-----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, SfDYKQvepvUbc1xUXkB8EVbnoJbihL0EcE2r7qrxyW5Y6MKTiI0qTM5kuig4jobA AB6ugRPtZHYZpa0Nb/eIpQ== 0000950147-96-000175.txt : 19960515 0000950147-96-000175.hdr.sgml : 19960515 ACCESSION NUMBER: 0000950147-96-000175 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19960331 FILED AS OF DATE: 19960514 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: 1934 Act SEC FILE NUMBER: 001-04473 FILM NUMBER: 96563390 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 FORM 10-Q 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 March 31, 1996 --------------------------- OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to --------------- ---------------- Commission file number 1-4473 ------------- ARIZONA PUBLIC SERVICE COMPANY ------------------------------------------------------ (Exact name of registrant as specified in its charter) Arizona 86-0011170 - ------------------------------- ------------------- (State or other jurisdiction 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 May 14, 1996: 71,264,947 -i- Glossary -------- ACC - Arizona Corporation Commission ACC Staff - Staff of the Arizona Corporation Commission AFUDC - Allowance for funds used during construction Company - Arizona Public Service Company EPA - Environmental Protection Agency ITC - Investment tax credit 1995 10-K - Arizona Public Service Company Annual Report on Form 10-K for the fiscal year ended December 31, 1995 Palo Verde - Palo Verde Nuclear Generating Station Pinnacle West - Pinnacle West Capital Corporation PRP's - Potentially Responsible Parties SEC - Securities and Exchange Commission Superfund - Comprehensive Environmental Response, Compensation, and Liability Act INDEPENDENT ACCOUNTANTS' REPORT Arizona Public Service Company: We have reviewed the accompanying condensed balance sheet of Arizona Public Service Company as of March 31, 1996 and the related condensed statements of income for the three-month and twelve-month periods ended March 31, 1996 and 1995 and cash flows for the three-month periods ended March 31, 1996 and 1995. These condensed financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and of making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to such condensed financial statements for them to be in conformity with generally accepted accounting principles. We have previously audited, in accordance with generally accepted auditing standards, the balance sheet of Arizona Public Service Company as of December 31, 1995 and the related statements of income, retained earnings, and cash flows for the year then ended (not presented herein); and in our report dated March 1, 1996, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying condensed balance sheet as of December 31, 1995, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived. DELOITTE & TOUCHE LLP DELOITTE & TOUCHE LLP Phoenix, Arizona May 2, 1996 -2- PART I - FINANCIAL INFORMATION ------------------------------ Item 1. Financial Statements ---------------------------- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME ------------------------------ (Unaudited)
Three Months Ended March 31, ------------------------------------- 1996 1995 ---------------- ----------------- (Thousands of Dollars) ELECTRIC OPERATING REVENUES . . . . . . . . . . . . . . . $ 345,261 $ 336,968 ---------------- ----------------- FUEL EXPENSES: Fuel for electric generation . . . . . . . . . . . . . . 42,334 46,710 Purchased power . . . . . . . . . . . . . . . . . . . . 13,938 8,210 ---------------- ----------------- Total . . . . . . . . . . . . . . . . . . . . . . . . 56,272 54,920 ---------------- ----------------- OPERATING REVENUES LESS FUEL EXPENSES . . . . . . . . . . 288,989 282,048 ---------------- ----------------- OTHER OPERATING EXPENSES: Operations excluding fuel expenses . . . . . . . . . . . 63,769 65,566 Maintenance . . . . . . . . . . . . . . . . . . . . . . 23,974 25,866 Depreciation and amortization . . . . . . . . . . . . . 58,386 60,426 Income taxes . . . . . . . . . . . . . . . . . . . . . . 31,359 21,622 Other taxes . . . . . . . . . . . . . . . . . . . . . . 33,979 35,354 ---------------- ----------------- Total . . . . . . . . . . . . . . . . . . . . . . . . 211,467 208,834 ---------------- ----------------- OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . 77,522 73,214 ---------------- ----------------- OTHER INCOME (DEDUCTIONS): AFUDC - equity . . . . . . . . . . . . . . . . . . . . 1,675 1,186 Other - net . . . . . . . . . . . . . . . . . . . . . . (291) 4,784 Income taxes . . . . . . . . . . . . . . . . . . . . . 5,650 1,722 ---------------- ----------------- Total . . . . . . . . . . . . . . . . . . . . . . . . 7,034 7,692 ---------------- ----------------- INCOME BEFORE INTEREST DEDUCTIONS . . . . . . . . . . . . 84,556 80,906 ---------------- ----------------- INTEREST DEDUCTIONS: Interest on long-term debt . . . . . . . . . . . . . . . 37,400 41,872 Interest on short-term borrowings . . . . . . . . . . . 2,670 1,224 Debt discount, premium and expense . . . . . . . . . . . 2,117 1,974 AFUDC - debt . . . . . . . . . . . . . . . . . . . . . (3,237) (1,996) ---------------- ----------------- Total . . . . . . . . . . . . . . . . . . . . . . . . 38,950 43,074 ---------------- ----------------- NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 45,606 37,832 PREFERRED STOCK DIVIDEND REQUIREMENTS . . . . . . . . . . 4,477 4,807 ---------------- ----------------- EARNINGS FOR COMMON STOCK . . . . . . . . . . . . . . . . $ 41,129 $ 33,025 ================ =================
See Notes to Condensed Financial Statements. -3- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME ------------------------------ (Unaudited)
Twelve Months Ended March 31, ------------------------------------- 1996 1995 ---------------- ----------------- (Thousands of Dollars) ELECTRIC OPERATING REVENUES . . . . . . . . . . . . . . . $ 1,623,245 $ 1,617,087 ---------------- ----------------- FUEL EXPENSES: Fuel for electric generation . . . . . . . . . . . . . . 204,552 225,845 Purchased power . . . . . . . . . . . . . . . . . . . . 66,598 61,733 ---------------- ----------------- Total . . . . . . . . . . . . . . . . . . . . . . . . 271,150 287,578 ---------------- ----------------- OPERATING REVENUES LESS FUEL EXPENSES . . . . . . . . . . 1,352,095 1,329,509 ---------------- ----------------- OTHER OPERATING EXPENSES: Operations excluding fuel expenses . . . . . . . . . . . 283,045 291,522 Maintenance . . . . . . . . . . . . . . . . . . . . . . 114,080 114,210 Depreciation and amortization . . . . . . . . . . . . . 240,058 238,624 Income taxes . . . . . . . . . . . . . . . . . . . . . 188,602 168,688 Other taxes . . . . . . . . . . . . . . . . . . . . . . 140,248 141,965 ---------------- ----------------- Total . . . . . . . . . . . . . . . . . . . . . . . . 966,033 955,009 ---------------- ----------------- OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . 386,062 374,500 ---------------- ----------------- OTHER INCOME (DEDUCTIONS): AFUDC - equity . . . . . . . . . . . . . . . . . . . . 5,471 4,281 Palo Verde accretion income . . . . . . . . . . . . . -- 13,616 Other - net . . . . . . . . . . . . . . . . . . . . . . (22,107) 21,195 Income taxes . . . . . . . . . . . . . . . . . . . . . 41,526 (527) ---------------- ----------------- Total . . . . . . . . . . . . . . . . . . . . . . . . 24,890 38,565 ---------------- ----------------- INCOME BEFORE INTEREST DEDUCTIONS . . . . . . . . . . . . 410,952 413,065 ---------------- ----------------- INTEREST DEDUCTIONS: Interest on long-term debt . . . . . . . . . . . . . . . 155,560 162,236 Interest on short-term borrowings . . . . . . . . . . . 9,589 5,834 Debt discount, premium and expense . . . . . . . . . . . 8,765 8,416 AFUDC - debt . . . . . . . . . . . . . . . . . . . . . (10,306) (6,271) ---------------- ----------------- Total . . . . . . . . . . . . . . . . . . . . . . . . 163,608 170,215 ---------------- ----------------- NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 247,344 242,850 PREFERRED STOCK DIVIDEND REQUIREMENTS . . . . . . . . . . 18,804 22,571 ---------------- ----------------- EARNINGS FOR COMMON STOCK . . . . . . . . . . . . . . . . $ 228,540 $ 220,279 ================ =================
See Notes to Condensed Financial Statements. -4- ARIZONA PUBLIC SERVICE COMPANY CONDENSED BALANCE SHEETS ------------------------ ASSETS (Unaudited)
March 31, December 31, 1996 1995 -------------- -------------- (Thousands of Dollars) UTILITY PLANT: Electric plant in service and held for future use . . . $ 6,559,022 $ 6,544,860 Less accumulated depreciation and amortization . . . . . 2,279,736 2,231,614 ---------------- ----------------- Total . . . . . . . . . . . . . . . . . . . . . . . . 4,279,286 4,313,246 Construction work in progress . . . . . . . . . . . . . 300,552 281,757 Nuclear fuel, net of amortization . . . . . . . . . . . 59,788 52,084 ---------------- ----------------- Utility plant - net . . . . . . . . . . . . . . . . . 4,639,626 4,647,087 ---------------- ----------------- INVESTMENTS AND OTHER ASSETS :. . . . . . . . . . . . . . . 104,355 97,742 ---------------- ----------------- CURRENT ASSETS: Cash and cash equivalents . . . . . . . . . . . . . . . 20,300 18,389 Accounts receivable: Service customers . . . . . . . . . . . . . . . . . . 86,595 100,433 Other . . . . . . . . . . . . . . . . . . . . . . . . 18,753 28,107 Allowance for doubtful accounts . . . . . . . . . . . (1,288) (1,656) Accrued utility revenues . . . . . . . . . . . . . . . . 44,090 53,519 Materials and supplies, at average cost . . . . . . . . 77,660 78,271 Fossil fuel, at average cost . . . . . . . . . . . . . 21,284 21,722 Deferred income taxes . . . . . . . . . . . . . . . . . 5,637 5,653 Other . . . . . . . . . . . . . . . . . . . . . . . . . 17,412 17,839 ---------------- ----------------- Total current assets . . . . . . . . . . . . . . . . 290,443 322,277 ---------------- ----------------- DEFERRED DEBITS: Regulatory asset for income taxes . . . . . . . . . . . 546,881 548,464 Palo Verde Unit 3 cost deferral . . . . . . . . . . . . 281,135 283,426 Palo Verde Unit 2 cost deferral . . . . . . . . . . . . 164,358 165,873 Unamortized costs of reacquired debt . . . . . . . . . . 67,431 63,518 Unamortized debt issue costs . . . . . . . . . . . . . . 17,483 17,772 Other . . . . . . . . . . . . . . . . . . . . . . . . . 273,713 272,103 ---------------- ----------------- Total deferred debits . . . . . . . . . . . . . . . . 1,351,001 1,351,156 ---------------- ----------------- TOTAL . . . . . . . . . . . . . . . . . . . . . . . . $ 6,385,425 $ 6,418,262 ================ =================
See Notes to Condensed Financial Statements. -5- ARIZONA PUBLIC SERVICE COMPANY CONDENSED BALANCE SHEETS ------------------------ LIABILITIES (Unaudited)
March 31, December 31, 1996 1995 -------------- -------------- (Thousands of Dollars) CAPITALIZATION: Common stock . . . . . . . . . . . . . . . . . . . . . . $ 178,162 $ 178,162 Premiums and expense - net . . . . . . . . . . . . . . . 1,039,515 1,039,550 Retained earnings . . . . . . . . . . . . . . . . . . . 402,472 403,843 ---------------- ----------------- Common stock equity . . . . . . . . . . . . . . . . . 1,620,149 1,621,555 Non-redeemable preferred stock . . . . . . . . . . . . . 174,089 193,561 Redeemable preferred stock . . . . . . . . . . . . . . . 72,000 75,000 Long-term debt less current maturities . . . . . . . . . 1,961,679 2,132,021 ---------------- ----------------- Total capitalization . . . . . . . . . . . . . . . . . 3,827,917 4,022,137 ---------------- ----------------- CURRENT LIABILITIES: Commercial paper . . . . . . . . . . . . . . . . . . . . 159,600 177,800 Current maturities of long-term debt . . . . . . . . . . 153,512 3,512 Accounts payable . . . . . . . . . . . . . . . . . . . . 73,457 106,583 Accrued taxes . . . . . . . . . . . . . . . . . . . . . 146,474 82,827 Accrued interest . . . . . . . . . . . . . . . . . . . . 29,430 41,549 Customer deposits . . . . . . . . . . . . . . . . . . . 32,819 32,746 Other . . . . . . . . . . . . . . . . . . . . . . . . . 30,377 21,134 ---------------- ----------------- Total current liabilities . . . . . . . . . . . . . . 625,669 466,151 ---------------- ----------------- DEFERRED CREDITS AND OTHER: Deferred income taxes . . . . . . . . . . . . . . . . . . 1,429,059 1,429,482 Deferred investment tax credit . . . . . . . . . . . . . 109,898 115,353 Unamortized gain - sale of utility plant . . . . . . . . 90,371 91,514 Customer advances for construction . . . . . . . . . . . 20,730 19,846 Other . . . . . . . . . . . . . . . . . . . . . . . . . 281,781 273,779 ---------------- ----------------- Total deferred credits and other . . . . . . . . . . 1,931,839 1,929,974 ---------------- ----------------- COMMITMENTS AND CONTINGENCIES (Notes 6 and 7) TOTAL . . . . . . . . . . . . . . . . . . . . . . . . $ 6,385,425 $ 6,418,262 ================ =================
See Notes to Condensed Financial Statements. -6- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF CASH FLOWS ---------------------------------- (Unaudited)
Three Months Ended March 31, ------------------------------------- 1996 1995 ---------------- ----------------- (Thousands of Dollars) Cash Flows from Operating Activities: Net income . . . . . . . . . . . . . . . . . . . . . . . $ 45,606 $ 37,832 Items not requiring cash: Depreciation and amortization . . . . . . . . . . . . 58,386 60,426 Nuclear fuel amortization . . . . . . . . . . . . . . 8,357 7,723 AFUDC - equity . . . . . . . . . . . . . . . . . . . . (1,675) (1,186) Deferred income taxes - net . . . . . . . . . . . . . 1,176 4,531 Deferred investment tax credit - net . . . . . . . . . (5,455) (3,858) Changes in certain current assets and liabilities: Accounts receivable - net . . . . . . . . . . . . . . 22,824 26,895 Accrued utility revenues . . . . . . . . . . . . . . . 9,429 9,885 Materials, supplies and fossil fuel . . . . . . . . . 1,049 (1,035) Other current assets . . . . . . . . . . . . . . . . . 427 (2,829) Accounts payable . . . . . . . . . . . . . . . . . . . (29,941) (26,184) Accrued taxes . . . . . . . . . . . . . . . . . . . . 63,647 53,529 Accrued interest . . . . . . . . . . . . . . . . . . . (12,119) (10,719) Other current liabilities . . . . . . . . . . . . . . 9,617 10,302 Other - net . . . . . . . . . . . . . . . . . . . . . . 12,608 (12,566) ---------------- ----------------- Net cash flow provided by operating activities . . . 183,936 152,746 ---------------- ----------------- Cash Flows from Investing Activities: Capital expenditures . . . . . . . . . . . . . . . . . . (60,138) (69,548) Sale of Property . . . . . . . . . . . . . . . . . . . . 2,824 -- AFUDC - debt . . . . . . . . . . . . . . . . . . . . . . (3,237) (1,996) Other . . . . . . . . . . . . . . . . . . . . . . . . . (6,613) (1,449) ---------------- ----------------- Net cash flow used for investing activities. . . . . (67,164) (72,993) ---------------- ----------------- Cash Flows from Financing Activities: Long-term debt . . . . . . . . . . . . . . . . . . . . . 25,006 73,811 Short-term borrowings - net . . . . . . . . . . . . . . (18,200) (51,000) Dividends paid on common stock . . . . . . . . . . . . . (42,500) (42,500) Dividends paid on preferred stock . . . . . . . . . . . (4,778) (4,827) Repayment of preferred stock . . . . . . . . . . . . . . (23,410) (4) Repayment and reacquisition of long-term debt . . . . . (50,979) (51,867) ---------------- ----------------- Net cash flow used for financing activities . . . . (114,861) (76,387) ---------------- ----------------- Net increase in cash and cash equivalents . . . . . . . . 1,911 3,366 Cash and cash equivalents at beginning of period . . . . . 18,389 6,532 ---------------- ----------------- Cash and cash equivalents at end of period . . . . . . . . $ 20,300 $ 9,898 ================ ================= Supplemental Disclosure of Cash Flow Information: Cash paid during the period for: Interest (excluding capitalized interest) . . . . . . $ 48,444 $ 51,900 Income taxes . . . . . . . . . . . . . . . . . . . . . $ -- $ --
See Notes to Condensed Financial Statements. -7- 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 March 31, 1996, the results of operations for the three months and twelve months ended March 31, 1996 and 1995, and the cash flows for the three months ended March 31, 1996 and 1995. 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 1995 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 occurring in energy usage by customers 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. Pursuant to a Pledge Agreement, dated as of January 31, 1990, and as part of a restructuring of substantially all of its outstanding indebtedness, Pinnacle West granted certain of its lenders a security interest in all of the Company's outstanding common stock. 4. See "Liquidity and Capital Resources" in Part I, Item 2 of this report for changes in capitalization for the three months ended March 31, 1996. 5. Regulatory Matters Regulatory Agreement In April 1996, the ACC approved a regulatory agreement between the Company and the ACC Staff. This agreement is substantially the same as the agreement proposed by the Company and the ACC Staff in December 1995. The major provisions of the 1996 regulatory agreement are: * An annual rate reduction of approximately $48.5 million ($29 million after income taxes), or an average 3.4% 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 beginning 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, referencing a return on equity (as defined) of 11.25%. -8- * A moratorium on filing for permanent rate changes, except under the sharing formula and under certain other limited circumstances, prior to July 2, 1999. * Infusion of $200 million of common equity into the Company by Pinnacle West, in annual increments of $50 million starting in 1996. In recognition of evolving competition in the electric utility industry and an ongoing investigation by the ACC Staff into industry restructuring in an open competition docket involving many parties, the agreement also includes an element setting out a number of issues which the Company and the ACC Staff agree the ACC should be requested to consider in developing restructuring policies. See Note 3 of Notes to Financial Statements in Part II, Item 8 of the 1995 10-K for further discussion of the industry restructuring element of the agreement. 1994 Settlement Agreement In May 1994, the ACC approved a retail rate settlement agreement which provided for a net annual retail rate reduction of approximately $32 million ($19 million after income taxes), or 2.2% on average, effective June 1, 1994. As part of the settlement, in 1994 the Company reversed approximately $20 million of depreciation ($15 million after income taxes) related to a 1991 Palo Verde write-off. The 1994 rate settlement also provided for the accelerated amortization of substantially all deferred ITCs over a five-year period beginning in 1995, resulting in a decrease in annual income tax expense of approximately $21 million. 6. 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 this program exceed the accumulated funds for this program, the Company could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $79 million, subject to an annual limit of $10 million per incident. Based upon the Company's 29.1% interest in the three Palo Verde units, the Company's maximum potential assessment per incident is approximately $69 million, with an annual payment limitation of approximately $9 million. The Palo Verde participants maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. The Company has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions. 7. The Company has encountered tube cracking in the Palo Verde steam generators and has taken, and will continue to take, remedial actions that -9- it believes have slowed the rate of tube degradation. The projected service life of the steam generators is reassessed periodically in conjunction with inspections made during scheduled outages of the Palo Verde units. The Company's ongoing analyses indicate that it will be economically desirable for the Company to replace the Unit 2 steam generators, which have been most affected by tube cracking, in five to ten years. The Company expects that the steam generator replacement can be accomplished within financial parameters established before replacement was a consideration, and the Company estimates that its share of the replacement costs (in 1996 dollars and including installation and replacement power costs) will be between $30 million and $50 million, most of which will be incurred after the year 2000. The Company expects that the replacement would be performed in conjunction with a normal refueling outage in order to limit incremental outage time to approximately 50 days. 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- 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 and twelve-month periods ended March 31, 1996 and 1995:
Periods ended March 31 (Thousands of Dollars) Three Months Twelve Months ---------------------------------- ---------------------------------------- 1996 1995 1996 1995 ----------------- ---------------- ------------------- -------------------- Operating revenues $345,261 $336,968 $1,623,245 $1,617,087 Earnings for common stock $ 41,129 $ 33,025 $ 228,540 $ 220,279
Operating Results - Three-month period ended March 31, 1996 compared ----------------------------------------------------------------------- with three-month period ended March 31, 1995 -------------------------------------------- Earnings increased in the three-month period ended March 31, 1996 primarily due to customer growth, lower operations and maintenance expenses, and lower interest expense. Operations and maintenance expenses decreased due to fewer nuclear refueling outage days. Interest expense decreased due to lower rates and lower average debt balances. Partially offsetting these positive factors was a decrease in other income caused by the recognition of a gain on the sale of a small subsidiary in 1995. Operating Results - Twelve-month period ended March 31, 1996 compared ----------------------------------------------------------------------- with twelve-month period ended March 31, 1995 --------------------------------------------- Earnings increased in the twelve-month period ended March 31, 1996 primarily due to customer growth, accelerated investment tax credit amortization, lower fuel costs, and lower operations and maintenance expenses. The accelerated investment tax credit amortization was a result of the 1994 rate settlement (see Note 5 of Notes to Condensed Financial Statements in Part I, Item 1 of this report) and is reflected as a decrease in income tax expense. Fuel expense decreased due largely to lower fuel prices. Operations and maintenance expenses decreased due to employee severance costs incurred in 1994, lower fossil plant overhaul costs, and improved nuclear operations. Partially offsetting these positive factors were milder weather, the reversal in 1994 of certain previously-recorded depreciation related to Palo Verde, the absence of non-cash accretion income and revenue refund reversals related to a 1991 rate settlement (see Note 1 of Notes to Financial Statements in Part II, Item 8 of the 1995 10-K), write-downs of an office building and certain inventory, and a decrease in other income -11- caused by the recognition of a gain on the sale of a small subsidiary in the first quarter of 1995. Other Income ------------ Other income reflects accounting practices required for regulated public utilities and represents a composite of cash and non-cash items, including AFUDC and accretion income on Palo Verde Unit 3, which the Company completed recording in May 1994. See Note 1 of Notes to Financial Statements in Part II, Item 8 of the 1995 10-K. Regulatory Agreement - -------------------- See Note 5 of Notes to Condensed Financial Statements in Part I, Item 1 of this report and Note 3 of Notes to Financial Statements in Part II, Item 8 of the 1995 10-K for a discussion of the Company's regulatory agreement. Liquidity and Capital Resources - ------------------------------- For the three months ended March 31, 1996, the Company incurred approximately $58 million in capital expenditures, accounting for approximately 24% of the most recently estimated 1996 capital expenditures. The Company has estimated total capital expenditures for the years 1996, 1997 and 1998 to be approximately $246 million, $242 million, and $244 million, respectively. These amounts include about $30 million each year for nuclear fuel expenditures. Obligations for redemptions of preferred stock and long-term debt, a capitalized lease obligation, and certain actual and anticipated early redemptions, including premiums thereon, are expected to total approximately $123 million, $164 million, and $114 million for the years 1996, 1997, and 1998, respectively. During the three months ended March 31, 1996, the Company redeemed approximately $51 million of its long-term debt and approximately $23 million of its preferred stock, and incurred $25 million of long-term debt under a revolving credit agreement. It is the Company's present intention over the next several years to use excess cash flow to retire debt and preferred stock. Although provisions in the Company's bond indenture, articles of incorporation, and financing orders from the ACC restrict the issuance of additional first mortgage bonds and preferred stock, management does not expect any of these restrictions to limit the Company's ability to meet its capital requirements. -12- PART II - OTHER INFORMATION --------------------------- ITEM 1. Legal Proceedings ------------------------------ Property Taxes -------------- As previously reported, in November 1995, the Arizona Court of Appeals held that an Arizona state property tax law, effective December 31, 1989, is unconstitutional and a lawsuit filed by the Palo Verde participants, including the Company, was returned to the Arizona Tax Court for determination of the appropriate remedy consistent with that decision. See "Property Taxes" in Part I, Item 3 of the 1995 10-K. On April 23, 1996, the parties reached an agreement to settle the pending litigation. Pursuant to the tentative settlement, the Company will relinquish its claims for relief with respect to prior years and the defendants will not challenge the Court of Appeals' decision concerning prospective relief (for tax years 1996 and thereafter). The Company does not expect this matter to have a material impact on its financial position or results of operations. ITEM 5. Other Information ------------------------------ Palo Verde Nuclear Generating Station ------------------------------------- See Note 7 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. Environmental Matters --------------------- The Comprehensive Environmental Response, Compensation, and Liability Act ("Superfund") establishes liability for the cleanup of hazardous substances found contaminating the soil, water, or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are potentially responsible parties ("PRP's") and may be each strictly, and often jointly and severally, liable for the cost of any necessary remediation of the substances. The EPA had previously advised the Company that the EPA considers the Company to be a PRP in the Indian Bend Wash Superfund Site, South Area, where the Company's Ocotillo Power Plant is located. The Company is in the process of conducting a voluntary investigation to determine the extent and scope of contamination at the Plant site. Based on the information to date, the Company does not expect this matter to have a material impact on its financial position or results of operations. -13- ITEM 6. Exhibits and Reports on Form 8-K ----------------------------------------- (a) Exhibits Exhibit No. Description ----------- ----------- 10.1 Arizona Corporation Commission Order dated April 24, 1996 15.1 Letter in Lieu of Consent Regarding Unaudited Interim Financial Information 27.1 Financial Data Schedule (b) Reports on Form 8-K During the quarter ended March 31, 1996, and the period ended May 14, 1996, the Company did not file any reports on Form 8-K. -14- 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: May 14, 1996 By Jaron B. Norberg ---------------------------- ---------------- Jaron B. Norberg Executive Vice President and Chief Financial Officer (Principal Financial Officer and Officer Duly Authorized to sign this Report) EX-10.1 2 ACC ORDER EXHIBIT 10.1 BEFORE THE ARIZONA CORPORATION COMMISSION RENZ D. JENNINGS CHAIRMAN MARCIA WEEKS COMMISSIONER CARL J. KUNASEK COMMISSIONER IN THE MATTER OF ARIZONA PUBLIC ) DOCKET NO. U-1345-95-491 SERVICE COMPANY'S RATE REDUCTION ) AGREEMENT. ) DECISION NO. 59601 ) _________________________________________) ORDER Arizona Corporation Commission Open Meeting DOCKETED April 18, 1996 APR 24 1996 Phoenix, Arizona Docketed by SS FINDINGS OF FACT ---------------- 1. Arizona Public Service Company ("APS") is an Arizona corporation providing electric utility service within the State of Arizona. 2. The rates and charges currently in effect for APS were determined to be just and reasonable in Decision No. 58644, dated June 1, 1994. That decision approved a Settlement Agreement between Staff and APS which reduced rates. 3. Since Decision No. 58644, APS has continued its cost containment efforts, and has experienced customer growth well above the national average, and has recorded improved performance from nuclear and fossil-fueled generating units. 4. APS is also faced with increasing competition and the uncertainty of fundamental industry restructuring. 5. As a result of these events, and in order to prepare for the transition to a more competitive marketplace, APS and Staff concluded that the rates and charges previously authorized by the Commission for APS should be reduced, accelerated amortization of regulatory assets should be allowed, and additional incentives created for efficient operation. Staff and APS also reached agreement on a number of interrelated issues. 6. The particulars of the agreement are memorialized in a written Rate Reduction Agreement ("Agreement") dated December 4, 1995. On December 5, 1995, Staff filed the Agreement with the Commission. 7. On January 5 and February 26, 1996, Procedural Orders governing the conduct of this proceeding were issued. The Procedural Orders, inter alia, did the following: required that APS provide notice by publication of the hearing in this matter and provide copies of the Agreement to all parties of record in APS' 1994 rate reduction proceeding (Docket No. U-1345-94-120); established procedures for intervention; established procedures for discovery; established dates for Staff, APS and intervenors to file testimony or comments; and set a hearing date at which all parties would be able to present witnesses and evidence and cross-examine the witnesses of other parties. 8. Requests for intervention were filed by the Residential Utility Consumer Office (January 8, 1996), Cyprus Bagdad Copper Corporation (January 19, 1996), the Department of the Navy (February 9, 1996), Southwest Gas Corporation (February 12, 1996), Citizens Utilities Company (February 12, 1996), Arizona Electric Power Cooperative, Inc. (February 13, 1996), Arizona Cotton Growers Association (February 14, 1996), Tucson Electric Power Company (February 15, 1996), Lor-D's Ranch Mineso Dairy (February 15, 1996), Nordic Power of Southpoint I, LP (February 15, 1996), Arizona Interfaith Coalition on Energy (February 15, 1996), Maricopa County (February 15, 1996), Arizona Community Action Association (February 16, 1996), Arizonans for Sustainable Growth (February 16, 1996), Salt River Project Agricultural Improvement and Power District (February 16, 1996), Arizona Association of Industries (February 16, 1996) and Arizona Cogeneration Association (February 16, 1996). 9. Intervention was granted by Procedural Order dated January 10, 1996 for the Residential Utility Consumer Office; by Procedural Order dated January 29, 1996, for Cyprus Bagdad Copper Corporation; by Procedural Order dated February 14, 1996, for Department of the Navy, Southwest Gas Corporation, and Citizens Utilities Company; by Procedural Order dated February 21, 1996, for Arizona Electric Power Cooperative, Inc., Arizona Cotton Growers Association, Lor-D's Ranch Mineso Dairy, Arizona Interfaith Coalition on Energy, Maricopa County, Arizona Community Action Association, Arizonans for Sustainable Growth, Salt River Project Agricultural Improvement and Power District, Arizona Association of Industries, and Arizona Cogeneration Association; and by Procedural Order dated February 29, 1996, for Tucson Electric Power Company. 10. All intervenors had the opportunity to file comments regarding the Agreement, to file written testimony, and to present witnesses and exhibits and to cross-examine witnesses presented by other parties. 11. Beginning on April 9, 1996, a hearing was held on this matter at the Commission's offices in Phoenix, Arizona. 12. On April 11, 1996, Staff and APS submitted a Restated and Amended Rate Reduction Agreement, which addressed certain of theintervenor comments and corrected certain errors and omissions in the earlier Agreement. 13. On April 18, 1996, APS and Staff submitted a Second Restated and Amended Rate Reduction Agreement ("Amended Agreement"), which addressed additional concerns of intervenors and made other minor corrections to the Agreement. The Amended Agreement also adopted certain proposed changes to the Agreement from each of the Commissioners. 14. Staff and APS believe that the Amended Agreement they have reached is consistent with the best interests of the parties and the public interest generally. A copy of the Amended Agreement is attached hereto as Exhibit 1. 15. Pursuant to the Amended Agreement, Staff and APS have agreed to the following: A. APS will implement a first year rate decrease of $48.5 million, or 3.26%. Base rates will be reduced by $39.3 million, and the EEASE surcharge will be abolished resulting in a further decrease of $9.2 million. The rate decrease is based on retail sales to and revenues from eligible customers for the adjusted test year ended June 30, 1995. See Revised Attachment 1 to the Amended Agreement for details of the calculation. Such rate reduction will become effective July 1, 1996 or immediately upon a Commission order approving the Plan, whichever is later. Such rate reduction will be allocated among customers as shown in Revised Attachment 1 to the Amended Agreement. B. In order to provide customers with the opportunity for further price reductions, while maintaining its financial stability, the Company must continue to lower its average cost/kWh. To the extent the Company is successful, customers and shareholders will benefit. Each year following the initial rate reduction described in Paragraph A, above, through and including July 1, 1999 (the "Moratorium Period"), APS rates would be subject to a reduction in base rates determined as follows: if the average price/kWh exceeds the average cost/kWh, as defined in Attachment 3 to the Amended Agreement, based on results of operations for the preceding calendar year, then 55% of the difference will be reflected as a reduction in base rates effective July 1 of the current year. However, if APS experiences a decrease in Property Tax Expense from the previous year, then APS should identify that amount and include the following calculation in its filing of its annual rate incentive filing pursuant to Paragraph 4 of this Amended Agreement: if the UPR (as defined in Attachment 3) exceeds the UCR (as also defined in Attachment 3), APS should adjust the 55 percent ratepayer share to reflect inclusion of the Company's 45% share of such Property Tax Expense decrease that would otherwise result from the Amended Agreement's calculation of the rate incentive mechanism described in this Paragraph. After giving effect to the consolidation, elimination and restructuring of certain existing rate offerings as discussed below, any net revenue decrease would be allocated among customers by means of a uniform percent reduction in the demand and energy charges for all current APS rate schedules, except those set forth in Attachment 2 to the Amended Agreement. In any year, if the average cost/kWh is equal to or exceeds the average price/kWh, there would be no further change in base rates (neither a decrease nor an increase in base rates for that year). C. Under this Amended Agreement, certain regulatory assets will be recovered by accelerating their amortization over an eight year period commencing July 1, 1996. These assets are primarily cost deferrals from Palo Verde Units 2 and 3, that were recorded under ACC approved accounting orders, and regulatory assets to cover future income tax liabilities recorded in 1993 as a result of implementing Financial Accounting Standard No. 109 with respect to deferred income taxes. This amortization will be included in the calculation of the average cost/kWh. The accelerated amortization approved in this proceeding is for the purpose of settlement and anticipates the transition period toward a more competitive marketplace. Further, APS agrees that the accelerated amortization of these regulatory assets cannot be used as a separate justification for a net rate increase in any future rate proceeding. Finally, at the end of the Moratorium Period, the accelerated rate of amortization will continue until further order of the Commission. D. The determination of the reduction to base rates for the succeeding years will be determined pursuant to the Company's calculation of the average price and cost/kWh using data from the prior calendar year. A filing of this calculation will be made on or about March 1 of each year for Staff review. Such filing will also be made available to the Arizona Residential Consumer Office ("RUCO") for its review and comment. Any reduction for the current year will become effective for usage on or after July 1, if and only if such reduction is approved by the Commission. If the Commission orders a hearing on such decrease, this would automatically delay the effective date of any decrease until a final order is issued. E. To improve the Company's equity ratio in anticipation of greater competition, Pinnacle West Capital Corporation will infuse $200 million of common equity, in $50 million increments, by each year-end beginning in 1996, into APS with such infusion to be included in calculating each year's average cost/kWh under the Amended Agreement. F. During the Moratorium Period, no party shall seek to change the rates except as set forth specifically in the Amended Agreement. However, neither APS nor Staff shall be prevented from seeking a change in rates prior to July 2, 1999 in the event of: (a) conditions or circumstances which constitute an emergency, such as the inability to finance on reasonable terms, or (b) material changes in the Company's cost of service as a result of federal, tribal, state or local laws, regulatory requirements, judicial decisions, actions, or orders. G. The parties agree to the following revisions of current rate schedules and new tariffs: i. A flexible pricing tariff provision as was suggested by the Company in Revised Attachment 4 should be considered in the Commission's electric competition docket (Docket No. U-0000-94-165). ii. The Company shall retain the right to propose for Commission approval during the Moratorium Period new or revised rate designs. Examples of this type of filing might be: a. Revised time-of-use (TOU) pricing periods and prices (both residential and general service) once advanced meter communications systems are in place. APS agrees to submit such a TOU proposal before December 31, 1996. b. A real-time pricing experiment or operational program. c. Unbundled retail rates to provide customers alternative service options. H. The parties agree to the following changes to current rate schedules. These changes are designed to more accurately reflect the costs to serve, promote fairness among similar customer groups, and improve customer understanding and acceptability of the pricing, terms and conditions of the tariffs. i. Revise Schedule #1, General Terms and Conditions of Service, so that credit and collections practices and charges fairly and properly collect costs from customers who impose those costs on APS without subsidies from other customers. The parties also agree to other minor changes to clarify current practices and service specifications. These proposed changes are summarized in Revised Attachment 5 to the Agreement. ii. Revise partial requirements provisions of the tariff to consistently and fairly charge for services provided. APS has a variety of rates applicable to various types of partial requirements customers and these are proposed to be revised to apply market-based charges for standby, and cost-based charges for supplemental and maintenance service. The proposed tariffs (Schedules E-55 and E-52) are attached as Revised Attachment 6. Schedules E-55 and E-52 shall: * indicate that the customer designates the amount of standby capacity he or she wants in setting the contract standby capacity and that the capacity could be less than the capacity of the self generation facility. In addition, APS shall review whether the potential for lower rates for a customer with a capacity factor consistently below 75 percent (relative to a customer with a higher capacity factor) is in need of correction or clarification. Schedule E-51 shall be frozen to new and reconnecting customers. Schedule E-50 shall be cancelled. iii. EPR-1, -2, and -3, purchase rates for small qualified cogeneration customers, would be revised to reflect current buy-back rates, current metering technology and establish consistency among the rates. Schedule EPR-4 shall reference schedules for sales to the customer. In addition, Schedule EPR-2 shall offer an option for the incremental cost of the bidirectional meter to be paid in a lump sum or in monthly installments over a specified time period. Schedule EPR-1 will be canceled. Proposed tariffs (Schedules EPR-2, EPR-3, and EPR-4) are attached as Attachment 7 to the Amended Agreement. iv. Eliminate extra-small general service Rate E-31 and incorporate E-31 into Schedule E-32 so that the monthly service charge under the new Schedule E-32 is $12.50, and the energy charge (prior to application of the rate decrease) is increased by $0.00024 per kWh for all kWh. v. APS shall also submit a new rate (E-20) applicable only to "houses of worship." Said rate shall be open to all qualified customers and shall in all other respects be identical to E-21, which latter rate shall be frozen. A copy of proposed E-20 is attached as Attachment 10. vi. APS shall revise Schedule E-3 so that when an otherwise eligible customer uses more than 1200 kWh in any month, such customer will continue to receive a discount under E-3 for that month, but that discount will be a flat $10. A copy of revised Schedule E-3 is attached as Attachment 11 to the Amended Agreement. vii. APS shall revise Schedule E-4 so that when an otherwise eligible customer uses more than 2000 kWh in any month, such customer will continue to receive a discount under E-4 for that month, but that discount will be a flat $20. A copy of revised Schedule E-4 is attached as Attachment 12 to the Amended Agreement. I. The electric base rates proposed to be effective in 1996 include the costs associated with depreciation and decommissioning expense schedules currently being used by APS. The results of any future Palo Verde decommissioning cost or plant depreciation studies completed during the Moratorium Period would be reflected in the average cost/kWh used in the calculation of additional base rate reductions described in Paragraph B, above. Any depreciation or decommissioning study would be reviewed by Staff and RUCO, and the new schedules derived therefrom would be authorized and approved in accordance with the procedure established in Section 13.H of Decision No. 58644. J. APS' commitment to foster investment in DSM and renewables continues and shall be implemented as follows: i. The EEASE fund shall be eliminated. Any over-recovery shall be refunded to customers through a one-time refund within 120 days of the effective date of the Commission's order. APS will work with Staff and RUCO on a procedure to effectuate this provision. ii. A total of $7 million will be included in base rates for demand side management (DSM) and renewables. Of the $7 million total, APS shall undertake at least $3 million of renewables programs per year on average and at least $3 million of DSM per year on average. APS shall spend at least $7 million per year on DSM and renewables projects consistent with this Paragraph J. Moreover, APS shall attempt to identify and shall be authorized to expend and include in its calculation of UCR up to an additional $3 million per year on additional direct DSM program costs and/or renewables. If APS spends less than the $7 million included in base rates on renewables and DSM per year on average, the Commission, at the next rate case, shall review these expenditures and may order appropriate refunds to ratepayers taking into consideration any sharing that has occurred as a result of paragraph B, above. iii. APS shall move to phase out consumer rebate DSM programs for customers and instead substitute shareholder-funded, market-based DSM programs for larger customers and, for all customers, develop and implement ratepayer-funded market transformation activities (such as trade ally programs or consumer education programs). However, costs (including incentives and net lost revenues) for existing and approved customer rebate programs shall be included in the calculation of the Company's $7 million obligation under this paragraph until such programs have been phased out. APS shall evaluate the effectiveness of market transformation programs. iv. APS shall continue its low income DSM program (at least at current levels), complete current monitoring and evaluation commitments, and fulfill outstanding commitments under existing rebate programs. v. APS shall prepare an administrative and implementation plan for Staff review and approval for its DSM and renewables programs within six months of the effective date of this decision. APS shall prepare proposals for new DSM and renewables programs for Staff review and approval. vi. APS shall file detailed semi-annual reports with Staff and in Docket Control on all DSM and renewables activities, although confidential information need not be filed in Docket Control. K. APS recognizes that the jurisdictional portion of any net refund that it receives as a result of disposition of the property tax lawsuit (Tucson Electric Power v. Apache County, 175 Ariz. 485 (App. 1995)) is owed to its customers, since these taxes were collected from and paid by customers to APS through rates. Therefore, APS will refund to its customers the net jurisdictional amount of overcollected property taxes that are refunded to APS by the State of Arizona. APS agrees to work cooperatively with Staff and RUCO to determine the amount of any refund and method for returning the refund to customers. L. The rates and charges authorized herein fully include a return on the recorded book original cost of all jurisdictional APS assets (net of depreciation, amortization, and deferred income taxes and other deferred credits) as of June 30, 1995, excepting construction work in progress as of such date. However, nothing in this Amended Agreement shall be construed as prohibiting Staff or any other party from pursuing new issues related to expenditures made or actions taken after June 30, 1995. M. Staff and APS stipulate to the adoption of the fair value rate base and fair rate of return and agree that the resultant revenue decrease, as reflected in Paragraph A above, results in just and reasonable rates for the Company. The determinations made in this Paragraph are made solely for the purpose of the stipulation contained in this Amended Agreement. N. Each provision of the Amended Agreement is in consideration and support of all the other provisions. The Amended Agreement shall not become effective until the issuance of a final Commission Order approving the Amended Agreement without change or alteration on or before July 1, 1996 in the form of a Proposed Order agreed to by the parties. In the event that the Commission fails to adopt the Amended Agreement according to its terms on or before July 1, 1996, the Amended Agreement shall be deemed automatically withdrawn, the rate reduction provisions of the Amended Agreement shall not take effect, and APS and Staff shall be free to pursue their respective positions without prejudice. In addition, if any appeal is taken or other judicial review is sought of a final Commission Order approving the Amended Agreement, then the parties shall no longer be bound by the terms of the Amended Agreement and the Amended Agreement shall automatically become null and void, in which case: (1) the rate reduction specified in Paragraph A, above, shall immediately cease; (2) all bills rendered on or after that date shall be at the rates existing immediately prior to the Commission's approval of the Amended Agreement; and (3) the revenue reduction theretofore experienced by APS pursuant to Paragraph A, above, shall be recovered through a surcharge mechanism. O. The terms and provisions of the Amended Agreement apply solely to and are binding only in the context of the purposes and results of the Amended Agreement and none of the positions taken herein by APS may be referred to, cited or relied upon by any other party in any fashion as precedent or otherwise in any other proceeding before this Commission or any other regulatory agency or before any court of law for any purpose except in furtherance of the purposes and results of the Amended Agreement. Nothing in the Amended Agreement shall be construed as imposing a cap on the Company's otherwise reasonable and prudent cost of service for purposes of setting just and reasonable rates. P. The Amended Agreement represents an attempt to compromise and settle issues regarding the prospective just and reasonable rate levels for APS in a manner consistent with the public interest and applicable legal requirements. Nothing contained in the Amended Agreement is an admission by APS that its current rate levels or rate design are unjust or unreasonable. Q. APS' agreement to the matters contained herein is predicated on a national movement toward competition in the electricity industry. That movement raises a number of policy and legal issues in Arizona which are summarized (not necessarily completely) in the Points of Agreement (Attachment 8 to the Amended Agreement). APS has its own views, independent of any the Staff may have, of the proper resolution of certain of the issues presented in the Points of Agreement. Such views are summarized in Attachment 9 to the Amended Agreement. 16. Neither the Amended Agreement nor this Order purports to resolve the issues identified in Attachments 8 and 9 to the Agreement, nor does the Amended Agreement or this Order bind the parties or the Commission to take or adopt any particular substantive position with regard to those issues. 17. The Commission's approval of the Amended Agreement, and the implementation of the rate reduction and other matters contained in the Amended Agreement, are not conditioned upon the resolution of the issues identified in Attachments 8 and 9 to the Amended Agreement. 18. Paragraph 9 of the Amended Agreement, as submitted, contemplates the filing and approval of depreciation or decommissioning studies without explicitly stating a requirement that those studies be submitted to the Commission for consideration in Open Meeting. Under Paragraph 9 of the Amended Agreement, as submitted, changes in depreciation or decommissioning costs as a result of such studies may affect base rates by virtue of their inclusion in the calculation of average cost/kWh in connection with Paragraph 2 of the Amended Agreement. CONCLUSIONS OF LAW ------------------ 1. APS is a public service corporation within the meaning of Article 15 of the Arizona Constitution and Title 40 of the Arizona Revised Statutes. 2. The Commission has jurisdiction over APS, over the subject matter of this proceeding, and over the Amended Agreement submitted by the Staff and APS. 3. APS provided notice of this matter in accordance with law. 4. The Amended Agreement resolves all matters contained therein in a manner which is just and reasonable, and which promotes the public interest. 5. The Commission's acceptance and approval of the terms of the Amended Agreement between Staff and APS are in the public interest. 6. Based on the Amended Agreement of APS and Staff, for purposes of this proceeding, APS' fair value rate base as of June 30, 1995, is $4,890,018,000, and a fair and reasonable rate of return on that fair value rate base is 5.34%. 7. Based on the Amended Agreement between APS and Staff, it is appropriate to reduce APS' authorized revenues by $48.5 million from July 1, 1995 sales as adjusted, to be allocated among customers by means of the reduction as shown in Revised Attachment 1 to the Amended Agreement. 8. APS should be directed to file revised tariffs consistent with the Amended Agreement and the findings contained herein. 9. The rates and charges authorized herein are just and reasonable. 10. Neither the Amended Agreement nor this Order resolves the issues identified in Attachments 8 and 9 to the Amended Agreement, nor does the Amended Agreement or this Order bind the parties or the Commission to take or adopt any particular substantive position with regard to those issues. 11. It is not in the public interest to approve the provisions of Paragraph 9 of the Amended Agreement, insofar as those provisions contemplate the filing and approval of changes in depreciation or decommissioning costs, which could affect base rates without explicitly requiring that those changes in depreciation or decommissioning costs be submitted to the Commission for consideration in Open Meeting. ORDER ----- IT IS THEREFORE ORDERED that APS shall decrease its rates and charges for all usage on or after July 1, 1996, consistent with the Findings of Fact and Conclusions of Law contained herein so as to result in an annual decrease of $48.5 million based on June 30, 1995 sales as adjusted, to be allocated among customers by means of the reduction shown in Revised Attachment 1 to the Amended Agreement. IT IS FURTHER ORDERED that this Order incorporates the Amended Agreement executed April 18, 1996, between APS and Staff, and such Order is expressly conditioned thereon. IT IS FURTHER ORDERED that the terms and conditions of the Amended Agreement be and the same are hereby adopted and approved. IT IS FURTHER ORDERED that this Order shall not resolve the issues identified in Attachments 8 and 9 to the Amended Agreement, and that this Order shall not bind the parties or the Commission to take or adopt any particular substantive position with regard to those issues. IT IS FURTHER ORDERED that APS is authorized and directed to file revised schedules of rates and charges consistent with the Findings and Conclusions of this Order. IT IS FURTHER ORDERED that APS is authorized to accelerate the amortization of its regulatory assets in the manner, to the extent and for the purposes set forth in the Amended Agreement. IT IS FURTHER ORDERED that the EEASE fund be, and is hereby, eliminated, and that any over-recovery shall be refunded to customers through a one-time refund within 120 days of the effective date of this Order. IT IS FURTHER ORDERED that neither APS nor Commission Staff shall file any application to change the rates of APS prior to July 2, 1999, except as set forth specifically in the Amended Agreement. IT IS FURTHER ORDERED rejecting the provisions of Paragraph 9 of the Amended Agreement, insofar as those provisions contemplate the filing and approval of changes in depreciation or decommissioning costs, which could affect base rates without explicitly requiring that those changes in depreciation or decommissioning costs be submitted to the Commission for consideration in Open Meeting. No changes in depreciation or decommissioning costs pursuant to the Amended Agreement, or this Decision, shall be effective absent consideration and approval by the Commission in Open Meeting. To the extent this provision conflicts with the procedure established in Section 13.H of Decision No. 58644, the provisions of this Decision shall be followed. IT IS FURTHER ORDERED that this Order shall become effective immediately. BY ORDER OF THE ARIZONA CORPORATION COMMISSION Renz D. Jennings Marcia Weeks Carl J. Kunasek - ----------------------- --------------------- ------------------- CHAIRMAN COMMISSIONER COMMISSIONER IN WITNESS WHEREOF, I, JAMES MATTHEWS, Executive Secretary of the Arizona Corporation Commission, have hereunto, set my hand and caused the official seal of this Commission to be affixed at the Capitol, in the City of Phoenix, this 24 day of April, 1996. James Matthews ------------------------------ JAMES MATTHEWS Executive Secretary DISSENT____________________ EXHIBIT 1 SECOND RESTATED AND AMENDED RATE REDUCTION AGREEMENT ---------------------------------------------------- Staff of the Arizona Corporation Commission (Staff) and Arizona Public Service Company (APS or Company) hereby further restate and amend the Rate Reduction Agreement dated December 4, 1995 and amended April 10, 1996, as follows: 1. APS will implement a first year rate decrease of $48.5 million, or 3.26%. Base rates will be reduced by $39.3 million, and the EEASE surcharge will be abolished resulting in a further decrease of $9.2 million. The rate decrease is based on retail sales to and revenues from eligible customers for the adjusted test year ended June 30, 1995. See Revised Attachment 1 for details of the calculation. Such rate reduction will become effective July 1, 1996 or immediately upon a Commission order approving the Plan, whichever is later. Such rate reduction will be allocated among customers as shown in Revised Attachment 1. 2. In order to provide customers with the opportunity for further price reductions, while maintaining its financial stability, the Company must continue to lower its average cost/kWh. To the extent the Company is successful, customers and shareholders will benefit. Each year following the initial rate reduction described in Paragraph 1, through and including July 1, 1999 (the "Moratorium Period"), APS rates would be subject to a reduction in base rates determined as follows: if the average price/kWh exceeds the average cost/kWh, as defined in Attachment 3, based on results of operations for the preceding calendar year, then 55% of the difference will be reflected as a reduction in base rates effective July 1 of the current year. However, if APS experiences a decrease in Property Tax Expense from the previous year, then APS should identify that amount and include the following calculation in its filing of its annual rate incentive filing pursuant to Paragraph 4 of this Amended Agreement: if the UPR (as defined in Attachment 3) exceeds the UCR (as also defined in Attachment 3), APS should adjust the 55 percent ratepayer share to reflect inclusion of the Company's 45% share of such Property Tax Expense decrease that would otherwise result from the Amended Agreement's calculation of the rate incentive mechanism described in this Paragraph. After giving effect to the consolidation, elimination and restructuring of certain existing rate offerings as discussed below, any net revenue decrease would be allocated among customers by means of a uniform percentage reduction in the demand and energy charges for all current APS rate schedules, except those set forth in Attachment 2. In any year, if the average cost/kWh is equal to or exceeds the average price/kWh, there would be no further change in base rates (neither a decrease nor an increase in base rates for that year). 3. Under this Amended Agreement, certain regulatory assets will be recovered by accelerating their amortization over an eight year period commencing July 1, 1996. These assets are primarily cost deferrals from Palo Verde Units 2 and 3, that were recorded under ACC approved accounting orders, and regulatory assets to cover future income tax liabilities recorded in 1993 as a result of implementing Financial Accounting Standard No. 109 with respect to deferred income taxes. This amortization will be included in the calculation of the average cost/kWh. The accelerated amortization approved in this proceeding is for the purpose of settlement and anticipates the transition period toward a more competitive marketplace. Further, APS agrees that the accelerated amortization of these regulatory assets cannot be used as a separate justification for a net rate increase in any future rate proceeding. Finally, at the end of the Moratorium Period, the accelerated rate of amortization will continue until further order of the Commission. 4. The determination of the reduction to base rates for the succeeding years will be determined pursuant to the Company's calculation of the average price and cost/kWh using data from the prior calendar year. A filing of this calculation will be made on or about March 1 of each year for Staff review. Such filing will also be made available to the Arizona Residential Consumer Office ("RUCO") for its review and comment. Any reduction for the current year will become effective for usage on or after July 1, if and only if such reduction is approved by the Commission. If the Commission orders a hearing on such decrease, this would automatically delay the effective date of any decrease until a final order is issued. 5. To improve the Company's equity ratio in anticipation of greater competition, Pinnacle West Capital Corporation will infuse $200 million of common equity, in $50 million increments, by each year-end beginning in 1996, into APS with such infusion to be included in calculating each year's average cost/kWh under this Amended Agreement. 6. During the Moratorium Period, no party shall seek to change the rates except as set forth specifically in this Amended Agreement. However, neither APS nor Staff shall be prevented from seeking a change in rates prior to July 2, 1999 in the event of: (a) conditions or circumstances which constitute an emergency, such as the inability to finance on reasonable terms, or (b) material changes in the Company's cost of service as a result of federal, tribal, state or local laws, regulatory requirements, judicial decisions, actions, or orders. 7. The parties agree to the following revisions of current rate schedules and new tariffs: a. Any flexible pricing tariff provision as was suggested by APS in Revised Attachment 4 should be considered in the Commission's electric competition docket (Docket No. U-0000-94-165). b. The Company shall retain the right to propose for Commission approval during the Moratorium Period new or revised rate designs. Examples of this type of filing might be: i. Revised time-of-use (TOU) pricing periods and prices (both residential and general service) once advanced meter communications systems are in place. APS agrees to submit such a TOU proposal before December 31, 1996. ii. A real-time pricing experiment or operational program. iii. Unbundled retail rates to provide customers alternative service options. 8. The parties agree to the following changes to current rate schedules. These changes are designed to more accurately reflect the costs to serve, promote fairness among similar customer groups, and improve customer understanding and acceptability of the pricing, terms and conditions of the tariffs. a. Revise Schedule #1, General Terms and Conditions of Service, so that credit and collections practices and charges fairly and properly collect costs from customers who impose those costs on APS without subsidies from other customers. The parties also agree to other minor changes to clarify current practices and service specifications. These proposed changes are summarized in Revised Attachment 5. b. Revise partial requirements provisions of the tariff to consistently and fairly charge for services provided. APS has a variety of rates applicable to various types of partial requirements customers and these are proposed to be revised to apply market-based charges for standby, and cost-based charges for supplemental and maintenance service. The proposed tariffs (Schedules E-55 and E-52) are attached as Revised Attachment 6. Schedules E-55 and E-52 shall: * indicate that the customer designates the amount of standby capacity he or she wants in setting the contract standby capacity and that the capacity could be less than the capacity of the self generation facility. In addition, APS shall review whether the potential for lower rates for a customer with a capacity factor consistently below 75 percent (relative to a customer with a higher capacity factor) is in need of correction or clarification. Schedule E-51 shall be frozen to new and reconnecting customers. Schedule E-50 shall be cancelled. c. EPR-1, -2, and -3, purchase rates for small qualified cogeneration customers, would be revised to reflect current buy-back rates, current metering technology and establish consistency among the rates. Schedule EPR-4 shall reference schedules for sales to the customer. In addition, Schedule EPR-2 shall offer an option for the incremental cost of the bidirectional meter to be paid in a lump sum or in monthly installments over a specified time period. Schedule EPR-1 will be cancelled. Proposed tariffs (Schedules EPR-2, EPR-3, and EPR-4) are attached as Attachment 7. d. Eliminate extra-small general service Rate E-31 and incorporate E-31 into Schedule E-32 so that the monthly service charge under the new Schedule E-32 is $12.50, and the energy charge (prior to application of the rate decrease) is increased by $0.00024 per kWh for all kWh. e. APS shall submit a new rate (E-20) applicable only to "houses of worship." Said rate shall be open to all qualified customers and shall in all other respects be identical to E-21, which latter rate shall be frozen. A copy of proposed E-20 is attached as Attachment 10. f. APS shall revise Schedule E-3 so that when an otherwise eligible customer uses more than 1200 kWh in any month, such customer will continue to receive a discount under E-3 for that month, but that discount will be a flat $10. A copy of revised Schedule E-3 is attached as Attachment 11. g. APS shall revise Schedule E-4 so that when an otherwise eligible customer uses more than 2000 kWh in any month, such customer will continue to receive a discount under E-4 for that month, but that discount will be a flat $20. A copy of revised Schedule E-4 is attached as Attachment 12. 9. The electric base rates proposed to be effective in 1996 include the costs associated with depreciation and decommissioning expense schedules currently being used by APS. The results of any future Palo Verde decommissioning cost or plant depreciation studies completed during the Moratorium Period would be reflected in the average cost/kWh used in the calculation of additional base rate reductions described in Paragraph 2. Any depreciation or decommissioning study would be reviewed by Staff and RUCO, and the new schedules derived therefrom would be authorized and approved in accordance with the procedure established in Section 13.H of Decision No. 58644. 10. APS' commitment to foster investment in DSM and renewables continues and shall be implemented as follows: a. The EEASE fund shall be eliminated. Any over-recovery shall be refunded to customers through a one-time refund within 120 days of the effective date of the Commission's order. APS will work with Staff and RUCO on a procedure to effectuate this provision. b. A total of $7 million will be included in base rates for demand side management (DSM) and renewables. Of the $7 million total, APS shall undertake at least $3 million of renewables programs per year on average and at least $3 million of DSM per year on average. APS shall spend at least $7 million per year on DSM and renewables projects consistent with this Paragraph 10. Moreover, APS shall attempt to identify, and be authorized to expend and include in its calculation of UCR, up to an additional $3 million per year on additional direct DSM program costs and/or renewables. If APS spends less than the $7 million included in base rates on renewables and DSM per year on average, the Commission, at the next rate case, shall review these expenditures and may order appropriate refunds to ratepayers taking into consideration any sharing that has occurred as a result of Paragraph 2. c. APS shall move to phase out consumer rebate DSM programs for customers and instead substitute shareholder-funded, market-based DSM programs for larger customers and, for all customers, develop and implement ratepayer-funded market transformation activities (such as trade ally programs or consumer education programs). However, costs (including incentives and net lost revenues) for existing and approved customer rebate programs shall be included in the calculation of the Company's $7 million obligation under this Paragraph until such programs have been phased out. APS shall evaluate the effectiveness of market transformation programs. d. APS shall continue its low income DSM program (at least at current levels), complete current monitoring and evaluation commitments, and fulfill outstanding commitments under existing rebate programs. e. APS shall prepare an administrative and implementation plan for Staff review and approval for its DSM and renewables programs within six months of the effective date of this decision. APS shall prepare proposals for new DSM and renewables programs for Staff review and approval. f. APS shall file detailed semi-annual reports with Staff and in Docket Control on all DSM and renewables activities, although confidential information need not be filed in Docket Control. 11. APS recognizes that the jurisdictional portion of any net refund that it receives as a result of disposition of the property tax lawsuit (Tucson Electric Power v. Apache County, 175 Ariz. 485 (App. 1995)) is owed to its customers, since these taxes were collected from and paid by customers to APS through rates. Therefore, APS will refund to its customers the net jurisdictional amount of overcollected property taxes that are refunded to APS by the State of Arizona. APS agrees to work cooperatively with Staff and RUCO to determine the amount of any refund and method for returning the refund to customers. 12. The rates and charges authorized herein fully include a return on the recorded book original cost of all jurisdictional APS assets (net of depreciation, amortization, and deferred income taxes and other deferred credits) as of June 30, 1995, excepting construction work in progress as of such date. However, nothing in this Amended Agreement shall be construed as prohibiting Staff or any other party from pursuing new issues related to expenditures made or actions taken after June 30, 1995. 13. Staff and APS stipulate to the adoption of the fair value rate base and fair rate of return and agree that the resultant revenue decrease, as reflected in Paragraph 1 above, results in just and reasonable rates for the Company. The determinations made in this Paragraph are made solely for the purpose of the stipulation contained in this Amended Agreement. 14. Each provision of this Amended Agreement is in consideration and support of all the other provisions. This Amended Agreement shall not become effective until the issuance of a final Commission Order approving this Amended Agreement without change or alteration on or before July 1, 1996 in the form of a Proposed Order to be agreed to by the parties. In the event that the Commission fails to adopt this Amended Agreement according to its terms on or before July 1, 1996, this Agreement shall be deemed automatically withdrawn, the rate reduction provisions of this Amended Agreement shall not take effect, and APS and Staff shall be free to pursue their respective positions without prejudice. In addition, if any appeal is taken or other judicial review is sought of a final Commission Order approving this Amended Agreement, then the parties shall no longer be bound by the terms of this Amended Agreement and this Amended Agreement shall automatically become null and void, in which case: (1) the rate reduction specified in Paragraph 1 shall immediately cease; (2) all bills rendered on or after that date shall be at the rates existing immediately prior to the Commission's approval of this Amended Agreement; and (3) the revenue reduction theretofore experienced by APS pursuant to Paragraph 1 shall be recovered through a surcharge mechanism. 15. The terms and provisions of this Amended Agreement apply solely to and are binding only in the context of the purposes and results of this Amended Agreement and none of the positions taken herein by APS may be referred to, cited or relied upon by any other party in any fashion as precedent or otherwise in any other proceeding before this Commission or any other regulatory agency or before any court of law for any purpose except in furtherance of the purposes and results of this Agreement. Nothing in this Amended Agreement shall be construed as imposing a cap on the Company's otherwise reasonable and prudent cost of service for purposes of setting just and reasonable rates. 16. This Amended Agreement represents an attempt to compromise and settle issues regarding the prospective just and reasonable rate levels for APS in a manner consistent with the public interest and applicable legal requirements. Nothing contained in this Amended Agreement is an admission by APS that its current rate levels or rate design are unjust or unreasonable. 17. APS' agreement to the matters contained herein is predicated on a national movement toward competition in the electricity industry. That movement raises a number of policy and legal issues in Arizona which are summarized (not necessarily completely) in the Points of Agreement (Attachment 8). APS has its own views, independent of any the Staff may have, of the proper resolution of certain of the issues presented in the Points of Agreement. Such views are summarized in Attachment 9. Dated at Phoenix, Arizona, this 18th day of April, 1996. STAFF OF ARIZONA ARIZONA PUBLIC SERVICE CORPORATION COMMISSION COMPANY By: Gary Yaquinto By: William J. Post ----------------------- ----------------------- Title: Director, Utilities Division Title: SVP & COO ---------------------------- --------- Attachment 1 Page 1 of 2 REVISED ATTACHMENT 1 Calculation of Rate Reduction Adjusted Test Year 12 Months Ended June 30, 1995
(a) (b) (c) (d) (e) Average Base Revenue Total Revenue Ln. No. of at 5/27/94 W/ EEASE Factor Base Revenue # Rate Customers Rate Level @ $0.00057/kWh Less B.S.C. ----------------- --------- -------------- -------------- -------------- 1 Residential Class 629,423 $ 666,809,056 $ 670,737,289 $ 596,409,819 2 Commercial & Industrial 78,948 $ 741,101,257 $ 746,327,818 $ 727,789,547 3 Outdoor Lighting 8,573 $ 15,701,309 $ 15,755,725 $ 15,701,309 --------- -------------- -------------- -------------- 4 Base Revenues Subject to Decrease 716,944 $1,423,611,622 $1,432,820,832 $1,339,900,675 5 Revenue Not Subject to Decrease 6 $ 61,523,908 $ 62,086,338 $ 61,435,918 ========= ============== ============== ============== 6 Retail Totals 716,950 $1,485,135,530 $1,494,907,170 $1,401,336,593 (L4 + L5)
(a) (f) (g) (h) (i) (j) Revenue Decrease ------------------------------------------------------------------- Base Rate Decrease Ln. Excluding B.S.C. Total Decrease Ln. EEASE ------------------------ --------------------- # Rate Decrease ($/Yr) % ($/Yr) % # ----------------- ---------- ----------- -------- ----------- --------- (d) - (c) (e) x (h) (f) + (g) (i) / (c) 1 Residential Class $3,928,233 $18,771,708 3.147% $22,699,941 3.40% 1 2 Commercial & Industrial $5,226,561 $19,998,980 2.748% $25,225,541 3.40% 2 3 Outdoor Lighting $ 54,416 $ 480,098 3.058%$ 534,514 3.40% 3 ---------- ----------- ----------- 4 Base Revenues Subject to Decrease $9,209,210 $39,250,786 $48,459,996 3.40% 4 5 Revenue Not Subject to Decrease $ - $ - 0.000 $ - 0.00% 5 ========== =========== =========== 6 Retail Totals $9,209,210 $39,250,786 $48,459,996 3.26% 6 (L4 + L5)
Notes: 1. Includes customer annualization, weather normalization, and rate annualization. 2. The non-firm portion of Stone Southwest (Papermill) is not subject to the decrease. The firm portion of their load is included with the Other Contracts. 3. EEASE factor of $0.00057/kWh was authorized by the ACC effective 11/1/95. 4. The EEASE decrease of $9,209,210 excludes the special contracts listed in Attachment 2. Page 2 of 2 REVISED ATTACHMENT 1 Detailed Calculation of Reductions by Rate Adjusted Test Year 12 Months Ended June 30, 1995
(a) (b) (c) (d) (e) Average Base Revenue Total Revenue Ln. No. of at 5/27/94 W/ EEASE Factor Base Revenue # Rate Customers Rate Level @ $0.00057/kWh Less B.S.C. ---------------------- ----------- ------------------- ----------------------------------------- Residential Class ----------------- 1 E-10 173,276 $ 150,992,011 $ 151,847,207 $ 135,397,194 2 E-12 268,602 $ 213,357,415 $ 214,499,943 $ 189,183,235 3 EC-1 52,133 $ 97,322,262 $ 97,943,953 $ 91,066,362 4 ET-1 103,016 $ 141,855,712 $ 142,726,499 $ 123,312,817 5 ECT-1R 32,397 $ 63,281,656 $ 63,719,687 $ 57,450,211 --------- -------------- -------------- -------------- 6 Class Totals 629,423 $ 666,809,056 $ 670,737,289 $ 596,409,819 General Service Class --------------------- 7 E-21 82 $ 346,180 $ 348,131 $ 319,666 8 E-22 11 $ 520,650 $ 523,507 $ 517,086 9 E-23 18 $ 663,376 $ 667,532 $ 650,906 10 E-24 22 $ 9,960,509 $ 10,053,133 $ 9,693,509 11 E-30 2,951 $ 1,529,919 $ 1,535,734 $ 1,308,575 12 E-31 18,290 $ 13,276,445 $ 13,332,218 $ 10,532,983 13 E-32 55,499 $ 598,376,967 $ 602,324,754 $ 590,052,192 14 E-34 37 $ 56,733,442 $ 57,285,705 $ 55,654,522 15 E-35 5 $ 14,573,343 $ 14,744,198 $ 14,426,343 16 E-40 37 $ 33,423 $ 33,451 $ 33,423 17 E-51 3 $ 547,604 $ 552,652 $ 546,452 18 E-67 255 $ 185,337 $ 188,144 $ 185,337 19 E-221 826 $ 14,073,150 $ 14,177,352 $ 13,924,530 20 BHP Minerals 1 $ 3,581,217 $ 3,615,797 $ 3,581,217 21 Cyprus Bagdad 1 $ 21,510,570 $ 21,510,570 $ 21,510,570 22 EPNG (Leupp) 1 $ 1,000,000 $ 1,000,000 $ 970,660 23 EPNG (Seligman) 1 $ 1,000,000 $ 1,000,000 $ 970,660 24 Magma Copper 1 $ 36,701,430 $ 37,263,860 $ 36,672,270 25 Phelps Dodge 1 $ 194,220 $ 194,220 $ 194,220 26 Stone Southwest 1 $ 1,117,688 $ 1,117,688 $ 1,117,538 27 Other Contracts 15 $ 16,771,704 $ 16,946,331 $ 16,594,878 --------- -------------- -------------- -------------- 28 Class Totals 78,057 $ 792,697,174 $ 798,414,976 $ 779,457,537 Irrigation Class ---------------- 29 E-31 19 $ 6,198 $ 6,215 $ 3,311 30 E-32 24 $ 55,005 $ 55,284 $ 51,355 31 E-38 336 $ 3,330,901 $ 3,356,027 $ 3,270,346 32 E-221 517 $ 6,535,887 $ 6,581,654 $ 6,442,917 --------- -------------- -------------- -------------- 33 Class Totals 897 $ 9,927,991 $ 9,999,180 $ 9,767,929 Street Lighting Class --------------------- 34 E-58 471 $ 6,479,599 $ 6,494,434 $ 6,479,599 35 Share the Light 0 $ 160,263 $ 160,739 $ 160,263 36 Dept. of Trans. 35 $ 420,022 $ 423,252 $ 420,022 37 City Contracts 13 $ 4,054,925 $ 4,078,327 $ 4,054,925 --------- -------------- -------------- -------------- 38 Class Totals 518 $ 11,114,809 $ 11,156,753 $ 11,114,809 Dusk to Dawn Lighting Class --------------------------- 39 Residential 2,333 $ 458,497 $ 459,814 $ 458,497 40 General Service 5,722 $ 4,128,003 $ 4,139,158 $ 4,128,003 --------- -------------- -------------- -------------- 41 Class Totals 8,055 $ 4,586,500 $ 4,598,973 $ 4,586,500 $ - --------- -------------- -------------- -------------- 42 Retail Totals 716,950 $1,485,135,530 $1,494,907,170 $1,401,336,593
(a) (f) (g) (h) (i) (j) Revenue Decrease --------------------------------------------------------------------------- Base Rate Decrease Ln. EEASE Excluding B.S.C. Total Decrease Ln. ---------------------------- ---------------------------- # Rate Decrease ($/Yr) % ($/Yr) % # ---------------------- --------------- ----------------- ---------- ---------------- ---------- (d) - (c) (e) x (h) (f) + (g) (i) / (c) Residential Class ----------------- 1 E-10 $ 855,196 $ 4,261,561 3.147% $ 5,116,756 3.39% 1 2 E-12 $ 1,142,528 $ 5,954,450 3.147% $ 7,096,978 3.33% 2 3 EC-1 $ 621,691 $ 2,866,269 3.147% $ 3,487,960 3.58% 3 4 ET-1 $ 870,787 $ 3,881,211 3.147% $ 4,751,997 3.35% 4 5 ECT-1R $ 438,031 $ 1,808,217 3.147% $ 2,246,248 3.55% 5 ----------- ------------ ------------ 6 Class Totals $ 3,928,233 $ 18,771,708 $ 22,699,941 3.40% 6 General Service Class --------------------- 7 E-21 $ 1,951 $ 8,786 2.749% $ 10,738 3.10% 7 8 E-22 $ 2,857 $ 14,213 2.749% $ 17,070 3.28% 8 9 E-23 $ 4,156 $ 17,891 2.749% $ 22,047 3.32% 9 10 E-24 $ 92,624 $ 266,436 2.749% $ 359,060 3.60% 10 11 E-30 $ 5,815 $ 35,968 2.749% $ 41,783 2.73% 11 12 E-31 $ 55,773 $ 289,510 2.749% $ 345,283 2.60% 12 13 E-32 $ 3,947,787 $ 16,218,216 2.749% $ 20,166,002 3.37% 13 14 E-34 $ 552,263 $ 1,529,724 2.749% $ 2,081,987 3.67% 14 15 E-35 $ 170,855 $ 396,523 2.749% $ 567,379 3.89% 15 16 E-40 $ 28 $ 919 2.749% $ 947 2.83% 16 17 E-51 $ 5,048 $ 15,020 2.749% $ 20,068 3.66% 17 18 E-67 $ 2,807 $ - 0.000% $ 2,807 1.51% 18 19 E-221 $ 104,202 $ 382,731 2.749% $ 486,932 3.46% 19 20 BHP Minerals $ 34,580 $ 98,434 2.749% $ 133,013 3.71% 20 21 Cyprus Bagdad $ - $ - 0.000% $ - 0.00% 21 22 EPNG (Leupp) $ - $ - 0.000% $ - 0.00% 22 23 EPNG (Seligman) $ - $ - 0.000% $ - 0.00% 23 24 Magma Copper $ - $ - 0.000% $ - 0.00% 24 25 Phelps Dodge $ - $ - 0.000% $ - 0.00% 25 26 Stone Southwest $ - $ - 0.000% $ - 0.00% 26 27 Other Contracts $ 174,627 $ 456,128 2.749% $ 630,755 3.76% 27 ----------- ------------ ------------ 28 Class Totals $ 5,155,372 $ 19,730,498 $ 24,885,870 3.14% 28 Irrigation Class 29 E-31 $ 17 $ 91 2.749% $ 108 1.74% 29 30 E-32 $ 279 $ 1,412 2.749% $ 1,691 3.07% 30 31 E-38 $ 25,126 $ 89,889 2.749% $ 115,015 3.45% 31 32 E-221 $ 45,767 $ 177,090 2.749% $ 222,858 3.41% 32 ----------- ------------ ------------ 33 Class Totals $ 71,189 $ 268,482 $ 339,671 3.42% 33 Street Lighting Class --------------------- 34 E-58 $ 14,835 $ 196,131 3.027% $ 210,966 3.26% 34 35 Share the Light $ 476 $ 4,851 3.027% $ 5,327 3.32% 35 36 Dept. of Trans. $ 3,230 $ 12,714 3.027% $ 15,944 3.80% 36 37 City Contracts $ 23,402 $ 122,738 3.027% $ 146,140 3.60% 37 ----------- ------------ ------------ 38 Class Totals $ 41,944 $ 336,434 $ 378,377 3.40% 38 Dusk to Dawn Lighting Class --------------------------- 39 Residential $ 1,317 $ 14,362 3.132% $ 15,679 3.42% 39 40 General Service $ 11,155 $ 129,302 3.132% $ 140,458 3.40% 40 ----------- ------------ ------------ 41 Class Totals $ 12,473 $ 143,664 $ 156,137 3.40% 41 ----------- ------------ ------------ 42 Retail Totals $ 9,209,210 $ 39,250,786 $ 48,459,996 3.26% 42
Notes: 1. Includes customer annualization, weather normalization, and rate annualization. 2. The non-firm portion of Stone Southwest (Papermill) is not subject to the decrease. The firm portion of their load is included with the Other Contracts. 3. EEASE factor of $0.00057/kWh was authorized by the ACC effective 11/1/95. 4. The EEASE decrease of $9,209,210 excludes the special contracts listed in Attachment 2. Attachment 2 Attachment 2 Rates and Contracts Exempt From General Rate Decreases 1. Rate E-67, Municipal Lighting Service -- City of Phoenix 2. Cyprus Copper Company Contract 3. El Paso Natural Gas (Leupp and Seligman) Contract 4. Magma Copper Company Contract 5. Phelps Dodge Contract 6. Stone Southwest Contract 7. Future ACC approved contracts with pricing provisions that exempt them from general rate decreases. These rates and contracts are already discounted or have fixed rate provisions and will not be subject to the general price decreases resulting from the operation of the Plan unless so specified by contract. Attachment 3 Attachment 3 Unit Cost Ratio and Unit Price Ratio Definitions (The revenues and costs to be utilized in this calculation will be derived from the actual audited financial statements of the Company) Unit Cost Ratio (UCR): Annual cents-per-kilowatt-hour average cost of electric services. UCR = Annual total electric costs (1) -------------------------------- Annual total Company kwh sales(2) Unit Price Ratio (UPR): Annual cents-per-kilowatt-hour average price of electric services. UPR = Annual electric revenues (3) ---------------------------------- Annual total Company kwh sales (2) 1. Excludes sales taxes (as in the case of the income statement), all ITC amortization (as required by federal tax laws), annual Pinnacle West charges net of costs for shareholder services, fuel expenses for non-traditional and interchange sales (generally defined as opportunity sales which are cost justified on an incremental basis), and non-utility income or deductions and related income tax effects. Includes fuel, operations and maintenance, depreciation and amortization (including the accelerated amortization of regulatory assets), property and other taxes, cost of capital (consisting of long-term interest; debt discount, premium and expense; preferred stock dividend requirements; and a return on equity of 11.25% applied to the average annual equity balance), the gross profit margin on non-traditional and interchange sales, DSM and renewable expenditures (including net lost revenues and incentives), and income taxes on Operating Income including adjustments to income taxes for the above exclusions and inclusions. 2. Excludes kwh sales for non-traditional and interchange sales. 3. Includes miscellaneous revenues. Excludes sales taxes (as in the case of the income statement) and non-traditional and interchange revenues. ATTACHMENT 4 REVISED ATTACHMENT 4 (April 10, 1996) ELECTRIC RATES E-36 -------------- ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5223 Phoenix, Arizona Tariff or Schedule No. E-36 Filed by: Gary J. Volkenant Original Filing Title: Director, Business Financial Services Effective: Original Effective Date: FLEXIBLE CONTRACTING -------------------- AVAILABILITY - ------------ In all territory served by Company at all points where facilities of adequate capacity and the required and suitable voltage are adjacent to the premise served. APPLICATION - ----------- This Schedule shall not be used to displace certain natural gas applications installed as of the effective date of this schedule. These applications consist of natural gas boilers, chillers, or cogeneration facilities. Qualified customers must: 1. Maintain a single billing account with an annual average metered demand greater than 2,000 kW, or 2. Have single billing accounts with annual average metered demands greater than 50 kW that, when summed, are greater than 2,000 kW, and 3. Agree to an energy audit or review, unless the customer has recently completed a significant demand side management program or energy audit/review and provides APS with adequate documentation concerning demand side management activities or audit/review, and 4. Have or may acquire a competitive alternative to receiving electric service at APS' otherwise effective price for each billing account, or 5. Have the ability to acquire all or part of their electric service requirements from an alternate supplier, or 6. Desire a long-term contract for electric service. SERVICE BILLING - --------------- Only customers meeting the above criteria can be served under Rate E-36. The negotiated price must be commensurate with the costs to the customer of that customer's current or potential alternative(s). Prices may be revised periodically as specified in the service contract to account for changing conditions, costs, and individual customer requirements. The revenue from the customer shall exceed the marginal cost of serving that customer. For contracts whose terms extend beyond the date when APS will need to add capacity, marginal cost shall mean long run marginal cost. SERVICE CONTRACT - ---------------- The contract terms and conditions will be at the Company's option, based on its assessment of the qualified customer's competitive alternative. The contract may be for varying lengths of time as determined by individual customer or Company requirements. Each executed contract will be submitted to the Commissioners and Commission Staff, on a confidential basis, at least thirty days prior to the effective date of the proposed contract and Staff shall determine whether the contract complies with the tariff prior to the effective date. Such contract will also be provided to the Arizona Residential Utility Consumer Office on a confidential basis. APS must provide adequate documentation on each element of the tariff (for example, the customer's alternatives) before the thirty day review period commences. If no action is taken within 30 days of the filing, the contract is deemed approved by the Commission. Nothing in this tariff is intended to limit the Arizona Corporation Commission's power to order recovery of costs determined to be attributable to the customer either prior to or after termination of the contract. ATTACHMENT 5 REVISED ATTACHMENT 5 PROPOSED CHANGES TO SCHEDULE #1 2. ESTABLISHMENT OF SERVICE 2.2 Add to first sentence, "or to make a special read without a disconnect and calculate a bill for a partial month." 2.2 Change last sentence "Billing for the service charge will be rendered as a part of service bill, but not later than the second service bill." 2.3 GROUNDS FOR REFUSAL OF SERVICE 2.3.8 Change wording to "Service is requested by an Applicant and a prior Customer living with the Applicant owes a delinquent bill." 2.3.9 Change wording to "Applicant is acting as an agent for a prior Customer who is deriving benefits of the electric service and who owes a delinquent bill." 2.4 ESTABLISHMENT OF CREDIT OR SECURITY DEPOSIT 2.4.1.3 Delete Letter of Guarantee. Add ..."Company receives deposit guarantee notification from a social or governmental agency acceptable to the Company" 2.6 SECURITY DEPOSITS 2.6.3 Add "effective on the first business day of each year". 2.6.5.1 Change bankruptcy from within last 6 months to within the last 12 months. 2.6.6 Change to "...Customer's maximum monthly billing as estimated by the Company." 4.2 BILLING AND COLLECTION 4.2.1 Add "All past due charges will be" ...Change late charge from 12% to "18%" 4.4 RETURNED CHECKS 4.4.1 Change $10 to "$15" 4.5 Change collection charge to "field charge", change amount from $9.50 to "$15.00" and add "or terminate the service if not reconnected. This charge will only be applied for field calls resulting from the termination process." 4.5.2 Change acceptable to "satisfactory to Company." 5.3 COMPANY ACCESS TO CUSTOMER PREMISES 5.3 Add requirement of "unassisted" access in two sentences 5.3 Expand remedy for inaccessibility. Add ", or denial of any existing rate options where access is required." Add "All existing conditions shall be grandfathered, i.e. tariff shall apply only to services established after XXXXXX, 1996" 5.5 Add "a minimum standard is IEEE 519" and simplify language to "shall not impair service" 6. METERING AND METERING EQUIPMENT 6.1.1 Add "and/or Electric Service Requirements manual" and "All updates to the Electric Service Requirements manual shall be provided to Staff in a timely manner." 7. TERMINATION 7.1.5 Add "satisfactory and unassisted" and "All existing conditions shall be grandfathered, i.e., tariff shall apply only to services established after XXXXXX, 1996." Attachment 6 ELECTRIC RATES -------------- ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5215 Phoenix, Arizona Tariff or Schedule No. E-52 Filed by: Gary J. Volkenant Original Filing Title: Director, Business Financial Services Effective Date: Original Effective Date: ELECTRIC SERVICE FOR PARTIAL REQUIREMENTS SERVICE ------------------------------------------------- OF LESS THAN 3,000 KW --------------------- I. AVAILABILITY ------------ In all territory served by Company at all points where facilities of adequate capacity and the required phase and suitable voltage are adjacent to the premises served and when all applicable provisions described herein have been met. II. APPLICATION ----------- Applicable to any non-residential customer requiring Partial Requirements services, Supplemental Power, Standby Power or Maintenance Energy with an aggregate Partial Requirements service load of less than 3,000 kW. Customer may elect to take any of the Partial Requirements services offered hereunder, Supplemental Power, Standby Power and Maintenance Power independently of one another or in combination with one another as required. Each customer shall be allowed to designate the specific periods and hours within a month for which utilization of Standby Service is required (see Designated Standby Service Hours). III. TYPE OF SERVICE --------------- Single or three phase, 60 Hertz, at one standard voltage as may be selected by Customer subject to availability at Customer's premise. IV. MONTHLY BILL ------------ The monthly bill shall be the sum of the amounts computed under A., B., C., and D. below, including the applicable Adjustments: A. Basic Service ------------- $ 106.79 per month Basic Service Charge, plus $ 17.06 per month for each Generator Meter B. Supplemental Service -------------------- In accordance with the rate levels contained in General Service Rate Schedule E-32 excluding the monthly Basic Service Charge. C. Standby Service --------------- The monthly charge for Standby Service shall be the sum of the amounts computed in accordance with sections 1 and 2 below: 1. Monthly Reservation Charge of either a, b or c: a. $5.54 per kW of Contract Standby Capacity for Standby Service customers with alternate supply resources demonstrating an aggregate Capacity Factor of 90% or greater during the billing month. b. $7.29 per kW of contract Standby Capacity for Standby Service customers with alternate supply resources demonstrating an aggregate Capacity Factor between 80% - 89.9% during the billing month. c. Standby Service customers whose alternate supply resource(s) achieved an aggregate capacity factor of less than 80% during a billing month shall be assessed the same charge as set forth in Section VIII of this rate schedule. (CONTINUED ON NEXT PAGE) 2. Standby Energy Charge: June - October $0.0202 per kWh on-peak Billing Cycles $0.0140 per kWh off-peak (Summer) November - May $0.0168 per kWh on-peak Billing Cycles $0.0124 per kWh off-peak (Winter) The charges for Standby Service contained in Section C herein reflect the Company's costs to serve Standby Service loads. For applications where the charges for Standby Service stated herein are not competitive with customer installed standby resource alternatives, the Company may negotiate alternate Monthly Reservation Charges from those contained in this rate schedule; however, the maximum discount allowed shall not be greater than fifty percent (50%) of the Reservation Charges stated herein; however, such discount shall not result in a reservation charge lower than the Company's long run capacity costs associated with this service. No changes to the Standby Energy Charge rate component shall be allowed. To be eligible for negotiated Monthly Reservation Charges different than those contained herein, the customer must demonstrate to the Company's satisfaction and provide conclusive documentation (e.g., engineering studies, analysis, etc.) that the customer's on-site self-generation resource(s) would be a lower cost option over the life of the equipment than had the customer subscribed to Standby Service from the Company. Notwithstanding the potential competitiveness of the customer's self generation standby facilities, the Company in its sole opinion, shall have the option of not offering any discounts to the otherwise applicable Reservation Charge. D. Maintenance Service ------------------- $0.0168 per kWh on-peak $0.0124 per kWh off-peak E. Energy Rates ------------ The energy rates in Sections C and D above are based on the Company's estimated marginal costs and will be updated annually to reflect changes in the Company's fuel costs. V. DETERMINATION OF SUPPLEMENTAL SERVICE ------------------------------------- Supplemental service shall be defined as demand and energy contracted by Customer to augment the power and energy generated by Customer's generation facility. Supplemental demand shall be the highest 15-minute interval during the billing month which shall equal the (a) 15-minute integrated kW demand calculated for every 15-minute interval as recorded on the Supply Meter, plus (b) the simultaneous 15 minute integrated kW demand as recorded on the Generator Meter(s), less (c) the aggregate Contract Standby Capacity of all the customer's generating units; however, the result shall never be less than zero (0) for purposes of determining Supplemental Demand. If Company authorized scheduled maintenance was being performed on any of the customer's generators at the time of the highest 15 minute interval during the billing month, the amount of demand recorded on the Supply Meter shall be reduced by the applicable Maintenance Power Level (as determined in Section VII hereof) of the generator unit(s) undergoing authorized scheduled maintenance for purposes of calculating supplemental demand used for billing. Customer's maximum Supplemental Service kW requirements shall not exceed that established in the Electric Supply Agreement. Supplemental energy shall be equal to all energy supplied to Customer as determined from readings of the Supply Meter, less any energy determined to be either Standby or Maintenance energy as defined in this Schedule. VI. DETERMINATION OF STANDBY ENERGY ------------------------------- Standby Energy shall be defined to be electric energy supplied by Company to replace power ordinarily generated by Customer's generation facility during unscheduled full and partial outages of said facility. (CONTINUED ON NEXT PAGE) When the sum of the energy measured on both the Supply and Generator(s) Meters during simultaneous periods is greater than the maximum energy output of the generator(s) at Contract Standby Capacity, the Standby Energy shall be equal to the summation of the differences between the maximum energy output of the generator(s) at Contract Standby Capacity and the energy measured on the Generator Meter(s) for every 15-minute interval of the month, except when maintenance power is being utilized or those intervals where energy measured on the Supply Meter is zero. When the sum of the energy measured on both the Supply and Generator(s) Meter is equal to or less than the maximum energy output of the generator(s) at Contract Standby Capacity, then the Standby energy shall be that energy measured on the Supply Meter. VII. DETERMINATION OF MAINTENANCE ENERGY ----------------------------------- Maintenance energy shall be defined as energy supplied to Customer to replace energy normally supplied by the Customer's generator(s) during an authorized Scheduled Maintenance period. Maintenance periods shall not exceed 30 days per cogeneration unit during any consecutive 12-month period and must be scheduled during the non-Summer billing months. Customer shall provide Company with its planned maintenance schedule 12 months in advance of any planned maintenance in order for the Company to coordinate customer's scheduled maintenance with that of the Company. Upon review, Company shall either approve customer's planned maintenance schedule or notify customer of alternate acceptable periods. Customer, in turn, shall notify the Company of an acceptable alternate maintenance period(s), and shall also confirm with the Company its intention to perform its planned maintenance 45 days prior to the actual commencement date of the planned maintenance period. Any energy used in excess of a 30-day period or unauthorized maintenance energy shall be billed on either the Standby or Supplemental Rate as specified in this Schedule. Maintenance energy, during a Company authorized period of scheduled maintenance to a customer's generation unit(s), shall be determined as follows: Maintenance Power Level = (Contract Standby Capacity) X (Generating Unit(s) Capacity Factor for the most recent 12 months) The maintenance power level as determined by the above formula shall not exceed any actual 15 minute interval of integrated kW demand as recorded on the supply meter. If customer has less than 12 months of billing history on Standby Service, use the capacity factor demonstrated to date; however, not less than one full month. Maintenance Energy = (Maintenance Power Level) X (hours of maintenance authorized by Company during billing month) VIII. CAPACITY FACTOR STANDARDS ------------------------- Customer's generating unit(s) must maintain a Capacity Factor of no less than 75% over a continuous rolling 18 month period to remain eligible to receive Standby Service under this rate schedule. The calculation of the Capacity Factor is designed so that the customer shall not be subject to this Capacity Factor Standard provision for any purpose other than substandard operational performance of the customer's generating unit(s) recognizing that the customer's load profile may not require the full output capability of such generation unit(s). If the Capacity Factor falls below 75%, in lieu of the otherwise applicable Reservation Charge for Standby Service, the customer shall be assessed a monthly Reservation Charge the greater of: 1. $20.78 per kW/month X 2/3 X Contract Standby Capacity; or 2. $20.78 per kW/month X Maximum Standby Capacity (If customer's system is directly interconnected with the Company's bulk transmission system, the applicable Reservation Charge shall be $15.90 per kW per month.) Maximum Standby Capacity is intended to represent the maximum 15-minute interval of Standby Power provided the customer by the Company during the billing month. Maximum Standby Capacity shall equal the highest 15-minute interval during the billing month of the following calculation: MSC = (SIGMA)CSC - Maint. Where: MSC = Maximum 15-minute interval during the billing month of Standby Power (kW) being supplied by Company. (SIGMA)CSC = The aggregate Contract Standby Capacity of all the customer's self-generation units. Maint = The simultaneous 15-minute interval of any Maintenance Power (kW) being supplied to customer by the Company. (CONTINUED ON NEXT PAGE) IX. METERING -------- The Company will install a Supply Meter at its point of delivery to Customer and a Generator Meter(s) at the point(s) of output from each of Customer's generators. All meters will record integrated demand and energy on the same 15-minute interval basis as specified by Company. X. DEFINITIONS ----------- 1. Contract Standby Capacity - for each specific customer generating unit for which the Company is providing Standby Service, Contract Standby Capacity shall be the greater of: a) the measured kW output of each customer self-generation unit at time of start-up test, or b) the highest 15 minute measured kW output of each generating unit, however, not to exceed Customer's actual total load. 2. Generator Meter - the time-of-use meter used to measure in 15-minute intervals the total power and energy output of each Customer's cogeneration units. 3. Designated Standby Service Hours - Customers requiring Standby Service for less than the total hours in a billing month shall be allowed to designate those periods and hours of a month when Standby Service is required. These Designated Standby Service Hours shall represent those hours within a billing month during which the customer is authorized to utilize Standby Service. Use during any period or hours other than Designated Standby Service Hours shall represent an Unauthorized Use of Standby Service subject to certain special provisions for determining the appropriate Capacity Factor value during billing periods when unauthorized Standby Service was utilized. Such hours shall be specified in whole hour intervals beginning on an hour for each designated day of the week. Designated Standby Service Hours shall never total less than 280 hours a billing month. 4. Capacity Factor - for purposes of this rate schedule, capacity factor shall mean the capacity factor of the customer's generating unit(s) and shall not reflect any period of time during a billing month that Company authorized Maintenance Power was being utilized. The Capacity factor shall be calculated in accordance with the following formula: Capacity Factor = Actual customer generated kWh's during the billing month -------------------------------------------------------- A For purposes of use in this rate schedule, the value of the capacity factor calculation shall never exceed 100%. Where: A = The lesser of: a) [(Contract Standby Capacity) X (MH)]; or b) CTL MH = The number of Designated Standby Service Hours in the billing month, exclusive of any hours during the billing month that customer's unit(s) were non-operational during Company authorized scheduled maintenance, for which the customer has contracted for Standby Service (but not less than 280 hours per billing month). In the event the customer utilizes Standby Service in any period other than during Designated Standby Service Hours, MH shall be represented as the actual number of hours in the billing month (exclusive of any hours during which the customer was receiving Company authorized scheduled Maintenance Energy). Furthermore, in the event there is more than two (2) instances in any 12 month rolling period of Unauthorized Use of Standby Service, MH shall be represented as the actual number of hours in the billing month (exclusive of any hours during which the customer was receiving Company authorized scheduled Maintenance Energy) for the month during which the third breach of service occurred, and for the next three months thereafter. At the end of any three month breach period, a new twelve (12) month rolling period shall commence for determining the number of instances of Unauthorized Use. CTL = Customer's maximum total load during the billing month during the Designated Standby Service Hours for which the Customer has contracted for Standby Service (but not less than 280 hours per month). (CONTINUED ON NEXT PAGE) CTL shall represent the customer's maximum total load during the hours in the billing month for which use of Standby Service has been authorized as set forth in the definition of Designated Standby Service Hours. CTL shall be calculated by first adding the maximum simultaneous 15-minute kW peak periods as recorded on the Supply Meter and Generator Meter(s) during authorized periods of Standby Service the sum of which is then multiplied by MH. In the event the customer utilizes Standby Service during any period of a billing month other than those authorized, CTL shall represent the customer's maximum total (peak demand) load during the billing month calculated as the sum of the maximum simultaneous 15-minute kW peak period during the billing period recorded on the Supply Meter and the Generator Meter(s) during all hours of the billing month. CTL shall be similarly calculated for any other months during which the provision for breach of service explained in the definition of MH above is being assessed. CTL shall only be used for calculating Capacity Factor in those months where the customer's maximum kW load is less than total Contract Standby Capacity. 4. Supply Meter - the time-of-use meter used to measure in 15-minute intervals the total power and energy supplied by Company to Customer. 5. Time Periods - On-Peak Period: 9 a.m. - 9 p.m. Monday through Friday Off-Peak Period: All Other Hours Mountain Standard Time shall be used in the application of this rate schedule. In addition, to prevent radical changes in the system loads the beginning and ending hours for individual customers may be varied by up to one hour (total hours in each time period to remain unchanged) and because of potential differences of the timing devices, there may be a variation of up to 15 minutes in timing for the pricing periods. XI ADJUSTMENTS ----------- The applicable proportionate part of any taxes or governmental impositions which are or may in the future be assessed on the basis of gross revenues of the Company and/or the price or revenue from the electric energy or service sold and/or the volume of energy generated or purchased for sale and/or sold hereunder. XII. TERMINATION PROVISION --------------------- Should Customer cease to operate his cogeneration unit(s) for 60 consecutive days during periods other than planned scheduled maintenance periods, Company reserves the option to terminate the Agreement for service under this rate schedule with Customer. XIII. CONTRACT PERIOD --------------- As provided in the Electric Supply Agreement between Company and Customer. XIV. TERMS AND CONDITIONS -------------------- Customer must enter into an Agreement for the Interconnection and The Sale of Power with Company and an Electric Supply Agreement which shall establish all pertinent details related to interconnection and other required service standards. Customer will not have the option to sell power and energy to Company under this tariff. Should Customer desire to do so, Customer would be required to enter into a new Service Agreement which would set forth the applicable purchase rate in addition terms and conditions for interconnection and for the sale of power to the Company. Customer will be required to contract for adequate standby power to cover the total output of all the customer's generators unless adequate facilities have been installed, to the satisfaction of APS, that isolates portions of the customer's load from APS' system so that APS will in no event be providing standby service in excess of Contracted Standby Capacity. XV. CHANGE IN DESIGNATED STANDBY SERVICE HOURS ------------------------------------------ Customers shall be allowed no more than one (1) change in their Designated Standby Service Hours during any eighteen (18) month time period. In no event shall the total of Designated Standby Service Hours during a month fall below 280 hours. ELECTRIC RATES -------------- ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5214 Phoenix, Arizona Tariff or Schedule No. E-55 Filed by: Gary J. Volkenant Original Filing Title: Director, Business Financial Services Effective Date: Original Effective Date: ELECTRIC SERVICE FOR PARTIAL REQUIREMENTS SERVICE ------------------------------------------------- 3,000 KW OR GREATER ------------------- I. AVAILABILITY ------------ In all territory served by Company at all points where facilities of adequate capacity and the required phase and suitable voltage are adjacent to the premises served and when all applicable provisions described herein have been met. II. APPLICATION ----------- Applicable to any customer requiring Partial Requirements services, Supplemental Power, Standby Power or Maintenance Energy with an aggregate Partial Requirements service load of no less than 3,000 kW. Customer may elect to take any of the Partial Requirements services offered hereunder (Supplemental Power, Standby Power and Maintenance Power) independently of one another or in combination with one another as required. Customers having Standby Service requirements not exceeding 2,999 kW shall be allowed to designate specific periods and hours within a month for which utilization of Standby Service is required (see Designated Standby Service Hours). III. TYPE OF SERVICE --------------- Single or three phase, 60 Hertz, at one standard voltage as may be selected by Customer subject to availability at Customer's premise. IV. MONTHLY BILL ------------ The monthly bill shall be the sum of the amounts computed under A., B., C., and D. below, including the applicable Adjustments: A. Basic Service ------------- 1. a) For applications no greater than 15,000 kW: $ 1,671.39 per month Basic Service Charge; plus b) For applications greater than 15,000 kW: The monthly Basic Service Charge shall be $1,671.39 plus an applicable adder for recovery of non-standard metering costs and related O&M expenses; plus 2. $ 62.51 per month for each Generator Meter B. Supplemental Service -------------------- In accordance with the rate levels contained in General Service Rate Schedule E-32, excluding the monthly Basic Service Charge (or E-34 if Supplemental Power requirements are 3,000 kW or more). C. Standby Service --------------- The monthly charge for Standby Service shall be the sum of the amounts computed in accordance with sections 1, 2 and 3 below: 1. For customers taking service at voltage levels of less than 69 kV, a Monthly Reservation Charge of either a, b, c or d: a. $ 4.53 per kW of Contract Standby Capacity for Standby Service customers with alternate supply resources demonstrating an aggregate Capacity Factor of 95% or greater during the billing month. b. $ 5.54 per kW of Contract Standby Capacity for Standby Service customers with alternate supply resources demonstrating an aggregate Capacity Factor between 90% - 94.9% during the billing month. c. $ 7.29 per kW of Contract Standby Capacity for Standby Service customers with alternate supply resources demonstrating an aggregate Capacity Factor between 80% - 89.9% during the billing month. d. Standby Service customers whose alternate supply resource(s) achieved an aggregate capacity factor of less than 80% during a billing month shall be assessed the same charge as set forth in Section VIII.A of this rate schedule. (CONTINUED ON NEXT PAGE) 2. For customers who take service at voltage levels of 69 kV or greater, a Monthly Reservation Charge of either a, b, c or d: a. $ 1.56 per kW of Contract Standby Capacity for Standby Service customers with alternate supply resources demonstrating an aggregate Capacity Factor of 95% or greater during the billing month. b. $ 2.49 per kW of Contract Standby Capacity for Standby Service customers with alternate supply resources demonstrating an aggregate Capacity Factor between 90% - 94%.9% during the billing month. c. $ 4.42 per kW of Contract Standby Capacity for Standby Service customers with alternate supply resources demonstrating an aggregate Capacity Factor between 80% - 89.9% during the billing month. d. Standby Service customers whose alternate supply resource(s) achieved an aggregate capacity factor of less than 80% during a billing month shall be assessed the same charge as set forth in Section VIII.B of this rate schedule. 3. Standby Energy Charge: June - October $0.0208 per kWh on-peak Billing Cycles $0.0147 per kWh off-peak (Summer) November - May $0.0173 per kWh on-peak Billing Cycles $0.0128 per kWh off-peak (Winter) The charges for Standby Service contained in Section C herein reflect the Company's costs to serve Standby Service loads. For applications where the charges for Standby Service stated herein are not competitive with customer installed standby resource alternatives, the Company may negotiate alternate Monthly Reservation Charges from those contained in this rate schedule; however, the maximum discount allowed shall not be greater than fifty percent (50%) of the Reservation Charges stated herein; however, such discount shall not result in a reservation charge lower than the Company's long run capacity costs associated with this service. No changes to the Standby Energy Charge rate component shall be allowed. To be eligible for negotiated Monthly Reservation Charges different than those contained herein, the customer must demonstrate to the Company's satisfaction and provide conclusive documentation (e.g., engineering studies, analysis, etc.) that the customer's on-site self-generation resource(s) would be a lower cost option over the life of the equipment than had the customer subscribed to Standby Service from the Company. Notwithstanding the potential competitiveness of the customer's self generation standby facilities, the Company in its sole opinion, shall have the option of not offering any discounts to the otherwise applicable Reservation Charge. D. Maintenance Service ------------------- $0.0173 per kWh on-peak $0.0128 per kWh off-peak E. Energy Rates ------------ The energy rates in Sections C and D above are based on the Company's estimated marginal costs and will be updated annually to reflect changes in the Company's fuel costs. V. DETERMINATION OF SUPPLEMENTAL SERVICE ------------------------------------- Supplemental service shall be defined as demand and energy contracted by Customer to augment the power and energy generated by Customer's generation facility. Supplemental demand shall be the highest 15-minute interval during the billing month which shall equal the (a) 15-minute integrated kW demand calculated for every 15-minute interval as recorded on the Supply Meter, plus (b) the simultaneous 15 minute integrated kW demand as recorded on the Generator Meter(s), less (c) the aggregate Contract Standby Capacity of all the customer's generating units; however, the result shall never be less than zero (0) for purposes of determining Supplemental Demand. If Company authorized scheduled maintenance was being performed on any of the customer's generators at the time of the highest 15 minute interval during the billing month, the amount of demand recorded on the Supply Meter shall be reduced by the applicable Maintenance Power Level (as determined in Section VII hereof) of the generator unit(s) undergoing authorized scheduled maintenance for purposes of calculating supplemental demand used for billing. Customer's maximum Supplemental Service kW requirements shall not exceed that established in the Electric Supply Agreement. Supplemental energy shall be equal to all energy supplied to Customer as determined from readings of the Supply Meter, less any energy determined to be either Standby or Maintenance energy as defined in this Schedule. (CONTINUED ON NEXT PAGE) VI. DETERMINATION OF STANDBY ENERGY ------------------------------- Standby Energy shall be defined to be electric energy supplied by Company to replace power ordinarily generated by Customer's generation facility during unscheduled full and partial outages of said facility. When the sum of the energy measured on both the Supply and Generator(s) Meters during simultaneous periods is greater than the maximum energy output of the generator(s) at Contract Standby Capacity, the Standby Energy shall be equal to the summation of the differences between the maximum energy output of the generator(s) at Contract Standby Capacity and the energy measured on the Generator Meter(s) for every 15-minute interval of the month, except when maintenance power is being utilized or those intervals where energy measured on the Supply Meter is zero. When the sum of the energy measured on both the Supply and Generator(s) Meter is equal to or less than the maximum energy output of the generator(s) at Contract Standby Capacity, then the Standby energy shall be that energy measured on the Supply Meter. VII. DETERMINATION OF MAINTENANCE ENERGY ----------------------------------- Maintenance energy shall be defined as energy supplied to Customer to replace energy normally supplied by the Customer's generator(s) during an authorized Scheduled Maintenance period. Maintenance periods shall not exceed 30 days per cogeneration unit during any consecutive 12-month period and must be scheduled during the non-Summer billing months. Customer shall provide Company with its planned maintenance schedule 12 months in advance of any planned maintenance in order for the Company to coordinate customer's scheduled maintenance with that of the Company. Upon review, Company shall either approve customer's planned maintenance schedule or notify customer of alternate acceptable periods. Customer, in turn, shall notify the Company of an acceptable alternate maintenance period(s), and shall also confirm with the Company its intention to perform its planned maintenance 45 days prior to the actual commencement date of the planned maintenance period. Any energy used in excess of a 30-day period or unauthorized maintenance energy shall be billed on either the Standby or Supplemental Rate as specified in this Schedule. Maintenance energy, during a Company authorized period of scheduled maintenance to a customer's generation unit(s), shall be determined as follows: Maintenance Power Level = (Contract Standby Capacity) X (Generating Unit(s) Capacity Factor for the most recent 12 months) The maintenance power level as determined by the above formula shall not exceed any actual 15 minute interval of integrated kW demand as recorded on the supply meter. If customer has less than 12 months of billing history on Standby Service, use the capacity factor demonstrated to date; however, not less than one full month. Maintenance Energy = (Maintenance Power Level) X (hours of maintenance authorized by Company during billing month) VIII. CAPACITY FACTOR STANDARDS ------------------------- Customer's generating unit(s) must maintain a Capacity Factor of no less than 75% over a continuous rolling 18 month period to remain eligible to receive Standby Service under this rate schedule. The calculation of the Capacity Factor is designed so that the customer shall not be subject to this Capacity Factor Standard provision for any purpose other than substandard operational performance of the customer's generating unit(s) recognizing that the customer's load profile may not require the full output capability of such generation unit(s). If the Capacity Factor falls below 75%, in lieu of the otherwise applicable Reservation Charge for Standby Service, the customer shall be assessed a monthly Reservation Charge the greater of: A. For customers taking service at voltage levels of less than 69 kV: 1. $ 22.90 per kW/month X 2/3 X Contract Standby Capacity; or 2. $ 22.90 per kW/month X Maximum Standby Capacity (If customer's system is directly interconnected with the Company's bulk transmission system, the applicable Reservation Charge shall be $ 19.45 per kW per month.) B. For customers who take service at voltage levels of 69 kV or greater: 1. $ 20.38 per kW/month X 2/3 X Contract Standby Capacity; or 2. $ 20.38 per kW/month X Maximum Standby Capacity (If customer's system is directly interconnected with the Company's bulk transmission system, the applicable Reservation Charge shall be $ 19.49 per kW per month.) (CONTINUED ON NEXT PAGE) Maximum Standby Capacity is the maximum 15-minute interval of Standby Power provided the customer by the Company during the billing month. Maximum Standby Capacity shall equal the highest 15-minute interval during the billing month of the following calculation: MSC = (SIGMA)CSC - Maint. Where: MSC = Maximum 15-minute interval during the billing month of Standby Power (kW) being supplied by Company. (SIGMA)CSC = The aggregate Contract Standby Capacity of all the customer's self-generation units. Maint = The simultaneous 15-minute interval of any Maintenance Power (kW) being supplied to customer by the Company. IX. METERING -------- The Company will install a Supply Meter at its point of delivery to Customer and a Generator Meter(s) at the point(s) of output from each of Customer's generators. All meters will record integrated demand and energy on the same 15-minute interval basis as specified by Company. X. DEFINITIONS ----------- 1. Contract Standby Capacity - for each specific customer generating unit for which the Company is providing Standby Service, Contract Standby Capacity shall be the greater of a) the measured kW output of each customer self-generation unit at time of start-up test, or b) the highest 15 minute measured kW output of each generating unit, however, not to exceed Customer's actual total load. 2. Generator Meter - the time-of-use meter used to measure in 15-minute intervals the total power and energy output of each Customer's cogeneration units. 3. Designated Standby Service Hours - Customers requiring Standby Service for less than the total hours in a billing month shall be allowed to designate those periods and hours of a month when Standby Service is required. These Designated Standby Service Hours shall represent those hours within a billing month during which the customer is authorized to utilize Standby Service. Use during any period or hours other than Designated Standby Service Hours shall represent an Unauthorized Use of Standby Service subject to certain special provisions for determining the appropriate Capacity Factor value during billing periods when unauthorized Standby Service was utilized. Such hours shall be specified in whole hour intervals beginning on an hour for each designated day of the week. Designated Standby Service Hours shall never total less than 365 hours a billing month. This provision is applicable only to those customers whose Standby Service requirements are less than 3,000 kW. 4. Capacity Factor - for purposes of this rate schedule, capacity factor shall mean the capacity factor of the customer's generating unit(s) and shall not reflect any period of time during a billing month that Company authorized Maintenance Power was being utilized. The Capacity factor shall be calculated in accordance with the following formula: Capacity Factor = Actual customer generated kWh's during the billing month -------------------------------------------------------- A For purposes of use in this rate schedule, the value of the capacity factor calculation shall never exceed 100%. Where: A = The lesser of: a) [(Contract Standby Capacity) X (MH)]; or b) CTL Customers having Standby Service Requirements of 3,000 kW or greater: MH = Hours in the billing month exclusive of any hours during the billing month that customer's unit(s) were non- operational during Company authorized scheduled maintenance. CTL = Customer's maximum total load during the billing month as determined by the total of energy generated on customer's generating unit as recorded on the Generator Meter plus all energy provided by Company during the billing month (exclusive of maintenance energy) as recorded on the Supply Meter (CONTINUED ON NEXT PAGE) Customers having Standby Service Requirements of less than 3,000 kW: MH = The number of Designated Standby Service Hours in the billing month, exclusive of any hours during the billing month that customer's unit(s) were non-operational during Company authorized scheduled maintenance, for which the customer has contracted for Standby Service (but not less than 365 hours per billing month). In the event the customer utilizes Standby Service in any period other than during Designated Standby Service Hours, MH shall be represented as the actual number of hours in the billing month (exclusive of any hours during which the customer was receiving Company authorized scheduled Maintenance Energy). Furthermore, in the event there is more than two (2) instances in any 12 month rolling period of Unauthorized Use of Standby Service, MH shall be represented as the actual number of hours in the billing month (exclusive of any hours during which the customer was receiving Company authorized scheduled Maintenance Energy) for the month during which the third breach of service occurred, and for the next three months thereafter. At the end of any three month period, a new twelve (12) month rolling period shall commence for determining the number of instances of Unauthorized Use. CTL = Customer's maximum total load during the billing month during the Designated Standby Service Hours for which the Customer has contracted for Standby Service (but not less than 365 hours per month).as determined by the total of energy generated on customer's generating unit as recorded on the Generator Meter plus all energy provided by Company during the billing month (exclusive of maintenance energy) as recorded on the Supply Meter. CTL shall represent the customer's maximum total load during the hours in the billing month for which use of Standby Service has been authorized as set forth in the definition of Designated Standby Service Hours. CTL shall be calculated by first adding the maximum simultaneous 15-minute kW peak periods as recorded on the Supply Meter and Generator Meter(s) during authorized periods of Standby Service the sum of which is then multiplied by MH. In the event the customer utilizes Standby Service during any period of a billing month other than those authorized, CTL shall represent the customer's maximum total load (peak demand) during the billing month calculated as the sum of the maximum simultaneous 15-minute kW peak period during the billing period recorded on the Supply Meter and the Generator Meter(s) during all hours of the billing month. CTL shall be similarly calculated for any other months during which the provision for breach of service explained in the definition of MH above is being assessed. CTL shall only be used for calculating Capacity Factor in those months where the customer's maximum kW load is less than total Contract Standby Capacity. 5. Supply Meter - the time-of-use meter used to measure in 15-minute intervals the total power and energy supplied by Company to Customer. 6. Time Periods - On-Peak Period: 9 a.m. - 9 p.m. Monday through Friday Off-Peak Period: All Other Hours Mountain Standard Time shall be used in the application of this rate schedule. In addition, to prevent radical changes in the system loads the beginning and ending hours for individual customers may be varied by up to one hour (total hours in each time period to remain unchanged) and because of potential differences of the timing devices, there may be a variation of up to 15 minutes in timing for the pricing periods. 7. Unauthorized Use - any period or hour of the month that the customer utilized Standby Service other than Designated Standby Service Hours. XI. ADJUSTMENTS ----------- The applicable proportionate part of any taxes or governmental impositions which are or may in the future be assessed on the basis of gross revenues of the Company and/or the price or revenue from the electric energy or service sold and/or the volume of energy generated or purchased for sale and/or sold hereunder. XII. TERMINATION PROVISION --------------------- Should Customer cease to operate his cogeneration unit(s) for 60 consecutive days during periods other than planned scheduled maintenance periods, Company reserves the option to terminate the Agreement for service under this rate schedule with Customer. XIII. CONTRACT PERIOD --------------- As provided in the Electric Supply Agreement between Company and Customer. (CONTINUED ON NEXT PAGE) XIV. TERMS AND CONDITIONS -------------------- Customer must enter into an Agreement for the Interconnection and The Sale of Power with Company and an Electric Supply Agreement which shall establish all pertinent details related to interconnection and other required service standards. Customer will not have the option to sell power and energy to Company under this tariff. Should Customer desire to do so, Customer would be required to enter into a new Service Agreement which would set forth the applicable purchase rate in addition terms and conditions for interconnection and for the sale of power to the Company. Customer will be required to contract for adequate standby power to cover the total output of all the customer's generators unless adequate facilities have been installed, to the satisfaction of APS, that isolates portions of the customer's load from APS' system so that APS will in no event be providing standby service in excess of Contracted Standby Capacity. XV. CHANGE IN DESIGNATED STANDBY SERVICE HOURS ------------------------------------------ Customers for which Designated Standby Service Hours is applicable shall be allowed no more than one (1) change in their Designated Standby Service Hours during any eighteen (18) month time period. In no event shall the total of Designated Standby Service Hours during a month fall below 365 hours. Attachment 7 ELECTRIC RATES ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5216 Phoenix, Arizona Cancelling A.C.C. No. 5137 Filed by: Gary J. Volkenant Tariff or Schedule No. EPR-2 Title: Director, Business Financial Services Revision No. 4 Original Effective Date: October 25, 1981 Effective: PURCHASE RATES FOR QUALIFIED COGENERATION AND SMALL POWER PRODUCTION -------------------------------------------------------------------- FACILITIES UNDER 100 KW RECEIVING PARTIAL REQUIREMENTS OR INTERRUPTIBLE SERVICE ------------------------------------------------------------------------------- AVAILABILITY - ------------ In all territory served by Company. APPLICATION - ----------- To all cogeneration and small power production facilities 100 kW or less where the facility's generator(s) and load are located at the same premise and that otherwise meet qualifying status pursuant to the Arizona Corporation Commission's Decision No. 52345 on cogeneration and small power production facilities. Applicable only to qualifying facilities (QF's) electing to configure their systems as to require only partial requirements or interruptible service from the Company in order to meet their electric requirements. TYPE OF SERVICE - --------------- Electric sales to the Company must be single or three phase, 60 Hertz, at one standard voltage as may be selected by customer (subject to availability at the premises). The qualifying facility will have the option to sell energy to the Company at a voltage level different than that for purchases from the Company; however, the QF will be responsible for all incremental costs incurred to accommodate such an arrangement. PAYMENT FOR PURCHASES FROM AND SALES TO THE CUSTOMER - ---------------------------------------------------- Power sales and special services supplied by the Company to the Customer in order to meet its supplemental or interruptible electric requirements will be priced at the applicable retail rate or rates. The Company will pay the Customer for any energy purchased as calculated on the standard purchase rate (see below). MONTHLY PURCHASE RATE - --------------------- Rate for pricing of energy, net of that for the customer's own use, that is delivered to the Company: Cents per kWh -------------------------------------------- Non-Firm Power Firm Power -------------------------------------------- On-Peak(1) Off-Peak(2) On-Peak(1) Off-Peak(2) ---------- ----------- ---------- ----------- Summer Billing Cycles 1.58 1.17 2.20 1.52 (June - October) Winter Billing Cycles 1.25 1.08 1.74 1.38 (November - May) (1) On-Peak Periods: 9 a.m. to 9 p.m., weekdays (2) Off-Peak Periods: All other hours These rates are based on the Company's estimated avoided energy costs and will be updated annually to reflect changes in the Company's fuel costs. (CONTINUED ON REVERSE SIDE) SERVICE CHARGE - -------------- The monthly service charge shall be determined in accordance with the type of customer service characteristics as set forth below: Monthly Charge -------------- Single Phase Service: 0-200 amp service $ 7.34 Three Phase Service: 0-200 amp service $ 8.87 201-400 amp service $ 18.31 CONTRACT PERIOD - --------------- As provided for in the Purchase Agreement. DEFINITIONS - ----------- 1. Partial Requirements Service - A QF's system configuration whereby the output from its electric generator(s) first go to supply its own electric requirements with any excess energy (over and above its own requirements at the time) then being sold to the Company. The Company supplies the Customer's supplemental electric requirements (those not met by the QF's own generation facilities). This also may be referred to as the "parallel mode" of operation. 2. Special Service(s) - The electric service(s) specified in this section that will be provided by the Company in addition to or in lieu of normal service(s). * Interruptible Power - Electric energy or capacity supplied by the Company subject to interruption by the Company under specified conditions and under agreed upon lead time requirements. 3. Non-Firm Power - Electric power which is supplied by the power producer at the producer's option, where no firm guarantee is provided, and the power can be interrupted by the power producer at any time. 4. Firm Power - Power available, upon demand, at all times (except for forced outages and scheduled maintenance) during the period covered by the Purchase Agreement from the Customer's facilities with an expected or demonstrated reliability which is greater than or equal to the average reliability of the Company's firm power sources. 5. Time Periods - Mountain Standard Time shall be used in the application of this rate schedule. Because of potential differences of the timing devices, there may be a variation of up to 15 minutes in timing for the pricing periods. TERMS AND CONDITIONS - -------------------- Subject to Company's Terms and Conditions for Energy Purchases from Qualified Cogeneration or Small Power Production Facilities, or as it may be amended or modified from time to time by any supplemental or special Terms and Conditions pursuant to Customer's Purchase Agreement with the Company. Customer and Company will share in the cost of the bi-directional meter used to record sales to the Customer and purchases from the Customer. Company shall be responsible for all costs up to and equal to the installed cost of a residential time-of-use meter, and Customer shall be responsible for the difference between the installed cost of the bi-directional meter compared to a standard residential time-of-use meter. Customer shall have the option to pay the incremental metering costs initially or in monthly installements over a five year time period. (CONTINUED ON PAGE 3) METERING CONFIGURATION - ---------------------- [GRAPHIC OMITTED] (The omitted material is a diagram of a bidirectional meter which reads energy flows from the Company into the customer for the customer's QF's load and also reads the QF's generator's excess supply sold back to the Company.) ELECTRIC RATES ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5217 Phoenix, Arizona Cancelling A.C.C. No. 5159 Filed by: Gary J. Volkenant Tariff or Schedule No. EPR-3 Title: Director, Business Financial Services Revision No. 1 Original Effective Date: February 4, 1993 Effective: PURCHASE RATES FOR QUALIFIED SOLAR/PHOTOVOLTAIC SMALL POWER PRODUCTION ---------------------------------------------------------------------- FACILITIES 10 KW OR LESS THAT RECEIVE FULL OR PARTIAL REQUIREMENTS ------------------------------------------------------------------ ELECTRIC SERVICE ---------------- FROZEN AVAILABILITY - ------------ In all territory served by Company. APPLICATION - ----------- To all small power production facilities with a nameplate rating of 10 kW or less utilizing solar/photovoltaic technology where the customer's generator(s) and load are located at the same premise and meet qualifying status pursuant to the Arizona Corporation Commission's Decision No. 52345 on cogeneration and small power production facilities. Applicable only to qualifying facilities (QF's) either: a) operating in the simultaneous buy/sell mode (whereby all the QF's generation output is fed directly into the Company's system and all of the QF's electric requirements are met by sales from the Company) or; b) QF's electing to configure their systems as to require only partial requirements or interruptible service from the company in order to meet their electric requirements. Applicable only to those customers being served on the Company's Rate Schedule EPR-3 prior to ____________________. TYPE OF SERVICE - --------------- Electric sales to the Company must be single phase, 60 Hertz, at one standard voltage as may be selected by customer (subject to availability at the premises). The qualifying facility will have the option to sell energy to the Company at a voltage level different than that for purchases from the Company; however, the Customer will be responsible for all incremental costs incurred by APS to accommodate such an arrangement. BILLING OPTIONS FOR PURCHASES FROM AND SALES TO THE CUSTOMER - ------------------------------------------------------------ The Customer will have the option of choosing either of the following two methods for determining the bill for purchases and sales: A. Net Bill Method: The energy (kWh's) sold to the Company shall be subtracted from the energy purchased from the Company. If the difference is positive, the net energy received from the Company will be priced at the applicable standard retail rate under which the Customer would otherwise purchase its full requirements service. If the difference is negative, the net energy delivered to the Company will be priced at the Monthly Purchase Rate shown below. B. Separate Bill Method: All sales and purchases shall each be treated separately with sales to the Customer billed on the applicable standard retail rate for full requirements service, and purchases of energy from the Customer's QF priced at the Monthly Purchase Rate shown below. MONTHLY PURCHASE RATE - --------------------- Rate for pricing of energy, net of that for the customer's own use, that is delivered to the Company under either Billing Option A or Option B: Cents per kWh ---------------------------------------------- Non-Firm Power Firm Power --------------------- ----------------------- On-Peak(1) Off-Peak(2) On-Peak(1) Off-Peak(2) ---------- ----------- ---------- ----------- Summer Billing Cycles 1.58 1.17 2.20 1.52 (June - October) Winter Billing Cycles 1.25 1.08 1.74 1.38 (November - May) (CONTINUED ON REVERSE SIDE) (1) On-Peak Periods: 9 a.m. to 9 p.m., weekdays (2) Off-Peak Periods: All other hours These rates are based on the Company's estimated avoided energy costs and will be updated annually to reflect changes in the Company's fuel costs. METERING - -------- See pages 3 and 4 Metering Configurations & Options outlining the metering options available to solar/photovoltaic QF Customers electing the simultaneous buy/sell mode or the parallel mode of operation. CONTRACT PERIOD - --------------- As provided for in the Purchase Agreement. DEFINITIONS - ----------- 1. Full Requirements Service - Any instance whereby the Company provides all the electric requirements of a Customer. 2. Partial Requirements Service - A QF's system configuration whereby the output from its electric generator(s) first go to supply its own electric requirements with any excess energy (over and above its own requirements at the time) then being sold to the Company. The Company supplies the Customer's supplemental electric requirements (those not met by the QF's own-generation facilities). This also may be referred to as the "parallel mode" of operation. 3. Special Service(s) - The electric service(s) specified in this section that will be provided by the Company in addition to or in lieu of normal service(s). * Interruptible Power - Electric energy or capacity supplied by the Company subject to interruption by the Company under specified conditions and under agreed upon lead time requirements. 4. Non-Firm Power - Electric power which is supplied by the power producer at the producer's option, where no firm guarantee is provided, and the power can be interrupted by the power producer at any time. 5. Firm Power - Power available, upon demand, at all times (except for forced outages and scheduled maintenance) during the period covered by the Purchase Agreement from the Customer's facilities with an expected or demonstrated reliability which is greater than or equal to the average reliability of the Company's firm power sources. 6. Net Energy - The total kilowatthours (kWh's) sold to the Customer by the Company less the total kWh's purchased by the Company from the Customer's QF. "Net energy" applies only to those QF's operating in the simultaneous buy/sell mode. 7. Time Periods - Mountain Standard Time shall be used in the application of this rate schedule. Because of potential differences of the timing devices, there may be a variation of up to 15 minutes in timing for the pricing periods. TERMS AND CONDITIONS - -------------------- Subject to Company's Schedule No. 2, "Terms and Conditions for Energy Purchases from Qualified Cogeneration or Small Power Production Facilities", or as it may be amended or modified from time to time by any supplemental or special Terms and Conditions pursuant to Customer's Purchase Agreement with the Company. (CONTINUED ON PAGE 3) METERING CONFIGURATIONS & OPTIONS FOR SOLAR/PHOTOVOLTAIC QF APPLICATIONS 10 KW OR LESS (Simultaneous Buy/Sell Mode) [GRAPHIC OMITTED] (The omitted material is a diagram of the QF's generator which has meter 1 of what is sold into the Company. The Company's line goes through meter 2 selling to QF's load.) METERING OPTIONS - -------------------------------------------------------------------------------- Type of Meter Type of Meter (Meter 1) (Meter 2) ------------- ------------- Qualifying Facilities Utilizing Solar/Photovoltaic - --------------------------------------------------- Technology 10 kW or less: - ------------------------- f on an Energy Only (kWh) Type Rate* TOU(a) kWh(b) f on a Time-of-Use Type Rate* TOU(c) TOU(d) * Refers to the Customer's otherwise applicable standard retail rate for firm purchases from the Company. (a) A Time-of-use (TOU) meter that registers kWh's only during peak and off-peak periods as specified in the "Monthly Purchase Rate" section of this rate schedule. (b) A non-timed watthour meter that registers kWh's only. (c) A TOU meter that registers kWh's only during peak and off-peak periods concurrent with those periods used in measuring energy for billing purposes by Meter 2. (d) As per applicable rate schedule. NOTE: APS shall be responsible for providing all required meters for the Simultaneous Buy/Sell Mode under the EPR-3 Metering Configuration. (CONTINUED ON REVERSE SIDE) METERING CONFIGURATIONS & OPTIONS FOR SOLAR/PHOTOVOLTAIC QF APPLICATIONS 10 KW OR LESS (Parallel Mode of Operation) [GRAPHIC OMITTED] (The omitted material is a diagram of two meters which are set between the Company and QF's generator and load. Meter 1 registers sales by the Company and meter 2 represents sales to the Company.) METERING OPTIONS - -------------------------------------------------------------------------------- Type of Meter Type of Meter (Meter 1) (Meter 2) Qualifying Facilities Utilizing Solar/Photovoltaic Technology 10 kW or less: If on an Energy Only (kWh) Type Rate* kWh(a) TOU(b) If on a Time-of-Use Type Rate* TOU(c) TOU(d) *Refers to the Customer's otherwise applicable standard retail rate for firm purchases from the Company. (a) A non-timed watthour meter that registers kWh's only. (b) A Time-of-use (TOU) meter that registers kWh's only during peak and off-peak periods as specified in the "Monthly Purchase Rate" section of this rate schedule. (c) As per applicable rate schedule. NOTE: APS shall be responsible for providing all required meters for the parallel mode of operation under the EPR-3 Metering Configuration. ELECTRIC RATES -------------- ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5188 Phoenix, Arizona Tariff or Schedule No. Filed by: Gary J. Volkenant Original Filing Title: Director, Business Financial Services Effective: Original Effective Date: PURCHASE RATES FOR QUALIFIED SMALL POWER PRODUCTION FACILITIES 10 KW OR LESS ---------------------------------------------------------------------------- UTILIZING RENEWABLE RESOURCE TECHNOLOGIES THAT RECEIVE PARTIAL REQUIREMENTS --------------------------------------------------------------------------- ELECTRIC SERVICE ---------------- AVAILABILITY - ------------ In all territory served by Company. APPLICATION - ----------- To all small power production facilities with a nameplate rating of 10 kW or less utilizing renewable resource technologies where the customer's generator(s) and load are located at the same premise and meet qualifying status pursuant to the Arizona Corporation Commission's Decision No. 52345 on cogeneration and small power production facilities. Applicable only to qualifying facilities (QF's) electing to configure their systems as to require only partial requirements or interruptible service from the Company in order to meet their electric requirements. TYPE OF SERVICE - --------------- Electric sales to the Company must be single phase, 60 Hertz, at one standard voltage as may be selected by customer (subject to availability at the premises). The qualifying facility will have the option to sell energy to the Company at a voltage level different than that for purchases from the Company; however, the Customer will be responsible for all incremental costs incurred by APS to accommodate such an arrangement. PAYMENT FOR PURCHASES FROM AND SALES TO THE CUSTOMER - ---------------------------------------------------- Power sales and special services supplied by the Company to the Customer in order to meet its supplemental or interruptible electric requirements will be priced at the applicable retail rate or rates. The Company will pay the Customer for any energy purchased as calculated on the standard purchase rate (see below). MONTHLY PURCHASE RATE - --------------------- Rate for pricing of energy, net of that for the customer's own use, that is delivered to the Company: Cents per kWh --------------------------------------------- Non-Firm Power Firm Power ---------------------- ---------------------- On-Peak(1) Off-Peak(2) On-Peak(1) Off-Peak(2) ---------- ----------- ---------- ----------- Summer Billing Cycles 1.58 1.17 2.20 1.52 (June - October) Winter Billing Cycles 1.25 1.08 1.74 1.38 (November - May) (1) On-Peak Periods: 9 a.m. to 9 p.m., weekdays (2) Off-Peak Periods: All other hours These rates are based on the Company's estimated avoided energy costs and will be updated annually to reflect changes in the Company's fuel costs. CONTRACT PERIOD - --------------- As provided for in the Purchase Agreement. (CONTINUED ON REVERSE SIDE) DEFINITIONS - ----------- 1. Partial Requirements Service - A QF's system configuration whereby the output from its electric generator(s) first go to supply its own electric requirements with any excess energy (over and above its own requirements at the time) then being sold to the Company. The Company supplies the Customer's supplemental electric requirements (those not met by the QF's own-generation facilities). This also may be referred to as the "parallel mode" of operation. 2. Special Service(s) - The electric service(s) specified in this section that will be provided by the Company in addition to or in lieu of normal service(s). * Interruptible Power - Electric energy or capacity supplied by the Company subject to interruption by the Company under specified conditions and under agreed upon lead time requirements (Non-Firm Power). 3. Non-Firm Power - Electric power which is supplied by the power producer at the producer's option, where no firm guarantee is provided, and the power can be interrupted by the power producer at any time. 4. Firm Power - Power available, upon demand, at all times (except for forced outages and scheduled maintenance) during the period covered by the Purchase Agreement from the Customer's facilities with an expected or demonstrated reliability which is greater than or equal to the average reliability of the Company's firm power sources. 5. Time Periods - Mountain Standard Time shall be used in the application of this rate schedule. Because of potential differences of the timing devices, there may be a variation of up to 15 minutes in timing for the pricing periods. TERMS AND CONDITIONS - -------------------- Subject to Company's Schedule No. 2, "Terms and Conditions for Energy Purchases from Qualified Cogeneration or Small Power Production Facilities", or as it may be amended or modified from time to time by any supplemental or special Terms and Conditions pursuant to Customer's Purchase Agreement with the Company. METERING CONFIGURATION - ---------------------- [GRAPHIC OMITTED] (The omitted material is a diagram of a bidirectional meter which reads energy flows from the Company into the customer for the customer's QF's load and also reads the QF's generator's excess supply sold back to the Company.) Attachment 8 Attachment 8 Points of Agreement RESTRUCTURING ELEMENT Staff has commenced an investigation into electric industry restructuring in Docket No. U-0000-94-165. A Working Group and Task Forces were established to obtain information on possible options, implementation of those options, and some of the advantages and disadvantages of those options. A progress report was issued on October 5, 1995 (Report of the Working Group on Retail Electric Competition). APS has actively participated in all the Working Group efforts. These points of agreement pertain to procedures and outcomes in Docket No. U-0000-94-165 regarding electric industry restructuring. The parties recognize that the Commission may also consider other procedural issues and outcomes. These points of agreement do not commit either APS or the Staff to assert any particular position on the issues identified in Paragraph 5 of Procedural Matters, below, nor do they commit the Commission to resolve any issue in any particular manner or in any particular time frame or sequence. In addition, these points of agreement do not preclude APS, the Staff, or any other participant in Docket No. U-0000-94-165 from raising other issues not identified in this document. Procedural Matters - ------------------ 1. The Commission's process for developing an information base and for considering electric industry restructuring shall continue to be a public process open to all interested parties. 2. In addition to hearings and litigation, a collaborative effort among some interested parties seeking common ground may help resolve some restructuring issues; APS and Staff agree to participate in and support collaborative efforts in good faith. 3. APS and Staff agree to foster resolution of issues in the restructuring Docket and in related activities. 4. Staff and APS agree that they shall urge the Commission to consider the following issues as the Commission develops its policies regarding restructuring, recognizing that other issues may also be raised: a. The legal nature of electric public service corporations' service rights and responsibilities. b. Electric public service corporations' obligations to serve in a restructured environment. c. Compensation for restructuring, taking into account, among other matters: the estimated magnitude of stranded investment; the magnitude of offsetting increases in the market value of assets such as transmission or distribution assets; mitigation of stranded investment; allocation of stranded investment among utilities, consumers in competitive markets, and consumers in noncompetitive markets; collection mechanisms; the period over which stranded investment is collected; and the impacts of alternative compensation approaches on public service corporations, lenders, shareholders, and consumers over the long run. d. Clarification of federal-state jurisdictional uncertainties and possible activities in other forums, including the Legislature and FERC, to help resolve those uncertainties. e. Commission jurisdiction over market entrants (including independent power producers, utilities, and others) and uniformity of regulation of market entrants. f. Maintenance of generation, transmission, and distribution system reliability, including mechanisms and responsibility for services related to reliability. g. Concerns of public power entities over which the Commission does not have jurisdiction regarding restructuring. h. Access by Arizona electric public service corporations to consumers located in other service territories and the terms for access by others to the customers of Arizona public service corporations. i. Whether some or all consumers should be able to access generation in a competitive marketplace, and, if applicable, the pace of introducing competition, including phasing in of competition. j. Market structure, including whether and how to require or induce utility divestiture into generation, transmission, distribution, or other companies. k. Generation structure, including the proper roles of bilateral contracting and pooling of generation. l. Encouragement of energy efficiency through demand side management and other techniques, including competitively neutral allocation of the costs of demand side management programs not borne by participants. m. Encouragement of renewable energy resources through various techniques, such as renewables portfolio requirements, in a manner which does not put some suppliers of electricity to Arizona consumers in a relatively less competitive situation than other suppliers. n. Encouragement of environmental protection in a manner which does not put some suppliers of electricity to Arizona consumers in a relatively less competitive situation than other suppliers. o. Coordination of restructuring with the public interest in integrated resource planning. p. The proper form of regulation for noncompetitive markets in generation and distribution. q. The effect of the market power of existing public service corporations on the development of competitive generation markets, and ways to reduce any impediments to competition. r. The affordability of electric service, especially for low income consumers and consumers in rural areas. s. Limitations on the ability of cooperatives to sell electricity or transmission service to non-members. t. Transaction costs of participation in competitive markets. u. Impacts of restructuring on employment and other economic factors. v. Utility tax structure and its impact on Arizona customers and companies. Outcomes - -------- 1. The results of restructuring should reflect a deliberate process which considers the economic, financial, operational and system planning effects of such restructuring. 2. Restructuring of the electric industry should result in increased efficiency in electric markets, with nondiscriminatory access to transmission and distribution facilities and services. 3. All major customer groups should benefit from competition, including residential customers. 4. Special needs programs, such as lifeline programs, should be continued. 5. Transaction costs of participating in competitive markets and consumer confusion should be minimized. 6. Fair dispute resolution process should be available. 7. The supply of electricity should be reliable over the long term, of adequate quality for consumers, and safe. 8. The investment environment should be conducive to raising capital necessary to provide long-term electric energy services. 9. The electric industry should: * actively seek to protect the natural environment; * promote renewable generating resources to manage uncertainty, control costs, and meet consumer needs over the long run; * encourage efficiency in the use of electric energy, including cost effective demand side management; and * maintain a long term planning perspective. Expectations - ------------ Staff and APS recognize that there is a diversity of opinion on many matters. Staff and APS agree that the Commission should be requested to consider all the procedural and outcome issues listed above in developing its policies on restructuring. The Commission may use hearings and other mechanisms (such as collaborative approaches) to achieve resolution of the issues. Staff and APS agree that the market and political environments may evolve rapidly and that timetables for introducing restructuring cannot be rigidly set a priori. ATTACHMENT 9 ------------ ATTACHMENT 9 APS POSITION ON ISSUES RAISED BY INDUSTRY RESTRUCTURING ------------------------------------------------------- The Points of Agreement to the restructuring element of the Plan, which are set forth in Attachment 8 to this Agreement, deal with the electric utility industry in Arizona. APS believes cooperative legislative and regulatory actions at both the state and federal levels will be necessary to permit broader access to the generation market by retail customers of regulated public service corporations in Arizona. The steps proposed herein are presented by the Company as a balanced, comprehensive package, each part of which is dependent on the others. APS will not be committed to support any particular part in the event one or more other parts are dropped or materially changed in the legislative or regulatory processes. It is the Company's firm position that these issues must be addressed and resolved prior to allowing open access in the retail markets of Arizona public service corporations. As APS has pointed out during the Commission's Docket on Competition In The Electric Utility Industry, a number of legislative, regulatory and market issues must be satisfactorily addressed for Arizona to benefit from the increased economic efficiency that competition potentially can produce. By its concurrence to the Points of Agreement in Attachment 8, Staff has likewise agreed to the importance of such issues. In addition, APS believes that the record should be clear as to its present position on industry restructuring. For consistency sake, the Company has divided its comments using the categorization of issues from Attachment 8. However, APS has retained its own descriptive titles when referring to specific issues. PROCEDURAL AND SUBSTANTIVE MATTERS Process for Considering Restructuring Issues As indicated by its concurrence in Attachment 8, APS agrees that industry restructuring should be debated and resolved in an open process after consideration of all points of view. The Commission's Docket No. U-0000-94-165 provides an appropriate forum for this process, although as noted above, both the Arizona Legislature and the U.S. Congress (in addition to FERC) will be important players in any comprehensive industry restructuring. Exclusive Service Rights In Arizona, electric public service corporations are granted statutorily established Certificates of Convenience and Necessity by the Commission. Under the State's concept of "regulated monopoly," these certificates confer an exclusive and perpetual right to serve all customers within a delineated territory as long as the utility provides or is ready and willing to provide reasonable service at Commission-regulated prices, sometimes referred to as the regulatory compact. This territorial right has been characterized by the Arizona Supreme Court as a "vested property right" protected by the Arizona Constitution that cannot be condemned or otherwise "taken" without payment of adequate compensation. If the issue of compensation is adequately addressed, APS will support legislation that allows the Commission to open, on a "phased" basis, heretofore exclusive electric service territories in Arizona to competition from all regulated electric public service corporations. Obligation To Serve In return for exclusive territorial rights, public service corporations are generally required to serve all customers requesting service (whether profitable or not) in accordance with rules and regulations established by the Commission. This obligation to serve is an essential part of the regulatory compact and has required Arizona's electric utilities to anticipate customer growth, demand and usage and prudently invest in generation, transmission, distribution, and other utility assets. Unlike an enterprise in a fully competitive market, Arizona's electric public service corporations cannot decide unilaterally which markets they wish to serve, set the terms for providing such service, or determine whether or not to expend the capital funds necessary to meet future demands. As customers gain access to other generation suppliers, this will require a symmetrical change in the obligation of incumbent suppliers so that the incumbent utility is not unfairly burdened with "provider-of-last-resort" status. A clear breach of the regulatory compact will occur if the obligation to serve (and associated cost burdens) remains on a particular utility, while its competitors are free to pick who, how, and when they wish to serve. Accordingly, APS will support appropriate modifications to service obligations of Arizona public service corporations that recognize increasing customer options (at least with respect to generation) while still preserving the availability of reliable and affordable service. Compensation Issues Arizona public service corporations have rightful constitutional and equitable claims for compensation relative to recovery of stranded investment, compensable property rights and wheeling charges; specifically, compensation is due for: (a) investments in assets prudently made, or commitments prudently incurred, by an Arizona public service corporation for the benefit of the customers in its service territory which becomes "stranded", i.e., non-recoverable, because of changes in the regulatory compact; (b) investments "stranded" because of accounting or other regulatory changes occurring in the transition from a regulated monopoly environment to a competitive market; (c) the loss of constitutionally protected property rights in an exclusive service territory conferred by the Commission pursuant to statute, both when the exclusiveness of such service rights is phased out as to a particular customer class and when the loss occurs as to a particular customer; (d) wheeling services by an incumbent public service corporation for dedicating a portion of its "wires" capacity and ancillary services to accommodate a competitor's access to one or more retail customers within the incumbent's service territory, which compensation should reflect appropriate charges fully compensating the incumbent public service corporation for such service, regardless of whether such charges are regulated by FERC or the Commission. In the economic proposal of the Plan, APS will take an important step towards mitigating its "stranded" investment by accelerating the amortization of "regulatory assets" over an eight (8) year transition period. The "7(cent) Result" which represents the Company's goal to reduce its per kWh cost by a combination of aggressive cost containment and the development of new marketing opportunities, is another example of how APS hopes to mitigate the compensable damages it will experience upon the implementation of retail competition. Federal-State Jurisdictional Uncertainties Electric power commerce across the state and region is impeded by the jurisdictional uncertainty over the conflicting scope of federal versus state regulation in the utility industry. Therefore, at the federal level, APS, in cooperation with the industry and others, will seek congressional legislation that clarifies the right of states to authorize retail access and related terms and conditions of service and to effectively regulate such transactions when necessary. The Company will also seek clarification, through legislation or by FERC actions, that will clear the jurisdictional haze between the reach of federal control over transmission in interstate commerce and a state's critical ability to regulate and set retail rates. Competitive Balance Efficient competition will occur when all players, including out-of-state suppliers entering the Arizona market, are subject to the same rights and responsibilities, free from market-distorting special privileges, regulations or unequal burdens. APS will propose that any market entrant allowed into a previously exclusive territory of a regulated electric public service corporation pursuant to the legislation previously discussed regarding "Exclusive Service Rights" must itself be, or become, a public service corporation subject to appropriate Commission regulatory oversight and related obligations, including plant and line siting requirements (which should be administered directly by the Commission) and shared responsibility for maintaining service reliability. Such entrants could include out-of-state utilities, power marketers, independent power producers and other competitors. Public Power Entities The Arizona Constitution expressly excludes municipal corporations from the category of entities (public service corporations) which it subjects to regulation by the Commission. Due among other things to the uncertainties that any amendment of the Constitution would entail, the Company proposes to exclude municipal, tribal or other government-owned utilities from this restructuring proposal. Where such utilities have lawfully-conferred rights to serve all customers within a delineated territory, those rights would remain intact (i.e., would not be subject to being "phased" out as proposed above with respect to public service corporations); conversely, such utilities, by virtue of their not being public service corporations subject to Commission regulatory oversight and related obligations, would not be allowed competitive access to public service corporation territories in Arizona. However, it appears to APS that changes in law and relationships at the federal level, such as entitlements to preferential power from federal facilities or federal income tax advantages, could lead to a common interest in eliminating or reducing differences among utilities at the state level, thereby occasioning future reexamination of the difference proposed in this paragraph. Reciprocal Trade Opportunities Efficient competition and the public interest require that public service corporations be allowed the reciprocal opportunity to trade in each other's markets. The willingness of APS to open its service territory to competitors is contingent upon APS obtaining meaningful reciprocity from such competitors and their regulators. The Company's desire to remove barriers to entry into other state and regional markets can only be achieved through Commission and State support and involvement. The Company will urge federal legislation that will explicitly recognize the ability of states to condition the entry of out-of-state power suppliers into Arizona upon on reciprocal opportunities for Arizona public service corporations in other states. Finally, APS will support amendments to federal laws, such as the Public Utility Holding Company Act, to remove artificial and unnecessary restraints on utilities that desire to compete in regional and national markets. Integrated Resource Planning APS continues to support efficiency in electric usage, environmental protection and the Commission's Integrated Resource Planning ("IRP") process. Although the IRP is solidly grounded in traditional regulatory principles, many of APS' potential competitors are exempt from the IRP process. APS will ask the Commission to revise, consistent with the changes proposed herein, the current IRP process to recognize the emergence of competition and the need to maintain generation reliability in a system with proliferating suppliers. APS will continue to support cost-effective DSM and renewables as long as competitively neutral funding mechanisms are established. Market Structure The Company is, of course, aware of proposals in other jurisdictions for mandatory pooling of generation and for separation of generation and "wires" through mandatory divestiture. APS believes mandatory pooling is another form of regulation, one which presumably would be beyond the bounds of Commission jurisdiction and which could well be more pervasive and onerous than current regulation and ultimately contrary to the interests of customers. APS believes that bilateral contracting (which could be tri-or-more lateral when aggregators and marketers are considered) will afford effective competition, particularly if and when facilitated by the emergence of an exchange mechanism such as the NY Mercantile Exchange. Mandatory divestiture in the Company's judgment contravenes two important principles, one of an engineering nature and the other economic. System reliability depends on both generation and wires--some entity will have to control both to assure an effective operating system. The economic perspective is that there seems to be a natural tendency toward vertical integration in analogous situations: United Kingdom electric companies; telecommunications (where APS interprets the recent AT&T announcement of separation of its manufacturing and service functions as a move toward re-integration of local and long-distance services and facilities). Such a tendency is not necessarily anti-competitive; in the case of telecommunications, the opposite is probably true. Additionally, mandatory divestiture could require a complete restructuring of contract rights under the Company's mortgage indenture and other financing instruments; furthermore, such divestiture would be extremely expensive to implement, and could result in significant economic dislocation among customers, bondholders and shareholders, with no proven customer benefit. The policy goal should be an efficiently functioning generation market, free from concentration of market power and from abuse of a monopoly asset (such as transmission). APS does not believe this goal is served by mandatory pooling (which may actually trend in the other direction), or that mandatory divestiture is the appropriate answer to the monopoly asset issue in view of the necessity for system reliability. The market power issue is difficult to address without knowing the size of the market, but that should come into view by 2000. By then there will have been considerable experience with wholesale wheeling by way of FERC standard setting and adversarial proceedings. APS considers it unlikely that any Arizona-based electric utility will have excessive dominion over the relevant market as defined in 2000, or that the Commission will then need to do anything more about any wire monopoly in the field than what FERC will have by then already done in the wholesale field. Phased Direct Retail Access Assuming that the economic proposal of the Plan is approved, and that the foregoing issues have by then been resolved, APS would request the Commission to authorize access by retail customers of public service corporations to the broad generation market starting in the year 2000. For its system, APS would propose that initial access would apply to retail transmission customers receiving power at 69 kv or above. If this proves successful, it would be expanded approximately two years later by allowing access for all customers whose loads are greater than 3 mW and, by 2004, access for customers with demand in excess of 1 mW. Access for all remaining customers would be proposed at the appropriate time. APS would expect that other Arizona public service corporations would propose comparable retail access provisions that provide meaningful competitive opportunities. Such retail access would not necessarily "deregulate" utility service or eliminate the Commission's ultimate responsibility to public service corporations and their customers; it would, however, require modifications of the manner in which that oversight role is performed. OUTCOMES APS would like to emphasize the first three (3) of the "Outcomes" listed in Attachment 8. It is critical that electric industry restructuring should be a careful and deliberative process that fully considers the economic, financial, operational, and system planning aspects of restructuring. This can be accomplished by addressing and resolving issues before rather than after or during the restructuring. The goal of any industry restructuring should be increased efficiency, and hence lower costs. Restructuring "benefits" based on preditory pricing, cost shifting, or shareholder losses are illusory. APS' proposals to address the compensation issues and create competitive balance are intended to further an outcome based on increased efficiency. Third, all major customer groups should be permitted to benefit from this increased efficiency. APS' proposals to maintain competitive balance, create reciprocal trade opportunities, and preserve the Commission's ability to effectively establish retail rates will help to make this preferred outcome more achievable. APS proposes that the Commission specifically address and resolve these and other related issues through a series of hearings during 1996 (as contemplated by the Commission Staff in its Competition Docket) which will seek to develop appropriate legislative and regulatory solutions to these barriers. These hearings would be held independent from the Commission's consideration of the Agreement described above. APS believes that Commission action, in consultation with interested parties, can produce a set of regulatory and legislative reforms that can be presented to the Arizona Legislature and to the U.S. Congress in 1997. However, APS recognizes that the foregoing issues are difficult ones, legally and politically, and that their resolution will require time, particularly at the federal level. ATTACHMENT 10 ATTACHMENT 10 ELECTRIC RATES -------------- ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5194 Phoenix, Arizona Tariff or Schedule No. E-20 Filed by: Gary J. Volkenant Original Filing Title: Director, Business Financial Services Effective Date: Original Effective Date: GENERAL SERVICE --------------- TIME OF USE FOR --------------- RELIGIOUS HOUSES OF WORSHIP --------------------------- AVAILABILITY - ------------ In all territory served by Company at all points where facilities of adequate capacity and the required phase and suitable voltage are adjacent to the premises served. APPLICATION - ----------- Applicable to non-taxable religious houses of worship, that apply for and are eligible for such service, whose main purpose is worship and who have an established and continuing membership, but will be limited to the meter that serves the building in which the sanctuary or principal place of worship is located. The religious houses of worship may be requested to provide the Company a copy of the letter of determination of non-taxable status as a religious organization from the Internal Revenue Service. In addition, the religious houses of worship agrees to provide the Company a copy within 30 days if the letter is changed by the Internal Revenue Service. Service must be supplied at one point of delivery and measured through one meter unless otherwise specified by individual customer contract. Not applicable to breakdown, standby, supplementary, residential or resale service, nor to service for which Rate Schedule E-34 is applicable. Rate selection is subject to Sections numbered 3.3 of Schedule No. 1 of the Company's "Terms and Conditions", except that this rate schedule would become effective from the next meter reading after written notice to Company and after Company has installed the required timed kilowatt meter. 1/ TYPE OF SERVICE - --------------- Single or three phase, 60 Hertz, at one standard voltage as may be selected by customer subject to the availability at the customer's premise. Three phase service is furnished under Company's standard rules covering line extensions. Transformation equipment is included in cost of extension. Three phase service is not furnished for motors of an individual rated capacity of less than 7-1/2 HP, except for existing facilities or where total aggregate HP of all connected three phase motors exceed 12 HP. Three phase service is required for motors of an individual rated capacity of more than 7-1/2 HP. MONTHLY BILL - ------------ The monthly bill shall be the greater of the amount computed under A. or B. below, including the applicable Adjustments. A. RATE ---- June-October $27.00 Basic Service Charge, plus Billing Cycles 2.19 per kW* Demand Charge On-Peak (Summer) 0.1319 per kWh On-Peak 0.0637 per kWh Off-Peak November-May $27.00 Basic Service Charge Billing Cycles 1.98 per kW* Demand Charge On-Peak (Winter) 0.1160 per kWh On-Peak 0.0571 per kWh Off-Peak * In the event the Off-Peak kW is greater than twice the highest On-Peak kW established during the current month, the difference between such Off-Peak kW and twice the On-Peak kW shall be billed at 50% of the current month's On-Peak kW charge, in addition to the Demand Charge as stated above. (1) The type of meter required is not generally used for general service purposes and therefore their availability is limited. Consequently, the Company cannot guarantee installation within any specific time. (CONTINUED ON REVERSE SIDE) DETERMINATION OF KW DEMAND -------------------------- The average kW demands supplied during the 15-minute periods of maximum use during the On-Peak and Off-Peak periods of the month, as determined from the reading of the Company's meter. TIME PERIODS ------------ On-Peak Period: 11 a.m. - 9 p.m., Monday through Friday Off-Peak Period: All Other Hours Mountain Standard Time shall be used in the application of this rate schedule. In addition, to prevent radical changes in the system loads the beginning and ending hours for individual customers may be varied by up to one hour (total hours in each time period to remain unchanged) and because of potential differences of the timing devices, there may be a variation of up to 15 minutes in timing for the pricing periods. B. MINIMUM ----------- $20.00 plus $1.83 for each kW in excess of five of either the highest kW established during either the On- or Off-Peak period during the 12 months ending with the current month or the minimum kW specified in the agreement for service, whichever is the greater. ADJUSTMENTS ----------- Subject to the applicable proportionate part of any taxes or governmental impositions which are or may in the future be assessed on the basis of gross revenues of the Company and/or the price or revenue from the electric energy or service sold and/or the volume of energy generated or purchased for sale and/or sold hereunder. CONTRACT PERIOD - --------------- One (1) year, or longer, at Company's option. TERMS AND CONDITIONS AND CONTRACT PROVISIONS - -------------------------------------------- Subject to Company's Terms and Conditions for the sale of electric service, and/or special Terms and Conditions at Company's option as provided for in any contract or agreement for service with any customer subject hereto. Attachment 11 Attachment 11 ELECTRIC RATES -------------- ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5095 Phoenix, Arizona Cancelling A.C.C No. Filed by: Gary J. Volkenant Tariff or Schedule No. E-3 Title: Director, Business Financial Services Revision No. 3 Original Effective Date: April 1, 1988 Effective: RESIDENTIAL ENERGY SUPPORT PROGRAM ---------------------------------- AVAILABILITY - ------------ In all territory served by Company at all points where facilities of adequate capacity and the required phase and suitable voltage are adjacent to the premises served. APPLICATION - ----------- To electric service billed under Residential Rate Schedules where the customer has qualified for this rate as specified in the Company's plan for administration. All provisions of the applicable Residential rate schedule will apply except as modified herein. MONTHLY BILL - ------------ The monthly bill shall be in accordance with above specified schedules except: The Total Bill (before Taxes For Bills with and Regulatory Assessment) Usage of Will be Discounted by: ------------- ---------------------- 0 - 400 kWh 30% 401 - 800 kWh 20% 801 - 1200 kWh 10% 1200 kWh and above $10.00 Attachment 12 Attachment 12 ELECTRIC RATES -------------- ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5189 Phoenix, Arizona Tariff or Schedule No. E-4 Filed by: Gary J. Volkenant Revision No. 1 Title: Director, Business Financial Services Effective: Original Effective Date: September 1, 1995 MEDICAL CARE EQUIPMENT PROGRAM ------------------------------ AVAILABILITY - ------------ In all territory served by Company at all points where facilities of adequate capacity and the required phase and suitable voltage are adjacent to the premises served. APPLICATION - ----------- To electric service billed under Residential Rate Schedules where the customer has qualified for this rate as specified in the Company's plan for administration. All provisions of the applicable Residential rate schedule will apply except as modified herein. MONTHLY BILL - ------------ The monthly bill shall be in accordance with above specified schedules except: The Total Bill (before Taxes For Bills with and Regulatory Assessment) Usage of Will be Discounted by: -------------- --------------------- 0 - 800 kWh 30% 801 - 1400 kWh 20% 1401 - 2000 kWh 10% 2000 kWh and above $20.00 EX-15.1 3 LETTER IN LIEU OF CONSENT Exhibit 15.1 May 10, 1996 Arizona Public Service Company Post Office Box 53999 Phoenix, Arizona 85072-3999 We have made a review, in accordance with standards established by the American Institute of Certified Public Accountants, of the unaudited interim financial information of Arizona Public Service Company for the periods ended March 31, 1996 and 1995, as indicated in our report dated May 2, 1996; because we did not perform an audit, we expressed no opinion on that information. We are aware that our report referred to above, which is included in your Quarterly Report on Form 10-Q for the quarter ended March 31, 1996, is incorporated by reference in Registration Statement Nos. 33-51085, 33-57822, 33-61228, 33-55473, and 33-64455 on Form S-3. We are also aware that the aforementioned report, pursuant to Rule 436(c) under the Securities Act of 1933, is not considered a part of the Registration Statement prepared or certified by an accountant or a report prepared or certified by an accountant within the meaning of Sections 7 and 11 of the Act. DELOITTE & TOUCHE LLP DELOITTE & TOUCHE LLP Phoenix, Arizona EX-27.1 4 FINANCIAL DATA SCHEDULE
UT PUBLIC UTILITY COMPANIES AND PUBLIC UTILITY HOLDING COMPANIES (THOUSANDS OF DOLLARS) FISCAL YEAR ENDED DECEMBER 31, 1996 FOR PERIOD JANUARY 1, 1996 THROUGH MARCH 31, 1996 THREE MONTHS ENDED 1000 U.S. DOLLARS 3-MOS DEC-31-1996 JAN-01-1996 MAR-31-1996 1 PER-BOOK 4639626 104355 290443 1351001 0 6385425 178162 1039515 402472 1620149 72000 174089 1961679 0 0 159600 153512 0 0 0 2244396 6385425 345261 31359 236380 267739 77522 7034 84556 38950 45606 4477 41129 42500 36253 183936 0 0
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