-----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, DiXD72hxrfOL7NPc0ER57b7b4DHV75var0c4hMfUh/ET4yQCevAfRssMlBfd0R/s i9si9rGaL1rPXY6Z1tAo0w== 0000950147-98-000636.txt : 19980817 0000950147-98-000636.hdr.sgml : 19980817 ACCESSION NUMBER: 0000950147-98-000636 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19980630 FILED AS OF DATE: 19980814 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: ARIZONA PUBLIC SERVICE CO CENTRAL INDEX KEY: 0000007286 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 860011170 STATE OF INCORPORATION: AZ FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-04473 FILM NUMBER: 98689365 BUSINESS ADDRESS: STREET 1: 400 N FIFTH ST STREET 2: P O BOX 53999 CITY: PHOENIX STATE: AZ ZIP: 85004 BUSINESS PHONE: 6022501000 10-Q 1 QUARTERLY REPORT F.T.Q.E. 6/30/98 FORM 10-Q Securities and Exchange Commission Washington, D.C. 20549 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 1998 ----------------------- OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number 1-4473 ARIZONA PUBLIC SERVICE COMPANY ------------------------------------------------------ (Exact name of registrant as specified in its charter) ARIZONA 86-0011170 - ------------------------------- ---------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona 85072-3999 - -------------------------------------------------------- ---------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (602) 250-1000 --------------------------------------------------- (Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Number of shares of common stock, $2.50 par value, outstanding as of August 14, 1998: 71,264,947 GLOSSARY ACC - Arizona Corporation Commission ACC Staff - Staff of the Arizona Corporation Commission Company - Arizona Public Service Company DOE - United States Department of Energy EITF - Emerging Issues Task Force EITF 97-4 - Emerging Issues Task Force Issue No. 97-4, "Deregulation of the Pricing of Electricity -- Issues Related to the Applications of FASB Statements No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101, Regulated Enterprises -- Accounting for the Discontinuation of Application of FASB Statement No. 71" EPA - United States Environmental Protection Agency FERC - Federal Energy Regulatory Commission ITC - Investment tax credit 1997 10-K - Arizona Public Service Company Annual Report on Form 10-K for the fiscal year ended December 31, 1997 Palo Verde - Palo Verde Nuclear Generating Station Pinnacle West - Pinnacle West Capital Corporation Power Coordination Agreement - 1955 agreement between the Company and Salt River Project that provides for certain electric system and power sales SFAS No. 71 - Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" SFAS No. 131 - Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information" SFAS No. 133 - Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" Salt River Project - Salt River Project Agricultural Improvement and Power District Territorial Agreement - 1955 agreement between the Company and Salt River Project that has provided exclusive retail service territories in Arizona as against each other -2- PART I - FINANCIAL INFORMATION ------------------------------ Item 1. Financial Statements - ---------------------------- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME ------------------------------ (Unaudited) Three Months Ended June 30, ---------------------- 1998 1997 --------- --------- (Thousands of Dollars) ELECTRIC OPERATING REVENUES .......................... $ 441,715 $ 458,751 --------- --------- FUEL EXPENSES: Fuel for electric generation ....................... 50,434 55,626 Purchased power .................................... 45,151 43,684 --------- --------- Total ........................................... 95,585 99,310 --------- --------- OPERATING REVENUES LESS FUEL EXPENSES ................ 346,130 359,441 --------- --------- OTHER OPERATING EXPENSES: Operations and maintenance excluding fuel expenses . 102,713 89,162 Depreciation and amortization ...................... 92,666 91,138 Income taxes ....................................... 39,933 49,579 Other taxes ........................................ 29,519 29,856 --------- --------- Total ........................................... 264,831 259,735 --------- --------- OPERATING INCOME ..................................... 81,299 99,706 --------- --------- OTHER INCOME (DEDUCTIONS): Other - net ........................................ (2,519) (910) Income taxes ....................................... 7,488 6,550 --------- --------- Total ........................................... 4,969 5,640 --------- --------- INCOME BEFORE INTEREST DEDUCTIONS .................... 86,268 105,346 --------- --------- INTEREST DEDUCTIONS: Interest on long-term debt ......................... 34,160 35,262 Interest on short-term borrowings .................. 2,376 3,095 Debt discount, premium and expense ................. 1,918 2,056 Capitalized interest ............................... (4,370) (4,560) --------- --------- Total ........................................... 34,084 35,853 --------- --------- NET INCOME ........................................... 52,184 69,493 PREFERRED STOCK DIVIDEND REQUIREMENTS ................ 2,435 3,195 --------- --------- EARNINGS FOR COMMON STOCK ............................ $ 49,749 $ 66,298 ========= ========= See Notes to Condensed Financial Statements. -3- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME ------------------------------ (Unaudited) Six Months Ended June 30, ---------------------- 1998 1997 --------- --------- (Thousands of Dollars) ELECTRIC OPERATING REVENUES .......................... $ 822,138 $ 837,772 --------- --------- FUEL EXPENSES: Fuel for electric generation ....................... 100,762 106,748 Purchased power .................................... 68,740 78,031 --------- --------- Total ........................................... 169,502 184,779 --------- --------- OPERATING REVENUES LESS FUEL EXPENSES ................ 652,636 652,993 --------- --------- OTHER OPERATING EXPENSES: Operations and maintenance excluding fuel expenses . 199,129 177,178 Depreciation and amortization ...................... 184,813 183,153 Income taxes ....................................... 64,397 71,871 Other taxes ........................................ 59,457 59,646 --------- --------- Total ........................................... 507,796 491,848 --------- --------- OPERATING INCOME ..................................... 144,840 161,145 --------- --------- OTHER INCOME (DEDUCTIONS): Other - net ........................................ (4,915) (3,119) Income taxes ....................................... 11,943 10,890 --------- --------- Total ........................................... 7,028 7,771 --------- --------- INCOME BEFORE INTEREST DEDUCTIONS .................... 151,868 168,916 --------- --------- INTEREST DEDUCTIONS: Interest on long-term debt ......................... 69,343 69,691 Interest on short-term borrowings .................. 3,060 5,423 Debt discount, premium and expense ................. 3,867 4,058 Capitalized interest ............................... (8,521) (8,394) --------- --------- Total ........................................... 67,749 70,778 --------- --------- NET INCOME ........................................... 84,119 98,138 PREFERRED STOCK DIVIDEND REQUIREMENTS ................ 5,313 6,821 --------- --------- EARNINGS FOR COMMON STOCK ............................ $ 78,806 $ 91,317 ========= ========= See Notes to Condensed Financial Statements -4- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME ------------------------------ (Unaudited) Twelve Months Ended June 30, -------------------------- 1998 1997 ----------- ----------- (Thousands of Dollars) ELECTRIC OPERATING REVENUES ..................... $ 1,862,919 $ 1,784,125 ----------- ----------- FUEL EXPENSES: Fuel for electric generation .................. 195,355 237,518 Purchased power ............................... 225,995 136,757 ----------- ----------- Total ...................................... 421,350 374,275 ----------- ----------- OPERATING REVENUES LESS FUEL EXPENSES ........... 1,441,569 1,409,850 ----------- ----------- OTHER OPERATING EXPENSES: Operations and maintenance excluding fuel expenses............................... 421,385 419,853 Depreciation and amortization ................. 367,331 363,182 Income taxes .................................. 177,263 169,361 Other taxes ................................... 120,070 111,601 ----------- ----------- Total ...................................... 1,086,049 1,063,997 ----------- ----------- OPERATING INCOME ................................ 355,520 345,853 ----------- ----------- OTHER INCOME (DEDUCTIONS): AFUDC - equity ................................ -- 1,531 Other - net ................................... (11,623) (15,621) Income taxes .................................. 32,466 41,253 ----------- ----------- Total ...................................... 20,843 27,163 ----------- ----------- INCOME BEFORE INTEREST DEDUCTIONS ............... 376,363 373,016 ----------- ----------- INTEREST DEDUCTIONS: Interest on long-term debt .................... 140,583 142,597 Interest on short-term borrowings ............. 7,041 9,245 Debt discount, premium and expense ............ 7,600 8,113 Capitalized interest .......................... (16,335) (12,502) ----------- ----------- Total ...................................... 138,889 147,453 ----------- ----------- NET INCOME ...................................... 237,474 225,563 PREFERRED STOCK DIVIDEND REQUIREMENTS ........... 11,295 15,110 ----------- ----------- EARNINGS FOR COMMON STOCK ....................... $ 226,179 $ 210,453 =========== =========== See Notes to Condensed Financial Statements. -5- ARIZONA PUBLIC SERVICE COMPANY CONDENSED BALANCE SHEETS ------------------------ ASSETS (Unaudited) June 30, December 31, 1998 1997 ----------- ----------- (Thousands of Dollars) UTILITY PLANT: Electric plant in service and held for future use $ 7,057,168 $ 7,009,059 Less accumulated depreciation and amortization ... 2,720,762 2,620,607 ----------- ----------- Total ......................................... 4,336,406 4,388,452 Construction work in progress .................... 294,978 237,492 Nuclear fuel, net of amortization ................ 51,165 51,624 ----------- ----------- Utility plant - net ........................... 4,682,549 4,677,568 ----------- ----------- INVESTMENTS AND OTHER ASSETS ..................... 180,393 164,906 ----------- ----------- CURRENT ASSETS: Cash and cash equivalents ........................ 14,192 12,552 Accounts receivable: Service customers ............................. 130,568 141,022 Other ......................................... 31,494 31,313 Allowance for doubtful accounts ............... (1,012) (1,338) Accrued utility revenues ......................... 66,922 58,559 Materials and supplies, at average cost .......... 71,207 70,634 Fossil fuel, at average cost ..................... 17,960 9,621 Deferred income taxes ............................ 3,496 3,496 Other ............................................ 29,824 24,529 ----------- ----------- Total current assets .......................... 364,651 350,388 ----------- ----------- DEFERRED DEBITS: Regulatory asset for income taxes ................ 430,601 458,369 Rate synchronization cost deferral ............... 331,265 358,871 Unamortized costs of reacquired debt ............. 59,088 63,501 Unamortized debt issue costs ..................... 15,294 15,303 Other ............................................ 231,163 242,236 ----------- ----------- Total deferred debits ......................... 1,067,411 1,138,280 ----------- ----------- TOTAL ......................................... $ 6,295,004 $ 6,331,142 =========== =========== See Notes to Condensed Financial Statements. -6- ARIZONA PUBLIC SERVICE COMPANY CONDENSED BALANCE SHEETS ------------------------ LIABILITIES (Unaudited) June 30, December 31, 1998 1997 ------------ ------------ (Thousands of Dollars) CAPITALIZATION: Common stock .................................... $ 178,162 $ 178,162 Additional paid-in capital ...................... 1,143,586 1,142,364 Retained earnings ............................... 479,690 528,798 ------------ ------------ Common stock equity .......................... 1,801,438 1,849,324 Non-redeemable preferred stock .................. 124,034 142,051 Redeemable preferred stock ...................... 15,377 29,110 Long-term debt less current maturities .......... 1,861,783 1,953,162 ------------ ------------ Total capitalization ......................... 3,802,632 3,973,647 ------------ ------------ CURRENT LIABILITIES: Commercial paper ................................ 213,485 130,750 Current maturities of long-term debt ............ 154,220 104,068 Accounts payable ................................ 98,480 107,423 Accrued taxes ................................... 78,451 85,886 Accrued interest ................................ 31,743 31,660 Common dividends payable ........................ 42,500 -- Customer deposits ............................... 29,298 29,116 Other ........................................... 23,657 19,588 ------------ ------------ Total current liabilities .................... 671,834 508,491 ------------ ------------ DEFERRED CREDITS AND OTHER: Deferred income taxes ........................... 1,324,121 1,345,177 Deferred investment tax credit .................. 50,142 60,093 Unamortized gain - sale of utility plant ........ 80,075 82,363 Customer advances for construction .............. 29,920 29,294 Other ........................................... 336,280 332,077 ------------ ------------ Total deferred credits and other ............. 1,820,538 1,849,004 ------------ ------------ COMMITMENTS AND CONTINGENCIES (Notes 5, 8, and 9) TOTAL ........................................ $ 6,295,004 $ 6,331,142 ============ ============ See Notes to Condensed Financial Statements. -7- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF CASH FLOWS ---------------------------------- (Unaudited) Six Months Ended June 30, ---------------------- 1998 1997 --------- --------- (Thousands of Dollars) Cash Flows from Operating Activities: Net income ......................................... $ 84,119 $ 98,138 Items not requiring cash: Depreciation and amortization .................... 184,813 183,153 Nuclear fuel amortization ........................ 16,580 16,186 Deferred income taxes - net ...................... (18,428) (25,107) Deferred investment tax credit - net ............. (9,951) (9,926) Changes in certain current assets and liabilities: Accounts receivable - net ........................ 9,947 (6,092) Accrued utility revenues ......................... (8,363) (14,047) Materials, supplies and fossil fuel .............. (8,912) 1,153 Other current assets ............................. (5,295) (6,964) Accounts payable ................................. (10,279) (37,099) Accrued taxes .................................... (7,435) 8,163 Accrued interest ................................. 83 (6,898) Other current liabilities ........................ 2,922 2,826 Other - net ........................................ 10,267 34,120 --------- --------- Net cash flow provided by operating activities ....... 240,068 237,606 --------- --------- Cash Flows from Investing Activities: Capital expenditures ............................... (144,580) (145,203) Capitalized interest ............................... (8,521) (8,394) Other .............................................. (3,347) (12,577) --------- --------- Net cash flow used for investing activities .... (156,448) (166,174) --------- --------- Cash Flows from Financing Activities: Long-term debt ..................................... 99,375 99,875 Short-term borrowings - net ........................ 82,735 181,100 Dividends paid on common stock ..................... (85,000) (85,000) Dividends paid on preferred stock .................. (5,631) (7,345) Repayment of preferred stock ....................... (31,209) (46,044) Repayment and reacquisition of long-term debt ...... (142,250) (219,192) --------- --------- Net cash flow used for financing activities .... (81,980) (76,606) --------- --------- Net increase (decrease) in cash and cash equivalents . 1,640 (5,174) Cash and cash equivalents at beginning of period ..... 12,552 12,521 --------- --------- Cash and cash equivalents at end of period ........... $ 14,192 $ 7,347 ========= ========= Supplemental Disclosure of Cash Flow Information: Cash paid during the period for: Interest (excluding capitalized interest) ........ $ 63,960 $ 74,291 Income taxes ..................................... $ 86,397 $ 84,432 See Notes to Condensed Financial Statements. -8- ARIZONA PUBLIC SERVICE COMPANY NOTES TO CONDENSED FINANCIAL STATEMENTS 1. In the opinion of the Company, the accompanying unaudited condensed financial statements contain all adjustments (consisting of normal recurring accruals) necessary to present fairly the financial position of the Company as of June 30, 1998, the results of operations for the three months, six months and twelve months ended June 30, 1998 and 1997, and the cash flows for the six months ended June 30, 1998 and 1997. It is suggested that these condensed financial statements and notes to condensed financial statements be read in conjunction with the financial statements and notes to financial statements included in the 1997 10-K. Certain prior year balances have been restated to conform to the current year presentation. 2. The Company's operations are subject to seasonal fluctuations, with variations in energy usage by customers occurring from season to season and from month to month within a season, primarily as a result of changing weather conditions. For this and other reasons, the results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. 3. All the outstanding shares of common stock of the Company are owned by Pinnacle West. 4. See "Liquidity and Capital Resources" in Part I, Item 2 of this report for changes in capitalization for the six months ended June 30, 1998. 5. Regulatory Matters -- Electric Industry Restructuring State ACC Rules. In December 1996, the ACC adopted rules that provide a framework for the introduction of retail electric competition in Arizona. On August 5, 1998, the ACC adopted amendments to the rules. The ACC rules, as amended, include the following major provisions: + The rules apply to virtually all of the Arizona electric utilities regulated by the ACC, including the Company. + The rules require each affected utility, including the Company, to make available at least 20% of its 1995 system retail peak demand for competitive generation supply to all customer classes beginning January 1, 1999, and 100% beginning January 1, 2001. + All affected utility customers with single premise loads of one megawatt or greater will be eligible for competitive electric services beginning January 1, 1999, until the 20% level described in the preceding paragraph is met. Until the -9- 20% level is met, affected utility customers with single premise loads of forty kilowatts or greater will be able to aggregate into a combined load of one megawatt or greater to be eligible for competitive electric services beginning January 1, 1999. + Prior to January 1, 2001, residential customers will have access to competitive services through a quarterly phase-in of one-half percent of residential customers per quarter beginning January 1, 1999. + Electric service providers that obtain Certificates of Convenience and Necessity (CC&Ns) from the ACC will be allowed to supply, market, and/or broker specified electric services at retail. These services include electric generation, but exclude electric transmission and distribution. + As required by the rules, in February 1998 the Company filed with the ACC proposed tariffs for unbundled service (electric service elements provided and priced separately). The ACC has not issued a decision in this matter. + The rules establish that the ACC shall allow a reasonable opportunity for the recovery of unmitigated stranded costs. See "Stranded Costs" below. Affected utilities are expected to take reasonable, cost-effective steps to mitigate stranded costs. + Absent a waiver from the ACC, each affected utility must separate itself from all competitive generation assets and services prior to January 1, 2001. The separation must be either to an unaffiliated party or to a separate corporate affiliate or affiliates. + Beginning January 1, 1999, each affected utility will be prohibited from providing certain competitive electric services, except through a separate affiliate. + The rules contain affiliate transaction rules generally prohibiting an affected utility and its competitive electric affiliates from sharing personnel, office space, equipment, services, and systems, except to the extent appropriate to perform certain permissible shared corporate support functions. No later than December 31, 1998, each affected utility must file a compliance plan with the ACC demonstrating its compliance with the affiliate transaction rules. + By September 15, 1998, each affected utility must file a report detailing possible mechanisms to provide benefits, such as rate reductions of 3% to 5%, to all standard offer customers and a proposed plan for residential phase-in implementation. The amended rules, a copy of which has been filed as an exhibit to this Report on Form 10-Q, became effective on an emergency basis upon their filing with the Secretary of State on August 10, 1998; however, the ACC must complete a public process to adopt -10- the rules on a permanent basis within 180 days. The Company anticipates the completion of this process by year-end 1998 or early 1999. The Company believes that certain provisions of the ACC rules are deficient. In February 1997, a lawsuit was filed by the Company to protect its legal rights regarding those rules. That lawsuit is pending but two related cases filed by other utilities have been partially decided in a manner adverse to those utilities' positions. Stranded Costs. In February 1998, the ACC completed a formal, generic hearing on stranded cost determination and recovery. On June 22, 1998, the ACC issued an order in this matter. The order allows an affected utility, such as the Company, to choose between two options for the recovery of its stranded costs. Under the first option, an affected utility that chooses to divest its generating assets to an unaffiliated party must file a divestiture plan for ACC approval no later than October 1, 1998, and such divestiture must be completed by January 1, 2001, after which the affected utility would be permitted to collect 100 percent of its stranded costs, including a return on the unamortized balance, over a ten-year period. Under the second option (referred to by the ACC as the "Transition Revenues Methodology"), an affected utility would be provided sufficient revenues necessary to maintain financial integrity for a period of ten years or the ACC would "otherwise provide an allocation of stranded cost responsibilities and risks between ratepayers and shareholders as is determined to be in the public interest." The order also states an intent that the various recovery options "will provide the affected utilities sufficient revenues to enable them to recover appropriate regulatory assets." The order requires each affected utility to file with the ACC, on or before August 21, 1998, its choice of options for stranded cost recovery as well as an implementation plan relating to its chosen option, including its estimated stranded costs separated out into regulatory assets and other generation related assets. Stranded costs estimates vary depending on various assumptions, estimates, methodologies and measurement periods. Based on various assumptions, estimates and methodologies, the Company has previously estimated that its recoverable stranded costs (excluding regulatory assets which have already been addressed in the 1996 regulatory agreement with the ACC) would be less than $500 million, assuming a measurement period 2001 through 2006. The Company intends to use the Transition Revenues Methodology and does not intend to divest its generating assets to an unaffiliated party. The Company cannot accurately predict the outcome of this matter. Legislative Initiatives. An Arizona joint legislative committee studied electric utility industry restructuring issues in 1996 and 1997. In conjunction with that study, Arizona legislative counsel prepared memoranda in late 1997 related to the legal authority of the ACC to deregulate the Arizona electric utility industry. The memoranda raise a question as to the degree to which the ACC may, under the Arizona Constitution, deregulate any portion of the electric utility industry and allow rates to be determined by market forces. This latter issue (the ability of the ACC to set rates based on the competitive market) has been subsequently decided in favor of the ACC in one -11- unrelated and two related lawsuits. In May 1998, a bill was enacted to facilitate implementation of retail electric competition in the state. The bill includes the following major provisions: (a) requirements that Arizona's largest government-operated electric utility (Salt River Project) and, at their option, smaller city electric systems (i) open their service territories to electric service providers to implement retail electric generation competition for 20% of each utility's 1995 retail peak demand by December 31, 1998 and for all retail customers by December 31, 2000; (ii) decrease rates by at least 10% over a ten-year period beginning as early as January 1, 1991; (iii) implement procedures and public processes, including judicial review at the request of either an interested party or the Arizona Attorney General, for establishing the terms, conditions and pricing of electric services as well as certain other decisions affecting retail electric competition, which procedures and processes are comparable to those already applicable to public service corporations; (b) a description of the factors which form the basis of consideration by Salt River Project in determining stranded costs; and (c) a requirement that metering and meter reading services be provided on a competitive basis during the first two years of competition only for customers having demands in excess of one megawatt (and that are eligible for competitive generation services), and thereafter for all customers receiving competitive electric generation. In addition, the Arizona legislature will review and make recommendations for the 1999 legislature on certain competitive issues. Federal The Energy Policy Act of 1992 and recent rulemakings by FERC have promoted increased competition in the wholesale electric power markets. The Company does not expect these rules to have a material impact on its financial statements. Several electric utility reform bills have been introduced during recent congressional sessions, which as currently written, would allow consumers to choose their electricity suppliers by 2000 or 2003. These bills, other bills that are expected to be introduced, and ongoing discussions at the federal level suggest a wide range of opinion that will need to be narrowed before any substantial restructuring of the electric utility industry can occur. Regulatory Accounting The Company prepares its financial statements in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements. The Company's existing regulatory orders and current regulatory environment support its accounting practices related to regulatory assets, which amounted to approximately $0.9 billion at June 30, 1998. In accordance with the 1996 regulatory agreement, the ACC accelerated the amortization of substantially all of the Company's regulatory assets to an eight-year period that began July 1, 1996. -12- During 1997, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) issued EITF 97-4, which requires that SFAS No. 71 be discontinued no later than when legislation is passed or a rate order is issued that contains sufficient detail to determine its effect on the portion of the business being deregulated, which could result in write-downs or write-offs of physical and/or regulatory assets. Additionally, the EITF determined that regulatory assets should not be written off if they are to be recovered from a portion of the entity which continues to apply SFAS No. 71. Although the ACC has issued rules for transitioning generation services to competition, there are many unresolved issues. The Company continues to apply SFAS No. 71 to all of its operations. If rate recovery of regulatory assets is no longer probable, whether due to competition or regulatory action, the Company would be required to write off the remaining balance as an extraordinary charge to expense. General Changes in ACC decisions, Arizona and federal legislation, and possible amendments to the Arizona Constitution may impact the implementation of retail electric competition in Arizona. Until the details of implementation of competition, including addressing stranded costs, are determined, the Company cannot accurately predict the impact of full retail competition on its financial position, cash flows or results of operation. As competition in the electric industry continues to evolve, the Company will continue to evaluate strategies and alternatives that will position the Company to compete in the new regulatory environment. 6. Regulatory Matters -- 1996 Regulatory Agreement In April 1996, the ACC approved a regulatory agreement between the Company and the ACC Staff. The major provisions of this agreement are: + An annual rate reduction of approximately $48.5 million ($29 million after income taxes), or 3.4% on average for all customers except certain contract customers, effective July 1, 1996. + Recovery of substantially all of the Company's present regulatory assets through accelerated amortization over an eight-year period that began July 1, 1996, increasing annual amortization by approximately $120 million ($72 million after income taxes). + A formula for sharing future cost savings between customers and shareholders (price reduction formula) referencing a return on equity (as defined) of 11.25%. -13- + A moratorium on filing for permanent rate changes prior to July 2, 1999, except under the price reduction formula and under certain other limited circumstances. + Infusion of $200 million of common equity into the Company by Pinnacle West, in annual payments of $50 million starting in 1996. Pursuant to the price reduction formula, in May 1997, the ACC approved a retail price decrease of approximately $17.6 million ($10.5 million after income taxes), or 1.2%, effective July 1, 1997. In March 1998, the Company filed with the ACC its calculation of an annual price reduction of approximately $17 million ($10 million after income taxes), or 1.1%, to become effective July 1, 1998. The amount and timing of the price decrease are subject to ACC approval. 7. Agreement with Salt River Project On April 25, 1998, the Company and Salt River Project entered into a Memorandum of Agreement in anticipation of, and to facilitate, the opening of the Arizona electric industry. The Agreement contains the following major components: + The Company and Salt River Project would amend the Territorial Agreement to remove any barriers to the provision of competitive electricity supply and non-distribution services. + The Company and Salt River Project would amend the Power Coordination Agreement to lower the price that the Company will pay Salt River Project for purchased power by approximately $17 million (pretax) in 1999 and by lesser annual amounts through 2006. + The Company and Salt River Project agreed on certain legislative positions regarding electric utility restructuring at the state and federal level. An ACC docket had previously been established and the ACC held a hearing on August 6, 1998 so that the ACC could review certain provisions of the Memorandum of Agreement, as amended, including, whether: (a) the Territorial Agreement remains in the public interest, (b) the Agreement is a contract in restraint of trade, and (c) the Agreement will materially lessen the potential for retail electric competition in Arizona. The Antitrust Unit of the Arizona Attorney General's Office, which has been involved in the ongoing regulatory and legislative proceedings regarding the restructuring of the Arizona electric industry, requested clarification of the operation of certain of the Agreement's provisions. Pursuant to an Addendum to Memorandum of Agreement, dated as of May 19, 1998 (the "Addendum"), the Company and Salt River Project amended and clarified certain provisions of the Memorandum of Agreement in response to certain issues raised by the Antitrust Unit. By letter dated May 19, 1998, the Antitrust Unit advised the Company and Salt River Project that, upon their execution of the Addendum, it would take no action regarding the language of the -14- Memorandum of Agreement, although it reserved the right to take action in the future if new information justified doing so. 8. The Palo Verde participants have insurance for public liability payments resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $200 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, the Company could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $88 million, subject to an annual limit of $10 million per incident. Based upon the Company's 29.1% interest in the three Palo Verde units, the Company's maximum potential assessment per incident is approximately $77 million, with an annual payment limitation of approximately $9 million. The Palo Verde participants maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. The Company has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions. 9. The Company has encountered tube cracking in the Palo Verde steam generators and has taken, and will continue to take, remedial actions that it believes have slowed the rate of tube degradation. The projected service life of the steam generators is reassessed periodically and these analyses indicate that it will be economically desirable for the Company to replace the Unit 2 steam generators between 2003 and 2008. The Company estimates that its share of the replacement costs (in 1998 dollars) will be approximately $50 million, most of which will be incurred after the year 2000. During the fourth quarter of 1997, the Palo Verde participants, including the Company, entered into a contract for the fabrication of two replacement steam generators. The cost to the Company is estimated at approximately $26 million. These generators will be used as replacements if performance of existing generators deteriorates to less than acceptable levels. The generators are expected on site in 2002. The Company's share of installation costs is approximately $24 million. Based on the latest available data, the Company estimates that the Unit 1 and Unit 3 steam generators should operate for the license periods (until 2025 and 2027, respectively), although the Company will continue its normal periodic assessment of these steam generators. 10. The Financial Accounting Standards Board issued SFAS No. 131 on "Disclosures about Segments of an Enterprise and Related Information" which is effective for fiscal years beginning after December 15, 1997. SFAS No. 131 requires that public companies report certain information about operating segments in their financial statements. It also establishes related disclosures about products and services, geographic areas, and -15- major customers. The Company is currently evaluating what impact this standard will have on its disclosures. In June 1998 the Financial Accounting Standards Board issued SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities," which is effective for the Company in 2000. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value. The standard also provides specific guidance for accounting for derivatives designated as hedging instruments. The Company is currently evaluating what impact this standard will have on its financial statements. -16- ARIZONA PUBLIC SERVICE COMPANY Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations. Operating Results The following table summarizes the Company's revenues and earnings for the three-month, six-month and twelve-month periods ended June 30, 1998 and 1997: Periods ended June 30 (Unaudited) (Thousands of Dollars)
Three Months Six Months Twelve Months ------------------- ------------------ ----------------------- 1998 1997 1998 1997 1998 1997 Operating Revenues $441,715 $458,751 $822,138 $837,772 $1,862,919 $1,784,125 Earnings for Common Stock $ 49,749 $ 66,298 $ 78,806 $ 91,317 $ 226,179 $ 210,453
Operating Results - Three-month period ended June 30, 1998 compared with three-month period ended June 30, 1997 Earnings decreased $17 million in the three-month comparison primarily because of the effects of weather, increased operations and maintenance expenses, and a retail price reduction, partially offset by customer growth and lower fuel expenses. See Note 6 of Notes to Condensed Financial Statements for information on the price reduction. Operating revenues decreased $17 million because of weather effects ($41 million) and the price reduction ($4 million), partially offset by the effects of customer growth ($17 million), increased sales for resale ($8 million) and other ($3 million). Sales for resale are wholesale electricity sales to third parties who resell the electricity to their customers. The increase in sales for resale was a result of changes in power marketing activity, which can vary from period to period without corresponding effects on earnings because of related fluctuations in purchased power costs. Operations and maintenance expenses increased $14 million as a result of the timing of scheduled outages at power plants and other miscellaneous expenses. Fuel expenses decreased $4 million primarily because of lower fuel prices and lower retail sales, partially offset by higher sales for resale. -17- Operating Results - Six-month period ended June 30, 1998 compared with six-month period ended June 30, 1997 Earnings decreased $13 million in the six-month comparison primarily because of the effects of weather, increased operations and maintenance expenses, and a retail price reduction, partially offset by customer growth and lower fuel expenses. See Note 6 of Notes to Condensed Financial Statements for additional information about the price reduction. Operating revenues decreased $16 million because of weather effects ($38 million) and the price reduction ($8 million), partially offset by the effects of customer growth ($29 million). Operations and maintenance expenses increased $22 million as a result of growth and increased expenses due to impending competition, the timing of scheduled outages at power plants and other miscellaneous factors. Fuel expenses decreased $15 million primarily because of lower prices and a more favorable mix. Operating Results - Twelve-month period ended June 30, 1998 compared with twelve-month period ended June 30, 1997 Earnings increased $16 million in the twelve-month comparison primarily because of customer growth; two fuel-related settlements in the third quarter of 1997; and lower fuel prices. These positive factors more than offset the effects of weather and a retail price reduction. See Note 6 of Notes to Condensed Financial Statements for additional information about the price reduction. In the period ended June 30, 1997, the Company also recognized $8 million of income tax benefits associated with capital loss carryforwards. Operating revenues increased $79 million primarily because of increases in sales for resale ($80 million) and customer growth ($57 million), partially offset by the effects of weather ($37 million) and the price reduction ($18 million). Sales for resale are wholesale electricity sales to third parties who resell the electricity to their customers. The increase in sales for resale was a result of changes in power marketing activity, which can vary from period to period without corresponding effects on earnings because of related fluctuations in purchased power costs. The two fuel-related settlements increased the Company's pretax earnings by approximately $21 million. The Company's income statement reflects these settlements as reductions in fuel expense and as other income. Operations and maintenance expenses increased $2 million because higher expenses related to growth and impending competition, the timing of scheduled -18- outages at power plants and other miscellaneous factors more than offset the effects of a charge for a voluntary severance program recorded in 1996 and related savings in 1997. Other Income As part of a 1994 rate settlement with the ACC, the Company accelerated amortization of substantially all deferred ITCs over a five-year period that ends on December 31, 1999. The amortization of ITCs is shown on the Company's income statement as Other Income -- Income Taxes and decreases annual income tax expense by approximately $28 million. Liquidity and Capital Resources For the six months ended June 30, 1998, the Company incurred approximately $145 million in capital expenditures, which is approximately 45% of the most recently estimated 1998 capital expenditures. The Company's projected capital expenditures for the next three years are: 1998, $323 million; 1999, $322 million; and 2000, $317 million, respectively. These amounts include about $30 - $35 million each year for nuclear fuel expenditures. In addition, the Company is considering expanding certain of its businesses over the next several years, which may result in increased expenditures. The Company's long-term debt and preferred stock redemption requirements and payment obligations on a capitalized lease for the next three years are: 1998, $176 million; 1999, $174 million; and 2000, $109 million. During the six months ended June 30, 1998, the Company redeemed approximately $142 million of its long-term debt and approximately $31 million of its preferred stock with cash from operations and long-term and short-term debt. As a result of the 1996 regulatory agreement (see Note 6 of Notes to Condensed Financial Statements), Pinnacle West invested $50 million in the Company in 1996 and 1997 and will invest similar amounts annually in 1998 and 1999. Although provisions in the Company's bond indenture, articles of incorporation, and financing orders from the ACC establish maximum amounts of additional first mortgage bonds and preferred stock that the Company may issue, management does not expect any of these restrictions to limit the Company's ability to meet its capital requirements. Year 2000 Issue As the year 2000 approaches many companies face problems because many software application and operational programs will not properly recognize calendar dates beginning with the year 2000. The Company initiated a comprehensive -19- Company-wide Year 2000 program over a year ago to review and resolve all Year 2000 issues in critical systems and equipment in a timely manner in an effort to ensure the reliability of electric service to its customers. This included a Company-wide awareness program of the Year 2000 issue. The Company believes that substantially all of its major information technology (IT) systems are Year 2000 compliant. The Company has made, and will continue to make, certain modifications to its computer hardware and software systems and applications in an effort to ensure they are capable of handling changing business needs, including dates in the year 2000 and thereafter. In addition, other IT systems and non-IT systems, including embedded technology and real-time process control systems, are being analyzed for potential modifications. To date, the Company has inventoried essentially all critical IT and non-IT systems and the assessment of these systems is ongoing. The analysis of the IT and non-IT systems should be complete in late 1998 and any renovation, validation, and implementation to be made will be completed by mid-1999 for all critical systems that affect operations, except for those items that can only be completed during maintenance outages at Palo Verde, which will be completed during the last half of 1999. The Company has also designated an internal audit/quality review team that is reviewing the individual Year 2000 projects and their Year 2000 readiness on a quarterly basis. The cost to the Company of Year 2000 remediation has not had, and is not expected to have, a material adverse effect on the Company's financial position, cash flows, or results of operations. The Company is in the process of communicating with its significant suppliers, business partners, other utilities, and large customers to determine the extent to which it may be affected by these third parties' plans to remediate their own Year 2000 issues in a timely manner. The Company has been interfacing with suppliers for systems, services, and materials in order to assess whether their schedules for analysis and remediation of Year 2000 issues are timely and to assess their ability to continue to supply services and materials required by the Company. However, the Company cannot currently predict the effect on the Company if the systems of these other companies are not Year 2000 compliant. Competition and Electric Industry Restructuring See Note 5 of Notes to Condensed Financial Statements in Part I, Item 1 of this report for discussions of competitive developments and regulatory accounting. See Note 7 of Notes to Condensed Financial Statements in Part I, Item 1 of this report for a discussion of a proposed amendment to a Power Coordination Agreement with Salt River Project that the Company estimates would reduce its pretax costs for purchased power by approximately $17 million in 1999 and by lesser annual amounts through 2006. -20- Rate Matters See Note 6 of Notes to Condensed Financial Statements in Part I, Item 1 of this report for a discussion of a proposed price reduction. Forward-Looking Statements The above discussion contains forward-looking statements that involve risks and uncertainties. Words such as "estimates," "expects," "anticipates," "plans," "believes," "projects," and similar expressions identify forward-looking statements. These risks and uncertainties include, but are not limited to, the ongoing restructuring of the electric industry; the outcome of the regulatory proceedings relating to the restructuring; regulatory, tax and environmental legislation; the ability of the Company to successfully compete outside its traditional regulated markets; regional economic conditions, which could affect customer growth; the cost of debt and equity capital; weather variations affecting customer usage; technological developments in the electric industry; and Year 2000 issues. These factors and the other matters discussed above may cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by the Company. -21- PART II - OTHER INFORMATION ITEM 4. Submission Of Matters to a Vote of Security Holders At the Annual Meeting of Shareholders held on May 19, 1998, the shareholders elected all of the directors of the Company, each of whom will serve for the ensuing year or until his or her successor is elected or qualified, as follows: Votes Against Broker Director Votes For and Withheld Abstentions Non-votes -------- --------- ------------ ----------- --------- O. Mark De Michele 74,335,487 12,620 N/A N/A Michael L. Gallagher 74,334,952 13,120 N/A N/A Martha O. Hesse 74,335,702 12,420 N/A N/A Marianne M. Jennings 74,332,821 15,109 N/A N/A Robert E. Keever 74,334,952 13,120 N/A N/A Robert G. Matlock 74,335,702 12,420 N/A N/A Bruce J. Nordstrom 74,335,702 12,420 N/A N/A John R. Norton III 74,335,103 12,979 N/A N/A William J. Post 74,335,166 12,920 N/A N/A Donald M. Riley 74,334,952 13,120 N/A N/A George A. Schreiber, Jr. 74,335,166 12,920 N/A N/A Quentin P. Smith, Jr. 74,334,952 13,120 N/A N/A Richard Snell 74,333,387 14,580 N/A N/A Dianne C. Walker 74,334,952 13,120 N/A N/A Ben F. Williams, Jr. 74,335,434 12,670 N/A N/A ITEM 5. Other Information EPA Environmental Regulation As previously reported, the EPA has been considering the Grand Canyon Visability Transport Commission's recommendations prior to promulgating final regulations on a regional haze regulatory program and final regulations were expected by June 1998. See "Environmental Matters - EPA Environmental Regulation" in Part I, Item 1 of the 1997 10-K. These final regulations are now expected by December 1998. The Company cannot currently estimate the capital expenditures, if any, which may be required as a result of the EPA studies and the Commission's recommendations. As previously reported, in July 1997, the EPA promulgated final National Ambient Air Quality Standards for ozone and particulate matter. See "Environmental Matters - EPA Environmental Regulation" in Part I, Item 1 of the 1997 10-K. Congress recently -22- enacted legislation that could delay the implementation of the regional haze requirements and particulate matter ambient standard. Spent Nuclear Fuel and Waste Disposal As previously reported, in November 1997, the D.C. Circuit issued a Writ of Mandamus precluding DOE from excusing its delay in accepting spent nuclear fuel by January 31, 1998. See "Generating Fuel and Purchased Power - Nuclear Fuel Supply - Spent Nuclear Fuel and Waste Disposal" in Part I, Item 1 of the 1997 10-K. On May 5, 1998, the D.C. Circuit issued a ruling refusing to order DOE to begin moving spent nuclear fuel. On July 24, 1998, the Company filed a Petition for Review with the D.C. Circuit regarding DOE's obligation to begin accepting spent nuclear fuel. Arizona Public Service Company v. Department -------------------------------------------- of Energy and United States of America, No. 98-1346 (D.C. Cir.). - --------------------------------------- Palo Verde Nuclear Generating Station See Note 9 of Notes to Condensed Financial Statements in Part I, Item 1 of this report for a discussion of issues regarding the Palo Verde steam generators. Construction and Financing Programs See "Liquidity and Capital Resources" in Part I, Item 2 of this report for a discussion of the Company's construction and financing programs. Competition and Electric Industry Restructuring See Note 5 of Notes to Condensed Financial Statements in Part I, Item 1 of this report for a discussion of competition and the rules regarding the introduction of retail electric competition in Arizona. On February 28, 1997, a lawsuit was filed by the Company to protect its legal rights regarding the rules and in its complaint the Company asked the Court for (i) a judgment vacating the retail electric competition rules, (ii) a declaratory judgment that the rules are unlawful because, among other things, they were entered into without proper legal authorization, and (iii) a permanent injunction barring the ACC from enforcing or implementing the rules and from promulgating any other regulations without lawful authority. ITEM 6. Exhibits and Reports on Form 8-K (a) Exhibits Exhibit No. Description - ----------- ----------- 10.1 Retail Electric Competition Rules 27.1 Financial Data Schedule -23- In addition to those Exhibits shown above, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation section 229.10(d) by reference to the filings set forth below:
Exhibit No. Description Originally Filed as Exhibit: File No.a Date Effective - ----------- ----------- ---------------------------- --------- -------------- 3.1 Bylaws, amended as of 3.1 to 1995 Form 10-K 1-4473 3-29-96 February 20, 1996 Report 3.2 Resolution of Board of 3.2 to 1994 Form 10-K 1-4473 3-30-95 Directors temporarily Report suspending Bylaws in part 3.3 Articles of Incorporation, 4.2 to Form S-3 1-4473 9-29-93 restated as of May 25, 1988 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report 3.4 Certificates pursuant to 4.3 to Form S-3 1-4473 9-29-93 Sections 10-152.01 and Registration Nos. 10-016, Arizona Revised 33-33910 and 33-55248 by Statutes, establishing means of September 24, Series A through V of the 1993 Form 8-K Report Company's Serial Preferred Stock 3.5 Certificate pursuant to 4.4 to Form S-3 1-4473 9-29-93 Section 10-016, Arizona Registration Nos. Revised Statutes, establishing 33-33910 and 33-55248 by Series W of the Company's means of September 24, Serial Preferred Stock 1993 Form 8-K Report 10.2 Arizona Corporation 99.1 to 1996 Form 10-K 1-4473 3-28-97 Commission Order, Decision Report No. 59943, dated December 26, 1996, including the rules regarding the introduction of retail competition in Arizona
(b) Reports on Form 8-K During the quarter ended June 30, 1998, and the period from July 1 through August 14, 1998, the Company filed the following reports on Form 8-K: Report dated May 19, 1998 regarding the stranded cost hearing at the ACC, ACC Staff's Statement of Position related to retail competition and the Company's agreement with Salt River Project. Report dated August 5, 1998 regarding the ACC rules related to retail competition. - ---------- a Reports filed under File No. 1-4473 were filed in the office of the Securities and Exchange Commission located in Washington, D.C. -24- 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 thereunto duly authorized. ARIZONA PUBLIC SERVICE COMPANY (Registrant) Dated: August 14, 1998 By: George A. Schreiber -------------------------------- George A. Schreiber, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer and Officer Duly Authorized to sign this Report) EX-10.1 2 SECURITIES REGULATION Docket No. RE-00000C-94-0165 TITLE 14. PUBLIC SERVICE CORPORATIONS; CORPORATIONS AND ASSOCIATIONS; SECURITIES REGULATION CHAPTER 2. CORPORATION COMMISSION - FIXED UTILITIES ARTICLE 2. ELECTRIC UTILITIES Section R14-2-203. Establishment of service R14-2-204. Minimum customer information requirements R14-2-208. Provision of service R14-2-209. Meter reading R14-2-210. Billing and collection R14-2-211. Termination of service 1 R14-2-203. Establishment of service A. No change. B. Deposits 1. A utility shall not require a deposit from a new applicant for residential service if the applicant is able to meet any of the following requirements: a. The applicant has had service of a comparable nature with the utility within the past two years and was not delinquent in payment more than twice during the last 12 consecutive months or disconnected for nonpayment. b. The applicant can produce a letter regarding credit or verification from an electric utility where service of a comparable nature was last received which states applicant had a timely payment history at time of service discontinuance. c. In lieu of a deposit, a new applicant may provide a Letter of Guarantee from a governmental or non-profit entity or a surety bond as security for the utility. 2. The utility shall issue a nonnegotiable receipt to the applicant for the deposit. The inability of the customer to produce such a receipt shall in no way impair his right to receive a refund of the deposit which is reflected on the utility's records. 3. Deposits shall be interest bearing; the interest rate and method of calculation shall be filed with and approved by the Commission in a tariff proceeding. 4. Each utility shall file a deposit refund procedure with the Commission, subject to Commission review and approval during a tariff proceeding. However, each utility's refund policy shall include provisions for residential deposits and accrued interest to be refunded or letters of guarantee or surety bonds to expire after 12 months of service if the customer has not been delinquent more than twice in the payment of utility bills. 2 5. A utility may require a residential customer to establish or reestablish a deposit if the customer becomes delinquent in the payment of 2 bills within a 12 consecutive month period or has been disconnected for service during the last 12 months. 6. The amount of a deposit required by the utility shall be determined according to the following terms: a. Residential customer deposits shall not exceed two times that customer's estimated average monthly bill. b. Nonresidential customer deposits shall not exceed two and one-half times that customer's estimated maximum monthly bill. 7. The utility may review the customer's usage after service has been connected and adjust the deposit amount based upon the customer's actual usage. 8. A separate deposit may be required for each meter installed. C. No change. D. Service establishments, re-establishments or reconnection charge 1. Each utility may make a charge as approved by the Commission for the establishment, reestablishment, or reconnection of utility services, including transfers between Electric Service Providers. 2. Should service be established during a period other than regular working hours at the customer's request, the customer may be required to pay an after-hour charge for the service connection. Where the utility scheduling will not permit service establishment on the same day requested, the customer can elect to pay the after-hour charge for establishment that day or his service will be established on the next available normal working day. 3. For the purpose of this rule, the definition of service establishments are where the customer's facilities are ready and acceptable to the utility and the utility needs only to install a meter, read a meter, or turn the service on. 3 4. Service establishments with an Electric Service Provider will be scheduled for the next regular meter read date if the direct access service request is processed 15 calendar days prior to that date and appropriate metering equipment is in place. If a direct access service request is made in less than 15 days prior to the next regular read date, service will be established at the next regular meter read date thereafter. The utility may offer after-hours or earlier service for a fee. E. No change. R14-2-204. Minimum customer information requirements A. Information for residential customers 1. A utility shall make available upon customer request not later than 60 days from the date of request a concise summary of the rate schedule applied for by such customer. The summary shall include the following: a. The monthly minimum or customer charge, identifying the amount of the charge and the specific amount of usage included in the minimum charge, where applicable. b. Rate blocks, where applicable. c. Any adjustment factor(s) and method of calculation. 2. The utility shall to the extent practical identify its tariff that is most advantageous to the customer and notify the customer of such prior to service commencement. 3. In addition, a utility shall make available upon customer request, not later than 60 days from date of service commencement, a concise summary of the utility's tariffs or the Commission's rules and regulations concerning: a. Deposits b. Termination of service c. Billing and collection d. Complaint handling. 4 4. Each utility upon request of a customer shall transmit a written statement of actual consumption by such customer for each billing period during the prior 12 months unless such data is not reasonably ascertainable. 5. Each utility shall inform all new customers of their right to obtain the information specified above. B. No change. R14-2-208. Provision of Service A. Utility responsibility 1. Each utility shall be responsible for the safe transmission and/or distribution of electricity until it passes the point of delivery to the customer. 2. The entity having control of the meter shall be responsible for maintaining in safe operating condition all meters, equipment and fixtures installed on the customer's premises by the entity for the purposes of delivering electric service to the customer. 3. The Utility Distribution Company may, at its option, refuse service until the customer has obtained all required permits and/or inspections indicating that the customer's facilities comply with local construction and safety standards. B. No change. C. No change. D. No change. E. No change. F. No change. 5 R14-2-209. Meter Reading A. Company or customer meter reading 1. Each utility, billing entity or Meter Reading Service Provider may at its discretion allow for customer reading of meters. 2. It shall be the responsibility of the utility or Meter Reading Service Provider to inform the customer how to properly read his or her meter. 3. Where a customer reads his or her own meter, the utility or Meter Reading Service Provider will read the customer's meter at least once every six months. 4. The utility, billing entity or Meter Reading Service Provider shall provide the customer with postage-paid cards or other methods to report the monthly reading. 5. Each utility or Meter Reading Service Provider shall specify the timing requirements for the customer to submit his or her monthly meter reading to conform with the utility's billing cycle. 6. Where the Electric Service Provider is responsible for meter reading, reads will be available for the Utility Distribution Company's or billing entity's billing cycle for that customer, or as otherwise agreed upon by the Electric Service Provider and the Utility Distribution Company or billing entity. 7. In the event the customer fails to submit the reading on time, the utility or billing entity may issue the customer an estimated bill. 8. In the event the Electric Service Provider responsible for meter reading fails to deliver reads to the Meter Reader Service Provider server within 3 days of the scheduled cycle read date, the Affected Utility may estimate the reads. 9. Meters shall be read monthly on as close to the same day as practical. B. Measuring of service 1. All energy sold to customers and all energy consumed by the utility, except that sold according to fixed charge schedules, shall be measured by commercially 6 acceptable measuring devices, except where it is impractical to install meters, such as street lighting or security lighting, or where otherwise authorized by the Commission. 2. When there is more than one meter at a location, the metering equipment shall be so tagged or plainly marked as to indicate the circuit metered or metering equipment. 3. Meters which are not direct reading shall have the multiplier plainly marked on the meter. 4. All charts taken from recording meters shall be marked with the date of the record, the meter number, customer, and chart multiplier. 5. Metering equipment shall not be set "fast" or "slow" to compensate for supply transformer or line losses. C. Meter rereads 1. Each utility or Meter Reading Service Provider shall at the request of a customer, or the customer's Electric Service Provider, Utility Distribution Company (as defined in A.A.C. R14-2-1601) or billing entity reread that customer's meter within ten working days after such a request. 2. Any reread may be charged to the customer, or the customer's Electric Service Provider, Utility Distribution Company (as defined in A.A.C. R14-2-1601) or billing entity at a rate on file and approved by the Commission, provided that the original reading was not in error. 3. When a reading is found to be in error, the reread shall be at no charge to the customer, or the customer's Electric Service Provider, Utility Distribution Company (as defined in A.A.C. R14-2-1601) or billing entity. 7 D. Access to customer premises Each utility shall have the right of safe ingress to and egress from the customer's premises at all reasonable hours for any purpose reasonably connected with property used in furnishing service and the exercise of any and all rights secured to it by law or these rules. E. No change. F. Request for meter tests A utility or Meter Service Provider shall test a meter upon the request of the customer, or the customer's Electric Service Provider, Utility Distribution Company (as defined in A.A.C. R14-2-1601) or billing entity request, and each utility or billing entity shall be authorized to charge the customer, or the customer's Electric Service Provider, Utility Distribution Company (as defined in A.A.C. R14-2-1601) or billing entity for such meter test according to the tariff on file and approved by the Commission. However, if the meter is found to be in error by more than 3%, no meter testing fee will be charged to the customer, or the customer's Electric Service Provider, Utility Distribution Company or billing entity. R14-2-210. Billing and collection A. Frequency and estimated bills 1. Unless otherwise approved by the Commission, the utility or billing entity shall render a bill for each billing period to every customer in accordance with its applicable rate schedule and may offer billing options for the services rendered. Meter readings shall be scheduled for periods of not less than 25 days without customer authorization or more than 35 days. If the utility or Meter Reading Service Provider changes a meter reading route or schedule resulting in a significant alteration of billing cycles, notice shall be given to the affected customers. 2. Each billing statement rendered by the utility or billing entity shall be computed 8 on the actual usage during the billing period. If the utility or Meter Reading Service Provider is unable to obtain an actual reading, the utility or billing entity may estimate the consumption for the billing period giving consideration the following factors where applicable: a. The customer's usage during the same month of the previous year, b. The amount of usage during the preceding month. 3. Estimated bills will be issued only under the following conditions unless otherwise approved by the Commission: a. When extreme weather conditions, emergencies, or work stoppages prevent actual meter readings. b. Failure of a customer who reads his own meter to deliver his meter reading to the utility or Meter Reading Service Provider in accordance with the requirements of the utility or Meter Reading Service Provider billing cycle. c. When the utility or Meter Reading Service Provider is unable to obtain access to the customer's premises for the purpose of reading the meter, or in situations where the customer makes it unnecessarily difficult to gain access to the meter, that is, locked gates, blocked meters, vicious or dangerous animals, etc. If the utility or Meter Reading Service Provider is unable to obtain an actual reading for these reasons, it shall undertake reasonable alternatives to obtain a customer reading of the meter. d. Due to customer equipment failure, a 1-month estimation will be allowed. 9 Failure to remedy the customer equipment condition will result in penalties as imposed by the Commission. e. To facilitate timely billing for customers using load profiles. 4. After the third consecutive month of estimating the customer's bill due to lack of meter access, the utility or Meter Reading Service Provider will attempt to secure an accurate reading of the meter. Failure on the part of the customer to comply with a reasonable request for meter access may lead to discontinuance of service. 5. A utility or billing entity may not render a bill based on estimated usage if: a. The estimating procedures employed by the utility or billing entity have not been approved by the Commission. b. The billing would be the customer's first or final bill for service. c. If the customer is a direct access customer requiring load data. 6. When a utility or billing entity renders an estimated bill in accordance with these rules, it shall: 10 a. Maintain accurate records of the reasons therefore and efforts made to secure an actual reading; b. Clearly and conspicuously indicate that it is an estimated bill and note the reason for its estimation; c. Use customer supplied meter readings, whenever possible, to determine usage. B. Combining meters, minimum bill information 1. Each meter at a customer's premise will be considered separately for billing purposes, and the readings of two or more meters will not be combined unless otherwise provided for in the utility's tariffs. This provision does not apply in the case of aggregation of competitive services as described in A.A.C. R14-2-1601. 2. Each bill for residential service will contain the following minimum information: a. The beginning and ending meter readings of the billing period, the dates thereof, and the number of days in the billing period; b. The date when the bill will be considered due and the date when it will be delinquent, if not the same; c. Billing usage, demand, basic monthly service charge and total amount due; d. Rate schedule number or service offer; e. Customer's name and service account number; f. Any previous balance; 11 g. Fuel adjustment cost, where applicable; h. License, occupation, gross receipts, franchise and sales taxes; i. The address and telephone numbers of the Electric Service Provider, and/or the Utility Distribution Company designating where the customer may initiate an inquiry or complaint concerning the bill or services rendered; j. The Arizona Corporation Commission address and toll free telephone numbers; k. Other unbundled rates and charges. C. Billing terms 1. All bills for utility services are due and payable no later than 15 days from the date of the bill. Any payment not received within this time frame shall be considered delinquent and could incur a late payment charge. 2. For purposes of this rule, the date a bill is rendered may be evidenced by: a. The postmark date; b. The mailing date; c. The billing date shown on the bill (however, the billing date shall not 12 differ from the postmark or mailing date by more than 2 days); d. The transmission date for electronic bills. 3. All delinquent bills shall be subject to the provisions of the utility's termination procedures. 4. All payments shall be made at or mailed to the office of the utility or to the utility's authorized payment agency or the office of the billing entity. The date on which the utility actually receives the customer's remittance is considered the payment date. D. Applicable tariffs, prepayment, failure to receive, commencement date, taxes 1. Each customer shall be billed under the applicable tariff indicated in the customer's application for service. 2. Each utility or billing entity shall make provisions for advance payment of utility services. 3. Failure to receive bills or notices which have been properly placed in the United States mail shall not prevent such bills from becoming delinquent nor relieve the customer of his obligations therein. 4. Charges for electric service commence when the service is actually installed and connection made, whether used or not. A minimum one-month billing period is established on the date the service is installed (excluding landlord/utility special agreements). 13 5. Charges for services disconnected after 1 month shall be prorated back to the customer of record. E. Meter error corrections 1. The utility or Meter Reading Service Provider shall test a meter upon customer request and each utility or billing entity shall be authorized to charge the customer for such meter test according to the tariff on file approved by the Commission. However, if the meter is found to be in error by more than 3%, no meter testing fee may be charged to the customer. If the meter is found to be more than 3% in error, either fast or slow, the correction of previous bills will be made under the following terms allowing the utility or billing entity to recover or refund the difference: a. If the date of the meter error can be definitely fixed, the utility or billing entity shall adjust the customer's billings back to that date. If the customer has been underbilled, the utility or billing entity will allow the customer to repay this difference over an equal length of time that the underbillings occurred. The customer may be allowed to pay the backbill without late payment penalties, unless there is evidence of meter tampering or energy diversion. b. If it is determined that the customer has been overbilled and there is no evidence of meter tampering or energy diversion, the utility or billing entity will make prompt refunds in the difference between the original billing and the corrected billing within the next billing cycle. 14 2. No adjustment shall be made by the utility except to the customer last served by the meter tested. 3. Any underbilling resulting from a stopped or slow meter, utility or Meter Reading Service Provider meter reading error, or a billing calculation shall be limited to 3 months for residential customers and 6 months for non-residential customers. However, if an underbilling by the utility occurs due to inaccurate, false or estimated information from a third party, then that utility will have a right to back bill that third party to the point in time that may be definitely fixed, or 12 months. No such limitation will apply to overbillings. F. Insufficient funds (NSF) or returned checks 1. A utility or billing entity shall be allowed to recover a fee, as approved by the Commission in a tariff proceeding, for each instance where a customer tenders payment for electric service with a check which is returned by the customer's bank. 2. When the utility or billing entity is notified by the customer's bank that the check tendered for utility service will not clear, the utility or billing entity may require the customer to make payment in cash, by money order, certified check, or other means to guarantee the customer's payment. 15 3. A customer who tenders such a check shall in no way be relieved of the obligation to render payment to the utility or billing entity under the original terms of the bill nor defer the utility's provision of termination of service for nonpayment of bills. G. Levelized billing plan 1. Each utility may, at its option, offer its residential customers a levelized billing plan. 2. Each utility offering a levelized billing plan shall develop, upon customer request, an estimate of the customer's levelized billing for a 12-month period based upon: a. Customer's actual consumption history, which may be adjusted for abnormal conditions such as weather variations. b. For new customers, the utility will estimate consumption based on the customer's anticipated load requirements. c. The utility's tariff schedules approved by the Commission applicable to that customer's class of service. 3. The utility shall provide the customer a concise explanation of how the levelized billing estimate was developed, the impact of levelized billing on a customer's monthly utility bill, and the utility's right to adjust the customer's billing for any variation between the utility's estimated billing and actual billing. 4. For those customers being billed under a levelized billing plan, the utility shall show, at a minimum, the following information on their monthly bill: 16 a. Actual consumption b. Dollar amount due for actual consumption c. Levelized billing amount due d. Accumulated variation in actual versus levelized billing amount. 5. The utility may adjust the customer's levelized billing in the event the utility's estimate of the customer's usage and/or cost should vary significantly from the customer's actual usage and/or cost; such review to adjust the amount of the levelized billing may be initiated by the utility or upon customer request. H. Deferred payment plan 1. Each utility may, prior to termination, offer to qualifying residential customers a deferred payment plan for the customer to retire unpaid bills for utility service. 2. Each deferred payment agreement entered into by the utility and the customer shall provide that service will not be discontinued if: a. Customer agrees to pay a reasonable amount of the outstanding bill at the time the parties enter into the deferred payment agreement. b. Customer agrees to pay all future bills for utility service in accordance with the billing and collection tariffs of the utility. c. Customer agrees to pay a reasonable portion of the remaining outstanding balance in installments over a period not to exceed six months. 3. For the purposes of determining a reasonable installment payment schedule under these rules, the utility and the customer shall give consideration to the following conditions: a. Size of the delinquent account 17 b. Customer's ability to pay c. Customer's payment history d. Length of time that the debt has been outstanding e. Circumstances which resulted in the debt being outstanding f. Any other relevant factors related to the circumstances of the customer. 4. Any customer who desires to enter into a deferred payment agreement shall establish such agreement prior to the utility's scheduled termination date for nonpayment of bills. The customer's failure to execute such an agreement prior to the termination date will not prevent the utility from disconnecting service for nonpayment. 5. Deferred payment agreements may be in writing and may be signed by the customer and an authorized utility representative. 6. A deferred payment agreement may include a finance charge as approved by the Commission in a tariff proceeding. 7. If a customer has not fulfilled the terms of a deferred payment agreement, the utility shall have the right to disconnect service pursuant to the utility's termination of service rules. Under such circumstances, it shall not be required to offer subsequent negotiation of a deferred payment agreement prior to disconnection. I. Change of occupancy 1. To order service discontinued or to change occupancy, the customer must give the utility at least 3 working days advance notice in person, in writing, or by telephone. 18 2. The outgoing customer shall be responsible for all utility services provided and/or consumed up to the scheduled turnoff date. 3. The outgoing customer is responsible for providing access to the meter so that the utility may obtain a final meter reading. R14-2-211. Termination of service A. Nonpermissible reasons to disconnect service 1. A utility may not disconnect service for any of the reasons stated below: a. Delinquency in payment for services rendered to a prior customer at the premises where service is being provided, except in the instance where the prior customer continues to reside on the premises. b. Failure of the customer to pay for services or equipment which are not regulated by the Commission. c. Nonpayment of a bill related to another class of service. d. Failure to pay for a bill to correct a previous underbilling due to an inaccurate meter or meter failure if the customer agrees to pay over a reasonable period of time. e. A utility shall not terminate residential service where the customer has an inability to pay and: i. The customer can establish through medical documentation that, in the opinion of a licensed medical physician, termination would be especially dangerous to the customer's or a permanent resident residing on the customer's premises health, or 19 ii. Life supporting equipment used in the home that is dependent on utility service for operation of such apparatus, or iii. Where weather will be especially dangerous to health as defined herein or as determined by the Commission. f. Residential service to ill, elderly, or handicapped persons who have an inability to pay will not be terminated until all of the following have been attempted: i. The customer has been informed of the availability of funds from various government and social assistance agencies of which the utility is aware. ii. A third party previously designated by the customer has been notified and has not made arrangements to pay the outstanding utility bill. g. A customer utilizing the provisions of d. or e. above may be required to enter into a deferred payment agreement with the utility within ten days after the scheduled termination date. h. Disputed bills where the customer has complied with the Commission's rules on customer bill disputes. B. Termination of service without notice 1. In a competitive marketplace, the Electric Service Provider cannot order a disconnect for non-payment, but can only send a notice of contract cancellation to the customer and the Utility Distribution Company. Utility service may be disconnected without advance written notice under the following conditions: a. The existence of an obvious hazard to the safety or health of the consumer or the general population or the utility's personnel or facilities. b. The utility has evidence of meter tampering or fraud. 20 c. Failure of a customer to comply with the curtailment procedures imposed by a utility during supply shortages. 2. The utility shall not be required to restore service until the conditions which resulted in the termination have been corrected to the satisfaction of the utility. 3. Each utility shall maintain a record of all terminations of service without notice. This record shall be maintained for a minimum of one year and shall be available for inspection by the Commission. C. Termination of service with notice 1. In a competitive marketplace, the Electric Service Provider cannot order a disconnect for non-payment, but can only send a notice of contract cancellation to the customer and the Utility Distribution Company. A utility may disconnect service to any customer for any reason stated below provided the utility has met the notice requirements established by the Commission: a. Customer violation of any of the utility's tariffs. b. Failure of the customer to pay a delinquent bill for utility service. c. Failure to meet or maintain the utility's deposit requirements. d. Failure of the customer to provide the utility reasonable access to its equipment and property. e. Customer breach of a written contract for service between the utility and customer. f. When necessary for the utility to comply with an order of any governmental agency having such jurisdiction. 2. Each utility shall maintain a record of all terminations of service with notice. This record shall be maintained for one year and be available for Commission inspection. D. No change. E. No change. 21 F. No change. 22 Docket No. RE-00000C-94-0165 TITLE 14. PUBLIC SERVICE CORPORATIONS; CORPORATIONS AND ASSOCIATIONS; SECURITIES REGULATION CHAPTER 2. CORPORATION COMMISSION - FIXED UTILITIES ARTICLE 16. RETAIL ELECTRIC COMPETITION Section R14-2-1601. Definitions R14-2-1603. Certificates of Convenience and Necessity R14-2-1604. Competitive Phases R14-2-1605. Competitive Services R14-2-1606. Services Required To Be Made Available R14-2-1607. Recovery of Stranded Cost of Affected Utilities R14-2-1608. System Benefits Charges R14-2-1609. Solar Portfolio Standard R14-2-1610. Transmission and Distribution Access R14-2-1611. In-state Reciprocity R14-2-1612. Rates R14-2-1613. Service Quality, Consumer Protection, Safety, and Billing Requirements R14-2-1614. Reporting Requirements R14-2-1615. Administrative Requirements R14-2-1616. Separation of Monopoly and Competitive Services R14-2-1617. Affiliate Transactions R14-2-1618. Disclosure of Information 23 R14-2-1601. Definitions In this Article, unless the context otherwise requires: 1. No change. 2. "Aggregator" means an Electric Service Provider that combines retail electric customers into a purchasing group. 3. "Bundled Service" means electric service provided as a package to the consumer including all generation, transmission, distribution, ancillary and other services necessary to deliver and measure useful electric energy and power to consumers. 4. "Buy-through" refers to a purchase of electricity by an Affected Utility at wholesale for a particular retail consumer or aggregate of consumers or at the direction of a particular retail consumer or aggregate of consumers. 5. "Competition Transition Charge" (CTC) is a means of recovering Stranded Costs from the customers of competitive services. 6. "Competitive Services" means all aspects of retail electric service except those services specifically defined as "noncompetitive services" pursuant to R14-2-1601(29). 7. "Control Area Operator" is the operator of an electric system or systems, bounded by interconnection metering and telemetry, capable of controlling generation to maintain its interchange schedule with other such systems and contributing to frequency regulation of the interconnection. 8. "Consumer Information" is impartial information provided to consumers about competition or competitive and noncompetitive services and is distinct from advertising and marketing. 9. "Current Transformer" (CT) is an electrical device used in conjunction with an electric meter to provide a measurement of energy consumption for metering purposes. 10. "Direct Access Service Request" (DASR) means a form that contains all 24 necessary billing and metering information to allow customers to switch electric service providers. This form must be submitted to the Utility Distribution Company by the customer's Electric Service Provider or the customer. 11. "Delinquent Accounts" means customer accounts with outstanding past due payment obligations that remain unpaid after the due date. 12. "Distribution Primary Voltage" is voltage as defined under the Affected Utility's Federal Energy Regulatory Commission (FERC) Open Access Transmission Tariff, except for Meter Service Providers, for which Distribution Primary Voltage is voltage at or above 600 volts (600V) through and including 25 kilovolts (25 kV). 13. "Distribution Service" means the delivery of electricity to a retail consumer through wires, transformers, and other devices that are not classified as transmission services subject to the jurisdiction of the Federal Energy Regulatory Commission; Distribution Service excludes Metering Services, Meter Reading Services, and billing and collection services, as those terms are used herein. 14. "Electronic Data Interchange" (EDI) is the computer-to-computer electronic exchange of business documents using standard formats which are recognized both nationally and internationally. 15. "Electric Service Provider" (ESP) means a company supplying, marketing, or brokering at retail any of the competitive services described in R14-2-1605 or R14-2-1606, pursuant to a Certificate of Convenience and Necessity. 16. "Electric Service Provider Service Acquisition Agreement" or "Service 25 Acquisition Agreement" means a contract between an Electric Service Provider and a Utility Distribution Company to deliver power to retail end users or between an Electric Service Provider and a Scheduling Coordinator to schedule transmission service. 17. "Generation" means the production of electric power or contract rights to the receipt of wholesale electric power. 18. "Green Pricing" means a program offered by an Electric Service Provider where customers elect to pay a rate premium for solar-generated electricity. 19. "Independent Scheduling Administrator" (ISA) is a proposed entity, independent of transmission owning organizations, intended to facilitate nondiscriminatory retail direct access using the transmission system in Arizona. 20. "Independent System Operator" (ISO) is an independent organization whose objective is to provide nondiscriminatory and open transmission access to the interconnected transmission grid under its jurisdiction, in accordance with the Federal Energy Regulatory Commission principles of independent system operation. 21. "Load Profiling" is a process of estimating a customer's hourly energy consumption based on measurements of similar customers. 22. "Load-Serving Entity" means an Electric Service Provider, Affected Utility or Utility Distribution Company, excluding a Meter Reading Service, Meter Reading Service Provider or Aggregators. 23. "Meter Reading Service" means all functions related to the collection and storage of consumption data. 24. "Meter Reading Service Provider" (MRSP) means an entity providing Meter Reading Service, as that term is defined herein and that reads meters, performs validation, editing, and estimation on raw meter data to create validated meter data; translates validated data to an approved format; posts this data to a server for 26 retrieval by billing agents; manages the server; exchanges data with market participants; and stores meter data for problem resolution. 25. "Meter Service Provider" (MSP) means an entity providing Metering Service, as that term is defined herein. 26. "Metering and Metering Service" means all functions related to measuring electricity consumption. 27. "Must-Run Generating Units" are those units that are required to run to maintain distribution system reliability and meet load requirements in times of congestion on certain portions of the interconnected transmission grid. 28. "Net Metering" or "Net Billing" is a method by which customers can use electricity from customer-sited solar electric generators to offset electricity purchased from an Electric Service Provider. The customer only pays for the "Net" electricity purchased. 29. "Noncompetitive Services" means distribution service, Standard Offer service transmission and Federal Energy Regulatory Commission-required ancillary services, and these aspects of metering service set forth in R14-2-1613. All components of Standard Offer service shall be deemed noncompetitive as long as those components are provided in a bundled transaction pursuant to R14-2-1606(A). 30. "OASIS" is Open Access Same-Time Information System, which is an electronic bulletin board where transmission-related information is posted for all interested parties to access via the Internet to enable parties to engage in transmission transactions. 31. "Operating Reserve" means the generation capability above firm system demand used to provide for regulation, load forecasting error, equipment forced and scheduled outages, and local area protection to provide system reliability. 32. "Potential Transformer" (PT) is an electrical device used to step down primary voltages to 120V for metering purposes. 27 33. "Provider of Last Resort" means a provider of Standard Offer Service to customers within the provider's certificated area who are not buying competitive services. 34. "Retail Electric Customer" means the person or entity in whose name service is rendered. 35. "Scheduling Coordinator" means an entity that provides schedules for power transactions over transmission or distribution systems to the party responsible for the operation and control of the transmission grid, such as a Control Area Operator, Independent Scheduling Administrator or Independent System Operator. 36. "Self-Aggregation" is the action of a retail electric customer that combines its own metered loads into a single purchase block. 37. "Solar Electric Fund" is the funding mechanism established by this Article through which deficiency payments are collected and solar energy projects are funded in accordance with this Article. 38. "Standard Offer" means Bundled Service offered by the Affected Utility or Utility Distribution Company to all consumers in the Affected Utility's or Utility Distribution Company's service territory at regulated rates including metering, meter reading, billing, collection services and other consumer information services. 39. "Stranded Cost" includes: a. The verifiable net difference between: i. The value of all the prudent jurisdictional assets and obligations necessary to furnish electricity (such as generating plants, purchased power contracts, fuel contracts, and regulatory assets), acquired or entered into prior to the adoption of this Article, under traditional regulation of Affected Utilities; and 28 ii. The market value of those assets and obligations directly attributable to the introduction of competition under this Article; b. Reasonable costs necessarily incurred by an Affected Utility to effectuate divestiture of its generation assets; c. Reasonable employee severance and retraining costs necessitated by electric competition, where not otherwise provided. 40. "System Benefits" means Commission-approved utility low income, demand side management, environmental, renewables, and nuclear power plant decommissioning programs. 41. "Transmission Primary Voltage" is voltage above 25 kV as it relates to metering transformers. 42. "Transmission Service" refers to the transmission of electricity to retail electric customers or to electric distribution facilities and that is so classified by the Federal Energy Regulatory Commission or, to the extent permitted by law, so classified by the Arizona Corporation Commission. 43. "Unbundled Service" means electric service elements provided and priced separately, including, but not limited to, such service elements as generation, transmission, distribution, metering, meter reading, billing and collection and ancillary services. Unbundled Service may be sold to consumers or to other Electric Service Providers. 44. "Utility Distribution Company" (UDC) means the electric utility entity that constructs and maintains the distribution system for the delivery of power to the end user. 45. "Utility Industry Group" (UIG) refers to a utility industry association that establishes national standards for data formats. 46. "Universal Node Identifier" is a unique, permanent, identification number assigned to each service delivery point. 29 R14-2-1603. Certificates of Convenience and Necessity A. Any Electric Service Provider intending to supply services described in R14-2-1605 or R-14-2-1606, other than services subject to federal jurisdiction, shall obtain a Certificate of Convenience and Necessity from the Commission pursuant to this Article. A Certificate is not required to offer information services, billing and collection services, or self-aggregation. However, aggregators as defined in R14-2-1601 are required to obtain a Certificate of Convenience and Necessity and Self-Aggregators are required to negotiate a Service Acquisition Agreement consistent with subsection G(6). An Affected Utility need not apply for a Certificate of Convenience and Necessity to continue to provide electric service in its service area during the transition period set forth in R14-2-1604. An Affected Utility providing distribution and Standard Offer service after January 1, 2001 need not apply for a Certificate of Convenience and Necessity. All other Affected Utility affiliates created in compliance with R14-2-1616(A) shall be required to apply for appropriate Certificates of Convenience and Necessity. B. Any company desiring such a Certificate of Convenience and Necessity shall file with the Docket Control Center the required number of copies of an application. In support of the request for a Certificate of Convenience and Necessity, the following information must be provided: 1. A description of the electric services which the applicant intends to offer; 2. The proper name and correct address of the applicant, and a. The full name of the owner if a sole proprietorship, b. The full name of each partner if a partnership, c. A full list of officers and directors if a corporation, or 30 d. A full list of the members if a limited liability corporation; 3. A tariff for each service to be provided that states the maximum rate and terms and conditions that will apply to the provision of the service; 4. A description of the applicant's technical ability to obtain and deliver electricity if appropriate and provide any other proposed services; 5. Documentation of the financial capability of the applicant to provide the proposed services, including the most recent income statement and balance sheet, the most recent projected income statement, and other pertinent financial information. Audited information shall be provided if available; 6. A description of the form of ownership (for example, partnership, corporation); 7. All relevant tax licenses from lawful taxing authorities within the State of Arizona; 8. Such other information as the Commission or the staff may request. C. The applicant shall report in a timely manner during the application process any change(s) in the information initially reported to the Commission in the application for a Certificate of Convenience and Necessity. D. The applicant shall provide public notice of the application as required by the Commission. E. At the time of filing for a Certificate of Convenience and Necessity, each applicant shall notify the Affected Utilities, Utility Distribution Companies or an electric utility not subject to the jurisdiction of the Arizona Corporation Commission in whose service territories it wishes to offer service of the application by serving notification of the application on the Affected Utilities, Utility Distribution Companies or an electric utility not subject to the jurisdiction of the Arizona Corporation Commission. Prior to Commission action, each applicant shall provide written notice to the Commission that it has provided notification to each of the respective Affected Utilities, Utility Distribution Companies or an electric utility not subject to the jurisdiction of the Arizona Corporation Commission. 31 F. The Commission may issue a Certificate of Convenience and Necessity that is effective for a specified period of time if the applicant has limited or no experience in providing the retail electric service that is being requested. An applicant receiving such approval shall have the responsibility to apply for appropriate extensions. G. The Commission may deny certification to any applicant who: 1. Does not provide the information required by this Article; 2. Does not possess adequate technical or financial capabilities to provide the proposed services; 3. Does not have Electric Service Provider Service Acquisition Agreement(s) with a Utility Distribution Company and Scheduling Coordinator, if the applicant is not its own Scheduling Coordinator; 4. Fails to provide a performance bond, if required; 5. Fails to demonstrate that its certification will serve the public interest; 6. Fails to submit an executed Service Acquisition Agreement with a Utility Distribution Company or a Scheduling Coordinator for approval by the Director, Utilities Division prior to the offering of service to potential customers. A Request for approval of an executed Service Acquisition Agreement may be included with an application for a Certificate of Convenience and Necessity. In all negotiations relative to service acquisition agreements Affected Utilities or their successor entities are required to negotiate in good faith. H. Every Electric Service Provider obtaining a Certificate of Convenience and Necessity under this Article shall obtain certification subject to the following conditions: 1. The Electric Service Provider shall comply with all Commission rules, orders, and other requirements relevant to the provision of electric service and relevant to resource planning; 2. The Electric Service Provider shall maintain accounts and records as required by the Commission; 32 3. The Electric Service Provider shall file with the Director, Utilities Division all financial and other reports that the Commission may require and in a form and at such times as the Commission may designate; 4. The Electric Service Provider shall maintain on file with the Commission all current tariffs and any service standards that the Commission shall require; 5. The Electric Service Provider shall cooperate with any Commission investigation of customer complaints; 6. The Electric Service Provider shall obtain all necessary permits and licenses; 7. The Electric Service Provider shall comply with all disclosure requirements pursuant to R14-2-1618; 8. Failure to comply with any of the above conditions may result in recision of the Electric Service Provider's Certificate of Convenience and Necessity. I. In appropriate circumstances, the Commission may require, as a precondition to certification, the procurement of a performance bond sufficient to cover any advances or deposits the applicant may collect from its customers, or order that such advances or deposits be held in escrow or trust. 33 R14-2-1604. Competitive Phases A. Each Affected Utility shall make available at least 20% of its 1995 system retail peak demand for competitive generation supply on a first-come, first-served basis as further described in this rule. 1. All Affected Utility customers with non-coincident peak demand load of 1 MW or greater will be eligible for competitive electric services no later than January 1, 1999. Customers meeting this requirement shall be eligible for competitive services until at least 20% of the Affected Utility's 1995 system peak demand is served by competition. 2. Affected Utility customers with single premise non-coincident peak load demands of 40 kW or greater aggregated into a combined load of 1 MW or greater will be eligible for competitive electric services beginning January 1, 1999. Self-aggregation is also allowed pursuant to the minimum and combined load demands set forth in this rule. If peak load data are not available, the 40 kW criterion shall 34 be determined to be met if the customer's usage exceeded 16,500 kWh in any month within the last 12 consecutive months. From January 1, 1999, through December 31, 2000, aggregation of new competitive customers will be allowed until such time as at least 20% of the Affected Utility's 1995 system peak demand is served by competitors. At that point all additional aggregated customers must wait until January 1, 2001 to obtain competitive service. 3. Affected Utilities shall notify customers eligible under this subsection of the terms of the subsection no later than October 31, 1998. B. As part of the minimum 20% of 1995 system peak demand set forth in R14-2-1604(A), each Affected Utility shall reserve a residential phase-in program with the following components: 1. A minimum of 1/2 of 1% of residential customers as of January 1, 1999 will have access to competitive electric services on January 1, 1999. The number of customers eligible for the residential phase-in program shall increase by an additional 1/2 of 1% every quarter until January 1, 2001. 2. Access to the residential phase-in program will be on a first-come, first-served basis. The Affected Utility shall create and maintain a waiting list to manage the residential phase-in program. 3. Load Profiling may be used; however, residential customers participating in the residential phase-in program may choose other metering options offered by their Electric Service Provider consistent with the Commission's rules on metering. 4. Each Affected Utility shall file a residential phase-in program proposal to the Commission for approval by Director, Utilities Division by September 15, 1998. Interested parties will have until September 29, 1998 to comment on any proposal. At a minimum, the residential phase-in program proposal will include specifics concerning the Affected Utility's proposed: 35 a. Process for customer notification of residential phase-in program; b. Selection and tracking mechanism for customers based on first-come, first-served method; c. Customer notification process and other education and information services to be offered; d. Load Profiling methodology and actual load profiles, if available; and e. Method for calculation of reserved load. 5. Each Affected Utility shall file quarterly residential phase-in program reports within 45 days of the end of each quarter. The first such report shall be due within 45 days of the quarter ending March 31, 1999. The final report due under this rule shall be due within 45 days of the quarter ending December 31, 2002. As a minimum, these quarterly reports shall include: a. The number of customers and the load currently enrolled in residential phase-in program by energy service provider; b. The number of customers currently on the waiting list; c. A description and examples of all customer education programs and other information services including the goals of the education program and a discussion of the effectiveness of the programs; and d. An overview of comments and survey results from participating residential customers. C. Each Affected Utility shall file a report by September 15, 1998, detailing possible mechanisms to provide benefits, such as rate reductions of 3% - 5%, to all Standard Offer customers. D. All customers shall be eligible to obtain competitive electric services no later than January 1, 2001. 36 E. Subject to the minimum 20% limitation described in subsection (A) of this Section, all customers who produce or purchase at least 10% of their annual electricity consumption from photovoltaic or solar thermal electric resources installed in Arizona after January 1, 1997 shall be selected for participation in the competitive market if those customers apply for participation in the competitive market. F. No change. G. An Affected Utility, Utility Distribution Company, or Load-Serving Entity may, beginning January 1, 2001, engage in buy-throughs with individual or aggregated consumers. Any buy-through contract shall ensure that the consumer pays all non-bypassable charges that would otherwise apply. Any contract for a buy-through effective prior to the date indicated in R14-2-1604(A) must be approved by the Commission. 37 H. Schedule Modifications for Cooperatives 1. An electric cooperative may request that the Commission modify the schedule described in R14-2-1604(A) through R14-2-1604(E) so as to preserve the tax exempt status of the cooperative or to allow time to modify contractual arrangements pertaining to delivery of power supplies and associated loans. 2. As part of the request, the cooperative shall propose methods to enhance consumer choice among generation resources. 3. The Commission shall consider whether the benefits of modifying the schedule exceed the costs of modifying the schedule. R14-2-1605. Competitive Services A properly certificated Electric Service Provider may offer any of the following services under bilateral or multilateral contracts with retail consumers: A. No change. B. Any service described in R14-2-1606, except Noncompetitive services as defined by R14-2-1601.29 or Noncompetitive services as defined by the Federal Energy Regulatory Commission Billing and collection services, information services, and self-aggregation services do not require a Certificate of Convenience and Necessity. Aggregation of retail electric customers into a purchasing group is considered to be a competitive service. 38 R14-2-1606. Services Required To Be Made Available A. Each Affected Utility shall make available to all consumers in that class in its service area, as defined on the date indicated in R14-2-1602, Standard Offer bundled generation, transmission, ancillary, distribution, and other necessary services at regulated rates. After January 1, 2001 Standard Offer service shall be provided by Utility Distribution Companies who shall also act as Providers of Last Resort. B. After January 1, 2001, power purchased by a Utility Distribution Company to serve Standard Offer customers, except purchases made through spot markets, shall be acquired through competitive bid. Any resulting contract in excess of 12 months shall contain provisions allowing the Utility Distribution Company to ratchet down its power purchases. A Utility Distribution Company may request that the Commission modify any provision of this subsection for good cause. C. Standard Offer Tariffs 1. By the date indicated in R14-2-1602, each Affected Utility may file proposed tariffs to provide Standard Offer Bundled Service and such rates shall not become effective until approved by the Commission. If no such tariffs are filed, rates and services in existence as of the date in R14-2-1602 shall constitute the Standard Offer. 39 2. Affected Utilities may file proposed revisions to such rates. It is the expectation of the Commission that the rates for Standard Offer service will not increase, relative to existing rates, as a result of allowing competition. Any rate increase proposed by an Affected Utility for Standard Offer service must be fully justified through a rate case proceeding. 3. Such rates shall reflect the costs of providing the service. 4. Consumers receiving Standard Offer service are eligible for potential future rate reductions authorized by the Commission, such as reductions authorized in Decision No. 59601. D. By the date indicated in R14-2-1602, each Affected Utility shall file Unbundled Service tariffs to provide the services listed below to the extent allowed by these rules to all eligible purchasers on a nondiscriminatory basis. Other entities seeking to provide any of these services must also file tariffs consistent with these rules: 1. Distribution Service; 2. Metering and Meter Reading Services; 3. Billing and collection services; 4. Open access transmission service (as approved by the Federal Energy Regulatory Commission, if applicable); 5. Ancillary services in accordance with Federal Energy Regulatory Commission Order 888 (III FERC Stats. & Regs. paragraph 31,036, 1996) incorporated herein by reference; 6. Information services such as provision of customer information to other Electric Service Providers; 7. Other ancillary services necessary for safe and reliable system operation. E. To manage its risks, an Affected Utility or Electric Service Provider may include in its tariffs deposit requirements and advance payment requirements for Unbundled Services. 40 F. The Affected Utilities must provide transmission and ancillary services according to the following guidelines: 1. Services must be provided consistent with applicable tariffs filed with the Federal Energy Regulatory Commission. 2. Unless otherwise required by federal regulation, Affected Utilities must accept power and energy delivered to their transmission systems by others and offer transmission and related services comparable to services they provide to themselves. G. Customer Data 1. Upon written authorization by the customer, a Load-Serving Entity shall release in a timely and useful manner that customer's demand and energy data for the most recent 12-month period to a customer-specified Electric Service Provider. 2. The Electric Service Provider requesting such customer data shall provide an accurate account number for the customer. 3. The form of data shall be mutually agreed upon by the parties and such data shall not be unreasonably withheld. 4. Utility Distribution Companies shall be allowed access to the Meter Reading Service Provider server for customers served by the Utility Distribution Company's distribution system. H. Rates for Unbundled Services 1. The Commission shall review and approve rates for services listed in R14-2-1606(D) and requirements listed in R14-2-1606(E)), where it has jurisdiction, before such services can be offered. 2. Such rates shall reflect the costs of providing the services. 3. Such rates may be downwardly flexible if approved by the Commission. I. Electric Service Providers offering services under this R14-2-1606 shall provide adequate 41 supporting documentation for their proposed rates. Where rates are approved by another jurisdiction, such as the Federal Energy Regulatory Commission, those rates shall be provided to this Commission. R14-2-1607. Recovery of Stranded Cost of Affected Utilities A. The Affected Utilities shall take every reasonable , cost-effective measure to mitigate or offset Stranded Cost by means such as expanding wholesale or retail markets, or offering a wider scope of services for profit, among others. B. The Commission shall allow a reasonable opportunity for recovery of unmitigated Stranded Cost by Affected Utilities. C. The Affected Utilities shall file estimates of unmitigated Stranded Cost. Such estimates shall be fully supported by analyses and by records of market transactions undertaken by willing buyers and willing sellers. 42 D. An Affected Utility shall request Commission approval, on or before August 21, 1998, of distribution charges or other means of recovering unmitigated Stranded Cost from customers who reduce or terminate service from the Affected Utility as a direct result of competition governed by this Article, or who obtain lower rates from the Affected Utility as a direct result of the competition governed by this Article. 43 E. The Commission shall, after hearing and consideration of analyses and recommendations presented by the Affected Utilities, staff, and intervenors, determine for each Affected Utility the magnitude of Stranded Cost, and appropriate Stranded Cost recovery mechanisms and charges. In making its determination of mechanisms and charges, the Commission shall consider at least the following factors: 1. The impact of Stranded Cost recovery on the effectiveness of competition; 2. The impact of Stranded Cost recovery on customers of the Affected Utility who do not participate in the competitive market; 3. The impact, if any, on the Affected Utility's ability to meet debt obligations; 4. The impact of Stranded Cost recovery on prices paid by consumers who participate in the competitive market; 5. The degree to which the Affected Utility has mitigated or offset Stranded Cost; 6. The degree to which some assets have values in excess of their book values; 7. Appropriate treatment of negative Stranded Cost; 8. The time period over which such Stranded Cost charges may be recovered. The Commission shall limit the application of such charges to a specified time period; 9. The ease of determining the amount of Stranded Cost; 10. The applicability of Stranded Cost to interruptible customers; 11. The amount of electricity generated by renewable generating resources owned by the Affected Utility. 44 F. A Competitive Transition Charge (CTC) may be assessed only on customer purchases made in the competitive market using the provisions of this Article. Any reduction in electricity purchases from an Affected Utility resulting from self-generation, demand side management, or other demand reduction attributable to any cause other than the retail access provisions of this Article shall not be used to calculate or recover any Stranded Cost from a consumer. G. Stranded Cost shall be recovered from customer classes in a manner consistent with the specific company's current rate treatment of the stranded asset, in order to effect a recovery of Stranded Cost that is in substantially the same proportion as the recovery of similar costs from customers or customer classes under current rates. H. The Commission may order an Affected Utility to file estimates of Stranded Cost and mechanisms to recover or, if negative, to refund Stranded Cost. I. The Commission may order regular revisions to estimates of the magnitude of Stranded Cost. 45 R14-2-1608. System Benefits Charges A. By the date indicated in R14-2-1602, each Affected Utility or Utility Distribution Company shall file for Commission review non-bypassable rates or related mechanisms to recover the applicable pro-rata costs of System Benefits from all consumers located in the Affected Utility's or Utility Distribution Companies' service area who participate in the competitive market. Affected Utilities or Utility Distribution Companies shall file for review of the Systems Benefits Charge every 3 years. The amount collected annually through the System Benefits charge shall be sufficient to fund the Affected Utilities' or Utility Distribution Companies' Commission-approved low income, demand side management, market transformation, environmental, renewables, long-term public benefit research and development, and nuclear fuel disposal and nuclear power plant decommissioning programs in effect from time to time. Now, the Commission will approve a solar water heater rebate program: $200,000 to be allocated proportionally among the state's Utility Distribution Companies in 1999, $400,000 in 2000, $600,000 in 2001, $800,000 in 2002, and $1 million in 2003; the rebate will not be more than $500 per system for Commission staff-approved solar water heaters. After 2003, future Commissions may review this program for efficacy. B. Each Affected Utility or Utility Distribution Company shall provide adequate supporting documentation for its proposed rates for System Benefits. C. An Affected Utility or Utility Distribution Company shall recover the costs of System Benefits only upon hearing and approval by the Commission of the recovery charge and mechanism. The Commission may combine its review of System Benefits charges with its review of filings pursuant to R14-2-1606. 46 R14-2-1609. Solar Portfolio Standard A. Starting on January 1, 1999, any Electric Service Provider selling electricity or aggregating customers for the purpose of selling electricity under the provisions of this Article must derive at least .2% of the total retail energy sold competitively from new solar energy resources, whether that solar energy is purchased or generated by the seller. Solar resources include photovoltaic resources and solar thermal resources that generate electricity. New solar resources are those installed on or after January 1, 1997. B. Starting January 1 of each year from 2000 through 2003, the solar resource requirement shall increase by .2% with the result that starting January 1, 2003, any Electric Service Provider selling electricity or aggregating customers for the purpose of selling electricity under the provisions of this Article must derive at least 1.0% of the total retail energy sold competitively from new solar energy resources. The 1.0% requirement shall be in effect from January 1, 2003 through December 31, 2012. 47 C. The solar portfolio requirement shall only apply to competitive retail electricity in the years 1999 and 2000 and shall apply to all retail electricity in the years 2001 and thereafter. D. Electric Service Providers shall be eligible for a number of extra credit multipliers that may be used to meet the solar portfolio standard requirements: 1. Early Installation Extra Credit Multiplier: For new solar electric systems installed and operating prior to December 31, 2003, Electric Service Providers would qualify for multiple extra credits for kWh produced for 5 years following operational start-up of the solar electric system. The 5-year extra credit would vary depending upon the year in which the system started up, as follows: YEAR EXTRA CREDIT MULTIPLIER ---- ----------------------- 1997 .5 1998 .5 1999 .5 2000 .4 2001 .3 2002 .2 2003 .1 The Early Installation Extra Credit Multiplier would end in 2003. 2. Solar Economic Development Extra Credit Multipliers: There are 2 equal parts to this multiplier, an in-state installation credit and an in-state content multiplier. 48 a. In-State Power Plant Installation Extra Credit Multiplier: Solar electric power plants installed in Arizona shall receive a .5 extra credit multiplier. b. In-State Manufacturing and Installation Content Extra Credit Multiplier: Solar electric power plants shall receive up to a .5 extra credit multiplier related to the manufacturing and installation content that comes from Arizona. The percentage of Arizona content of the total installed plant cost shall be multiplied by .5 to determine the appropriate extra credit multiplier. So, for instance, if a solar installation included 80% Arizona content, the resulting extra credit multiplier would be .4 (which is .8 X .5). 3. Distributed Solar Electric Generator and Solar Incentive Program Extra Credit Multiplier: Any distributed solar electric generator that meets more than one of the eligibility conditions will be limited to only one .5 extra credit multiplier from this subsection. Appropriate meters will be attached to each solar electric generator and read at least once annually to verify solar performance. a. Solar electric generators installed at or on the customer premises in Arizona. Eligible customer premises locations will include both grid-connected and remote, non-grid-connected locations. In order for Electric Service Providers to claim an extra credit multiplier, the Electric Service Provider must have contributed at least 10% of the total installed cost or have financed at least 80% of the total installed cost. b. Solar electric generators located in Arizona that are included in any Electric Service Provider's Green Pricing program. c. Solar electric generators located in Arizona that are included in any Electric Service Provider's Net Metering or Net Billing program. d. Solar electric generators located in Arizona that are included in any Electric Service Provider's solar leasing program. e. All Green Pricing, Net Metering, Net Billing, and Solar Leasing programs 49 must have been reviewed and approved by the Director, Utilities Division in order for the Electric Service Provider to accrue extra credit multipliers from this subsection. 4. All multipliers are additive, allowing a maximum combined extra credit multiplier of 2.0 in years 1997-2003, for equipment installed and manufactured in Arizona and either installed at customer premises or participating in approved solar incentive programs. So, if an Electric Service Provider qualifies for a 2.0 extra credit multiplier and it produces 1 solar kWh, the Electric Service Provider would get credit for 3 solar kWh (1 produced plus 2 extra credit). E. No change. F. If an Electric Service Provider selling electricity under the provisions of this Article fails to meet the requirement in R14-2-1609(A) or (B) in any year, the Commission shall impose a penalty on that Electric Service Provider that the Electric Service Provider pay an amount equal to 30 cents per kWh to the Solar Electric Fund for deficiencies in the provision of solar electricity . This Solar Electric Fund will be established and utilized to purchase solar electric generators or solar electricity in the following calendar year for the use by public entities in Arizona such as schools, cities, counties, or state agencies. Title to any equipment purchased by the Solar Electric Fund will be transferred to the public entity. In addition, if the provision of solar energy is consistently deficient, the Commission may void an Electric Service Provider's contracts negotiated under this Article. 1. The Director, Utilities Division shall establish a Solar Electric Fund in 1999 to receive deficiency payments and finance solar electricity projects. 2. The Director, Utilities Division shall select an independent administrator for the selection of projects to be financed by the Solar Electric Fund. A portion of the Solar Electric Fund shall be used for administration of the Fund and a designated portion of the Fund will be set aside for ongoing operation and maintenance of projects financed by the Fund. 50 G. Photovoltaic or solar thermal electric resources that are located on the consumer's premises shall count toward the solar portfolio standard applicable to the current Electric Service Provider serving that consumer. H. Any solar electric generators installed by an Affected Utility to meet the solar portfolio standard shall be counted toward meeting renewable resource goals for Affected Utilities established in Decision No. 58643. I. Any Electric Service Provider or independent solar electric generator that produces or purchases any solar kWh in excess of its annual portfolio requirements may save or bank those excess solar kWh for use or sale in future years. Any eligible solar kWh produced subject to this rule may be sold or traded to any Electric Service Provider that is subject to this rule. Appropriate documentation, subject to Commission review, shall be given to the purchasing entity and shall be referenced in the reports of the Electric Service Provider that is using the purchased kWh to meet its portfolio requirements. J. Solar portfolio standard requirements shall be calculated on an annual basis, based upon electricity sold during the calendar year. K. An Electric Service Provider shall be entitled to receive a partial credit against the solar portfolio requirement if the Electric Service Provider or its affiliate owns or makes a significant investment in any solar electric manufacturing plant that is located in Arizona. The credit will be equal to the amount of the nameplate capacity of the solar electric generators produced in Arizona and sold in a calendar year times 2,190 hours (approximating a 25% capacity factor). 1. The credit against the portfolio requirement shall be limited to the following percentages of the total portfolio requirement: 1999 Maximum of 50 % of the portfolio requirement 2000 Maximum of 50 % of the portfolio requirement 2001 Maximum of 25 % of the portfolio requirement 51 2002 Maximum of 25 % of the portfolio requirement 2003 and on Maximum of 20 % of the portfolio requirement 2. No extra credit multipliers will be allowed for this credit. In order to avoid double-counting of the same equipment, solar electric generators that are used by other Electric Service Providers to meet their Arizona solar portfolio requirements will not be allowable for credits under this Section for the manufacturer/Electric Service Provider to meet its portfolio requirements. L. The Director, Utilities Division shall develop appropriate safety, durability, reliability, and performance standards necessary for solar generating equipment to qualify for the solar portfolio standard. Standards requirements will apply only to facilities constructed or acquired after the standards are publicly issued. R14-2-1610. Transmission and Distribution Access A. The Affected Utilities shall provide non-discriminatory open access to transmission and distribution facilities to serve all customers. No preference or priority shall be given to any distribution customer based on whether the customer is purchasing power under the Affected Utility's Standard Offer or in the competitive market. Any transmission capacity that is reserved for use by the retail customers of the Affected Utility's Utility Distribution Company shall be allocated among Standard Offer customers and competitive market customers on a pro-rata basis. B. The Commission supports the development of an Independent System Operator (ISO) or, absent an Independent System Operator, an Independent Scheduling Administrator (ISA). 52 C. The Commission believes that an Independent Scheduling Administrator is necessary in order to provide non-discriminatory retail access and to facilitate a robust and efficient electricity market. Therefore, those Affected Utilities that own or operate Arizona transmission facilities shall file with the Federal Energy Regulatory Commission by October 31, 1998 for approval of an Independent Scheduling Administrator having the following characteristics: 1. The Independent Scheduling Administrator shall calculate Available Transmission Capacity (ATC) for Arizona transmission facilities that belong to the Affected Utilities or other Independent Scheduling Administrator participants, and shall develop and operate an overarching statewide OASIS. 2. The Independent Scheduling Administrator shall implement and oversee the non-discriminatory application of protocols to ensure statewide consistency for transmission access. These protocols shall include, but are not limited to, protocols for determining transmission system transfer capabilities, committed uses of the transmission system, available transfer capabilities, and Must-Run Generating Units. 3. The Independent Scheduling Administrator shall provide dispute resolution processes that enable market participants to expeditiously resolve claims of discriminatory treatment in the reservation, scheduling, use and curtailment of transmission services. 4. All requests (wholesale, Standard Offer retail, and competitive retail) for reservation and scheduling of the use of Arizona transmission facilities that belong to the Affected Utilities or other Independent Scheduling Administrator participants shall be made to, or through, the Independent Scheduling Administrator using a single, standardized procedure. 53 D. The Affected Utilities that own or operate Arizona transmission facilities shall file a proposed Independent Scheduling Administrator implementation plan with the Commission by September 1, 1998. The implementation plan shall address Independent Scheduling Administrator governance, incorporation, financing and staffing; the acquisition of physical facilities and staff by the Independent Scheduling Administrator; the schedule for the phased development of Independent Scheduling Administrator functionality; contingency plans to ensure that critical functionality is in place by January 1, 1999; and any other significant issues related to the timely and successful implementation of the Independent Scheduling Administrator. E. Each of the Affected Utilities shall make good faith efforts to develop a regional, multi-state Independent System Operator, to which the Independent Scheduling Administrator should transfer its relevant assets and functions as the Independent System Operator becomes able to carry out those functions. F. It is the intent of the Commission that prudently-incurred costs incurred by the Affected Utilities in the establishment and operation of the Independent Scheduling Administrator, and subsequently the Independent System Operator, should be recovered from customers using the transmission system, including the Affected Utilities' wholesale customers, Standard Offer retail customers, and competitive retail customers on a non-discriminatory basis through Federal Energy Regulatory Commission-regulated prices. Proposed rates for the recovery of such costs shall be filed with the Federal Energy Regulatory Commission and the Commission. In the event that the Federal Energy Regulatory Commission does not permit recovery of prudently incurred Independent Scheduling Administrator costs within 90 days of the date of making an application with the Federal Energy Regulatory Commission, the Commission may authorize Affected Utilities to recover such costs through a distribution surcharge. G. The Commission supports the use of "Scheduling Coordinators" to provide aggregation of customers' schedules to the Independent Scheduling Administrator and the respective Control Area Operators simultaneously until the implementation of a regional 54 Independent System Operator, at which time the schedules will be submitted to the Independent System Operator. The primary duties of Scheduling Coordinators are to: 1. Forecast their customers' load requirements; 2. Submit balanced schedules (i.e., schedules for which total generation is equal to total load of the Scheduling Coordinator's customers plus appropriate transmission losses) and North American Electric Reliability Council/Western Systems Coordinating Council tags; 3. Arrange for the acquisition of the necessary transmission and ancillary services; 4. Respond to contingencies and curtailments as directed by the Control Area Operators, Independent Scheduling Administrator or Independent System Operator; 5. Actively participate in the schedule checkout process and the settlement processes of the Control Area Operators, Independent Scheduling Administrator or Independent System Operator. H. The Affected Utilities shall provide services from the Must-Run Generating Units to Standard Offer retail customers and competitive retail customers on a comparable, non-discriminatory basis at regulated prices. The Affected Utilities shall specify the obligations of the Must-Run Generating Units in appropriate sales contracts prior to any divestiture. Under auspices of the Electric System Reliability and Safety Working Group, the Affected Utilities shall develop statewide protocols for pricing and availability of services from Must-Run Generating Units with input from other stakeholders. These protocols shall be presented to the Commission for review and filed with the Federal Energy Regulatory Commission, if necessary, by October 31, 1998. R14-2-1611. In-state Reciprocity A. No change. B. No change. C. No change. 55 D. If an electric utility is an Arizona political subdivision or municipal corporation, then the existing service territory of such electric utility shall be deemed open to competition if the political subdivision or municipality has entered into an intergovernmental agreement with the Commission that establishes nondiscriminatory terms and conditions for Distribution Services and other Unbundled Services, provides a procedure for complaints arising therefrom, and provides for reciprocity with Affected Utilities or their affiliates. The Commission shall conduct a hearing to consider any such intergovernmental agreement. E. An affiliate of an Arizona electric utility which is not an Affected Utility shall not be allowed to compete in the service territories of Affected Utilities unless the affiliate's parent company, the non-affected electric utility, submits a statement to the Commission indicating that the parent company will voluntarily open its service territory for competing sellers in a manner similar to the provisions of this Article and the Commission makes a finding to that effect. R14-2-1612. Rates A. No change. B. No change. C. Prior to the date indicated in R14-2-1604(D), competitively negotiated contracts governed by this Article customized to individual customers which comply with approved tariffs do not require further Commission approval. However, all such contracts whose term is 1 year or more and for service of 1 MW or more must be filed with the Director, Utilities Division as soon as practicable. If a contract does not comply with the provisions of this Article and the Affected Utility's or Electric Service Provider's approved tariffs, it shall not become effective without a Commission order. Such contracts shall be kept confidential by the Commission. D. Contracts entered into on or after the date indicated in R14-2-1604(D) which comply with approved tariffs need not be filed with the Director, Utilities Division. If a contract does not comply with the provisions of this Article and the Affected Utility's or 56 the Electric Service Provider's approved tariffs it shall not become effective without a Commission order. E. No change. F. No change. R14-2-1613. Service Quality, Consumer Protection, Safety, and Billing Requirements A. Except as indicated elsewhere in this Article, R14-2-201 through R14-2-212, inclusive, are adopted in this Article by reference. However, where the term "utility" is used in R14-2-201 through R14-2-212, the term "utility" shall pertain to Electric Service Providers providing the services described in each paragraph of R14-2-201 through R14-2-212. R14-2-203(E) and R14-2-212(H) shall pertain only to Utility Distribution Companies. B. The following shall not apply to this Article: 1. R14-2-202 in its entirety, 2. R14-2-206 in its entirety, 3. R14-2-207 in its entirety, 4. R14-2-212 (F)(1), 5. R14-2-213, 6. R14-2-208(E) and (F). C. No consumer shall be deemed to have changed providers of any service authorized in this Article (including changes from supply by the Affected Utility to another provider) without written authorization by the consumer for service from the new provider. If a consumer is switched (or slammed) to a different ("new") provider without such written authorization, the new provider shall cause service by the previous provider to be resumed and the new provider shall bear all costs associated with switching the consumer back to the previous provider. A written authorization that is obtained by deceit or deceptive 57 practices shall not be deemed a valid written authorization. Providers shall submit reports within 30 days of the end of each calendar quarter to the Commission itemizing the direct complaints filed by customers who have had their Electric Service Providers changed without their authorization. Violations of the Commission's rules concerning slamming may result in fines and penalties, including but not limited to suspension or revocation of the provider's certificate. D. Each Electric Service Provider providing service governed by this Article shall be responsible for meeting applicable reliability standards and shall work cooperatively with other companies with whom it has interconnections, directly or indirectly, to ensure safe, reliable electric service. Utility Distribution Companies shall make reasonable efforts to notify customers of scheduled outages, and also provide notification to the Commission. E. Each Electric Service Provider shall provide at least 45 days notice to all of its affected consumers of its intent to cease providing generation, transmission, distribution, or ancillary services necessitating that the consumer obtain service from another supplier of generation, transmission, distribution, or ancillary services. F. No change. G. No change. H. Electric Service Providers shall give at least 5 days notice to their customer of scheduled return to the Standard Offer, but that return of that customer to the Standard Offer would be at the next regular billing cycle. Responsibility for charges incurred between the notice and the next scheduled read date shall rest with the Electric Service Provider. I. Each Electric Service Provider shall ensure that bills rendered on its behalf include its address and toll free telephone numbers for billing, service, and safety inquiries. The bill must also include the address and toll free telephone numbers for the Phoenix and Tucson Consumer Service Sections of the Arizona Corporation Commission Utilities Division. 58 Each Electric Service Provider shall ensure that billing and collections services rendered on its behalf comply with R14-2-1613(A). J. Additional Provisions for Metering and Meter Reading Services 1. An Electric Service Provider who provides metering or meter reading services pertaining to a particular consumer shall provide access to meter reading data other Electric Service Providers serving that same consumer when authorized by the consumer. 2. Any person or entity relying on metering information provided by another Electric Service Provider may request a meter test according to the tariff on file and approved by the Commission. However, if the meter is found to be in error by more than 3%, no meter testing fee will be charged. 3. Each competitive customer shall be assigned a Universal Node Identifier for each service delivery point by the Affected Utility or the Utility Distribution Company whose distribution system serves the customer. 4. All competitive metered and billing data shall be translated into a consistent, statewide Electronic Data Interchange (EDI) format based on standards approved by the Utility Industry Group (UIG) that can be used by the Affected Utility or the Utility Distribution Company and the Electric Service Provider. 5. An Electronic Data Interchange Format shall be used for all data exchange transactions from the Meter Reading Service Provider to the Electric Service Provider, Utility Distribution Company, and Schedule Coordinator. This data will be transferred via the Internet using a secure sockets layer or other secure electronic media. 59 6. Minimum metering requirements for competitive customers over 20 kW, or 100,000 kWh annually, should consist of hourly consumption measurement meters or meter systems. 7. Competitive customers with hourly loads of 20 kW (or 100,000 kWh annually) or less, will be permitted to use Load Profiling to satisfy the requirements for hourly consumption data. 8. Meter ownership will be limited to the Affected Utility, Utility Distribution Company, and the Electric Service Provider, or the customer, who will obtain the meter from the Affected Utility, or Utility Distribution Company or an Electric Service Provider. 9. Maintenance and servicing of the metering equipment will be limited to the Affected Utility, Utility Distribution Company and the Electric Service Provider or their representative. 10. Distribution primary voltage Current Transformers and Potential Transformers may be owned by the Affected Utility, Utility Distribution Company or the Electric Service Provider or their representative. 11. Transmission primary voltage Current Transformers and Potential Transformers may be owned by the Affected Utility or Utility Distribution Company only. 12. North American Electric Reliability Council recognized holidays will be used in calculating "working days" for meter data timeliness requirements. 13. The operating procedures approved by the Director, Utilities Division will be used by the Utility Distribution Companies and the Meter Service Providers for performing work on primary metered customers. 14. The rules approved by the Director, Utilities Division will be used by the Meter Reading Service Provider for validating, editing, and estimating metering data. 15. The performance metering specifications and standards approved by the Director, Utilities Division will be used by all entities performing metering. 60 K. Working Group on System Reliability and Safety 1. The Commission shall establish, by separate order, a working group to monitor and review system reliability and safety. a. The working group may establish technical advisory panels to assist it. b. Members of the working group shall include representatives of staff, consumers, the Residential Utility Consumer Office, utilities, other Electric Service Providers and organizations promoting energy efficiency. In addition, the Executive and Legislative Branches shall be invited to send representatives to be members of the working group. c. The working group shall be coordinated by the Director, Utilities Division of the Commission or by his or her designee. 2. All Electric Service Providers governed by this Article shall cooperate and participate in any investigation conducted by the working group, including provision of data reasonably related to system reliability or safety. 3. The working group shall report to the Commission on system reliability and safety regularly, and shall make recommendations to the Commission regarding improvements to reliability or safety. L. Electric Service Providers shall comply with applicable reliability standards and practices established by the Western Systems Coordinating Council and the North American Electric Reliability Council or successor organizations. M. Electric Service Providers shall provide notification and informational materials to consumers about competition and consumer choices, such as a standardized description of services, as ordered by the Commission. N. Unbundled Billing Elements All customer bills after January 1, 1999 will list, at a minimum, the following billing cost elements: 61 1. Electricity Costs a. Generation b. Competition Transition Charge c. Fuel or purchased power adjustor, if applicable 2. Delivery costs a. Distribution services b. Transmission services c. Ancillary services 3. Other Costs a. Metering Service b. Meter Reading Service c. Billing and collection d. System Benefits charge O. The operating procedures approved by the Director, Utilities Division will be used for Direct Access Service Requests as well as other billing and collection transactions. R14-2-1614. Reporting Requirements A. Reports covering the following items, as applicable, shall be submitted to the Director, Utilities Division by Affected Utilities or Utility Distribution Companies and all Electric Service Providers granted a Certificate of Convenience and Necessity pursuant to this Article. These reports shall include the following information pertaining to competitive service offerings, Unbundled Services, and Standard Offer services in Arizona: 1. Type of services offered; 2. kW and kWh sales to consumers, disaggregated by customer class (for example, residential, commercial, industrial); 3. Solar energy sales (kWh) and sources for grid connected solar resources; kW capacity for off-grid solar resources; 62 4. Revenues from sales by customer class (for example, residential, commercial, industrial); 5. Number of retail customers disaggregated as follows: residential, commercial under 40 kW, commercial 41 to 999 kW, , commercial 1000 kW or more, industrial less than 1000 kW, industrial 1000 kW or more, agricultural (if not included in commercial), and other; 6. Retail kWh sales and revenues disaggregated by term of the contract (less than 1 year, 1 to 4 years, longer than 4 years), and by type of service (for example, firm, interruptible, other); 7. Amount of and revenues from each service provided under R14-2-1605, and, if applicable, R14-2-1606; 8. Value of all assets used to serve Arizona customers and accumulated depreciation; 9. Tabulation of Arizona electric generation plants owned by the Electric Service Provider broken down by generation technology, fuel type, and generation capacity; 10. The number of customers aggregated and the amount of aggregated load; 11. Other data requested by staff or the Commission; 12. In addition, prior to the date indicated in R14-2-1604(D), Affected Utilities shall provide data demonstrating compliance with the requirements of R14-2-1604. B. No change. C. No change. D. No change. E. No change. F. No change. 63 G. No change. R14-2-1615. Administrative Requirements A. Any Electric Service Provider certificated under this Article may file proposed additional tariffs for services at any time which include a description of the service, maximum rates, terms and conditions. The proposed new service may not be provided until the Commission has approved the tariff. B. No change. C. No change. D. No change. R14-2-1616. Separation of Monopoly and Competitive Services A. All competitive generation assets and competitive services shall be separated from an Affected Utility prior to January 1, 2001. Such separation shall either be to an unaffiliated party or to a separate corporate affiliate or affiliates. If an Affected Utility chooses to transfer its competitive generation assets or competitive services to a competitive electric affiliate, such transfer shall be at a value determined by the Commission to be fair and reasonable. B. Beginning January 1, 1999, an Affected Utility or Utility Distribution Company shall not provide competitive services as defined herein, except as otherwise authorized by these rules or by the Commission. However, this rule does not preclude an Affected Utility's or Utility Distribution Company's affiliate from providing competitive services. Nor does this rule preclude an Affected Utility or Utility Distribution Company from billing its own customers for distribution service, or from providing billing services to Electric Service Providers in conjunction with its own billing or from providing meters for Load Profiled residential customers. Nor does this rule require an Affected Utility or Utility Distribution Company to separate such assets or services utilized in these circumstances. Affected Utilities and Utility Distribution Companies may provide metering, meter 64 reading, billing, and collection services within their service territories at tariffed rates to customers that do not have access to these services. C. An Electric Distribution Cooperative is not subject to the provisions of R14-2-1616 except if it offers competitive electric services outside of the service territory it had as of the effective date of these rules. D. To meet the solar portfolio requirement in R14-2-1609, the Utility Distribution Company may purchase, install, and operate the solar electric systems or contract with an affiliate to meet the solar portfolio requirement. R14-2-1617. Affiliate Transactions A. Separation 65 An Affected Utility or Utility Distribution Company and its affiliates shall operate as separate corporate entities. Books and records shall be kept separate, in accordance with applicable Uniform System of Accounts (USOA) and Generally Accepted Accounting Procedures (GAAP). The books and records of any Electric Service Provider that is an affiliate of an Affected Utility or Utility Distribution Company shall be open for examination by the Commission and its staff consistent with the provisions set forth in R14-2-1614. All proprietary information shall remain confidential. 1. An Affected Utility or Utility Distribution Company shall not share office space, equipment, services, and systems with its competitive electric affiliates, nor access any computer or information systems of one another, except to the extent appropriate to perform shared corporate support functions permitted under subsection (A)(2). An Affected Utility or Utility Distribution Company shall not share office space, equipment, services, and systems with its other affiliates without full compensation in accordance with subsection (A)(7). 2. An Affected Utility or Utility Distribution Company, its parent holding company, or a separate affiliate created solely for the purpose of corporate support functions, may share with its affiliates joint corporate oversight, governance, support systems and personnel. Any shared support shall be priced, reported and conducted in accordance with all applicable Commission pricing and reporting requirements. An Affected Utility or Utility Distribution Company shall not use shared corporate support functions as a means to transfer confidential information, allow preferential treatment, or create significant opportunities for cross-subsidization of its affiliates, and shall provide mechanisms and safeguards against such activity in its compliance plan. 3. An affiliate of an Affected Utility or Utility Distribution Company shall not trade, promote, or advertise its affiliation with the Affected Utility or Utility Distribution Company, nor use or make use of the Affected Utility's name or logo 66 in any material circulated by the affiliate, unless it discloses in plain legible or audible language, on the first page or at the first instance the Affected Utility or Utility Distribution Company name or logo appears, that: a. The affiliate is not the same company as the Affected Utility or Utility Distribution Company, and b. Customers do not have to buy the affiliate product in order to continue to receive quality regulated services from the Affected Utility or Utility Distribution Company. 4. An Affected Utility or Utility Distribution Company shall not offer or provide to its affiliates advertising space in any customer written communication unless it provides access to all other unaffiliated service providers on the same terms and conditions. 5. An Affected Utility or Utility Distribution Company shall not participate in joint advertising, marketing or sales with its affiliates. Any joint communication and correspondence with an existing customer by an Affected Utility or Utility Distribution Company and its affiliate shall be limited to consolidated billing, when applicable, and in accordance with these rules. 6. Except as provided in subsection A(2), an Affected Utility or Utility Distribution Company and its affiliate shall not jointly employ the same employees. This rule applies to Board of Directors and corporate officers. However, any board member or corporate officer of a holding company may also serve in the same capacity with the Affected Utility or Utility Distribution Company, or its affiliate, but not both. Where the Affected Utility is a multi-state utility, is not a member of a holding company structure, and assumes the corporate governance functions for its affiliates, the prohibition outlined in this section shall only apply to affiliates that operate within Arizona 67 7. Transfer of Goods and Services: To the extent that these rules do not prohibit transfer of goods and services between an Affected Utility or Utility Distribution Company and its affiliates, all such transfers shall be subject to the following price provisions: a. Goods and services provided by an Affected Utility or Utility Distribution Company to an affiliate shall be transferred at the price and under the terms and conditions specified in its tariff. If the goods or service to be transferred is a non-tariffed item, the transfer price shall be the higher of fully allocated cost or the market price. Transfers from an affiliate to its affiliated Utility Distribution Company shall be priced at the lower of fully allocated cost or fair market value. b. Goods and services produced, purchased or developed for sale on the open market by the Affected Utility or Utility Distribution Company will be provided to its affiliates and unaffiliated companies on a nondiscriminatory basis, except as otherwise permitted by these rules or applicable law. 8. No Cross-subsidization: A competitive affiliate of an Affected Utility or Utility Distribution Company shall not be subsidized by any rate or charge for any noncompetitive service, and shall not be provided access to confidential utility information. B. Access to Information As a general rule, an Affected Utility, Utility Distribution Company or Electric Service Provider shall provide customer information to its affiliates and nonaffiliates on a non-discriminatory basis, provided prior affirmative customer written consent is obtained. Any non-customer specific non-public information shall be made contemporaneously available by an Affected Utility, Utility Distribution Company or Electric Service Provider to its affiliates and all other service providers on the same terms and conditions. 68 C. An Affected Utility or Utility Distribution Company shall adhere to the following guidelines: 1. Any list of Electric Service Providers provided by an Affected Utility or Utility Distribution Company to its customers which includes or identifies the Affected Utility's or Utility Distribution Company's competitive electric affiliates must include or identify non-affiliated entities included on the list of those Electric Service Providers authorized by the Commission to provide service within the Affected Utility's or Utility Distribution Company's certificated area. The Commission shall maintain an updated list of such Electric Service Providers and make that list available to Affected Utilities or Utility Distribution Companies at no cost. 2. An Affected Utility or Utility Distribution Company may provide non-public supplier information and data, which it has received from unaffiliated suppliers, to its affiliates or nonaffiliated entities only if the Affected Utility or Utility Distribution Company receives prior authorization from the supplier. 3. Except as otherwise provided in these rules, an Affected Utility or Utility Distribution Company shall not offer or provide customers advice, which includes promoting, marketing or selling, about its affiliates or other service providers. 4. An Affected Utility or Utility Distribution Company shall maintain contemporaneous records documenting all tariffed and nontariffed transactions with its affiliates, including but not limited to, all waivers of tariff or contract provisions and all discounts. These records shall be maintained for a period of 3 years, or longer if required by this Commission or another governmental agency. D. Nondiscrimination An Affected Utility, Utility Distribution Company, or their affiliates shall not represent that, as a result of the affiliation, customers of such affiliates will receive any treatment different from that provided to other, non-affiliated entities or their customers. An Affected Utility, Utility Distribution Company, or their affiliates shall not provide their 69 affiliates, or customers of their affiliates, any preference over non-affiliated suppliers or their customers in the provision of services. For example: 1. Except when made generally available by an Affected Utility, Utility Distribution Company or their affiliates, through an open competitive bidding process, if the Affected Utility, Utility Distribution Company or their affiliates offers a discount or waives all or any part of any charge or fee to its affiliates, or offers a discount or waiver for a transaction in which their affiliates are involved, the entity shall contemporaneously make such discount or waiver available to all. 2. If a tariff provision allows for discretion in its application, an Affected Utility or Utility Distribution Company shall apply that provision equally among its affiliates and all other market participants and their respective customers. 3. Requests from affiliates and non-affiliated entities and their customers for services provided by the Affected Utility or Utility Distribution Company shall be processed on a nondiscriminatory basis. 4. An Affected Utility or Utility Distribution Company shall not condition or otherwise tie the provision of any service provided, nor the availability of discounts of rates or other charges or fees, rebates or waivers of terms and conditions of any services, to the taking of any goods or services from its affiliates. 5. In the course of business development and customer relations, except as otherwise provided in these rules, an Affected Utility or Utility Distribution Company shall refrain from: a. Providing leads to its affiliates; b. Soliciting business on behalf of affiliates; c. Acquiring information on behalf of, or provide information to, its affiliates; 70 d. Sharing market analysis reports or any non-publicly available reports, including but not limited to market, forecast, planning or strategic reports, with its affiliates. E. Compliance Plans No later than December 31, 1998, each Affected Utility or Utility Distribution Company shall file a compliance plan demonstrating the procedures and mechanisms implemented to ensure that activity prohibited by these rules will not take place. The compliance plan shall be submitted to the Director, Utilities Division and shall be in effect until a determination is made regarding its compliance under these rules. The compliance plan shall thereafter be submitted annually to reflect any material changes. No later than December 31, 1999, and every year thereafter until December 31, 2002, an Affected Utility or Utility Distribution Company shall have a performance audit prepared by an independent auditor to examine compliance with the rules set forth herein. Such audits shall be filed with the Director, Utilities Division. After December 31, 2002 the Director, Utilities Division may request a Utility Distribution Company to conduct such an audit. F. Waivers 1. Any affected entity may petition the Commission for a waiver by filing a verified application for waiver setting forth with specificity the circumstances whereby the public interest justifies a waiver from all or part of the provisions of this rule. 2. The Commission may grant such application upon a finding that a waiver is in the public interest. R14-2-1618 Disclosure of Information A. There are efforts under the auspices of the Western Conference of Public Service Commissioners to develop a tracking mechanism as to the source of electrons. To facilitate customer choice, the Commission intends to participate in developing this tracking mechanism and a side-by-side comparison for retail customers on price, price variability, fuel mix, and emissions of electricity offered for sale in Arizona and the West. Until this is accomplished, R14-2-1618 is a placeholder. 71 B. Each Load-Serving Entity shall prepare a consumer information label that sets forth the following information for customers with a demand of less than 1 MW: 1. Price to be charged for generation services, 2. Average price for generation service for each customer class, 3. Price variability information, 4. Customer service information, 5. Composition of resource portfolio, 6. Fuel mix characteristics of the resource portfolio, 7. Emissions characteristics of the resource portfolio, 8. Time period to which the reported information applies. C. The Director, Utilities Division shall develop the format and reporting requirements for the consumer information label to ensure that the information required by subsection (A) is appropriately and accurately reported and to ensure that customers can use the labels for comparisons among Load-Serving Entities. The format developed by the Director, Utilities Division shall be used by each Load-Serving Entity. D. Each Load-Serving Entity shall include the information disclosure label in a prominent position in all written marketing materials, including electronically published materials. When a Load-Serving Entity advertises in non-print media, the marketing materials shall indicate that the Load-Serving Entity shall provide the consumer information label to the public upon request. E. Each Load-Serving Entity shall prepare an annual disclosure report that aggregates the resource portfolios of the Load-Serving Entity and its affiliates. F. Each Load-Serving Entity shall prepare a statement of its terms of service that sets forth the following information: 1. Actual pricing structure or rate design according to which the customer with a load of less than 1 MW will be billed, including an explanation of price variability and price level adjustments that may cause the price to vary; 72 2. Length and description of the applicable contract and provisions and conditions for early termination by either party; 3. Due date of bills and consequences of late payment; 4. Conditions under which a credit agency is contacted; 5. Deposit requirements and interest on deposits; 6. Limits on warranties and damages; 7. All charges, fees, and penalties; 8. Information on consumer rights pertaining to estimated bills, third party billing, deferred payments, recission of supplier switches within 3 days of receipt of confirmation; 9. A toll-free telephone number for service complaints; 10. Low income rate eligibility; 11. Provisions for default service; 12. Applicable provisions of state utility laws; and 13. Method whereby customers will be notified of changes to the terms of service. G. The consumer information label, the disclosure report, and the terms of service shall be distributed in accordance with the following requirements: 1. Prior to the initiation of service for any retail customer, 2. Prior to processing written authorization from a retail customer with a load of less than 1 MW to change Electric Service Providers, 3. To any person upon request, 4. Made a part of the annual report required to be filed with the Commission pursuant to law. 5. The information described in this subsection shall be posted on any electronic information medium of the Load-Serving Entities. H. Failure to comply with the rules on information disclosure or dissemination of inaccurate information may result in suspension or revocation of certification or other penalties as determined by the Commission. 73 I. The Commission may establish a consumer information advisory panel to review the effectiveness of the provisions of this Section and to make recommendations for changes in the rules. 74 EX-27 3 FINANCIAL DATA SCHEDULE
UT 1,000 U.S. Dollars 6-MOS DEC-31-1998 JAN-01-1998 JUN-30-1998 1 PER-BOOK $4,682,549 180,393 364,651 1,067,411 0 6,295,004 178,162 1,143,586 479,690 1,801,438 15,377 124,034 1,861,783 0 0 213,485 154,220 0 0 0 2,124,667 6,295,004 822,138 64,397 612,901 677,298 144,840 7,028 151,868 67,749 84,119 5,313 78,806 127,500 58,953 240,068 0 0
-----END PRIVACY-ENHANCED MESSAGE-----