shall be allowed. To be eligible for negotiated Monthly Reservation Charges different than those contained herein, the customer must demonstrate to the Company's satisfaction and provide conclusive documentation (e.g., engineering studies, analysis, etc.) that the customer's on-site self-generation resource(s) would be a lower cost option over the life of the equipment than had the customer subscribed to Standby Service from the Company. Notwithstanding the potential competitiveness of the customer's self generation standby facilities, the Company in its sole opinion, shall have the option of not offering any discounts to the otherwise applicable Reservation Charge. D. Maintenance Service ------------------- $0.0187 per kWh on-peak $0.0135 per kWh off-peak E. Energy Rates ------------ The energy rates in Sections C and D above are based on the Company's estimated marginal costs and will be updated annually to reflect changes in the Company's fuel costs. V. DETERMINATION OF SUPPLEMENTAL SERVICE ------------------------------------- Supplemental service shall be defined as demand and energy contracted by Customer to augment the power and energy generated by Customer's generation facility. Supplemental demand shall be the highest 15-minute interval during the billing month which shall equal the (a) 15-minute integrated kW demand calculated for every 15-minute interval as recorded on the Supply Meter, plus (b) the simultaneous 15 minute integrated kW demand as recorded on the Generator Meter(s), less (c) the aggregate Contract Standby Capacity of all the customer's generating units; however, the result shall never be less than zero (0) for purposes of determining Supplemental Demand. If Company authorized scheduled maintenance was being performed on any of the customer's generators at the time of the highest 15 minute interval during the billing month, the amount of demand recorded on the Supply Meter shall be reduced by the applicable Maintenance Power Level (as determined in Section VII hereof) of the generator unit(s) undergoing authorized scheduled maintenance for purposes of calculating supplemental demand used for billing. Customer's maximum Supplemental Service kW requirements shall not exceed that established in the Electric Supply Agreement. Supplemental energy shall be equal to all energy supplied to Customer as determined from readings of the Supply Meter, less any energy determined to be either Standby or Maintenance energy as defined in this Schedule. VI. DETERMINATION OF STANDBY ENERGY ------------------------------- Standby Energy shall be defined to be electric energy supplied by Company to replace power ordinarily generated by Customer's generation facility during unscheduled full and partial outages of said facility. When the sum of the energy measured on both the Supply and Generator(s) Meters during simultaneous periods is greater than the maximum energy output of the generator(s) at Contract Standby Capacity, the Standby Energy shall be equal to the summation of the differences between the maximum energy output of the generator(s) at Contract Standby Capacity and the energy measured on the Generator Meter(s) for every 15-minute interval of the month, except when maintenance power is being utilized or those intervals where energy measured on the Supply Meter is zero. When the sum of the energy measured on both the Supply and Generator(s) Meter is equal to or less than the maximum energy output of the generator(s) at Contract Standby Capacity, then the Standby energy shall be that energy measured on the Supply Meter. VII. DETERMINATION OF MAINTENANCE ENERGY ----------------------------------- Maintenance energy shall be defined as energy supplied to Customer to replace energy normally supplied by the Customer's generator(s) during an authorized Scheduled Maintenance period. Maintenance periods shall not exceed 30 days per cogeneration unit during any consecutive 12-month period and must be scheduled during the non-Summer billing months. Customer shall provide Company with its planned maintenance schedule 12 months in advance of any planned maintenance in order for the Company to coordinate customer's scheduled maintenance with that of the Company. Upon review, Company shall either approve customer's planned maintenance schedule or notify customer of alternate acceptable periods. Customer, in turn, shall notify the Company of an acceptable alternate maintenance period(s), and shall also confirm with the Company its intention to perform its planned maintenance 45 days prior to the actual commencement date of the planned maintenance period. Any energy used in excess of a 30-day period or unauthorized maintenance energy shall be billed on either the Standby or Supplemental Rate as specified in this Schedule. Maintenance energy, during a Company authorized period of scheduled maintenance to a customer's generation unit(s), shall be determined as follows: Maintenance Power Level = (Contract Standby Capacity) X (Generating Unit(s) Capacity Factor for the most recent 12 months) The maintenance power level as determined by the above formula shall not exceed any actual 15 minute interval of integrated kw demand as recorded on the supply meter. If customer has less than 12 months of billing history on Standby Service, use the capacity factor demonstrated to date; however, not less than one full month. Maintenance Energy = (Maintenance Power Level) X (hours of maintenance authorized by Company during billing month) VIII. CAPACITY FACTOR STANDARDS ------------------------- Customer's generating unit(s) must maintain a Capacity Factor of no less than 75% over a continuous rolling 18 month period to remain eligible to receive Standby Service under this rate schedule. The calculation of the Capacity Factor is designed so that the customer shall not be subject to this Capacity Factor Standard provision for any purpose other than substandard operational performance of the customer's generating unit(s) recognizing that the customer's load profile may not require the full output capability of such generation unit(s). If the Capacity Factor falls below 75%, in lieu of the otherwise applicable Reservation Charge for Standby Service, the customer shall be assessed a monthly Reservation Charge the greater of: 1. $20.78 per kW/month X 2/3 X Contract Standby Capacity; or 2. $20.78 per kW/month X Maximum Standby Capacity (If customer's system is directly interconnected with the Company's bulk transmission system, the applicable Reservation Charge shall be $15.90 per kW per month.) Maximum Standby Capacity is intended to represent the maximum 15-minute interval of Standby Power provided the customer by the Company during the billing month. Maximum Standby Capacity shall equal the highest 15-minute interval during the billing month of the following calculation: MSC = (SIGMA)CSC - Maint. Where: MSC = Maximum 15-minute interval during the billing month of Standby Power (kW) being supplied by Company. (SIGMA)CSC= The aggregate Contract Standby Capacity of all the customer's self-generation units. Maint= The simultaneous 15-minute interval of any Maintenance Power (kW) being supplied to customer by the Company. IX. METERING -------- The Company will install a Supply Meter at its point of delivery to Customer and a Generator Meter(s) at the point(s) of output from each of Customer's generators. All meters will record integrated demand and energy on the same 15-minute interval basis as specified by Company. X. DEFINITIONS ----------- 1. Contract Standby Capacity - for each specific customer generating unit for ------------------------- which the Company is providing Standby Service, Contract Standby Capacity shall be the greater of: a) the measured kW output of each customer self-generation unit at time of start-up test, or b) the highest 15 minute measured kW output of each generating unit, however, not to exceed Customer's actual total load. 2. Generator Meter - the time-of-use meter used to measure in 15-minute ---------------- intervals the total power and energy output of each Customer's cogeneration units. 3. Capacity Factor - for purposes of this rate schedule, capacity factor shall --------------- mean the capacity factor of the customer's generating unit(s) and shall not reflect any period of time during a billing month that Company authorized Maintenance Power was being utilized. The Capacity factor shall be calculated in accordance with the following formula: Capacity Factor = Actual customer generated kWh's during the billing month -------------------------------------------------------- A For purposes of use in this rate schedule, the value of the capacity factor calculation shall never exceed 100%. Where: A = The lesser of: a) [(Contract Standby Capacity) X (MH)]; or b) CTL MH = Hours in the billing month exclusive of any hours during the billing month that customer's unit(s) were non-operational during Company authorized scheduled maintenance. CTL = Customer's maximum total load during the billing month as determined by the total of energy generated on customer's generating unit as recorded on the Generator Meter plus all energy provided by Company during the billing month (exclusive of maintenance energy) as recorded on the Supply Meter 4. Supply Meter - the time-of-use meter used to measure in 15-minute intervals ------------ the total power and energy supplied by Company to Customer. 5. Time Periods - On-Peak Period: 9 a.m. - 9 p.m. Monday through Friday ------------- Off-Peak Period: All Other Hours Mountain Standard Time shall be used in the application of this rate schedule. In addition, to prevent radical changes in the system loads the beginning and ending hours for individual customers may be varied by up to one hour (total hours in each time period to remain unchanged) and because of potential differences of the timing devices, there may be a variation of up to 15 minutes in timing for the pricing periods. XI ADJUSTMENTS ----------- The applicable proportionate part of any taxes or governmental impositions which are or may in the future be assessed on the basis of gross revenues of the Company and/or the price or revenue from the electric energy or service sold and/or the volume of energy generated or purchased for sale and/or sold hereunder. XII. TERMINATION PROVISION --------------------- Should Customer cease to operate his cogeneration unit(s) for 60 consecutive days during periods other than planned scheduled maintenance periods, Company reserves the option to terminate the Agreement for service under this rate schedule with Customer. XIII. CONTRACT PERIOD ---------------- As provided in the Electric Supply Agreement between Company and Customer. XIV. TERMS AND CONDITIONS -------------------- Customer must enter into an Agreement for the Interconnection and The Sale of Power with Company and an Electric Supply Agreement which shall establish all pertinent details related to interconnection and other required service standards. Customer will not have the option to sell power and energy to Company under this tariff. Should Customer desire to do so, Customer would be required to enter into a new Service Agreement which would set forth the applicable purchase rate in addition terms and conditions for interconnection and for the sale of power to the Company. Customer will be required to contract for adequate standby power to cover the total output of all the customer's generators unless adequate facilities have been installed, to the satisfaction of APS, that isolates portions of the customer's load from APS' system so that APS will in no event be providing standby service in excess of Contracted Standby Capacity. ELECTRIC RATES -------------- ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5214 Phoenix, Arizona Tariff or Schedule No. E-55 Filed by: Gary J. Volkenant Original Filing Title: Director, Business Financial Services Effective Date: Original Effective Date: ELECTRIC SERVICE FOR PARTIAL REQUIREMENTS SERVICE ------------------------------------------------- 3,000 KW OR GREATER ------------------- I. AVAILABILITY ------------ In all territory served by Company at all points where facilities of adequate capacity and the required phase and suitable voltage are adjacent to the premises served and when all applicable provisions described herein have been met. II. APPLICATION ----------- Applicable to any customer requiring Partial Requirements services, Supplemental Power, Standby Power or Maintenance Power with an aggregate Partial Requirements service load of no less than 3,000 kW. Customer may elect to take any of the Partial Requirements services offered hereunder (Supplemental Power, Standby Power and Maintenance Power) independently of one another or in combination with one another as required. III. TYPE OF SERVICE --------------- Single or three phase, 60 Hertz, at one standard voltage as may be selected by Customer subject to availability at Customer's premise. IV. MONTHLY BILL ------------ The monthly bill shall be the sum of the amounts computed under A., B., C., and D. below, including the applicable Adjustments: A. Basic Service ------------- 1. a) For applications no greater than 15,000 kW: $ 1,671.39 per month Basic Service Charge; plus b) For applications greater than 15,000 kW: The monthly Basic Service Charge shall be $1,671.39 plus an applicable adder for recovery of non-standard metering costs and related O&M expenses; plus 2. $ 62.51 per month for each Generator Meter B. Supplemental Service -------------------- In accordance with the rate levels contained in General Service Rate Schedule E-32, excluding the monthly Basic Service Charge (or E-34 if Supplemental Power requirements are 3,000 kW or more). C. Standby Service --------------- The monthly charge for Standby Service shall be the sum of the amounts computed in accordance with sections 1 and 2 below: 1. Monthly Reservation Charge of either a, b or c: a. $ 4.13 per kW of Contract Standby Capacity for Standby Service customers with alternate supply resources demonstrating an aggregate Capacity Factor of 95% or greater during the billing month. b. $ 5.05 per kW of contract Standby Capacity for Standby Service customers with alternate supply resources demonstrating an aggregate Capacity Factor between 90% - 94.9% during the billing month. c. $ 6.98 per kW of contract Standby Capacity for Standby Service customers with alternate supply resources demonstrating an aggregate Capacity Factor between 80% - 89.9% during the billing month. d. Standby Service customers whose alternate supply resource(s) achieved an aggregate capacity factor of less than 80% during a billing month shall be assessed the same charge as set forth in Section VIII of this rate schedule. 2. Standby Energy Charge: June - October $0.0217 per kWh on-peak Billing Cycles $0.0159 per kWh off-peak (Summer) November - May $0.0193 per kWh on-peak Billing Cycles $0.0139 per kWh off-peak (Winter) The charges for Standby Service contained in Section C herein reflect the Company's costs to serve Standby Service loads. For applications where the charges for Standby Service stated herein are not competitive with customer installed standby resource alternatives, the Company may negotiate alternate Monthly Reservation Charges from those contained in this rate schedule; however, the maximum discount allowed shall not be greater than fifty percent (50%) of the Reservation Charges stated herein; however, such discount shall not result in a reservation charge lower than the Company's long run capacity costs associated with this service. No changes to the Standby Energy Charge rate component shall be allowed. To be eligible for negotiated Monthly Reservation Charges different than those contained herein, the customer must demonstrate to the Company's satisfaction and provide conclusive documentation (e.g., engineering studies, analysis, etc.) that the customer's on-site self-generation resource(s) would be a lower cost option over the life of the equipment than had the customer subscribed to Standby Service from the Company. Notwithstanding the potential competitiveness of the customer's self generation standby facilities, the Company in its sole opinion, shall have the option of not offering any discounts to the otherwise applicable Reservation Charge. D. Maintenance Service ------------------- $0.0193 per kWh on-peak $0.0139 per kWh off-peak E. Energy Rates ------------ The energy rates in Sections C and D above are based on the Company's estimated marginal costs and will be updated annually to reflect changes in the Company's fuel costs. V. DETERMINATION OF SUPPLEMENTAL SERVICE ------------------------------------- Supplemental service shall be defined as demand and energy contracted by Customer to augment the power and energy generated by Customer's generation facility. Supplemental demand shall be the highest 15-minute interval during the billing month which shall equal the (a) 15-minute integrated kW demand calculated for every 15-minute interval as recorded on the Supply Meter, plus (b) the simultaneous 15 minute integrated kW demand as recorded on the Generator Meter(s), less (c) the aggregate Contract Standby Capacity of all the customer's generating units; however, the result shall never be less than zero (0) for purposes of determining Supplemental Demand. If Company authorized scheduled maintenance was being performed on any of the customer's generators at the time of the highest 15 minute interval during the billing month, the amount of demand recorded on the Supply Meter shall be reduced by the applicable Maintenance Power Level (as determined in Section VII hereof) of the generator unit(s) undergoing authorized scheduled maintenance for purposes of calculating supplemental demand used for billing. Customer's maximum Supplemental Service kW requirements shall not exceed that established in the Electric Supply Agreement. Supplemental energy shall be equal to all energy supplied to Customer as determined from readings of the Supply Meter, less any energy determined to be either Standby or Maintenance energy as defined in this Schedule. VI. DETERMINATION OF STANDBY ENERGY ------------------------------- Standby Energy shall be defined to be electric energy supplied by Company to replace power ordinarily generated by Customer's generation facility during unscheduled full and partial outages of said facility. When the sum of the energy measured on both the Supply and Generator(s) Meters during simultaneous periods is greater than the maximum energy output of the generator(s) at Contract Standby Capacity, the Standby Energy shall be equal to the summation of the differences between the maximum energy output of the generator(s) at Contract Standby Capacity and the energy measured on the Generator Meter(s) for every 15-minute interval of the month, except when maintenance power is being utilized or those intervals where energy measured on the Supply Meter is zero. When the sum of the energy measured on both the Supply and Generator(s) Meter is equal to or less than the maximum energy output of the generator(s) at Contract Standby Capacity, then the Standby energy shall be that energy measured on the Supply Meter. VII. DETERMINATION OF MAINTENANCE ENERGY ----------------------------------- Maintenance energy shall be defined as energy supplied to Customer to replace energy normally supplied by the Customer's generator(s) during an authorized Scheduled Maintenance period. Maintenance periods shall not exceed 30 days per cogeneration unit during any consecutive 12-month period and must be scheduled during the non-Summer billing months. Customer shall provide Company with its planned maintenance schedule 12 months in advance of any planned maintenance in order for the Company to coordinate customer's scheduled maintenance with that of the Company. Upon review, Company shall either approve customer's planned maintenance schedule or notify customer of alternate acceptable periods. Customer, in turn, shall notify the Company of an acceptable alternate maintenance period(s), and shall also confirm with the Company its intention to perform its planned maintenance 45 days prior to the actual commencement date of the planned maintenance period. Any energy used in excess of a 30-day period or unauthorized maintenance energy shall be billed on either the Standby or Supplemental Rate as specified in this Schedule. Maintenance energy, during a Company authorized period of scheduled maintenance to a customer's generation unit(s), shall be determined as follows: Maintenance Power Level = (Contract Standby Capacity) X (Generating Unit(s) Capacity Factor for the most recent 12 months) The maintenance power level as determined by the above formula shall not exceed any actual 15 minute interval of integrated kw demand as recorded on the supply meter. If customer has less than 12 months of billing history on Standby Service, use the capacity factor demonstrated to date; however, not less than one full month. Maintenance Energy = (Maintenance Power Level) X (hours of maintenance authorized by Company during billing month) VIII. CAPACITY FACTOR STANDARDS ------------------------- Customer's generating unit(s) must maintain a Capacity Factor of no less than 75% over a continuous rolling 18 month period to remain eligible to receive Standby Service under this rate schedule. The calculation of the Capacity Factor is designed so that the customer shall not be subject to this Capacity Factor Standard provision for any purpose other than substandard operational performance of the customer's generating unit(s) recognizing that the customer's load profile may not require the full output capability of such generation unit(s). If the Capacity Factor falls below 75%, in lieu of the otherwise applicable Reservation Charge for Standby Service, the customer shall be assessed a monthly Reservation Charge the greater of: 1. $22.90 per kW/month X 2/3 X Contract Standby Capacity; or 2. $22.90 per kW/month X Maximum Standby Capacity (If customer's system is directly interconnected with the Company's bulk transmission system, the applicable Reservation Charge shall be 19.43 per kW per month.) Maximum Standby Capacity is the maximum 15-minute interval of Standby Power provided the customer by the Company during the billing month. Maximum Standby Capacity shall equal the highest 15-minute interval during the billing month of the following calculation: MSC = (SIGMA)CSC - Maint. Where: MSC= Maximum 15-minute interval during the billing month of Standby Power (kW) being supplied by Company. (SIGMA)CSC= The aggregate Contract Standby Capacity of all the customer's self-generation units. Maint= The simultaneous 15-minute interval of any Maintenance Power (kW) being supplied to customer by the Company. IX. METERING -------- The Company will install a Supply Meter at its point of delivery to Customer and a Generator Meter(s) at the point(s) of output from each of Customer's generators. All meters will record integrated demand and energy on the same 15-minute interval basis as specified by Company. X. DEFINITIONS ----------- 1. Contract Standby Capacity - for each specific customer generating unit for ------------------------- which the Company is providing Standby Service, Contract Standby Capacity shall be the greater of a) the measured kW output of each customer self-generation unit at time of start-up test, or b) the highest 15 minute measured kW output of each generating unit, however, not to exceed Customer's actual total load. 2. Generator Meter - the time-of-use meter used to measure in 15-minute ---------------- intervals the total power and energy output of each Customer's cogeneration units. 3. Capacity Factor - for purposes of this rate schedule, capacity factor shall --------------- mean the capacity factor of the customer's generating unit(s) and shall not reflect any period of time during a billing month that Company authorized Maintenance Power was being utilized. The Capacity factor shall be calculated in accordance with the following formula: Capacity Factor = Actual customer generated kWh's during the billing month -------------------------------------------------------- A For purposes of use in this rate schedule, the value of the capacity factor calculation shall never exceed 100%. Where: A = The lesser of: a) [(Contract Standby Capacity) X (MH)]; or b) CTL MH = Hours in the billing month exclusive of any hours during the billing month that customer's unit(s) were non-operational during Company authorized scheduled maintenance. CTL = Customer's maximum total load during the billing month as determined by the total of energy generated on customer's generating unit as recorded on the Generator Meter plus all energy provided by Company during the billing month (exclusive of maintenance energy) as recorded on the Supply Meter 4. Supply Meter - the time-of-use meter used to measure in 15-minute intervals ------------ the total power and energy supplied by Company to Customer. 5. Time Periods - On-Peak Period: 9 a.m.- 9 p.m. Monday through Friday ------------- Off-Peak Period: All Other Hours Mountain Standard Time shall be used in the application of this rate schedule. In addition, to prevent radical changes in the system loads the beginning and ending hours for individual customers may be varied by up to one hour (total hours in each time period to remain unchanged) and because of potential differences of the timing devices, there may be a variation of up to 15 minutes in timing for the pricing periods. XI ADJUSTMENTS ----------- The applicable proportionate part of any taxes or governmental impositions which are or may in the future be assessed on the basis of gross revenues of the Company and/or the price or revenue from the electric energy or service sold and/or the volume of energy generated or purchased for sale and/or sold hereunder. XII. TERMINATION PROVISION --------------------- Should Customer cease to operate his cogeneration unit(s) for 60 consecutive days during periods other than planned scheduled maintenance periods, Company reserves the option to terminate the Agreement for service under this rate schedule with Customer. XIII. CONTRACT PERIOD ---------------- As provided in the Electric Supply Agreement between Company and Customer. XIV. TERMS AND CONDITIONS -------------------- Customer must enter into an Agreement for the Interconnection and The Sale of Power with Company and an Electric Supply Agreement which shall establish all pertinent details related to interconnection and other required service standards. Customer will not have the option to sell power and energy to Company under this tariff. Should Customer desire to do so, Customer would be required to enter into a new Service Agreement which would set forth the applicable purchase rate in addition terms and conditions for interconnection and for the sale of power to the Company. Customer will be required to contract for adequate standby power to cover the total output of all the customer's generators unless adequate facilities have been installed, to the satisfaction of APS, that isolates portions of the customer's load from APS' system so that APS will in no event be providing standby service in excess of Contracted Standby Capacity. ATTACHMENT 7 ELECTRIC RATES -------------- ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5216 Phoenix, Arizona Cancelling A.C.C. No. 5137 Filed by: Gary J. Volkenant Tariff or Schedule No. EPR-2 Title: Director, Business Financial Services Revision No. 4 Original Effective Date: October 25, 1981 Effective: PURCHASE RATES FOR QUALIFIED COGENERATION AND SMALL POWER PRODUCTION -------------------------------------------------------------------- FACILITIES UNDER 100 KW RECEIVING PARTIAL REQUIREMENTS OR INTERRUPTIBLE SERVICE - ------------------------------------------------------------------------------- AVAILABILITY - ------------ In all territory served by Company. APPLICATION - ----------- To all cogeneration and small power production facilities 100 kW or less where the facility's generator(s) and load are located at the same premise and that otherwise meet qualifying status pursuant to the Arizona Corporation Commission's Decision No. 52345 on cogeneration and small power production facilities. Applicable only to qualifying facilities (QF's) electing to configure their systems as to require only partial requirements or interruptible service from the Company in order to meet their electric requirements. TYPE OF SERVICE - --------------- Electric sales to the Company must be single or three phase, 60 Hertz, at one standard voltage as may be selected by customer (subject to availability at the premises). The qualifying facility will have the option to sell energy to the Company at a voltage level different than that for purchases from the Company; however, the QF will be responsible for all incremental costs incurred to accommodate such an arrangement. PAYMENT FOR PURCHASES FROM AND SALES TO THE CUSTOMER - ---------------------------------------------------- Power sales and special services supplied by the Company to the Customer in order to meet its supplemental or interruptible electric requirements will be priced at the applicable retail rate or rates. The Company will pay the Customer for any energy purchased as calculated on the standard purchase rate (see below). MONTHLY PURCHASE RATE - --------------------- Rate for pricing of energy, net of that for the customer's own use, that is delivered to the Company: Cents per kWh ------------------------------------------------ Non-Firm Power Firm Power ---------------------- ----------------------- On-Peak(1) Off-Peak(2) On-Peak(1) Off-Peak(2) ---------- ---------- ---------- ----------- Summer Billing Cycles 1.58 1.17 2.20 1.52 (June - October) Winter Billing Cycles 1.25 1.08 1.74 1.38 (November - May) (1) On-Peak Periods: 9 a.m. to 9 p.m., weekdays (2) Off-Peak Periods: All other hours These rates are based on the Company's estimated avoided energy costs and will be updated annually to reflect changes in the Company's fuel costs. SERVICE CHARGE - -------------- The monthly service charge shall be determined in accordance with the type of customer service characteristics as set forth below: Monthly Charge -------------- Single Phase Service: 0-200 amp service $ 7.34 Three Phase Service: 0-200 amp service $ 8.87 201-400 amp service $ 18.31 CONTRACT PERIOD - --------------- As provided for in the Purchase Agreement. DEFINITIONS - ----------- 1. Partial Requirements Service - A QF's system configuration whereby ---------------------------- the output from its electric generator(s) first go to supply its own electric requirements with any excess energy (over and above its own requirements at the time) then being sold to the Company. The Company supplies the Customer's supplemental electric requirements (those not met by the QF's own generation facilities). This also may be referred to as the "parallel mode" of operation. 2. Special Service(s) - The electric service(s) specified in this ------------------ section that will be provided by the Company in addition to or in lieu of normal service(s). * Interruptible Power - Electric energy or capacity supplied by ------------------- the Company subject to interruption by the Company under specified conditions and under agreed upon lead time requirements. 3. Non-Firm Power - Electric power which is supplied by the power --------------- producer at the producer's option, where no firm guarantee is provided, and the power can be interrupted by the power producer at any time. 4. Firm Power - Power available, upon demand, at all times (except ---------- for forced outages and scheduled maintenance) during the period covered by the Purchase Agreement from the Customer's facilities with an expected or demonstrated reliability which is greater than or equal to the average reliability of the Company's firm power sources. 5. Time Periods - Mountain Standard Time shall be used in the ------------- application of this rate schedule. Because of potential differences of the timing devices, there may be a variation of up to 15 minutes in timing for the pricing periods. TERMS AND CONDITIONS - -------------------- Subject to Company's Terms and Conditions for Energy Purchases from Qualified Cogeneration or Small Power Production Facilities, or as it may be amended or modified from time to time by any supplemental or special Terms and Conditions pursuant to Customer's Purchase Agreement with the Company. Customer and Company will share in the cost of the bi-directional meter used to record sales to the Customer and purchases from the Customer. Company shall be responsible for all costs up to and equal to the installed cost of a residential time-of-use meter, and Customer shall be responsible for the difference between the installed cost of the bi-directional meter compared to a standard residential time-of-use meter. Customer shall have the option to pay the incremental metering costs initially or in monthly installements over a five year time period. METERING CONFIGURATION - ---------------------- [GRAPHIC OMITTED] [The omitted material is a diagram of a bidirectional meter which reads energy flows from the Company into the customer for the customer's QF's load and also reads the QF's generator's excess supply sold back to the Company.] ELECTRIC RATES ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5217 Phoenix, Arizona Cancelling A.C.C. No. 5159 Filed by: Gary J. Volkenant Tariff or Schedule No. EPR-3 Title: Director, Business Financial Services Revision No. 1 Original Effective Date: February 4, 1993 Effective: PURCHASE RATES FOR QUALIFIED SOLAR/PHOTOVOLTAIC SMALL POWER PRODUCTION ---------------------------------------------------------------------- FACILITIES 10 KW OR LESS THAT RECEIVE FULL OR --------------------------------------------- PARTIAL REQUIREMENTS ELECTRIC SERVICE ------------------------------------- FROZEN AVAILABILITY - ------------ In all territory served by Company. APPLICATION - ----------- To all small power production facilities with a nameplate rating of 10 kW or less utilizing solar/photovoltaic technology where the customer's generator(s) and load are located at the same premise and meet qualifying status pursuant to the Arizona Corporation Commission's Decision No. 52345 on cogeneration and small power production facilities. Applicable only to qualifying facilities (QF's) either: a) operating in the simultaneous buy/sell mode (whereby all the QF's generation output is fed directly into the Company's system and all of the QF's electric requirements are met by sales from the Company) or; b) QF's electing to configure their systems as to require only partial requirements or interruptible service from the company in order to meet their electric requirements. Applicable only to those customers being served on the Company's Rate Schedule EPR-3 prior to ____________________. TYPE OF SERVICE - --------------- Electric sales to the Company must be single phase, 60 Hertz, at one standard voltage as may be selected by customer (subject to availability at the premises). The qualifying facility will have the option to sell energy to the Company at a voltage level different than that for purchases from the Company; however, the Customer will be responsible for all incremental costs incurred by APS to accommodate such an arrangement. BILLING OPTIONS FOR PURCHASES FROM AND SALES TO THE CUSTOMER - ------------------------------------------------------------ The Customer will have the option of choosing either of the following two methods for determining the bill for purchases and sales: A. Net Bill Method: The energy (kWh's) sold to the Company shall be subtracted from the energy purchased from the Company. If the difference is positive, the net energy received from the Company will be priced at the applicable standard retail rate under which the Customer would otherwise purchase its full requirements service. If the difference is negative, the net energy delivered to the Company will be priced at the Monthly Purchase Rate shown below. B. Separate Bill Method: All sales and purchases shall each be treated separately with sales to the Customer billed on the applicable standard retail rate for full requirements service, and purchases of energy from the Customer's QF priced at the Monthly Purchase Rate shown below. MONTHLY PURCHASE RATE - --------------------- Rate for pricing of energy, net of that for the customer's own use, that is delivered to the Company under either Billing Option A or Option B: Cents per kWh ------------------------------------------------- Non-Firm Power Firm Power ------------------------------------------------- On-Peak(1) Off-Peak(2) On-Peak(1) Off-Peak(2) ---------- ----------- ---------- ----------- Summer Billing Cycles 1.58 1.17 2.20 1.52 (June - October) Winter Billing Cycles 1.25 1.08 1.74 1.38 (November - May) (1) On-Peak Periods: 9 a.m. to 9 p.m., weekdays (2) Off-Peak Periods: All other hours These rates are based on the Company's estimated avoided energy costs and will be updated annually to reflect changes in the Company's fuel costs. METERING - -------- See pages 3 and 4 Metering Configurations & Options outlining the metering options available to solar/photovoltaic QF Customers electing the simultaneous buy/sell mode or the parallel mode of operation. CONTRACT PERIOD - --------------- As provided for in the Purchase Agreement. DEFINITIONS - ----------- 1. Full Requirements Service - Any instance whereby the Company provides all -------------------------- the electric requirements of a Customer. 2. Partial Requirements Service - A QF's system configuration whereby the ------------------------------ output from its electric generator(s) first go to supply its own electric requirements with any excess energy (over and above its own requirements at the time) then being sold to the Company. The Company supplies the Customer's supplemental electric requirements (those not met by the QF's own-generation facilities). This also may be referred to as the "parallel mode" of operation. 3. Special Service(s) - The electric service(s) specified in this section ------------------ that will be provided by the Company in addition to or in lieu of normal service(s). * Interruptible Power - Electric energy or capacity supplied by the -------------------- Company subject to interruption by the Company under specified conditions and under agreed upon lead time requirements. 4. Non-Firm Power - Electric power which is supplied by the power producer at -------------- the producer's option, where no firm guarantee is provided, and the power can be interrupted by the power producer at any time. 5. Firm Power - Power available, upon demand, at all times (except for forced ---------- outages and scheduled maintenance) during the period covered by the Purchase Agreement from the Customer's facilities with an expected or demonstrated reliability which is greater than or equal to the average reliability of the Company's firm power sources. 6. Net Energy - The total kilowatthours (kWh's) sold to the Customer by the ---------- Company less the total kWh's purchased by the Company from the Customer's QF. "Net energy" applies only to those QF's operating in the simultaneous buy/sell mode. 7. Time Periods - Mountain Standard Time shall be used in the application of ------------ this rate schedule. Because of potential differences of the timing devices, there may be a variation of up to 15 minutes in timing for the pricing periods. TERMS AND CONDITIONS - -------------------- Subject to Company's Schedule No. 2, "Terms and Conditions for Energy Purchases from Qualified Cogeneration or Small Power Production Facilities", or as it may be amended or modified from time to time by any supplemental or special Terms and Conditions pursuant to Customer's Purchase Agreement with the Company. METERING CONFIGURATIONS & OPTIONS FOR SOLAR/PHOTOVOLTAIC QF APPLICATIONS 10 KW OR LESS (Simultaneous Buy/Sell Mode) [GRAPHIC OMITTED] [The omitted material is a diagram of the QF's generator which has meter 1 of what is sold into the Company. The Company's line goes through meter 2 selling to QF's load.]
METERING OPTIONS - -------------------------------------------------------------------------------- Type of Meter Type of Meter (Meter 1) (Meter 2) ---------- ----------- Qualifying Facilities Utilizing Solar/Photovoltaic - -------------------------------------------------- Technology 10 kW or less: - ------------------------ f on an Energy Only (kWh) Type Rate* TOU(a) kWh(b) f on a Time-of-Use Type Rate* TOU(c) TOU(d)
* Refers to the Customer's otherwise applicable standard retail rate for firm purchases from the Company. (a) A Time-of-use (TOU) meter that registers kWh's only during peak and off-peak periods as specified in the "Monthly Purchase Rate" section of this rate schedule. (b) A non-timed watthour meter that registers kWh's only. (c) A TOU meter that registers kWh's only during peak and off-peak periods concurrent with those periods used in measuring energy for billing purposes by Meter 2. (d) As per applicable rate schedule. NOTE: APS shall be responsible for providing all required meters for the Simultaneous Buy/Sell Mode under the EPR-3 Metering Configuration. METERING CONFIGURATIONS & OPTIONS FOR SOLAR/PHOTOVOLTAIC QF APPLICATIONS 10 KW OR LESS (Parallel Mode of Operation) [GRAPHIC OMITTED] [The omitted material is a diagram of two meters which are set between the Company and QF's generator and load. Meter 1 registers sales by the Company and meter 2 represents sales to the Company.]
METERING OPTIONS - -------------------------------------------------------------------------------- Type of Meter Type of Meter (Meter 1) (Meter 2) ---------- ----------- Qualifying Facilities Utilizing Solar/Photovoltaic - -------------------------------------------------- Technology 10 kW or less: - ------------------------ If on an Energy Only (kWh) Type Rate* kWh(a) TOU(b) If on a Time-of-Use Type Rate* TOU(c) TOU(d)
*Refers to the Customer's otherwise applicable standard retail rate for firm purchases from the Company. (a) A non-timed watthour meter that registers kWh's only. (b) A Time-of-use (TOU) meter that registers kWh's only during peak and off-peak periods as specified in the "Monthly Purchase Rate" section of this rate schedule. (c) As per applicable rate schedule. NOTE: APS shall be responsible for providing all required meters for the parallel mode of operation under the EPR-3 Metering Configuration. ELECTRIC RATES -------------- ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5188 Phoenix, Arizona Tariff or Schedule No. EPR-4 Filed by: Gary J. Volkenant Original Filing Title: Director, Business Financial Services Effective: Original Effective Date: PURCHASE RATES FOR QUALIFIED SMALL POWER PRODUCTION FACILITIES 10 KW OR LESS ---------------------------------------------------------------------------- UTILIZING RENEWABLE RESOURCE TECHNOLOGIES ----------------------------------------- THAT RECEIVE PARTIAL REQUIREMENTS ELECTRIC SERVICE -------------------------------------------------- AVAILABILITY - ------------ In all territory served by Company. APPLICATION - ------------ To all small power production facilities with a nameplate rating of 10 kW or less utilizing renewable resource technologies where the customer's generator(s) and load are located at the same premise and meet qualifying status pursuant to the Arizona Corporation Commission's Decision No. 52345 on cogeneration and small power production facilities. Applicable only to qualifying facilities (QF's) electing to configure their systems as to require only partial requirements or interruptible service from the Company in order to meet their electric requirements. TYPE OF SERVICE - --------------- Electric sales to the Company must be single phase, 60 Hertz, at one standard voltage as may be selected by customer (subject to availability at the premises). The qualifying facility will have the option to sell energy to the Company at a voltage level different than that for purchases from the Company; however, the Customer will be responsible for all incremental costs incurred by APS to accommodate such an arrangement. PAYMENT FOR PURCHASES FROM AND SALES TO THE CUSTOMER - ---------------------------------------------------- Power sales and special services supplied by the Company to the Customer in order to meet its supplemental or interruptible electric requirements will be priced at the applicable retail rate or rates. The Company will pay the Customer for any energy purchased as calculated on the standard purchase rate (see below). MONTHLY PURCHASE RATE - --------------------- Rate for pricing of energy, net of that for the customer's own use, that is delivered to the Company: Cents per kWh -------------------------------------------------- Non-Firm Power Firm Power ------------------------ ----------------------- On-Peak(1) Off-Peak(2) On-Peak(1) Off-Peak(2) ---------- ----------- ---------- ----------- Summer Billing Cycles 1.58 1.17 2.20 1.52 (June - October) Winter Billing Cycles 1.25 1.08 1.74 1.38 (November - May) (1) On-Peak Periods: 9 a.m. to 9 p.m., weekdays (2) Off-Peak Periods: All other hours These rates are based on the Company's estimated avoided energy costs and will be updated annually to reflect changes in the Company's fuel costs. CONTRACT PERIOD - --------------- As provided for in the Purchase Agreement. DEFINITIONS - ----------- 1. Partial Requirements Service - A QF's system configuration whereby the ------------------------------ output from its electric generator(s) first go to supply its own electric requirements with any excess energy (over and above its own requirements at the time) then being sold to the Company. The Company supplies the Customer's supplemental electric requirements (those not met by the QF's own-generation facilities). This also may be referred to as the "parallel mode" of operation. 2. Special Service(s) - The electric service(s) specified in this section ------------------- that will be provided by the Company in addition to or in lieu of normal service(s). * Interruptible Power - Electric energy or capacity supplied by the -------------------- Company subject to interruption by the Company under specified conditions and under agreed upon lead time requirements (Non-Firm Power). 3. Non-Firm Power - Electric power which is supplied by the power producer at -------------- the producer's option, where no firm guarantee is provided, and the power can be interrupted by the power producer at any time. 4. Firm Power - Power available, upon demand, at all times (except for forced ---------- outages and scheduled maintenance) during the period covered by the Purchase Agreement from the Customer's facilities with an expected or demonstrated reliability which is greater than or equal to the average reliability of the Company's firm power sources. 5. Time Periods - Mountain Standard Time shall be used in the application of ------------ this rate schedule. Because of potential differences of the timing devices, there may be a variation of up to 15 minutes in timing for the pricing periods. TERMS AND CONDITIONS - -------------------- Subject to Company's Schedule No. 2, "Terms and Conditions for Energy Purchases from Qualified Cogeneration or Small Power Production Facilities", or as it may be amended or modified from time to time by any supplemental or special Terms and Conditions pursuant to Customer's Purchase Agreement with the Company. METERING CONFIGURATION - ---------------------- [GRAPHIC OMITTED] [The omitted material is a diagram of a bidirectional meter which reads energy flows from the Company into the customer for the customer's QF's load and also reads the QF's generator's excess supply sold back to the Company.] Attachment 8 ------------ Points of Agreement RESTRUCTURING ELEMENT Staff has commenced an investigation into electric industry restructuring in Docket No. U-0000-94-165. A Working Group and Task Forces were established to obtain information on possible options, implementation of those options, and some of the advantages and disadvantages of those options. A progress report was issued on October 5, 1995 (Report of the Working Group on Retail Electric Competition). APS has actively participated in all the Working Group efforts. These points of agreement pertain to procedures and outcomes in Docket No. U-0000-94-165 regarding electric industry restructuring. The parties recognize that the Commission may also consider other procedural issues and outcomes. These points of agreement do not commit either APS or the Staff to assert any particular position on the issues identified in Paragraph 5 of Procedural Matters, below, nor do they commit the Commission to resolve any issue in any particular manner or in any particular time frame or sequence. In addition, these points of agreement do not preclude APS, the Staff, or any other participant in Docket No. U-0000-94-165 from raising other issues not identified in this document. Procedural Matters - ------------------ 1. The Commission's process for developing an information base and for considering electric industry restructuring shall continue to be a public process open to all interested parties. 2. In addition to hearings and litigation, a collaborative effort among some interested parties seeking common ground may help resolve some restructuring issues; APS and Staff agree to participate in and support collaborative efforts in good faith. 3. APS and Staff agree to foster resolution of issues in the restructuring Docket and in related activities. 4. Staff and APS agree that they shall urge the Commission to consider the following issues as the Commission develops its policies regarding restructuring, recognizing that other issues may also be raised: a. The legal nature of electric public service corporations' service rights and responsibilities. b. Electric public service corporations' obligations to serve in a restructured environment. c. Compensation for restructuring, taking into account, among other matters: the estimated magnitude of stranded investment; the magnitude of offsetting increases in the market value of assets such as transmission or distribution assets; mitigation of stranded investment; allocation of stranded investment among utilities, consumers in competitive markets, and consumers in noncompetitive markets; collection mechanisms; the period over which stranded investment is collected; and the impacts of alternative compensation approaches on public service corporations, lenders, shareholders, and consumers over the long run. d. Clarification of federal-state jurisdictional uncertainties and possible activities in other forums, including the Legislature and FERC, to help resolve those uncertainties. e. Commission jurisdiction over market entrants (including independent power producers, utilities, and others) and uniformity of regulation of market entrants. f. Maintenance of generation, transmission, and distribution system reliability, including mechanisms and responsibility for services related to reliability. g. Concerns of public power entities over which the Commission does not have jurisdiction regarding restructuring. h. Access by Arizona electric public service corporations to consumers located in other service territories and the terms for access by others to the customers of Arizona public service corporations. i. Whether some or all consumers should be able to access generation in a competitive marketplace, and, if applicable, the pace of introducing competition, including phasing in of competition. j. Market structure, including whether and how to require or induce utility divestiture into generation, transmission, distribution, or other companies. k. Generation structure, including the proper roles of bilateral contracting and pooling of generation. l. Encouragement of energy efficiency through demand side management and other techniques, including competitively neutral allocation of the costs of demand side management programs not borne by participants. m. Encouragement of renewable energy resources through various techniques, such as renewables portfolio requirements, in a manner which does not put some suppliers of electricity to Arizona consumers in a relatively less competitive situation than other suppliers. n. Encouragement of environmental protection in a manner which does not put some suppliers of electricity to Arizona consumers in a relatively less competitive situation than other suppliers. o. Coordination of restructuring with the public interest in integrated resource planning. p. The proper form of regulation for noncompetitive markets in generation and distribution. q. The effect of the market power of existing public service corporations on the development of competitive generation markets, and ways to reduce any impediments to competition. r. The affordability of electric service, especially for low income consumer and consumers in rural areas. s. Limitations on the ability of cooperatives to sell electricity or transmission service to non-members. t. Transaction costs of participation in competitive markets. u. Impacts of restructuring on employment and other economic factors. v. Utility tax structure and its impact on Arizona customers and companies. Outcomes - -------- 1. The results of restructuring should reflect a deliberate process which considers the economic, financial, operational and system planning effects of such restructuring. 2. Restructuring of the electric industry should result in increased efficiency in electric markets, with nondiscriminatory access to transmission and distribution facilities and services. 3. All major customer groups should benefit from competition, including residential customers. 4. Special needs programs, such as lifeline programs, should be continued. 5. Transaction costs of participating in competitive markets and consumer confusion should be minimized. 6. Fair dispute resolution process should be available. 7. The supply of electricity should be reliable over the long term, of adequate quality for consumers, and safe. 8. The investment environment should be conducive to raising capital necessary to provide long-term electric energy services. 9. The electric industry should: * actively seek to protect the natural environment; * promote renewable generating resources to manage uncertainty, control costs, and meet consumer needs over the long run; * encourage efficiency in the use of electric energy, including cost effective demand side management; and * maintain a long term planning perspective. Expectations - ------------ Staff and APS recognize that there is a diversity of opinion on many matters. Staff and APS agree that the Commission should be requested to consider all the procedural and outcome issues listed above in developing its policies on restructuring. The Commission may use hearings and other mechanisms (such as collaborative approaches) to achieve resolution of the issues. Staff and APS agree that the market and political environments may evolve rapidly and that timetables for introducing restructuring cannot be rigidly set a priori. ATTACHMENT 9 ------------ APS POSITION ON ISSUES RAISED BY INDUSTRY RESTRUCTURING ------------------------------------------------------- The Points of Agreement to the restructuring element of the Plan, which are set forth in Attachment 8 to this Agreement, deal with the electric utility industry in Arizona. APS believes cooperative legislative and regulatory actions at both the state and federal levels will be necessary to permit broader access to the generation market by retail customers of regulated public service corporations in Arizona. The steps proposed herein are presented by the Company as a balanced, comprehensive package, each part of which is dependent on the others. APS will not be committed to support any particular part in the event one or more other parts are dropped or materially changed in the legislative or regulatory processes. It is the Company's firm position that these issues must be addressed and resolved prior to allowing open access in the retail markets of Arizona public service corporations. As APS has pointed out during the Commission's Docket on Competition In The Electric Utility Industry, a number of legislative, regulatory and market issues must be satisfactorily addressed for Arizona to benefit from the increased economic efficiency that competition potentially can produce. By its concurrence to the Points of Agreement in Attachment 8, Staff has likewise agreed to the importance of such issues. In addition, APS believes that the record should be clear as to its present position on industry restructuring. For consistency sake, the Company has divided its comments using the categorization of issues from Attachment 8. However, APS has retained its own descriptive titles when referring to specific issues. PROCEDURAL AND SUBSTANTIVE MATTERS Process for Considering Restructuring Issues As indicated by its concurrence in Attachment 8, APS agrees that industry restructuring should be debated and resolved in an open process after consideration of all points of view. The Commission's Docket No. U-0000-94-165 provides an appropriate forum for this process, although as noted above, both the Arizona Legislature and the U.S. Congress (in addition to FERC) will be important players in any comprehensive industry restructuring. Exclusive Service Rights In Arizona, electric public service corporations are granted statutorily established Certificates of Convenience and Necessity by the Commission. Under the State's concept of "regulated monopoly," these certificates confer an exclusive and perpetual right to serve all customers within a delineated territory as long as the utility provides or is ready and willing to provide reasonable service at Commission-regulated prices, sometimes referred to as the regulatory compact. This territorial right has been characterized by the Arizona Supreme Court as a "vested property right" protected by the Arizona Constitution that cannot be condemned or otherwise "taken" without payment of adequate compensation. If the issue of compensation is adequately addressed, APS will support legislation that allows the Commission to open, on a "phased" basis, heretofore exclusive electric service territories in Arizona to competition from all regulated electric public service corporations. Obligation To Serve In return for exclusive territorial rights, public service corporations are generally required to serve all customers requesting service (whether profitable or not) in accordance with rules and regulations established by the Commission. This obligation to serve is an essential part of the regulatory compact and has required Arizona's electric utilities to anticipate customer growth, demand and usage and prudently invest in generation, transmission, distribution, and other utility assets. Unlike an enterprise in a fully competitive market, Arizona's electric public service corporations cannot decide unilaterally which markets they wish to serve, set the terms for providing such service, or determine whether or not to expend the capital funds necessary to meet future demands. As customers gain access to other generation suppliers, this will require a symmetrical change in the obligation of incumbent suppliers so that the incumbent utility is not unfairly burdened with "provider-of-last-resort" status. A clear breach of the regulatory compact will occur if the obligation to serve (and associated cost burdens) remains on a particular utility, while its competitors are free to pick who, how, and when they wish to serve. Accordingly, APS will support appropriate modifications to service obligations of Arizona public service corporations that recognize increasing customer options (at least with respect to generation) while still preserving the availability of reliable and affordable service. Compensation Issues Arizona public service corporations have rightful constitutional and equitable claims for compensation relative to recovery of stranded investment, compensable property rights and wheeling charges; specifically, compensation is due for: (a) investments in assets prudently made, or commitments prudently incurred, by an Arizona public service corporation for the benefit of the customers in its service territory which becomes "stranded", i.e., non-recoverable, because of changes in the regulatory compact; (b) investments "stranded" because of accounting or other regulatory changes occurring in the transition from a regulated monopoly environment to a competitive market; (c) the loss of constitutionally protected property rights in an exclusive service territory conferred by the Commission pursuant to statute, both when the exclusiveness of such service rights is phased out as to a particular customer class and when the loss occurs as to a particular customer; (d) wheeling services by an incumbent public service corporation for dedicating a portion of its "wires" capacity and ancillary services to accommodate a competitor's access to one or more retail customers within the incumbent's service territory, which compensation should reflect appropriate charges fully compensating the incumbent public service corporation for such service, regardless of whether such charges are regulated by FERC or the Commission. In the economic proposal of the Plan, APS will take an important step towards mitigating its "stranded" investment by accelerating the amortization of "regulatory assets" over an eight (8) year transition period. The "7(cent) Result" which represents the Company's goal to reduce its per kWh cost by a combination of aggressive cost containment and the development of new marketing opportunities, is another example of how APS hopes to mitigate the compensable damages it will experience upon the implementation of retail competition. Federal-State Jurisdictional Uncertainties Electric power commerce across the state and region is impeded by the jurisdictional uncertainty over the conflicting scope of federal versus state regulation in the utility industry. Therefore, at the federal level, APS, in cooperation with the industry and others, will seek congressional legislation that clarifies the right of states to authorize retail access and related terms and conditions of service and to effectively regulate such transactions when necessary. The Company will also seek clarification, through legislation or by FERC actions, that will clear the jurisdictional haze between the reach of federal control over transmission in interstate commerce and a state's critical ability to regulate and set retail rates. Competitive Balance Efficient competition will occur when all players, including out-of-state suppliers entering the Arizona market, are subject to the same rights and responsibilities, free from market-distorting special privileges, regulations or unequal burdens. APS will propose that any market entrant allowed into a previously exclusive territory of a regulated electric public service corporation pursuant to the legislation previously discussed regarding "Exclusive Service Rights" must itself be, or become, a public service corporation subject to appropriate Commission regulatory oversight and related obligations, including plant and line siting requirements (which should be administered directly by the Commission) and shared responsibility for maintaining service reliability. Such entrants could include out-of-state utilities, power marketers, independent power producers and other competitors. Public Power Entities The Arizona Constitution expressly excludes municipal corporations from the category of entities (public service corporations) which it subjects to regulation by the Commission. Due among other things to the uncertainties that any amendment of the Constitution would entail, the Company proposes to exclude municipal, tribal or other government-owned utilities from this restructuring proposal. Where such utilities have lawfully-conferred rights to serve all customers within a delineated territory, those rights would remain intact (i.e., would not be subject to being "phased" out as proposed above with respect to public service corporations); conversely, such utilities, by virtue of their not being public service corporations subject to Commission regulatory oversight and related obligations, would not be allowed competitive access to public service corporation territories in Arizona. However, it appears to APS that changes in law and relationships at the federal level, such as entitlements to preferential power from federal facilities or federal income tax advantages, could lead to a common interest in eliminating or reducing differences among utilities at the state level, thereby occasioning future reexamination of the difference proposed in this paragraph. Reciprocal Trade Opportunities Efficient competition and the public interest require that public service corporations be allowed the reciprocal opportunity to trade in each other's markets. The willingness of APS to open its service territory to competitors is contingent upon APS obtaining meaningful reciprocity from such competitors and their regulators. The Company's desire to remove barriers to entry into other state and regional markets can only be achieved through Commission and State support and involvement. The Company will urge federal legislation that will explicitly recognize the ability of states to condition the entry of out-of-state power suppliers into Arizona upon on reciprocal opportunities for Arizona public service corporations in other states. Finally, APS will support amendments to federal laws, such as the Public Utility Holding Company Act, to remove artificial and unnecessary restraints on utilities that desire to compete in regional and national markets. Integrated Resource Planning APS continues to support efficiency in electric usage, environmental protection and the Commission's Integrated Resource Planning ("IRP") process. Although the IRP is solidly grounded in traditional regulatory principles, many of APS' potential competitors are exempt from the IRP process. APS will ask the Commission to revise, consistent with the changes proposed herein, the current IRP process to recognize the emergence of competition and the need to maintain generation reliability in a system with proliferating suppliers. APS will continue to support cost-effective DSM and renewables as long as competitively neutral funding mechanisms are established. Market Structure The Company is, of course, aware of proposals in other jurisdictions for mandatory pooling of generation and for separation of generation and "wires" through mandatory divestiture. APS believes mandatory pooling is another form of regulation, one which presumably would be beyond the bounds of Commission jurisdiction and which could well be more pervasive and onerous than current regulation and ultimately contrary to the interests of customers. APS believes that bilateral contracting (which could be tri-or-more lateral when aggregators and marketers are considered) will afford effective competition, particularly if and when facilitated by the emergence of an exchange mechanism such as the NY Mercantile Exchange. Mandatory divestiture in the Company's judgment contravenes two important principles, one of an engineering nature and the other economic. System reliability depends on both generation and wires--some entity will have to control both to assure an effective operating system. The economic perspective is that there seems to be a natural tendency toward vertical integration in analogous situations: United Kingdom electric companies; telecommunications (where APS interprets the recent AT&T announcement of separation of its manufacturing and service functions as a move toward re-integration of local and long-distance services and facilities). Such a tendency is not necessarily anti-competitive; in the case of telecommunications, the opposite is probably true. Additionally, mandatory divestiture could require a complete restructuring of contract rights under the Company's mortgage indenture and other financing instruments; furthermore, such divestiture would be extremely expensive to implement, and could result in significant economic dislocation among customers, bondholders and shareholders, with no proven customer benefit. The policy goal should be an efficiently functioning generation market, free from concentration of market power and from abuse of a monopoly asset (such as transmission). APS does not believe this goal is served by mandatory pooling (which may actually trend in the other direction), or that mandatory divestiture is the appropriate answer to the monopoly asset issue in view of the necessity for system reliability. The market power issue is difficult to address without knowing the size of the market, but that should come into view by 2000. By then there will have been considerable experience with wholesale wheeling by way of FERC standard setting and adversarial proceedings. APS considers it unlikely that any Arizona-based electric utility will have excessive dominion over the relevant market as defined in 2000, or that the Commission will then need to do anything more about any wire monopoly in the field than what FERC will have by then already done in the wholesale field. Phased Direct Retail Access Assuming that the economic proposal of the Plan is approved, and that the foregoing issues have by then been resolved, APS would request the Commission to authorize access by retail customers of public service corporations to the broad generation market starting in the year 2000. For its system, APS would propose that initial access would apply to retail transmission customers receiving power at 69 kv or above. If this proves successful, it would be expanded approximately two years later by allowing access for all customers whose loads are greater than 3 mW and, by 2004, access for customers with demand in excess of 1 mW. Access for all remaining customers would be proposed at the appropriate time. APS would expect that other Arizona public service corporations would propose comparable retail access provisions that provide meaningful competitive opportunities. Such retail access would not necessarily "deregulate" utility service or eliminate the Commission's ultimate responsibility to public service corporations and their customers; it would, however, require modifications of the manner in which that oversight role is performed. OUTCOMES APS would like to emphasize the first three (3) of the "Outcomes" listed in Attachment 8. It is critical that electric industry restructuring should be a careful and deliberative process that fully considers the economic, financial, operational, and system planning aspects of restructuring. This can be accomplished by addressing and resolving issues before rather than after or during the restructuring. The goal of any industry restructuring should be increased efficiency, and hence lower costs. Restructuring "benefits" based on preditory pricing, cost shifting, or shareholder losses are illusory. APS' proposals to address the compensation issues and create competitive balance are intended to further an outcome based on increased efficiency. Third, all major customer groups should be permitted to benefit from this increased efficiency. APS' proposals to maintain competitive balance, create reciprocal trade opportunities, and preserve the Commission's ability to effectively establish retail rates will help to make this preferred outcome more achievable. APS proposes that the Commission specifically address and resolve these and other related issues through a series of hearings during 1996 (as contemplated by the Commission Staff in its Competition Docket) which will seek to develop appropriate legislative and regulatory solutions to these barriers. These hearings would be held independent from the Commission's consideration of the Agreement described above. APS believes that Commission action, in consultation with interested parties, can produce a set of regulatory and legislative reforms that can be presented to the Arizona Legislature and to the U.S. Congress in 1997. However, APS recognizes that the foregoing issues are difficult ones, legally and politically, and that their resolution will require time, particularly at the federal level. -----END PRIVACY-ENHANCED MESSAGE-----