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 September 30, 1999
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 86-0011170
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(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
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(Address of principal executive offices) (Zip Code)
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Registrant's telephone number, including area code: (602) 250-1000
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 November 15, 1999: 71,264,947
THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(A) AND (B) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT.
Glossary
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
Company - Arizona Public Service Company
DOE - United States Department of Energy
EITF - Emerging Issues Task Force
EITF 97-4 - Emerging Issues Task Force Issue No. 97-4, "Deregulation of the Pricing of Electricity -- Issues Related to the Application of FASB Statements No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101, Regulated Enterprises -- Accounting for the Discontinuation of Application of FASB Statement No. 71"
EPA - Environmental Protection Agency
FASB - Financial Accounting Standards Board
FERC - Federal Energy Regulatory Commission
Four Corners - Four Corners Power Plant
ITC - Investment tax credit
June 10-Q - Arizona Public Service Company Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 1999
NGS - Navajo Generating Station
1998 10-K - Arizona Public Service Company Annual Report on Form 10-K for the fiscal year ended December 31, 1998
Palo Verde - Palo Verde Nuclear Generating Station
Pinnacle West - Pinnacle West Capital Corporation
Power Coordination Agreement - 1955 agreement between the Company and Salt River Project that provides for certain electric system and power sales
SFAS No. 71 - Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS No. 133 - Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities"
Salt River Project - Salt River Project Agricultural Improvement and Power District
Territorial Agreement - 1955 agreement between the Company and Salt River Project that has provided exclusive retail service territories in Arizona for each party
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Three Months
Ended September 30,
----------------------
1999 1998
--------- ---------
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES .......................... $ 867,504 $ 740,734
--------- ---------
FUEL EXPENSES:
Fuel for electric generation ....................... 68,137 74,112
Purchased power .................................... 328,270 178,587
--------- ---------
Total ........................................... 396,407 252,699
--------- ---------
OPERATING REVENUES LESS FUEL EXPENSES ................ 471,097 488,035
--------- ---------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel expenses . 108,264 110,259
Depreciation and amortization ...................... 94,184 94,284
Income taxes ....................................... 92,286 98,411
Other taxes ........................................ 25,449 30,002
--------- ---------
Total ........................................... 320,183 332,956
--------- ---------
OPERATING INCOME ..................................... 150,914 155,079
--------- ---------
OTHER INCOME (DEDUCTIONS):
Other - net ........................................ 620 (2,120)
Income taxes ....................................... 13,283 14,271
--------- ---------
Total ........................................... 13,903 12,151
--------- ---------
INCOME BEFORE INTEREST DEDUCTIONS .................... 164,817 167,230
--------- ---------
INTEREST DEDUCTIONS:
Interest on long-term debt ......................... 31,409 33,906
Interest on short-term borrowings .................. 2,775 2,359
Debt discount, premium and expense ................. 1,847 1,878
Capitalized interest ............................... (722) (4,106)
--------- ---------
Total ........................................... 35,309 34,037
--------- ---------
INCOME BEFORE EXTRAORDINARY CHARGE ................... 129,508 133,193
EXTRAORDINARY CHARGE - NET OF INCOME TAXES OF $94,115 139,885 --
--------- ---------
NET INCOME (LOSS) .................................... (10,377) 133,193
PREFERRED STOCK DIVIDEND REQUIREMENTS ................ -- 2,347
--------- ---------
EARNINGS (LOSS) FOR COMMON STOCK ..................... $ (10,377) $ 130,846
========= =========
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See Notes to Condensed Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Nine Months
Ended September 30,
--------------------------
1999 1998
----------- -----------
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES ......................... $ 1,792,921 $ 1,562,872
----------- -----------
FUEL EXPENSES:
Fuel for electric generation ...................... 178,536 174,874
Purchased power ................................... 449,655 247,327
----------- -----------
Total .......................................... 628,191 422,201
----------- -----------
OPERATING REVENUES LESS FUEL EXPENSES ............... 1,164,730 1,140,671
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel expenses 310,072 309,388
Depreciation and amortization ..................... 286,856 279,097
Income taxes ...................................... 166,945 162,808
Other taxes ....................................... 84,484 89,459
----------- -----------
Total .......................................... 848,357 840,752
----------- -----------
OPERATING INCOME .................................... 316,373 299,919
----------- -----------
OTHER INCOME (DEDUCTIONS):
Other - net ....................................... (3,799) (7,035)
Income taxes ...................................... 24,765 26,214
----------- -----------
Total .......................................... 20,966 19,179
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ................... 337,339 319,098
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ........................ 98,833 103,249
Interest on short-term borrowings ................. 6,779 5,419
Debt discount, premium and expense ................ 5,604 5,745
Capitalized interest .............................. (6,721) (12,627)
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Total .......................................... 104,495 101,786
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INCOME BEFORE EXTRAORDINARY CHARGE .................. 232,844 217,312
EXTRAORDINARY CHARGE - NET OF INCOME TAXES OF $94,115 139,885 --
----------- -----------
NET INCOME .......................................... 92,959 217,312
PREFERRED STOCK DIVIDEND REQUIREMENTS ............... 1,016 7,660
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EARNINGS FOR COMMON STOCK ........................... $ 91,943 $ 209,652
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See Notes to Condensed Financial Statements
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Twelve Months
Ended September 30,
--------------------------
1999 1998
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(Thousands of Dollars)
ELECTRIC OPERATING REVENUES ......................... $ 2,236,447 $ 1,970,832
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FUEL EXPENSES:
Fuel for electric generation ...................... 235,629 221,089
Purchased power ................................... 507,862 294,430
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Total .......................................... 743,491 515,519
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OPERATING REVENUES LESS FUEL EXPENSES ............... 1,492,956 1,455,313
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OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel expenses 414,725 421,542
Depreciation and amortization ..................... 384,333 370,741
Income taxes ...................................... 196,344 183,479
Other taxes ....................................... 110,289 119,844
----------- -----------
Total .......................................... 1,105,691 1,095,606
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OPERATING INCOME .................................... 387,265 359,707
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OTHER INCOME (DEDUCTIONS):
Other - net ....................................... (9,067) (14,188)
Income taxes ...................................... 31,302 32,685
----------- -----------
Total .......................................... 22,235 18,497
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ................... 409,500 378,204
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INTEREST DEDUCTIONS:
Interest on long-term debt ........................ 132,798 138,790
Interest on short-term borrowings ................. 8,841 7,237
Debt discount, premium and expense ................ 7,439 7,653
Capitalized interest .............................. (10,357) (16,444)
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Total .......................................... 138,721 137,236
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INCOME BEFORE EXTRAORDINARY CHARGE .................. 270,779 240,968
EXTRAORDINARY CHARGE - NET OF INCOME TAXES OF $94,115 139,885 --
----------- -----------
NET INCOME .......................................... 130,894 240,968
PREFERRED STOCK DIVIDEND REQUIREMENTS ............... 3,059 10,658
----------- -----------
EARNINGS FOR COMMON STOCK ........................... $ 127,835 $ 230,310
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See Notes to Condensed Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
ASSETS
September 30, December 31,
1999 1998
(Unaudited)
----------- -----------
(Thousands of Dollars)
UTILITY PLANT:
Electric plant in service and held for future use $ 7,475,666 $ 7,265,604
Less accumulated depreciation and amortization ... 3,005,785 2,814,762
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Total ......................................... 4,469,881 4,450,842
Construction work in progress .................... 204,000 228,643
Nuclear fuel, net of amortization ................ 53,560 51,078
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Utility plant - net ........................... 4,727,441 4,730,563
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INVESTMENTS AND OTHER ASSETS ..................... 212,517 183,549
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CURRENT ASSETS:
Cash and cash equivalents ........................ 4,867 5,558
Accounts receivable:
Service customers ............................. 312,927 205,999
Other ......................................... 18,316 23,213
Allowance for doubtful accounts ............... (1,441) (1,725)
Accrued utility revenues ......................... 101,283 67,740
Materials and supplies, at average cost .......... 69,897 69,074
Fossil fuel, at average cost ..................... 17,913 13,978
Deferred income taxes ............................ 3,999 3,999
Other ............................................ 28,869 26,695
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Total current assets .......................... 556,630 414,531
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DEFERRED DEBITS:
Regulatory assets ................................ 648,377 980,084
Unamortized debt issue costs ..................... 14,883 14,916
Other ............................................ 93,902 69,656
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Total deferred debits ......................... 757,162 1,064,656
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TOTAL ......................................... $ 6,253,750 $ 6,393,299
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See Notes to Condensed Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
LIABILITIES
September 30, December 31,
1999 1998
(Unaudited)
---------- ----------
(Thousands of Dollars)
CAPITALIZATION:
Common stock ....................................... $ 178,162 $ 178,162
Additional paid-in capital ......................... 1,196,804 1,195,625
Retained earnings .................................. 565,230 601,968
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Common stock equity ............................. 1,940,196 1,975,755
Non-redeemable preferred stock ..................... -- 85,840
Redeemable preferred stock ......................... -- 9,401
Long-term debt less current maturities ............. 1,812,262 1,876,540
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Total capitalization ............................ 3,752,458 3,947,536
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CURRENT LIABILITIES:
Commercial paper ................................... 223,500 178,830
Current maturities of long-term debt ............... 114,542 164,378
Accounts payable ................................... 228,386 145,139
Accrued taxes ...................................... 185,974 59,827
Accrued interest ................................... 22,380 31,218
Customer deposits .................................. 23,728 26,815
Other .............................................. 27,266 16,755
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Total current liabilities ....................... 825,776 622,962
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DEFERRED CREDITS AND OTHER:
Deferred income taxes .............................. 1,180,246 1,312,007
Deferred investment tax credit ..................... 8,962 32,465
Unamortized gain - sale of utility plant ........... 74,355 77,787
Customer advances for construction ................. 38,080 31,451
Other .............................................. 373,873 369,091
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Total deferred credits and other ................ 1,675,516 1,822,801
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COMMITMENTS AND CONTINGENCIES (Notes 6, 8 and 9)
TOTAL ........................................... $6,253,750 $6,393,299
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See Notes to Condensed Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months
Ended September 30,
----------------------
1999 1998
--------- ---------
(Thousands of Dollars)
Cash Flows from Operating Activities:
Net income ......................................... $ 92,959 $ 217,312
Items not requiring cash:
Depreciation and amortization .................... 286,856 279,097
Nuclear fuel amortization ........................ 24,306 24,991
Deferred income taxes - net ...................... (30,977) (47,749)
Deferred investment tax credit - net ............. (23,503) (23,369)
Extraordinary charge, net of income taxes ........ 139,885 --
Changes in certain current assets and liabilities:
Accounts receivable - net ........................ (102,315) (118,843)
Accrued utility revenues ......................... (33,543) (27,594)
Materials, supplies and fossil fuel .............. (4,758) (8,944)
Other current assets ............................. (2,174) (3,103)
Accounts payable ................................. 78,937 61,611
Accrued taxes .................................... 126,147 122,709
Accrued interest ................................. (8,838) (5,171)
Other current liabilities ........................ 7,897 16,799
Other - net ........................................ (18,750) (20,778)
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Net cash flow provided by operating activities ....... 532,129 466,968
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Cash Flows from Investing Activities:
Capital expenditures ............................... (228,540) (221,904)
Capitalized interest ............................... (6,721) (12,627)
Other .............................................. 592 (5,872)
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Net cash flow used for investing activities .... (234,669) (240,403)
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Cash Flows from Financing Activities:
Long-term debt ..................................... 142,952 109,375
Short-term borrowings - net ........................ 44,670 (15,400)
Dividends paid on common stock ..................... (127,500) (127,500)
Dividends paid on preferred stock .................. (1,393) (8,070)
Repayment of preferred stock ....................... (96,499) (37,585)
Repayment and reacquisition of long-term debt ...... (260,381) (142,250)
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Net cash flow used for financing activities .... (298,151) (221,430)
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Net increase (decrease) in cash and cash equivalents . (691) 5,135
Cash and cash equivalents at beginning of period ..... 5,558 12,552
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Cash and cash equivalents at end of period ........... $ 4,867 $ 17,687
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest) ........ $ 107,677 $ 100,929
Income taxes ..................................... $ 102,299 $ 115,585
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See Notes to Condensed Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS
1. Our condensed financial statements reflect all adjustments which we believe are necessary for the fair presentation of our financial position and results of operations for the periods presented. These adjustments are of a normal recurring nature with exception of the extraordinary item. We suggest that these condensed financial statements and notes to condensed financial statements be read along with the financial statements and notes to financial statements included in our 1998 10-K. We have reclassified certain prior year amounts for comparison purposes with 1999.
2. Weather conditions can have a significant impact on our results for interim periods. For this and other reasons, results for interim periods do not necessarily represent results to be expected for the year.
3. We are a wholly-owned subsidiary of Pinnacle West.
4. See "Liquidity and Capital Resources" in Part I, Item 2 of this report for changes in capitalization for the nine months ended September 30, 1999.
5. Regulatory Accounting
For our regulated operations, we prepare our financial statements in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements.
During 1997, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) issued EITF 97-4. EITF 97-4 requires that SFAS No. 71 be discontinued no later than when legislation is passed or a rate order is issued that contains sufficient detail to determine its effect on the portion of the business being deregulated.
In September 1999, our Settlement Agreement with the ACC was approved (see Note 6 for a discussion of the agreement), and, as a result, we have discontinued the application of SFAS No. 71 for our generation operations. This meant that regulatory assets, unless reestablished as recoverable through ongoing regulated cash flows, were eliminated and the generation assets were tested for impairment. We determined that the generation assets were not impaired. A regulatory disallowance, which removed $234 million pretax ($183 million net present value) from ongoing regulatory cash flows, was recorded as a net reduction of regulatory assets. This reduction ($140 million after income taxes) was reported as an extraordinary charge on the income
statement. The regulatory assets to be recovered under this Settlement Agreement will be amortized as follows:
(Millions)
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $86 $18 $686
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The condensed balance sheets include the amounts listed below for generation assets included in utility plant not subject to SFAS No. 71:
(Thousands of Dollars)
September 30, December 31,
1999 1998
----------- -----------
Electric plant in service and held for future use $ 3,730,840 $ 3,680,482
Accumulated depreciation and amortization (1,793,288) (1,681,099)
Construction work in progress 85,638 107,324
Nuclear fuel, net of amortization 53,560 51,078
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6. Regulatory Matters -- Electric Industry Restructuring
STATE
SETTLEMENT AGREEMENT As of May 14, 1999, we entered into a comprehensive Settlement Agreement with various other parties, including representatives of major consumer groups, related to the implementation of retail electric competition. On September 23, 1999, the ACC voted to approve the Settlement Agreement, with some modifications.
The following are the major provisions of the Settlement Agreement, as approved:
* We will reduce rates for standard offer service for customers with loads less than 3 megawatts in a series of annual rate reductions of 1.5% beginning July 1, 1999 through July 1, 2003, for a total of 7.5%. The first reduction of approximately $24 million ($14 million after income taxes) includes the July 1, 1999 retail price decrease of approximately $10.8 million annually ($6.5 million after income taxes) related to the 1996 regulatory agreement. See "1996 Regulatory Agreement" below. For customers having loads 3 megawatts or greater, standard offer rates will be reduced in annual increments that total 5% through 2002.
* Unbundled rates being charged by us for competitive direct access service (for example, distribution services) became effective upon approval of the Settlement
Agreement, retroactive to July 1, 1999, and also will be subject to annual reductions, that vary by rate class, through 2003.
* There will be a moratorium on retail rate changes for standard offer and unbundled competitive direct access rates until July 1, 2004, except for the price reductions described above and certain other limited circumstances. Neither the ACC nor the Company will be prevented from seeking or authorizing rate changes prior to July 1, 2004 in the event of conditions or circumstances that constitute an emergency, such as an inability to finance on reasonable terms, or material changes in our cost of service for ACC-regulated services resulting from federal, tribal, state or local laws, regulatory requirements, judicial decisions, actions or orders.
* We will be permitted to defer for later recovery prudent and reasonable costs of complying with the ACC electric competition rules, system benefits costs in excess of the levels included in current rates, and costs associated with our "provider of last resort" and standard offer obligations for service after July 1, 2004. These costs are to be recovered through an adjustment clause or clauses commencing on July 1, 2004.
* Our distribution system opened for retail access, effective September 24, 1999. Customers will be eligible for retail access in accordance with the phase-in adopted by the ACC under the electric competition rules (see "Retail Electric Competition Rules" below), with an additional 140 megawatts being made available to eligible non-residential customers. Unless subject to judicial or regulatory restraint, we will open our distribution system to retail access for all customers on January 1, 2001.
* We are currently recovering substantially all of our regulatory assets through July 1, 2004, pursuant to the 1996 regulatory agreement. In addition, the Settlement Agreement states that we have demonstrated that our allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value. We will not be allowed to recover $183 million net present value of the above amounts. The Settlement Agreement provides that we will have the opportunity to recover $350 million net present value through a competitive transition charge (CTC) that will remain in effect through December 31, 2004, at which time it will terminate. Any over/under-recovery will be credited/debited against the costs subject to recovery under the adjustment clause described above.
* We will form a separate corporate affiliate or affiliates and transfer to that affiliate(s) our generating assets and competitive services at book value as of the date of transfer, which transfer shall take place by December 31, 2002. We will be allowed to defer and later collect sixty-seven percent of our costs to accomplish the required transfer of generation assets to an affiliate.
* When the Settlement Agreement approved by the ACC is no longer subject to judicial review, we will move to dismiss all of our litigation pending against the ACC as of the date we entered into the Settlement Agreement.
On October 25, 1999, two parties filed motions for reconsideration of the Settlement Agreement with the ACC. The ACC took no action within the twenty day limit, so the motions are deemed denied. We continue to operate under the terms of the Settlement Agreement.
In its motion for reconsideration, one of the parties has questioned the degree to which the ACC may, under the Arizona Constitution, deregulate any portion of the electric utility industry and allow rates to be determined by market forces. The issue of competitively set rates has been decided by lower Arizona courts in favor of the ACC in four separate lawsuits, two of which relate to telecommunications companies. Appeals of the lower courts' decisions are pending.
As discussed in Note 5 above, we have discontinued the application of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation," for our generation operations.
RETAIL ELECTRIC COMPETITION RULES On September 21, 1999, the ACC voted to approve the rules that provide a framework for the introduction of retail electric competition in Arizona (the "Rules"). If any of the Rules conflict with the Settlement Agreement, the terms of the Settlement Agreement govern. On October 19, 1999, several parties, including us, filed motions for reconsideration of the Rules with the ACC. The ACC took no action within the twenty day limit, so the motions are deemed denied.
The Rules approved by the ACC include the following major provisions:
* They apply to virtually all Arizona electric utilities regulated by the ACC, including us.
* The Rules require each affected utility, including us, to make available at least 20% of its 1995 system retail peak demand for competitive generation supply beginning when the ACC makes a final decision on each utility's stranded costs and unbundled rates (Final Decision Date) or January 1, 2001, whichever is earlier, and 100% beginning January 1, 2001. Under the Settlement Agreement, the Company will provide retail access to customers representing the minimum 20% required by the ACC and an additional 140 megawatts of non-residential load in 1999, and to all customers as of January 1, 2001, or such other dates as approved by the ACC.
* Subject to the 20% requirement, all utility customers with single premise loads of one megawatt or greater will be eligible for competitive electric services on the Final Decision Date, which for the Company's customers was the approval of the
Settlement Agreement. Customers may aggregate loads to meet this one megawatt requirement.
* When effective, residential customers will be phased in at 1 1/4% per quarter calculated beginning on January 1, 1999, subject to the 20% requirement above.
* Electric service providers that get Certificates of Convenience and Necessity (CC&Ns) from the ACC can supply only competitive services, including electric generation, but not electric transmission and distribution.
* Affected utilities must file ACC tariffs with separate pricing for electric services provided for non-competitive services.
* The ACC shall allow a reasonable opportunity for recovery of unmitigated stranded costs.
* Absent an ACC waiver, prior to January 1, 2001, each affected utility (except certain electric cooperatives) must transfer all competitive generation assets and services either to an unaffiliated party or to a separate corporate affiliate. Under the Settlement Agreement, the Company received a waiver to allow transfer of its competitive generation assets and services to affiliates no later than December 31, 2002.
1996 REGULATORY AGREEMENT In April 1996, the ACC approved a regulatory agreement between the ACC Staff and us. Based on the price reduction formula of the agreement, the ACC approved retail price decreases of approximately $17.6 million ($10.5 million after income taxes), or 1.2%, effective July 1, 1997; approximately $17 million ($10 million after income taxes), or 1.1%, effective July 1, 1998; and approximately $10.8 million ($6.5 million after income taxes), or 0.7%, effective as of July 1, 1999. The July 1, 1999 rate decrease was included in the first rate reduction under the Settlement Agreement discussed above. The regulatory agreement also requires Pinnacle West to infuse $200 million of common equity into us in annual payments of $50 million in 1996 through 1999.
LEGISLATION In May 1998, a law was enacted to facilitate implementation of retail electric competition in Arizona. The law includes the following major provisions:
* Arizona's largest government-operated electric utility (Salt River Project) and, at their option, smaller municipal electric systems must (i) make at least 20% of their 1995 retail peak demand available to electric service providers by December 31, 1998 and for all retail customers by December 31, 2000; (ii) decrease rates by at least 10% over a ten-year period beginning as early as January 1, 1991; (iii) implement procedures and public processes comparable to those already applicable to public service corporations for establishing the terms, conditions, and pricing of electric services as well as certain other decisions affecting retail electric competition;
* describes the factors which form the basis of consideration by Salt River Project in determining stranded costs; and
* metering and meter reading services must be provided on a competitive basis during the first two years of competition only for customers having demands in excess of one megawatt (and that are eligible for competitive generation services), and thereafter for all customers receiving competitive electric generation.
In addition, the Arizona legislature will review and make recommendations for the 1999-2000 legislative session on certain competitive issues.
GENERAL We cannot accurately predict the impact of full retail competition on our financial position, cash flows, or results of operation. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete in the new regulatory environment.
FEDERAL The Energy Policy Act of 1992 and recent rulemakings by FERC have promoted increased competition in the wholesale electric power markets. We do not expect these rules to have a material impact on our financial statements.
Several electric utility industry restructuring bills have been introduced during the 106th Congress. Several of these bills are written to allow consumers to choose their electricity suppliers beginning in 2000 and beyond. These bills, other bills that are expected to be introduced, and ongoing discussions at the federal level suggest a wide range of opinion that will need to be narrowed before any substantial restructuring of the electric utility industry can occur.
7. Agreement with Salt River Project
On April 25, 1998, we entered into a Memorandum of Agreement with Salt River Project in anticipation of, and to facilitate, the opening of competition in the Arizona electric industry. On February 18, 1999, the ACC approved the Agreement. The Agreement contains the following major components:
* Both parties amended the Territorial Agreement to remove any barriers in that agreement to the provision of competitive electricity supply and non-distribution services.
* Both parties amended the Power Coordination Agreement to lower the price that we will pay Salt River Project for purchased power by approximately $17 million (pretax) during the first full year that the Agreement is effective and by lesser annual amounts during the next seven years.
* Both parties agreed on certain legislative positions regarding electric utility restructuring at the state and federal level.
Certain provisions of the Agreement (including those relating to the amendments of the Territorial Agreement and the Power Coordination Agreement) became effective upon the introduction of competition. See Note 6.
8. Nuclear Insurance
The Palo Verde participants have insurance for public liability payments resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $200 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, we could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $88 million, subject to an annual limit of $10 million per incident. Based upon our 29.1% interest in the three Palo Verde units, our maximum potential assessment per incident is approximately $77 million, with an annual payment limitation of approximately $9 million.
The Palo Verde participants maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. We have also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
9. Accounting Matters
In June 1998 the Financial Accounting Standards Board (FASB) issued SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. The standard also provides specific guidance for accounting for derivatives designated as hedging instruments. The statement was to have been effective for us in 2000; however, the FASB has moved the effective date to 2001. We are currently evaluating what impact this standard will have on our financial statements.
ARIZONA PUBLIC SERVICE COMPANY
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
In this section, we explain our results of operations, general financial condition, and outlook, including:
* the changes in our earnings for the periods presented
* the factors impacting our business, including competition and electric
industry restructuring
* the effects of regulatory agreements on our results
* our capital needs and resources and
* Year 2000 technology issues.
We suggest this section be read along with the 1998 10-K. Throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations, we refer to specific "Notes" in the Notes to Condensed Financial Statements. These Notes add further details to the discussion.
OPERATING RESULTS
The following table summarizes our revenues and earnings for the three-month, nine-month and twelve-month periods ended September 30, 1999 and 1998:
Periods ended September 30
(Unaudited)
(Thousands of Dollars)
Three Months Nine Months Twelve Months
------------------------ ----------------------- -----------------------
1999 1998 1999 1998 1999 1998
---------- ---------- ---------- ---------- ---------- ----------
Operating Revenues $ 867,504 $ 740,734 $1,792,921 $1,562,872 $2,236,447 $1,970,832
Earnings (Loss) for
Common Stock (1) $ (10,377) $ 130,846 $ 91,943 $ 209,652 $ 127,835 $ 230,310
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(1) 1999 periods include an extraordinary charge of $139,885, net of income taxes of $94,115.
OPERATING RESULTS - THREE-MONTH PERIOD ENDED SEPTEMBER 30, 1999 COMPARED
WITH THREE-MONTH PERIOD ENDED SEPTEMBER 30, 1998
Earnings decreased $141 million in the three-month comparison primarily because of the effects of a $140 million after-tax extraordinary charge for a regulatory disallowance (see Notes 5 and 6). Earnings excluding the extraordinary charge were
$1 million lower because of the effects of milder weather, a retail price reduction and lower contributions from power marketing and trading activities. These reductions in earnings were substantially offset by an increase in customers and lower property taxes. See Note 6 for information on the price reduction.
Operating revenues increased $127 million because of:
* increased power marketing and trading revenues ($131 million)
* increases in the number of customers and the average amount of
electricity used by customers ($24 million) and
* miscellaneous factors ($2 million).
As mentioned above, these positive factors were partially offset by weather impacts ($22 million) and the effect of a reduction in retail prices ($8 million).
Power marketing and trading activities are predominantly short-term opportunity wholesale sales. The increase in power marketing revenues resulted primarily from increased activity in western U.S. bulk power markets and was accompanied by an increase in purchased power expenses. Although these activities contribute positively to earnings in both periods, the contribution in 1999 was lower than in 1998.
Fuel and purchased power expenses increased $144 million primarily because of increased wholesale sales volume and higher purchased power prices.
Other taxes decreased $5 million primarily because of an adjustment to reflect lower property tax rates for 1999.
OPERATING RESULTS - NINE-MONTH PERIOD ENDED SEPTEMBER 30, 1999 COMPARED
WITH NINE-MONTH PERIOD ENDED SEPTEMBER 30, 1998
Earnings decreased $118 million in the nine-month comparison primarily because of the effects of a $140 million after-tax extraordinary charge for a regulatory disallowance (see Notes 5 and 6). Earnings excluding the extraordinary charge were $22 million higher because of an increase in customers, lower property taxes and lower financing costs. These increases in earnings were partially offset by the effects of milder weather, retail price reductions, higher depreciation and lower contributions from power marketing and trading activities. See Note 6 for information on the price reductions.
Operating revenues increased $230 million because of:
* increased power marketing and trading revenues ($188 million) and
* increases in the number of customers and the average amount of
electricity used by customers ($69 million).
As mentioned above, these positive factors were partially offset by weather impacts ($10 million) and the effect of reductions in retail prices ($17 million).
Power marketing and trading activities are predominantly short-term opportunity wholesale sales. The increase in power marketing revenues resulted primarily from increased activity in western U.S. bulk power markets and was accompanied by an increase in purchased power expenses. Although these activities contribute positively to earnings in both periods, the contribution in 1999 was lower than in 1998.
Fuel and purchased power expenses increased $206 million primarily because of increased wholesale and retail sales volume and higher purchased power prices.
Other taxes decreased $5 million primarily because of lower property tax rates.
Financing costs decreased by $4 million primarily because of lower amounts of outstanding preferred stock.
Depreciation and amortization expense increased $8 million because we had more plant in service.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 1999 COMPARED
WITH TWELVE-MONTH PERIOD SEPTEMBER 30, 1998
Earnings decreased $102 million in the twelve-month comparison primarily because of the effects of a $140 million after-tax extraordinary charge for a regulatory disallowance (see Notes 5 and 6). Earnings excluding the extraordinary charge were $38 million higher because of an increase in customers, lower property taxes, lower operations and maintenance expenses and lower financing costs. These increases in earnings were partially offset by the effects of milder weather, retail price reductions and higher depreciation. See Note 6 for information on the price reductions.
Operating revenues increased $266 million because of:
* increased power marketing and trading revenues ($216 million)
* increases in the number of customers and the average amount of
electricity used by customers ($85 million) and
* miscellaneous factors ($8 million).
As mentioned above, these positive factors were partially offset by weather impacts ($23 million) and the effect of reductions in retail prices ($20 million).
Power marketing and trading activities are predominantly short-term opportunity wholesale sales. The increase in power marketing revenues resulted primarily from increased activity in western U.S. bulk power markets and was accompanied by an increase in purchased power expenses. Although these activities contribute positively
to earnings in both periods, the contribution in the current period was the same as in the previous period.
Fuel and purchased power expenses increased $228 million primarily because of increased wholesale and retail sales volume and higher purchased power prices.
Other taxes decreased $10 million primarily because of lower property tax rates for 1999 and an adjustment in the fourth quarter of 1998 to reflect lower property tax rates for 1998.
Operations and maintenance expenses were lower $7 million primarily due to lower employee benefit costs.
Financing costs decreased by $6 million primarily because of lower amounts of outstanding preferred stock.
Depreciation and amortization expense increased $14 million because we had more plant in service.
OTHER INCOME
As part of a 1994 rate settlement with the ACC, we accelerated amortization of substantially all deferred ITCs over a five-year period that ends on December 31, 1999. The amortization of ITCs is shown on our income statement as Other Income -- Income Taxes. It decreases annual income tax expense by approximately $28 million. Beginning in 2000, no further benefits from these deferred ITCs will be reflected in income tax expense.
LIQUIDITY AND CAPITAL RESOURCES
For the nine months ended September 30, 1999, we incurred approximately $229 million in capital expenditures, which is approximately 70% of the most recently estimated 1999 capital expenditures. Our projected capital expenditures for the next three years are: 1999, $328 million; 2000, $353 million; and 2001, $343 million. These amounts include about $30 - $35 million each year for nuclear fuel expenditures.
Our long-term debt and preferred stock redemption requirements, optional repayments and payment obligations on a capitalized lease for the next three years are: 1999, $406 million; 2000, $115 million; and 2001, $252 million. During the nine months ended September 30, 1999, we redeemed approximately $260 million of our long-term debt and all $96 million (including premiums) of our preferred stock with cash from operations and long-term and short-term debt. In February 1999 we issued $125 million of unsecured long-term debt, and in November 1999, we issued $250 million of unsecured long-term debt. As a result of the 1996 regulatory agreement (see Note 6), Pinnacle West invested $50 million in the Company in 1996, 1997 and 1998 and will make the final investment of $50 million in 1999.
Although provisions in our first mortgage bond indenture, articles of incorporation, and ACC financing orders establish maximum amounts of additional first mortgage bonds and preferred stock that we may issue, we do not expect any of these provisions to limit our ability to meet our capital requirements.
YEAR 2000 READINESS DISCLOSURE
OVERVIEW As the year 2000 approaches, many companies face problems because many computer systems and equipment will not properly recognize calendar dates beginning with the year 2000. We are addressing the Year 2000 issue as described below. We initiated a comprehensive company-wide Year 2000 program during 1997 to review and resolve all Year 2000 issues in mission critical systems (systems and equipment that are key to the power production, delivery, health, and safety functions) in a timely manner to ensure the reliability of electric service to our customers. This included a company-wide awareness program of the Year 2000 issue. We also have had an internal audit/quality team review the individual Year 2000 projects and their Year 2000 readiness.
The following chart shows Year 2000 readiness of our mission critical systems as of September 30, 1999:
INVENTORY ASSESSMENT REMEDIATION & TESTING --------- ---------- --------------------- 100% 100% 100% |
DISCUSSION We have been actively implementing and replacing systems and technology since 1995 for general business reasons unrelated to the Year 2000, and these actions have resulted in substantially all of our major information technology (IT) systems becoming Year 2000 ready. The major IT systems that were, and are being, implemented and replaced include the following:
* Work Management
* Materials Management
* Energy Management System
* Payroll
* Financial
* Human Resources
* Trouble Call Management System
* Computer and Communications Network Upgrades
* Geographic Information System
* Customer Information System and
* Palo Verde Site Work Management System.
We have made, and will continue to make, certain modifications to computer hardware, software, and application systems, including IT and non-IT systems, in an effort to
ensure they are capable of handling changing business needs, including dates in the year 2000 and thereafter. In addition, we will continue to analyze other IT and non-IT systems, including embedded technology and real-time process control systems, for potential modifications.
We have inventoried, assessed, remediated and tested all mission critical IT and non-IT systems and equipment as of June 30, 1999. Remediation and testing is also completed for the continuous emissions monitoring systems (CEMS). See "Year 2000 Readiness Disclosure" in Part I, Item 2 of the June 10-Q. We notified the North American Electric Reliability Council (NERC) on June 30, 1999, that our mission critical systems are ready for date changes associated with the Year 2000, in accordance with NERC's recommended criteria. We also notified the Nuclear Regulatory Commission (NRC) that Palo Verde is "Y2K Ready," which means that Palo Verde has followed a prescribed program to identify and resolve Year 2000 issues so that the plant can operate reliably while meeting commitments.
We had estimated that we would spend about $5 million relating to Year 2000 issues, almost all of which has been spent to date. This includes an estimated allocation of payroll costs for our employees working on Year 2000 issues, and costs for consultants, hardware, and software. We do not separately track other internal costs. This does not include costs incurred since 1995 to implement and replace systems for reasons unrelated to the Year 2000, as discussed above. Our cost to address the Year 2000 issue is charged to operating expenses as incurred and has not had, and is not expected to have, a material adverse effect on our financial position, cash flows, or results of operations. We funded this cost with available cash balances and cash provided by operations.
We continue to communicate with our significant suppliers, business partners, other utilities, and large customers to determine the extent to which we may be affected by these third parties' plans to remediate their own Year 2000 issues in a timely manner. We have been interfacing with suppliers of systems, services, and materials in order to assess whether their schedules for analysis and remediation of Year 2000 issues are timely and to assess their ability to continue to supply required services and materials.
We have also been working with NERC through the Western Systems Coordinating Council (WSCC) to develop operational plans for stable grid operation that will be used by other utilities and us in the western United States. Our operational plans are complete. However, we cannot currently predict the effect on us if the systems of these other companies are not Year 2000 ready.
We currently expect that our most reasonably likely worst case Year 2000 scenario would be intermittent loss of power to customers, similar to an outage during a severe weather disturbance. In this situation, we would restore power as soon as possible by, among other things, re-routing power flows. We do not currently expect that this scenario would have a material adverse effect on our financial position, cash flows, or results of operations.
We have developed our own contingency plans to handle Year 2000 issues, including the most reasonably likely worst case scenario, discussed above. These plans were completed June 30, 1999.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See Note 5 for a discussion of regulatory accounting. See Note 6 for a discussion of a Settlement Agreement related to the implementation of retail electric competition. See Note 7 for a discussion of a proposed amendment to a Power Coordination Agreement with Salt River Project that we estimate would reduce our pretax costs for purchased power by approximately $17 million during the first full year that the amendment is effective and by lesser annual amounts during the next seven years.
RATE MATTERS
See Note 6 for a discussion of a price reduction effective as of July 1, 1999, and for a discussion of a Settlement Agreement that will, among other things, result in price reductions over a four-year period ending July 1, 2003.
FORWARD-LOOKING STATEMENTS
The above discussion contains forward-looking statements that involve risks and uncertainties. Words such as "estimates," "expects," "anticipates," "plans," "believes," "projects," and similar expressions identify forward-looking statements. These risks and uncertainties include, but are not limited to, the ongoing restructuring of the electric industry; the outcome of the regulatory proceedings relating to the restructuring; regulatory, tax, and environmental legislation; our ability to successfully compete outside our traditional regulated markets; regional economic conditions, which could affect customer growth; the cost of debt and equity capital; weather variations affecting customer usage; technological developments in the electric industry; the successful completion of a large-scale construction project; and Year 2000 issues.
These factors and the other matters discussed above may cause future results to differ materially from historical results, or from results or outcomes we currently expect or seek.
ITEM 3. MARKET RISKS
Our operations include managing market risks related to changes in interest rates, commodity prices, and investments held by the nuclear decommissioning trust fund.
Our major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable rate debt and interest earned by the nuclear decommissioning trust fund. Our policy is to manage interest rates through the use of a combination of fixed and floating rate debt. The nuclear decommissioning fund also has risks associated with changing market values of equity investments. Nuclear decommissioning costs are recovered in rates.
We are exposed to the impact of market fluctuations in the price and distribution costs of electricity, natural gas, coal, and emissions allowances/credits and therefore employ established procedures to manage our risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange traded futures and options and over-the-counter forwards, options, and swaps. As part of our overall risk management program, we enter into these derivative transactions for trading and to hedge certain natural gas in storage as well as purchases and sales of electricity, fuels, and emissions allowances/credits.
We measure the price risk in our commodity derivative portfolio on a daily basis utilizing market sensitivity based modeling to understand expected and potential single day favorable or unfavorable impacts to income before tax. The model results are monitored daily to ensure compliance against thresholds on a commodity and portfolio basis. As of September 30, 1999, a hypothetical adverse price movement of 10% in the market price of our commodity derivative portfolio would decrease the fair market value of these contracts by approximately $7 million. This analysis does not include the favorable impact this same hypothetical price move would have on the underlying position being hedged with the commodity derivative portfolio.
We are exposed to credit losses in the event of non-performance or non-payment by counterparties. We use a credit management process to assess and monitor the financial exposure of counterparties. We do not expect counterparty defaults to materially impact our financial condition, results of operations or net cash flow.
PART II - OTHER INFORMATION
ITEM 5. OTHER INFORMATION
CONSTRUCTION AND FINANCING PROGRAMS
See "Liquidity and Capital Resources" in Part I, Item 2 of this report for a discussion of the Company's construction and financing programs.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See Note 6 of Notes to Condensed Financial Statements in Part I, Item 1 of this report for a discussion of competition and the rules regarding the introduction of retail electric competition in Arizona and a settlement agreement with the ACC.
ENVIRONMENTAL MATTERS
FEDERAL IMPLEMENTATION PLAN. In September 1999, the EPA proposed a Federal Implementation Plan (FIP) to set air quality standards at certain power plants, including the Navajo Generating Station and the Four Corners Power Plant. The comment period on this proposal ends in November 1999. The FIP is similar to current Arizona regulation of NGS and New Mexico regulation of Four Corners, with minor modifications. We do not currently expect the FIP to have a material impact on our financial position or results of operations.
CLEAN AIR ACT. As previously reported, we filed a petition for review alleging EPA improperly classified Four Corners Unit 4 with respect to nitrogen oxides emissions limitations. See "Environmental Matters - Clean Air Act" in Part I, Item 1 of the 1998 10-K. In October 1999, EPA issued a direct final rule, which classified Four Corners Unit 4 as we had proposed. Depending on the comments filed by other parties, if any, the rules may become final as soon as December 1999. We do not currently expect this rule to have a material impact on our financial position or results of operations.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit No. Description ----------- ----------- 10.1 Settlement Agreement 10.2 Retail Electric Competition Rules 27.1 Financial Data Schedule |
In addition to those Exhibits shown above, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation ss.229.10(d) by reference to the filings set forth below:
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(a) DATE EFFECTIVE
----------- ----------- ---------------------------- ----------- --------------
3.1 Bylaws, amended as of 3.1 to 1995 Form 10-K 1-4473 3-29-96
February 20, 1996 Report
3.3 Articles of Incorporation, 4.2 to Form S-3 1-4473 9-29-93
restated as of May 25, 1988 Registration Nos.
33-33910 and 33-55248 by
means of September 24,
1993 Form 8-K Report
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(b) Reports on Form 8-K
During the quarter ended September 30, 1999, and the period from October 1 through November 15, 1999, we filed the following reports on Form 8-K:
Report dated August 26, 1999 regarding the ACC Hearing Officer recommendations on our proposed Settlement Agreement and the proposed retail electric competition rules.
Report dated September 21, 1999 regarding ACC approval of our Settlement Agreement and the retail electric competition rules.
Report dated November 2, 1999 comprised of Exhibits to our Registration Statement (Registration No. 333-58445) relating to our offering of $250 million of Notes.
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: November 15, 1999 By: Michael V. Palmeri
------------------------------------
Michael V. Palmeri
Vice President, Finance
(Principal Financial Officer and
Officer Duly Authorized to sign this
Report)
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BEFORE THE ARIZONA CORPORATION COMMISSION
DOCKET NO. E-01345A-98-0473 ET AL.
DECISION NO. _______________
CARL J. KUNASEK
CHAIRMAN
JIM IRVIN
COMMISSIONER
WILLIAM A. MUNDELL
COMMISSIONER
IN THE MATTER OF THE APPLICATION OF ARIZONA PUBLIC SERVICE DOCKET NO. E-01345A-98-0473
COMPANY FOR APPROVAL OF ITS PLAN FOR STRANDED COST RECOVERY.
--------------------------------------------------------------
IN THE MATTER OF THE FILING OF ARIZONA PUBLIC SERVICE COMPANY DOCKET NO. E-01345A-97-0773
OF UNBUNDLED TARIFFS PURSUANT TO A.A.C. R14-2-1601 ET SEQ.
--------------------------------------------------------------
IN THE MATTER OF COMPETITION IN THE PROVISION OF ELECTRIC DOCKET NO. RE-00000C-94-0165
SERVICES THROUGHOUT THE STATE OF ARIZONA.
DECISION NO. 61973
--------------------------------------------------------------
OPINION AND ORDER
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DATES OF HEARING: July 12, 1999 (pre-hearing conference), July 14, 15, 16,
19, 20, and 21, 1999
PLACE OF HEARING: Phoenix, Arizona
PRESIDING OFFICER: Jerry L. Rudibaugh
IN ATTENDANCE: Carl J. Kunasek, Chairman
Jim Irvin, Commissioner
APPEARANCES: Mr. Steven M. Wheeler, Mr. Thomas Mumaw and Mr. Jeffrey B.
Guldner, SNELL & WILMER, LLP, on behalf of Arizona Public
Service Company;
Mr. C. Webb Crockett and Mr. Jay Shapiro, FENNEMORE CRAIG,
on behalf of Cyprus Climax Metals, Co., ASARCO, Inc., and
Arizonans for Electric Choice & Competition;
Mr. Scott S. Wakefield, Chief Counsel, and Ms. Karen Nally
on behalf of the Residential Utility Consumer Office;
Ms. Betty Pruitt on behalf of the Arizona Community Action
Association;
1 DECISION NO. 61973
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DOCKET NO. E-01345A-98-0473 ET AL.
Mr. Timothy Hogan on behalf of the Arizona Consumers
Council;
Mr. Robert S. Lynch on behalf of the Arizona Transmission
Dependent Utility Group;
Mr. Walter W. Meek on behalf of the Arizona Utility
Investors Association;
Mr. Douglas C. Nelson, DOUGLAS C. NELSON, P.C., on behalf
of Commonwealth Energy Corporation;
Mr. Lawrence V. Robertson, Jr., MUNGER & CHADWICK, and Ms.
Leslie Lawner, Director Government Affairs on behalf of
Enron Corporation, and Mr. Robertson on behalf of PG&E
Energy Services;
Mr. Lex J. Smith, BROWN & BAIN, P.A., on behalf of
Illinova Energy Partners and Sempra Energy Trading;
Mr. Randall H. Werner, ROSHKA, HEYMAN & DeWULF, P.L.C., on
behalf of NEV Southwest;
Mr. Norman Furuta on behalf of the Department of the Navy;
Mr. Bradley S. Carroll on behalf of Tucson Electric Power
Company; and
Mr. Christopher C. Kempley, Assistant Chief Counsel and
Ms. Janet F. Wagner, Staff Attorney, Legal Division on
behalf of the Utilities Division of the Arizona
Corporation Commission.
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BY THE COMMISSION:
On December 26, 1996, the Arizona Corporation Commission ("Commission") in Decision No. 59943 enacted A.A.C. R14-2-1601 through R14-2-1616 ("Rules" or "Electric Competition Rules").
On June 22, 1998, the Commission issued Decision No. 60977, the Stranded Cost Order which required each Affected Utility to file a plan for stranded cost recovery.
On August 10, 1998, the Commission issued Decision No. 61071 which made modifications to the Rules on an emergency basis.
On August 21, 1998, Arizona Public Service Company ("APS") filed its Stranded Costs plan.
On November 5, 1998, APS filed a Settlement Proposal that had been entered into with the Commission's Utilities Division Staff ("Staff Settlement Proposal"). Our November 24, 1998 Procedural Order set the matter for hearing. On November 25, 1998, the Commission issued
2 DECISION NO. 61973
DOCKET NO. E-01345A-98-0473 ET AL.
Decision No. 61259 which established an expedited procedural schedule for evidentiary hearings on the Staff Settlement Proposal.
On November 30, 1998, the Arizona Attorney General's Office, in association with numerous other parties, filed a Verified Petition for Special Action and Writ of Mandamus with the Arizona Supreme Court ("Court") regarding the Commission's November 25, 1998 Procedural Order, Decision No. 61259. The Attorney General sought a Stay of the Commission's consideration of the Staff Settlement Proposal with APS and Tucson Electric Power Company ("TEP").
On December 1, 1998, Vice Chief Justice Charles J. Jones granted a Motion for Immediate Stay of the Procedural Order. On December 9, 1998, the Commission Staff filed a notice with the Supreme Court that the Staff Settlement Proposal had been withdrawn from Commission consideration.
On April 27, 1999, the Commission issued Decision No. 61677, which modified Decision No. 60977. On May 17, 1999, APS filed with the Commission a Notice of Filing, Application for Approval of Settlement Agreement ("Settlement" or "Agreement") 1 and Request for Procedural Order.
Our May 25, 1999 Procedural Order set the matter for hearing commencing on July 14, 1999.
This matter came before a duly authorized Hearing Officer of the Commission at its offices in Phoenix, Arizona. APS, Cyprus Climax Metals, Co., ASARCO, Inc., Arizonans for Electric Choice & Competition ("AECC"), Residential Utility Consumer Office ("RUCO"), the Arizona Community Action Association ("ACAA"), the Arizona Consumers Council, the Arizona Transmission Dependent Utility Group, the Arizona Utility Investors Association, Enron Corporation, PG&E Energy Services, Illinova Energy Partners, Sempra Energy Trading, NEV Southwest, the Department of the Navy, Tucson Electric Power Company, Commonwealth Energy Corporation
3 DECISION NO. 61973
DOCKET NO. E-01345A-98-0473 ET AL.
("Commonwealth") and Staff of the Commission appeared through counsel. Evidence was presented concerning the Settlement Agreement, and after a full public hearing, this matter was adjourned pending submission of a Recommended Opinion and Order by the Presiding Officer to the Commission. In addition, a post-hearing briefing schedule was established with simultaneous briefs filed on August 5, 1999.
DISCUSSION
INTRODUCTION
The Settlement provides for rate reductions for residential and business customers; sets the amount, method, and recovery period of stranded costs that APS can collect in customer charges; establishes unbundled rates; and provides that APS will separate its generating facilities, which will operate in the competitive market, from its distribution system, which will continue to be regulated.
According to APS, the Settlement was the product of months of hard negotiations with various customer groups. APS opined that the Settlement provides many clear benefits to customers, potential competitors, as well as to APS. Some of those benefits as listed by APS are as follows:
* Allowing competition to commence in APS' service territory months before otherwise possible and expanding the initial eligible load by 140 MW;
* Establishing both Standard Offer and Direct Access rates, and providing for annual rate reductions with a cumulative total of as much as $475 million by 2004;
* Ensuring stability and certainty for both bundled and unbundled rates;
* Resolving the issue of APS' stranded costs and regulatory asset recovery in a fair and equitable manner;
* Providing for the divestiture of generation and competitive services by APS in a cost-effective manner;
* Removing the specter of years of litigation and appeals involving APS and Commission over competition-related issues;
* Continuing support for a regional ISO and the AISA;
* Continuing support for low income programs; and
* Requiring APS to file an interim code of conduct to address affiliate relationships.
4 DECISION NO. 61973
DOCKET NO. E-01345A-98-0473 ET AL.
The Settlement was entered into by RUCO and the ACAA reflecting Agreement by residential customers of APS to the Settlement's terms and conditions. In addition, the Settlement was executed by the AECC, a coalition of commercial and industrial customers and trade associations. AECC opined that since residential and non-residential customers have agreed to the Settlement, the "public interest" has been served. AECC indicated the Settlement was not perfect but was the result of "give and take" by each of the parties. Accordingly, AECC urged the Commission to protect the "public interest" by approving the Settlement and not allow Energy Service Providers ("ESPs") to delay the benefits that competition has to offer.
LEGAL ISSUES:
The Arizona Consumers Council ("Consumers Council") opined that the
Agreement was not legal because: (1) there was no full rate proceeding2; (2)
Section 2.8 of the Agreement violates A.R.S. Section 40-246, regarding
Commission initiated rate reductions; and (3) the Agreement illegally binds
future Commissions. According to the Consumers Council, the Commission does not
have evidence to support a finding that the rates proposed in the Agreement are
just and reasonable; that the rate base proposed is proper; and asserted the
proposed adjustment clause can not be established outside a general rate case.
Staff argued that the Commission in Decision No. 59601, dated April 26, 1996, has previously determined just and reasonable rates for APS which must be charged until changed in a rate proceeding. According to Staff, this case is not about changing existing rates, but instead involves the introduction of a new service - direct access. The direct access rates have been designed to replicate the revenue flow from existing rates. Staff opined that the Commission has routinely, and lawfully, approved rates for new services outside of a rate case. Further, Staff asserted that the rates proposed in the Settlement are directly related to a complete financial review. Staff indicated that the Consumers Council has provided no contrary information and should not be allowed to collaterally attack Decision No. 59601.
APS argued that no determination of fair value rate base ("FVRB"), fair value rate of return
5 DECISION NO. 61973
DOCKET NO. E-01345A-98-0473 ET AL.
("FVROR"), or other financial analysis is legally necessary to justify current APS rate levels, allow the introduction of a new service, or to evaluate a series of voluntary rate decreases. In spite of that, APS did provide information to support a FVRB of $5,195,675,000 and FVROR of 6.63 percent. No other party presented evidence in support of a FVRB or FVROR. Staff supported APS.
We concur with Staff and APS. The Consumers Council has provided no legal authority that a full rate proceeding is necessary in order to adopt a rate reduction or rates for new services. Further, pursuant to the Arizona Constitution, the Commission has jurisdiction over ratemaking matters. We also find that notice of the application and hearing was provided and that APS has provided sufficient financial information to support a finding of FVRB and FVROR. Lastly, this Commission can clearly bind future Commissions as a result of its Decision. However, as later discussed, we agree there are limitations to such legal authority.
SHOPPING CREDIT
One of the most contentious issues in the hearing was the level of the "shopping credit." The "shopping credit" is the difference between the customer's Standard Offer Rate and the Direct Access Rate available to customers who take service from ESPs. The ESPs generally argued that the Settlement's "shopping credits" were not sufficient to allow a new entrant to make a profit. AECC opined that such an argument was nothing more than a request to increase ESP's profits.
Staff opined that the "shopping credit" was too low and recommended it be increased without impacting the stranded cost recovery amount of $350 million. Under Staff's proposal, the increased "shopping credit" would be offset by reducing the competitive transition charge ("CTCs"). Further, Staff recommended that any stranded costs not collected could simply be deferred and collected after 2004.
The AECC expert testified that the "shopping credit" under the Agreement was superior to the "Shopping Credit" in the Staff Settlement Proposal as well as the one offered to SRP's customers. APS argued that artificially high shopping credits will likely increase ESP profits without lowering customer rates and will encourage inefficient firms to enter the market. Based on the analysis of the
6 DECISION NO. 61973
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40kW to 200 kW customer group3, APS showed an average margin on the "shopping credit" of over 8 mils per kWh or a 23 percent markup over cost. APS asserted that the test for a reasonable "shopping credit" "should not be whether ALL ESPs can profit on all APS customers ALL of the time".
Based on the evidence presented, the "shopping credits" appear to be reasonable to allow ESPs to compete in an efficient manner. Further, we do not find customer rates should be increased simply to have higher "shopping credits".
METERING AND BILLING CREDITS
The metering and billing credits resulting from the Agreement are based on decremental costs. Several of the ESPs and Staff argued that these credits should be based upon embedded costs and not decremental costs. APS responded that such a result could cause them to lose revenues since its costs would only go down by the decremental amounts. Staff testified that the Company would not lose significant income if it used embedded costs since it would free up resources to service new customers.
We concur. The proposed credits for metering, meter reading and billing4 will result in a direct access customer paying a portion of APS costs as well as a portion of the ESP's costs. We believe this would stymie the competitive market for these services. As a result, we find the approval of the Settlement should be conditioned upon the use of Staff's proposed credits for metering, meter reading, and billing.
PROPOSED ONE-YEAR ADVANCE NOTICE REQUIREMENT:
Section 2.3 provides that
"Customers greater than 3MW who chose a direct access supplier must give APS one year's advance notice before being eligible to RETURN to Standard Offer service." [emphasis added]
Several parties expressed concerns that the one-year notice requirement to return to Standard Offer service would create a deterrent to load switching by large industrial, institutional and commercial customers. PG&E proposed that any increased cost could be charged directly to the
access in phase one.
4 For example, the monthly credits for a direct access residential customers
are $1.30, $0.30, and $0.30 for metering, meter reading and billing,
respectively.
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customer as a condition to its return.
We agree that APS needs to have some protection from customers leaving the system when market prices are low and jumping back on Standard Offer rates when market prices go up. The suggestion by PG&E that the customer be allowed to go back to the Standard Offer if the customer pays for additional costs it has caused is a reasonable resolution. Accordingly, we will order APS to submit substitute language on this issue.
SECTION 2.8
Several of the parties expressed concern that Section 2.8 of the Agreement
allows APS to seek rate increases under specified conditions. Additionally, as
previously discussed, the Consumers Council opined that Section 2.8 violated
A.R.S. Section 40-246. Staff recommended the Commission condition approval of
the Agreement on Section 2.8 being amended to include language that the
Commission or Staff may commence rate change proceedings under conditions
paralleling those provided to the utility, including response to petitions
submitted under A.R.S. ss. 40-246.
We agree that Section 2.8 is too restrictive on the Commission's future action. Accordingly, we will condition approval of the Agreement on inclusion of the following language in Section 2.8:
Neither the Commission nor APS shall be prevented from seeking or authorizing a change in unbundled or Standard Offer rates prior to July 1, 2004, in the event of (a) conditions or circumstances which constitute an emergency, such as an inability to finance on reasonable terms, or (b) material changes in APS' cost of service for Commission-regulated services resulting from federal, tribal, state or local laws, regulatory requirements, judicial decisions, actions or orders. Except for the changes otherwise specifically contemplated by this Agreement, unbundled and Standard Offer rates shall remain unchanged until at least July 1, 2004.
SECTION 7.1
The Consumers Council opined that there was language in the Agreement which
would illegally bind future Commissions. While Staff disagreed with the legal
opinion of the Consumers Council, Staff was concerned with some of the binding
language in the Agreement and in particular with the following language in
Section 7.1:
7.1. To the extent any provision of this Agreement is inconsistent with any existing or future Commission order, rule or regulation or is inconsistent with the Electric
8 DECISION NO. 61973
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Competition Rules as now existing or as may be amended in the future, the provisions of this Agreement shall control and the approval of the Agreement by the Commission shall be deemed to constitute a Commission-approved variation or exemption to any conflicting provision of the Electric Competition Rules.
Staff recommended the Commission not approve Section 7.1.
We share Staff's concerns. We also recognize that the parties want to
preserve their benefits to their Agreement. We agree with the parties that to
the extent any provision of the Agreement is inconsistent with the Electric
Competition Rules as finalized by the Commission in September 1999, the
provisions of the Agreement shall control. We want to make it clear that the
Commission does not intend to revisit the stranded cost portion of the
Agreement. It is also not the Commission's intent to undermine the benefits that
parties have bargained for. With that said, the Commission must be able to make
rule changes/other future modifications that become necessary over time. As a
result, we will direct the parties and Staff to file within 10 days, a revised
Section 7.1 consistent with the Commission's discussions herein and subsequently
approved by this Commission.
GENERATION AFFILIATE
Section 4.1 of the Agreement provides the following:
4.1 The Commission will approve the formation of an affiliate or affiliates of APS to acquire at book value the competitive services assets as currently required by the Electric Competition Rules. In order to facilitate the separation of such assets efficiently and at the lowest possible cost, the Commission shall grant APS a two-year extension of time until December 31, 2002, to accomplish such separation. A similar two-year extension shall be authorized for compliance with A.A.C. R14-2-1606(B).
Related to Section 4.1 is Section 2.6(3) which allows APS to defer costs of forming the generation affiliate, to be collected beginning July 1, 2004.
According to NEV Southwest, APS indicated that it intends to establish a generation affiliate under Pinnacle West, not under APS. Further, that APS intends to procure generation for standard offer customers from the wholesale generation market as provided for in the Electric Competition Rules. Additionally, it was NEV Southwest's understanding that the affiliate generation company could bid for the APS standard offer load under an affiliate FERC tariff, but there would be no automatic privilege outside of the market bid. NEV Southwest supports the aforementioned concepts and recommended they be explicitly stated in the Agreement.
We concur with NEV Southwest. We shall order APS to include language as requested by
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NEV Southwest. Power for Standard Offer Service will be acquired in a manner
consistent with the Commission's Electric Competition Rules. We generally
support the request of APS to defer those costs related to formation of a new
generation affiliate pursuant to the Electric Competition Rules. We also
recognize the Company is making a business decision to transfer the generation
assets to an affiliate instead of an unrelated third party. As a result, we find
the Company's proposed mitigation of stranded costs(5) in the Settlement should
also apply to the costs of forming the new generation affiliate. Accordingly,
Section 2.6(3) should be modified to reflect that only 67 percent of those costs
to transfer generation assets to an affiliate shall be allowed to be deferred
for future collection.
Some parties were concerned that Sections 4.1 and 4.2 provide in effect that the Commission will have approved in advance any proposed financing arrangements associated with future transfers of "competitive services" assets to an affiliate. As a result, there was a recommendation that the Commission retain the right to review and approve or reject any proposed financing arrangements. In addition, some parties expressed concern that APS has not definitively described the assets it will retain and which it will transfer to an affiliate.
We share the concerns that the non-competitive portion of APS not subsidize the spun-off competitive assets through an unfair financial arrangement. We want to make it clear that the Commission will closely scrutinize the capital structure of APS at its 2004 rate case and make any necessary adjustments. The Commission supports and authorizes the transfer by APS to an affiliate or affiliates of all its generation and competitive electric service assets as set forth in the Agreement no later than December 31, 2002. However, we will require the Company to provide the Commission with a specific list of any assets to be so transferred, along with their net book values at the time of transfer, at least thirty days prior to the actual transfer. The Commission reserves the right to verify whether such specific assets are for the provision of generation and other competitive electric services or whether there are additional APS assets that should be so transferred.
UNBUNDLED RATES
Several parties expressed concern that the Agreement's unbundled rates fail to provide the
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necessary information to determine whether a competitor's price is lower than the Standard Offer rate. Further, some of the parties asserted that APS has not performed a functional cost-of-service study and as a result the Settlement's "shopping credit" is an artificial division of costs. In response, APS indicated the Standard Offer rates can not be unbundled on a strict cost-of-service basis unless the Standard Offer rates are redesigned to equal cost-of-service. APS opined that such a process would result in significant rate increases for many customers.
AECC asserted that a full rate case would result in additional months/years of delay with continued drain of resources by all interested entities.
The ESPs asserted that the bill format proposed by APS is misleading and too complex. In general, the ESPs desired a bill format that would allow customers to easily compare Standard Offer and Direct Access charges in order to make an informed decision. As a result, APS was directed to circulate an Informational Unbundled Standard Offer Bill ("Bill") to the parties for comments. Subsequent to the hearing, a Bill was circulated to the parties for comments to determine what consensus could be reached on its format. In general, there was little dispute with the format of the Bill. However, PG&E and Commonwealth disagreed with the underlying cost allocation methodologies. Enron was concerned that the Bill portrayed the Standard Offer to be more simplistic than the Direct Access portion of the Bill. Enron proposed a bill format that would clearly identify those services which are available from an ESP. Based on comments from RUCO and Staff, APS made general revisions to the proposed Bill.
We find the APS Attachment AP-1R, second revised dated 8/16/99 provides sufficient information in a concise manner to enable customers to make an informed choice. (See Attachment No. 2 herein). However, we find the Enron breakdown into a Part 1 versus Parts 2 and 3 will further help educate customers as to choice. We will direct APS to further revise its Bill to have a Part 1 as set forth by the Enron breakdown. We believe Parts 2 and 3 can be combined for simplicity.
We concur with APS that it is not necessary to file a revised cost-of-service study at this time. The proposed Standard Offer rates contained in the Settlement are based on existing tariffs approved by this Commission. Further, we concur with AECC that a full rate case with a revised cost-of-service study would result in months/years of additional delay. Lastly, the Standard Offer rates as
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proposed in the Settlement are consistent with the Commission's requirement that no customer shall receive a rate increase. The following was extracted from Decision No. 61677:
"No customer or customer class shall receive a rate increase as a result of stranded cost recovery by an Affected Utility under any of these options."
CODE OF CONDUCT
There were concerns expressed that APS would be writing its own Code of Conduct. Subsequently, APS did provide a copy of its proposed Code of Conduct to the parties for comment. Several parties also expressed concern that any Code of Conduct would not cover the actions of a single company during the two-year delay for transferring generation assets.
Based on the above, we will direct APS to file with the Commission no later than 30 days of the date of this Decision, its interim Code of Conduct. We will direct APS to file its revised Code of Conduct within 30 days of the date of this Decision. Such Code of Conduct should also include provisions to govern the supply of generation during the two-year period of delay for the transfer of generation assets so that APS doesn't give itself an undue advantage over the ESPs. All parties shall have 60 days from the date of this Decision to provide their comments to APS regarding the revised Code of Conduct. APS shall file its final proposed Code of Conduct within 90 days of the date of this Decision. Subsequently, within 10 days of filing the Code of Conduct, the Hearing Division shall establish a procedural schedule to hear the matter.
SECTION 2.6(1)
Pursuant to the Agreement, the Commission shall approve an adjustment clause or clauses which among other things would provide for a purchased power adjustor ("PPA") for service after July 1, 2004 for Standard Offer obligations. Part of the justification for the PPA was the fact that these costs would be outside of the Company's control.
We concur that a PPA would result in less risk to the Company resulting in lower costs for the Standard Offer customers. As a result, we will approve the concept of the PPA as set forth in Section 2.6(1) with the understanding that the Commission can eliminate the PPA once the Commission has provided reasonable notice to the Company.
12 DECISION NO. 61973
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REQUESTED WAIVERS
Section 4.3 of the Agreement would automatically act to exempt APS and its
affiliates from the application of a wide range of provisions under A.R.S. Title
40. In addition, under Section 4.5 of the Agreement, Commission approval without
modification will act to grant certain waivers to APS and its affiliates of a
variety of the provisions of the Commission's affiliate interest rules (A.A.C.
R14-2-801, ET SEQ.), and the rescission of all or portions of certain prior
Commission decisions.
Staff recommended that the Commission reserve its approval of the requested statute waivers until such time as their applicability can be evaluated on an industry-wide basis, rather than providing a blanket exemption for APS and its affiliates. Additionally, Staff recommended that the Commission not waive the applicability of A.A.C. R14-2-804(A), in order to preserve the regulatory authority needed by the Commission to justify approving Exempt Wholesale Generator ("EWG") status for APS' generation affiliate.
We concur with Staff. Accordingly, the requested statutory waivers shall
not be granted by this Decision. Those waivers will be considered in an
industry-wide proceeding to be scheduled at the Commission's earliest
convenience. The requested waivers of affiliate interest rules and rescission of
prior Commission decisions shall be granted, except that the provisions of
A.A.C. R14-2-804(A) shall not be waived.
ANALYSIS/SUMMARY
Consistent with our determination in Decision No. 60977, the following primary objectives need to be taken into consideration in deciding the overall stranded cost issue:
A. Provide the Affected Utilities a reasonable opportunity to collect 100 percent of their unmitigated stranded costs;
B. Provide incentives for the Affected Utilities to maximize their mitigation effort;
C. Accelerate the collection of stranded costs into as short of a transition period as possible consistent with other objectives;
D. Minimize the stranded cost impact on customers remaining on the standard offer;
E. Don't confuse customers as to the bottom line; and
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F. Have full generation competition as soon as possible.
The Commission also recognized in Decision No. 60977 that the aforementioned objectives were in conflict. Part of that conflict is reflected in the following language extracted from Decision No. 60977:
One of the main concerns expressed over and over by various consumer groups was that the small consumers would end up with higher costs during the transition phase and all the benefits would flow to the larger users. At the time of the hearing, there had been minimal participation in California by residential customers in the competitive electric market place. It is not the Commission's intent to have small consumers pay higher short-term costs in order to provide lower costs for the larger consumers. Accordingly, we will place limitations on stranded cost recovery that will minimize the impact on the standard offer.
Decision No. 61677 modified Decision No. 60977 and allowed each Affected Utility to chose from five options.
With the modifications contained herein, we find the overall Settlement satisfies the objectives set forth in Decision Nos. 60977 and 61677. We believe the Settlement will result in an orderly process that will have real rate reductions6 during the transition period to a competitive generation market. The Settlement allows EVERY APS CUSTOMER to have the immediate opportunity to benefit from the change in market structure while maintaining reliability and certainty of delivery. Further, the Settlement in conjunction with the Electric Rules will provide every APS customer with a choice in a reasonable timeframe and in an orderly manner. If anything, the Proposed Settlement favors customers over competitors in the short run since APS has agreed to reductions in rates totaling 7.5 percent(7). This Commission supports competition in the generation market because of increased benefits to customers, including lower rates and greater choice. While some of the potential competitors have argued that higher "shopping credits" will result in greater choice, we find that a higher shopping credit would also mean less of a rate reduction for APS customers. We find that the Settlement strikes the proper balance between competing objectives by allowing immediate
7 Pursuant to Decision No. 59601, dated April 24, 1996, 0.68 percent of that decrease would have occurred on July 1, 1999.
14 DECISION NO. 61973
DOCKET NO. E-01345A-98-0473 ET AL.
rate reductions while maintaining a relatively short transition period for collection of stranded costs, followed shortly thereafter with a full rate case. At that point in time the collection of stranded costs will be completed and unbundled rates can be modified based upon an updated cost study.
* * * * * * * * * *
Having considered the entire record herein and being fully advised in the premises, the Commission finds, concludes, and orders that:
FINDINGS OF FACT
1. APS is certificated to provide electric service as a public service corporation in the State of Arizona.
2. Decision No. 59943 enacted R14-2-1601 through -1616, the Retail Electric Competition Rules.
3. Following a hearing on generic issues related to stranded costs, the Commission issued Decision No. 60977, dated June 22, 1998.
4. Decision No. 61071 adopted the Emergency Rules on a permanent basis.
5. On August 21, 1998, APS filed its Stranded Costs plan.
6. On November 5, 1998, APS filed the Staff Settlement Proposal.
7. Our November 24, 1998 Procedural Order set the matter for hearing.
8. Decision No. 61259 established an expedited procedural schedule for evidentiary hearings on the Staff Settlement Proposal.
9. The Court issued a Stay of the Commission's consideration of the Staff Settlement Proposal.
10. Staff withdrew the Staff Settlement Proposal from Commission consideration.
11. On May 17, 1999, APS filed its Settlement requesting Commission approval.
12. Our May 25, 1999 Procedural Order set the Settlement for hearing commencing on July 14, 1999.
13. Decision No. 61311 (January 11, 1999) stayed the effectiveness of the Emergency Rules and related Decisions, and ordered the Hearing Division to conduct further proceedings in this Docket.
15 DECISION NO. 61973
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14. In Decision No. 61634 (April 23, 1999), the Commission adopted modifications to R14-2-201 through-207, -210 and 212 and R14-2-1601 through -1617.
15. Pursuant to Decision No. 61677, dated April 27, 1999, the Commission modified Decision No. 60977 whereby each Affected Utility could choose one of the following options: (a) Net Revenues Lost Methodology; (b) Divestiture/Auction Methodology; (c) Financial Integrity Methodology; (d) Settlement Methodology; and (e) the Alternative Methodology.
16. APS and other Affected Utilities filed with the Arizona Superior Court various appeals of Commission Orders adopting the Competition Rules and related Stranded Cost Decisions (the "Outstanding Litigation").
17. Pursuant to Decision No. 61677, APS, RUCO, AECC, and ACAA entered into the Settlement to resolve numerous issues, including stranded costs and unbundled tariffs.
18. The difference between market based prices and the cost of regulated power has been generally referred to as stranded costs.
19. Any stranded cost recovery methodology must balance the interests of the Affected Utilities, ratepayers, and the move toward competition.
20. All current and future customers of the Affected Utilities should pay their fair share of stranded costs.
21. Pursuant to the terms of the Settlement Agreement, APS has agreed to the modification of its CC&N in order to implement competitive retail access in its Service Territory.
22. The Settlement Agreement provides for competitive retail access in APS' Service Territory, establishes rate reductions for all APS customers, sets a mechanism for stranded cost recovery, resolves contentious litigation, and therefore, is in the public interest and should be approved.
23. The information and formula for rate reductions contained in Exhibit AP-3 Appended to APS Exhibit No. 2 provides current financial support for the proposed rates.
24. RUCO, ACAA, and AECC collectively, represent residential and non-residential customers.
25. According to AECC, the Agreement results in higher shopping credits than in the Staff
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Settlement Proposal as well as those offered by SRP.
26. The decremental approach for metering and billing will not provide sufficient credits for competitors to compete.
27. Pursuant to the Settlement, customers will receive substantial rate reductions without the necessity of a full rate case.
28. An APS rate case would take a minimum of one year to complete.
29. ESPs that have been certificated have shown more of an interest in serving larger business customers than residential customers.
30. It is not in the public or customers' interests to forego guaranteed Standard Offer rate reductions in order to have a higher shopping credit.
31. The Settlement will permit competition in a timely and efficient manner and insure all customers benefit during the transition period.
32. Based on the evidence presented, the FVRB and FVROR of APS is determined to be $5,195,675,000 and 6.63 percent, respectively.
33. The terms and conditions of the Settlement Agreement as modified herein are just and reasonable and in the public interest.
CONCLUSIONS OF LAW
1. The Affected Utilities are public service corporations within the meaning of the Arizona Constitution, Article XV, under A.R.S. ss.ss. 40-202, -203, -250, -321, -322, -331, -336, -361, -365, -367, and under the Arizona Revised Statutes, Title 40, generally.
2. The Commission has jurisdiction over the Affected Utilities and of the subject matter contained herein.
3. Notice of the proceeding has been given in the manner prescribed by law.
4. The Settlement Agreement as modified herein is just and reasonable and in the public interest and should be approved.
5. APS should be authorized to implement its Stranded Cost Recovery Plan as set forth in the Settlement Agreement.
6. APS' CC&N should be modified in order to permit competitive retail access in APS'
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CC&N service territory.
7. The requested statutory waivers should not be granted at this time. A
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proceeding should be commenced to consider statutory waivers on an industry-wide basis. The other waivers requested by APS in the Settlement should be granted as modified herein, except that the provisions of A.A.C. R14-2-804(A) shall not be waived.
ORDER
IT IS THEREFORE ORDERED that the Settlement Agreement as modified herein is hereby approved and all Commission findings, approvals and authorizations requested therein are hereby granted.
IT IS FURTHER ORDERED that Arizona Public Service Company's CC&N is hereby modified to permit competitive retail access consistent with this Decision and the Competition Rules.
IT IS FURTHER ORDERED that within 30 days of the date of this Decision, Arizona Public Service Company shall file a proposed Code of Conduct for Commission approval.
IT IS FURTHER ORDERED that Arizona Public Service Company shall file a revised Settlement Agreement consistent with the modifications herein.
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IT IS FURTHER ORDERED that within ten days of the date the proposed Code of Conduct is filed, the Hearing Division shall issue a Procedural Order setting a procedural schedule for consideration of the Code of Conduct.
IT IS FURTHER ORDERED that this Decision shall become effective
immediately. BY ORDER OF THE ARIZONA CORPORATION COMMISSION.
Carl J. Kunasek William A. Mundell
--------------------------------------------------------------------------------
CHAIRMAN COMMISSIONER COMMISSIONER
IN WITNESS WHEREOF, I, BRIAN C. McNEIL,
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Executive Secretary of the Arizona Corporation Commission, have hereunto set my hand and caused the official seal of the Commission to be affixed at the Capitol, in the City of Phoenix, this 6th day of October, 1999.
DISSENT _________________
JLR:dap
19 DECISION NO. 61973
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SERVICE LIST FOR: ARIZONA PUBLIC SERVICE COMPANY
DOCKET NOS.: E-01345A-98-0473, E-01345A-97-0773 and
RE-00000C-94-0165
Service List for RE-00000C-94-0165
Paul A. Bullis, Chief Counsel
LEGAL DIVISION
1200 W. Washington Street
Phoenix, Arizona 85007
Utilities Division Director
ARIZONA CORPORATION COMMISSION
1200 W. Washington Street
Phoenix, Arizona 85007
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20 DECISION NO. 61973
ATTACHMENT 1
SETTLEMENT AGREEMENT
May 14, 1999
This settlement agreement ("Agreement") is entered into as of May 14, 1999, by Arizona Public Service Company ("APS" or the "Company") and the various signatories to this Agreement (collectively, the "Parties") for the purpose of establishing terms and conditions for the introduction of competition in generation and other competitive services that are just, reasonable and in the public interest.
INTRODUCTION
In Decision No. 59943, dated December 26, 1996, the Arizona Corporation Commission ("ACC" or the "Commission") established a "framework" for introduction of competitive electric services throughout the territories of public service corporations in Arizona in the rules adopted in A.A.C. R14-2-1601 ET SEQ. (collectively, "Electric Competition Rules" as they may be amended from time to time). The Electric Competition Rules established by that order contemplated future changes to such rules and the possibility of waivers or amendments for particular companies under appropriate circumstances. Since their initial issuance, the Electric Competition Rules have been amended several times and are currently stayed pursuant to Decision No. 61311, dated January 5, 1999. During this time, APS, Commission Staff and other interested parties have participated in a number of proceedings, workshops, public comment sessions and individual negotiations in order to further refine and develop a restructured utility industry in Arizona that will provide meaningful customer choice in a manner that is just, reasonable and in the public interest.
This Agreement establishes the agreed upon transition for APS to a restructured entity and will provide customers with competitive choices for generation and certain other retail services. The Parties believe this Agreement will produce benefits for all customers through implementing customer choice and providing rate reductions so that the APS service territory may benefit from economic growth. The Parties also believe this Agreement will fairly treat APS and its shareholders by providing a reasonable opportunity to recover prudently incurred investments and costs, including stranded costs and regulatory assets.
Specifically, the Parties believe the Agreement is in the public interest for the following reasons. FIRST, customers will receive substantial rate reductions. SECOND, competition will be promoted through the introduction of retail access faster than would have been possible without this Agreement and by the functional separation of APS' power production and delivery functions. THIRD, economic development and the environment will
benefit through guaranteed rate reductions and the continuation of renewable and energy efficiency programs. FOURTH, universal service coverage will be maintained through APS' low income assistance programs and establishment of "provider of last resort" obligations on APS for customers who do not wish to participate in retail access. FIFTH, APS will be able to recover its regulatory assets and stranded costs as provided for in this Agreement without the necessity of a general rate proceeding. Sixth, substantial litigation and associated costs will be avoided by amicably resolving a number of important and contentious issues that have already been raised in the courts and before the Commission. Absent approval by the Commission of the settlement reflected by this Agreement, APS would seek full stranded cost recovery and pursue other rate and competitive restructuring provisions different than provided for herein. The other Parties would challenge at least portions of APS' requested relief, including the recovery of all stranded costs. The resulting regulatory hearings and related court appeals would delay the start of competition and drain the resources of all Parties.
NOW, THEREFORE, APS and the Parties agree to the following provisions which they believe to be just, reasonable and in the public interest:
TERMS OF AGREEMENT
ARTICLE I
IMPLEMENTATION OF RETAIL ACCESS
1.1 The APS distribution system shall be open for retail access on July 1, 1999; provided, however, that such retail access to electric generation and other competitive electric services suppliers will be phased in for customers in APS' service territory in accordance with the proposed Electric Competition Rules, as and when such rules become effective, with an additional 140 MW being made available to eligible non-residential customers. The Parties shall urge the Commission to approve Electric Competition Rules, at least on an emergency basis, so that meaningful retail access can begin by July 1, 1999. Unless subject to judicial or regulatory restraint, APS shall open its distribution system to retail access for all customers on January 1, 2001.
1.2 APS will make retail access available to residential customers pursuant to its December 21, 1998, filing with the Commission.
1.3 The Parties acknowledge that APS' ability to offer retail access is contingent upon numerous conditions and circumstances, a number of which are not within the direct control of the Parties. Accordingly, the Parties agree that it may become necessary to modify the terms of retail access to account for such factors, and they further agree to address such matters in good faith and to cooperate in an effort to propose joint resolutions of any such matters.
1.4. APS agrees to the amendment and modification of its Certificate(s) of Convenience and Necessity to permit retail access consistent with the terms of this Agreement. The Commission order adopting this Agreement shall constitute the necessary Commission Order amending and modifying APS' CC&Ns to permit retail access consistent with the terms of this Agreement.
ARTICLE II
RATE MATTERS
2.1. The Company's unbundled rates and charges attached hereto as Exhibit A will be effective as of July 1, 1999. The Company's presently authorized rates and charges shall be deemed its standard offer ("Standard Offer") rates for purposes of this Agreement and the Electric Competition Rules. Bills for Standard Offer service shall indicate individual unbundled service components to the extent required by the Electric Competition Rules.
2.2. Future reductions of standard offer tariff rates of 1.5% for customers having loads of less than 3 MW shall be effective as of July 1, 1999, July 1, 2000, July 1, 2001, July 1, 2002, and July 1, 2003, upon the filing and Commission acceptance of revised tariff sheets reflecting such decreases. For customers having loads greater than 3 MW served on Rate Schedules E-34 and E-35, Standard Offer tariff rates will be reduced: 1.5%, effective July 1, 1999; 1.5% effective July 1, 2000; 1.25% effective July 1, 2001; and .75% effective July 1, 2002. The 1.5% Standard Offer rate reduction to be effective July 1, 1999, includes the rate reduction otherwise required by Decision No. 59601. Such decreases shall become effective by the filing with and acceptance by the Commission of revised tariff sheets reflecting each decrease.
2.3. Customers greater than 3 MW who choose a direct access supplier must give APS one year's advance notice before being eligible to return to Standard Offer service.
2.4. Unbundled rates shall be reduced in the amounts and at the dates set forth in Exhibit A attached hereto upon the filing and Commission acceptance of revised tariff sheets reflecting such decreases.
2.5. This Agreement shall not preclude APS from requesting, or the Commission from approving, changes to specific rate schedules or terms and conditions of service, or the approval of new rates or terms and conditions of service, that do not significantly affect the overall earnings of the Company or materially modify the tariffs or increase the rates approved in this Agreement. Nothing contained in this Agreement shall preclude APS from filing changes to its tariffs or terms and conditions of service which are not inconsistent with its obligations under this Agreement.
2.6. Notwithstanding the rate reduction provisions stated above, the Commission shall, prior to December 31, 2002, approve an adjustment clause or clauses which
will provide full and timely recovery beginning July 1, 2004, of the reasonable and prudent costs of the following:
(1) APS' "provider of last resort" and Standard Offer obligations for service after July 1, 2004, which costs shall be recovered only from Standard Offer and "provider of last resort" customers;
(2) Standard Offer service to customers who have left Standard Offer service or a special contract rate for a competitive generation supplier but who desire to return to Standard Offer service, which costs shall be recovered only from Standard Offer and "provider of last resort" customers;
(3) compliance with the Electric Competition Rules or Commission-ordered programs or directives related to the implementation of the Electric Competition Rules, as they may be amended from time to time, which costs shall be recovered from all customers receiving services from APS; and
(4) Commission-approved system benefit programs or levels not included in Standard Offer rates as of June 30, 1999, which costs shall be recovered from all customers receiving services from APS.
By June 1, 2002, APS shall file an application for an adjustment clause or clauses, together with a proposed plan of administration, and supporting testimony. The Commission shall thereafter issue a procedural order setting such adjustment clause application for hearing and including reasonable provisions for participation by other parties. The Commission order approving the adjustment clauses shall also establish reasonable procedures pursuant to which the Commission, Commission Staff and interested parties may review the costs to be recovered. By June 30, 2003, APS will file its request for the specific adjustment clause factors which shall, after hearing and Commission approval, become effective July 1, 2004. APS shall be allowed to defer costs covered by this Section 2.6 when incurred for later full recovery pursuant to such adjustment clause or clauses, including a reasonable return.
2.7. By June 30, 2003, APS shall file a general rate case with prefiled testimony and supporting schedules and exhibits; provided, however, that any rate changes resulting therefrom shall not become effective prior to July 1, 2004.
2.8. APS shall not be prevented from seeking a change in unbundled or Standard Offer rates prior to July 1, 2004, 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 APS' cost of service for Commission regulated services resulting from federal, tribal,
state or local laws, regulatory requirements, judicial decision, actions or orders. Except for the changes otherwise specifically contemplated by this Agreement, unbundled and Standard Offer rates shall remain unchanged until at least July 1, 2004.
ARTICLE III
REGULATORY ASSETS AND STRANDED COSTS
3.1. APS currently recovers regulatory assets through July 1, 2004, pursuant to Commission Decision No. 59601 in accordance with the provisions of this Agreement.
3.2. APS has demonstrated that its allowable stranded costs after mitigation (which result from the impact of retail access), exclusive of regulatory assets, are at least $533 million net present value.
3.3. The Parties agree that APS should not be allowed to recover $183 million net present value of the amounts included above. APS shall have a reasonable opportunity to recover $350 million net present value through a competitive transition charge ("CTC") set forth in Exhibit A attached hereto. Such CTC shall remain in effect until December 31, 2004, at which time it will terminate. If by that date APS has recovered more or less than $350 million net present value, as calculated in accordance with Exhibit B attached hereto, then the nominal dollars associated with any excess recovery/under recovery shall be credited/debited against the costs subject to recovery under the adjustment clause set forth in Section 2.6(3).
3.4. The regulatory assets to be recovered under this Agreement, after giving effect to the adjustments set forth in Section 3.3, shall be amortized in accordance with Schedule C of Exhibit A attached hereto.
3.5. Neither the Parties nor the Commission shall take any action that would diminish the recovery of APS' stranded costs or regulatory assets provided for herein. The Company's willingness to enter into this Agreement is based upon the Commission's irrevocable promise to permit recovery of the Company's regulatory assets and stranded costs as provided herein. Such promise by the Commission shall survive the expiration of the Agreement and shall be specifically enforceable against this and any future Commission.
ARTICLE IV
CORPORATE STRUCTURE
4.1. The Commission will approve the formation of an affiliate or affiliates of APS to acquire at book value the competitive services assets as currently required by the Electric Competition Rules. In order to facilitate the separation of such assets efficiently and at the lowest possible cost, the Commission shall grant APS a two-year extension of time until
December 31, 2002, to accomplish such separation. A similar two-year extension shall be authorized for compliance with A.A.C. R14-2-1606(B).
4.2. Approval of this Agreement by the Commission shall be deemed to
constitute all requisite Commission approvals for (1) the creation by APS or its
parent of new corporate affiliates to provide competitive services including,
but not limited to, generation sales and power marketing, and the transfer
thereto of APS' generation assets and competitive services, and (2) the full and
timely recovery through the adjustment clause referred to in Section 2.6 above
for all of the reasonable and prudent costs so incurred in separating
competitive generation assets and competitive services as required by proposed
A.A.C. R14-2-1615, exclusive of the costs of transferring the APS power
marketing function to an affiliate. The assets and services to be transferred
shall include the items set forth on Exhibit C attached hereto. Such transfers
may require various regulatory and third party approvals, consents or waivers
from entities not subject to APS' control, including the FERC and the NRC. No
Party to this Agreement (including the Commission) will oppose, or support
opposition to, APS requests to obtain such approvals, consents or waivers.
4.3. Pursuant to A.R.S. ss. 40-202(L), the Commission's approval of this Agreement shall exempt any competitive service provided by APS or its affiliates from the application of various provisions of A.R.S. Title 40, including A.R.S. ss.ss. 40-203, 40-204(A), 40-204(B), 40-248, 40-250, 40-251, 40-285, 40-301, 40-302, 40-303, 40-321, 40-322, 40-331, 40-332, 40-334, 40-365, 40-366, 40-367 and 40-401.
4.4. APS' subsidiaries and affiliates (including APS' parent) may take advantage of competitive business opportunities in both energy and non-energy related businesses by establishing such unregulated affiliates as they deem appropriate, which will be free to operate in such places as they may determine. The APS affiliate or affiliates acquiring APS' generating assets may be a participant in the energy supply market within and outside of Arizona. Approval of this Agreement by the Commission shall be deemed to include the following specific determinations required under Sections 32(c) and (k)(2) of the Public Utility Holding Company Act of 1935:
APS or an affiliate is authorized to establish a subsidiary company, which will seek exempt wholesale generator ("EWG") status from the Federal Energy Regulatory Commission, for the purposes of acquiring and owning Generation Assets.
The Commission has determined that allowing the Generation Assets to become "eligible facilities," within the meaning of Section 32 of the Public Utility Holding Company Act ("PUHCA"), and owned by an APS EWG affiliate (1) will benefit consumers, (2) is in the public interest, and (3) does not violate Arizona law.
The Commission has sufficient regulatory authority, resources and access to the books and records of APS and any relevant associate, affiliate, or subsidiary company to exercise its duties under Section 32(k) of PUHCA.
APS will purchase any electric energy from its EWG affiliate at market
based rates. This Commission has determined that (1) the proposed
transaction will benefit consumers and does not violate Arizona law;
(2) the proposed transaction will not provide APS' EWG affiliate an
unfair competitive advantage by virtue of its affiliation with APS; (3)
the proposed transaction is in the public interest.
The APS affiliate or affiliates acquiring APS' generating assets will be subject to regulation by the Commission, to the extent otherwise permitted by law, to no greater manner or extent than that manner and extent of Commission regulation imposed upon other owners or operators of generating facilities.
4.5. The Commission's approval of this Agreement will constitute certain waivers to APS and its affiliates (including its parent) of the Commission's existing affiliate interest rules (A.A.C. R14-2-801, ET SEQ.), and the rescission of all or portions of certain prior Commission decisions, all as set forth on Exhibit D attached hereto.
4.6. The Parties reserve their rights under Sections 205 and 206 of the Federal Power Act with respect to the rates of any APS affiliate formed under the provisions of this Article IV.
ARTICLE V
WITHDRAWAL OF LITIGATION
5.1. Upon receipt of a final order of the Commission approving this Agreement that is no longer subject to judicial review, APS and the Parties shall withdraw with prejudice all of their various court appeals of the Commission's competition orders.
ARTICLE VI
APPROVAL BY THE COMMISSION
6.1. This Agreement shall not become effective until the issuance of a final Commission order approving this Agreement without modification on or before August 1, 1999. In the event that the Commission fails to approve this Agreement without modification according to its terms on or before August 1, 1999, any Party to this Agreement may withdraw from this Agreement and shall thereafter not be bound by its provisions; provided, however, that if APS withdraws from this Agreement, the Agreement shall be null and void and of no further force and effect. In any event, the rate reduction provisions of this Agreement shall not take effect until this Agreement is approved. Parties so withdrawing shall be free to pursue
their respective positions without prejudice. Approval of this Agreement by the Commission shall make the Commission a Party to this Agreement and fully bound by its provisions.
6.2. The Parties agree that they shall make all reasonable and good faith efforts necessary to (1) obtain final approval of this Agreement by the Commission, and (2) ensure full implementation and enforcement of all the terms and conditions set forth in this Agreement. Neither the Parties nor the Commission shall take or propose any action which would be inconsistent with the provisions of this Agreement. All Parties shall actively defend this Agreement in the event of any challenge to its validity or implementation.
ARTICLE VII
MISCELLANEOUS MATTERS
7.1. To the extent any provision of this Agreement is inconsistent with any existing or future Commission order, rule or regulation or is inconsistent with the Electric Competition Rules as now existing or as may be amended in the future, the provisions of this Agreement shall control and the approval of this Agreement by the Commission shall be deemed to constitute a Commission-approved variation or exemption to any conflicting provision of the Electric Competition Rules.
7.2. The provisions of this Agreement shall be implemented and enforceable notwithstanding the pendency of a legal challenge to the Commission's approval of this Agreement, unless such implementation and enforcement is stayed or enjoined by a court having jurisdiction over the matter. If any portion of the Commission order approving this Agreement or any provision of this Agreement is declared by a court to be invalid or unlawful in any respect, then (1) APS shall have no further obligations or liability under this Agreement, including, but not limited to, any obligation to implement any future rate reductions under Article II not then in effect, and (2) the modifications to APS' certificates of convenience and necessity referred to in Section 1.4 shall be automatically revoked, in which event APS shall use its best efforts to continue to provide noncompetitive services (as defined in the proposed Electric Competition Rules) at then current rates with respect to customer contracts then in effect for competitive generation (for the remainder of their term) to the extent not prohibited by law and subject to applicable regulatory requirements.
7.3. The terms and provisions of this Agreement apply solely to and are binding only in the context of the purposes and results of this Agreement and none of the positions taken herein by any Party 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.
7.4. This Agreement represents an attempt to compromise and settle disputed claims regarding the prospective just and reasonable rate levels, and the terms and conditions
of competitive retail access, for APS in a manner consistent with the public interest and applicable legal requirements. Nothing contained in this Agreement is an admission by APS that its current rate levels or rate design are unjust or unreasonable.
7.5. As part of this Agreement, APS commits that it will continue the APS Community Action Partnership (which includes weatherization, facility repair and replacement, bill assistance, health and safety programs and energy education) in an annual amount of at least $500,000 through July 1, 2004. Additionally, the Company will, subject to Commission approval, continue low income rates E-3 and E-4 under their current terms and conditions.
7.6. APS shall actively support the Arizona Independent Scheduling Administrator ("AISA") and the formation of the Desert Star Independent System Operator. APS agrees to modify its OATT to be consistent with any FERC approved AISA protocols. The Parties reserve their rights with respect to any AISA protocols, including the right to challenge or seek modifications to, or waivers from, such protocols. APS shall file changes to its existing OATT consistent with this section within ten (10) days of Commission approval of this Agreement pursuant to Section 6.1.
7.7. Within thirty (30) days of Commission approval of this Agreement pursuant to Section 6.1, APS shall serve on the Parties an Interim Code of Conduct to address inter-affiliate relationships involving APS as a utility distribution company. APS shall voluntarily comply with this Interim Code of Conduct until the Commission approves a code of conduct for APS in accordance with the Electric Competition Rules that is concurrently effective with codes of conduct for all other Affected Utilities (as defined in the Electric Competition Rules). APS shall meet and confer with the Parties prior to serving its Interim Code of Conduct.
7.8. In the event of any disagreement over the interpretation of this Agreement or the implementation of any of the provisions of this Agreement, the Parties shall promptly convene a conference and in good faith shall attempt to resolve such disagreement.
7.9. The obligations under this Agreement that apply for a specific term set forth herein shall expire automatically in accordance with the term specified and shall require no further action for their expiration.
7.10. The Parties agree and recommend that the Commission schedule public meetings and hearings for consideration of this Agreement. The filing of this Agreement with the Commission shall be deemed to be the filing of a formal request for the expeditious issuance of a procedural schedule that establishes such formal hearings and public meetings as may be necessary for the Commission to approve this Agreement in accordance with
Section 6.1 and that afford interested parties adequate opportunity to comment and be heard on the terms of this Agreement consistent with applicable legal requirements.
DATED at Phoenix, Arizona, as of this 14th day of May, 1999.
RESIDENTIAL UTILITY ARIZONA PUBLIC SERVICE COMPANY
CONSUMER OFFICE
By Greg Patterson By Jack E. Davis
------------------------------- -------------------------------
Title Director Title President, Energy
---------------------------- -------------------------------
Delivery & Sales
-------------------------------
ARIZONA COMMUNITY ACTION (Party)
ASSOCIATION ------------------------------------
By Janet Regner By
------------------------------- -------------------------------
Title Executive Director Title
---------------------------- ------------------------------
ARIZONANS FOR ELECTRIC CHOICE AND (Party)
COMPETITION,* a coalition of companies ------------------------------------
and associations in support of
competition that includes Cable Systems
International, BHP Copper, Motorola, By
Chemical Lime, Intel, Honeywell, -------------------------------
Allied Signal, Cyprus Climax Metals,
Asarco, Phelps Dodge, Homebuilders Title
of Central Arizona, Arizona Mining ------------------------------
Industry Gets Our Support, Arizona
Food Marketing Alliance, Arizona
Association of Industries, Arizona
Multi-housing Association, Arizona Rock
Products Association, Arizona Restaurant (Party)
Association, and Arizona Retailers ----------------------------------
Association.
By Peter A. Woog By
------------------------------- -------------------------------
Title Chairman Title
---------------------------- ----------------------------
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* Enron is not a signatory to this Agreement.
* Also included: Boeing, AZ School Board Association, National Federation of Independent Business (NFIB), AZ Hospital Association, Lockheed Martin, Abbot Labs, Raytheon
(Party) (Party)
--------------------------------- ---------------------------------
By By
------------------------------- -------------------------------
Title Title
---------------------------- ----------------------------
(Party) (Party)
--------------------------------- ---------------------------------
By By
------------------------------- -------------------------------
Title Title
---------------------------- ----------------------------
(Party) (Party)
--------------------------------- ---------------------------------
By By
------------------------------- -------------------------------
Title Title
---------------------------- ----------------------------
(Party) (Party)
--------------------------------- ---------------------------------
By By
------------------------------- -------------------------------
Title Title
---------------------------- ----------------------------
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EXHIBIT A
5/10/99
DA-R1
ELECTRIC DELIVERY RATES
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. XXXX
Phoenix, Arizona Tariff or Schedule No. DA-R1
Filed by: Alan Propper Original Tariff
Title: Director, Pricing and Regulation Effective: XXX XX, 1999
DIRECT ACCESS
RESIDENTIAL SERVICE
|
AVAILABILITY
This rate schedule is available in all certificated retail delivery service territory served by Company and where facilities of adequate capacity and the required phase and suitable voltage are adjacent to the premises served.
APPLICATION
This rate schedule is applicable to customers receiving electric energy on a direct access basis from any certificated Electric Service Provider (ESP) as defined in A.A.C. R14-2-1603. This rate schedule is applicable only to electric delivery required for residential purposes in individual private dwellings and in individually metered apartments when such service is supplied at one point of delivery and measured through one meter. For those dwellings and apartments where electric service has historically been measured through two meters, when one of the meters was installed pursuant to a water heating or space heating rate schedule no longer in effect, the electric service measured by such meters shall be combined for billing purposes.
This rate schedule shall become effective as defined in Company's Terms and Conditions for Direct Access (Schedule #10.)
TYPE OF SERVICE
Service shall be single phase, 60 Hertz, at one standard voltage (120/240 or 120/208 as may be selected by customer subject to availability at the customer's premise). Three phase service is furnished under the Company's Conditions Governing Extensions of Electric Distribution Lines and Services (Schedule #3). Transformation equipment is included in cost of extension. Three phase service is required for motors of an individual rated capacity of 7 1/2 HP or more.
METERING REQUIREMENTS
All customers shall comply with the terms and conditions for load profiling or hourly metering specified in Schedule #10.
MONTHLY BILL
The monthly bill shall be the greater of the amount computed under A. or B. below, including the applicable Adjustments.
A. RATE
May - October Billing Cycles (Summer):
Basic Competitive
Delivery System Transition
Service Distribution Benefits Charge
------- ------------ -------- ------
$/month $10.00
All kWh $0.04158 $0.00115 $0.00930
|
November - April Billing Cycles (Winter):
Basic Competitive
Delivery System Transition
Service Distribution Benefits Charge
------- ------------ -------- ------
$/month $10.00
All kWh $0.03518 $0.00115 $0.00930
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B. MINIMUM $ 10.00 per month
(CONTINUED ON REVERSE SIDE)
DA-R1
A.C.C. No. XXXX
Page 2 of 2
|
ADJUSTMENTS
1. When Metering, Meter Reading or Consolidated Billing are provided by the Customer's ESP, the monthly bill will be credited as follows:
Meter $1.30 per month Meter Reading $0.30 per month Billing $0.30 per month |
2. The monthly bill is also 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 service sold and/or the volume of energy delivered or purchased for sale and/or sold hereunder.
SERVICES ACQUIRED FROM CERTIFICATED ELECTRIC SERVICE PROVIDERS
Customers served under this rate schedule are responsible for acquiring their own generation and any other required competitively supplied services from an ESP. The Company will provide and bill its transmission and ancillary services on rates approved by the Federal Energy Regulatory Commission to the Scheduling Coordinator who provides transmission service to the Customer's ESP. The Customer's ESP must submit a Direct Access Service Request pursuant to the terms and conditions in Schedule #10.
ON-SITE GENERATION TERMS AND CONDITIONS
Customers served under this rate schedule who have on-site generation connected to the Company's electrical delivery grid shall enter into an Agreement for Interconnection with the Company which shall establish all pertinent details related to interconnection and other required service standards. The Customer does not have the option to sell power and energy to the Company under this tariff.
TERMS AND CONDITIONS
This rate schedule is subject to the Company's Terms and Conditions for Standard Offer and Direct Access Services (Schedule #1) and Schedule #10. These schedules have provisions that may affect customer's monthly bill.
EXHIBIT A
5/10/99
DA-GS1
ELECTRIC DELIVERY RATES
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. XXXX
Phoenix, Arizona Tariff or Schedule No. DA-GS1
Filed by: Alan Propper Original Tariff
Title: Director, Pricing and Regulation Effective: XXX XX, 1999
DIRECT ACCESS
GENERAL SERVICE
|
AVAILABILITY
This rate schedule is available in all certificated retail delivery service 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
This rate schedule is applicable to customers receiving electric energy on a direct access basis from any certificated Electric Service Provider (ESP) as defined in A.A.C. R14-2-1603. This rate schedule is applicable to all electric service required when such service is supplied at one point of delivery and measured through one meter. For those customers whose electricity is delivered through more than one meter, service for each meter shall be computed separately under this rate unless conditions in accordance with the Company's Schedule #4 (Totalized Metering of Multiple Service Entrance Sections At a Single Premise for Standard Offer and Direct Access Service) are met. For those service locations where electric service has historically been measured through two meters, when one of the meters was installed pursuant to a water heating rate schedule no longer in effect, the electric service measured by such meters shall be combined for billing purposes.
This rate schedule shall become effective as defined in Company's Terms and Conditions for Direct Access (Schedule #10).
This rate schedule is not applicable to residential service, resale service or direct access service which qualifies for Rate Schedule DA-GS10.
TYPE OF SERVICE
Service shall be single or three phase, 60 Hertz, at one standard voltage as may be selected by customer subject to availability at the customer's premise. Three phase service is furnished under the Company's Conditions Governing Extensions of Electric Distribution Lines and Services (Schedule #3). 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.
METERING REQUIREMENTS
All customers shall comply with the terms and conditions for load profiling or hourly metering specified in the Company's Schedule #10.
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 Billing Cycles (Summer):
Basic Competitive
Delivery System Transition
Service Distribution Benefits Charge
------- ------------ -------- ------
$/month $12.50
Per kW over 5 $0.721
Per kWh for the
first 2,500 kWh $0.04255
Per kWh for the
next 100 kWh per
kW over 5 $0.04255
Per kWh for the
next 42,000 kWh $0.02901
Per kWh for all
additional kWh $0.01811
Per all kWh $0.00115
Per all kW $2.43
(CONTINUED ON REVERSE SIDE)
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DA-GS1
A.C.C. No. XXXX
A. RATE (continued)
November - May Billing Cycles (Winter):
Basic Competitive
Delivery System Transition
Service Distribution Benefits Charge
------- ------------ -------- ------
$/month $12.50
Per kW over 5 $0.652
Per kWh for the
first 2,500 kWh $0.03827
Per kWh for the
next 100 kWh per
kW over 5 $0.03827
Per kWh for the
next 42,000 kWh $0.02600
Per kWh for all
additional kWh $0.01614
Per all kWh $0.00115
Per all kW $2.43
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PRIMARY AND TRANSMISSION LEVEL SERVICE:
1. For customers served at primary voltage (12.5kV to below 69kV),
the Distribution charge will be discounted by 11.6%.
2. For customers served at transmission voltage (69kV or higher),
the Distribution charge will be discounted 52.6%.
3. Pursuant to A.A.C. R14-2-1612.K.11, the Company shall retain
ownership of Current Transformers (CT's) and Potential
Transformers (PT's) for those customers taking service at voltage
levels of more than 25kV. For customers whose metering services
are provided by an ESP, a monthly facilities charge will be
billed, in addition to all other applicable charges shown above,
as determined in the service contract based upon the Company's
cost of CT and PT ownership, maintenance and operation.
DETERMINATION OF KW
The kW used for billing purposes shall be the average kW supplied during the 15-minute period of maximum use during the month, as determined from readings of the delivery meter.
B. MINIMUM
$12.50 plus $1.74 for each kW in excess of five of either the highest kW established during the 12 months ending with the current month or the minimum kW specified in the agreement for service, whichever is the greater.
ADJUSTMENTS
1. When Metering, Meter Reading or Consolidated Billing are provided by the Customer's ESP, the monthly bill will be credited as follows:
Meter $4.00 per month
Meter Reading $0.30 per month Billing $0.30 per month
2. The monthly bill is also 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 service sold and/or the volume of energy delivered or purchased for sale and/or sold hereunder.
SERVICES ACQUIRED FROM CERTIFICATED ELECTRIC SERVICE PROVIDERS
Customers served under this rate schedule are responsible for acquiring their own generation and any other required competitively supplied services from an ESP or under the Company's Open Access Transmission Tariff. The Company will provide and bill its transmission and ancillary services on rates approved by the Federal Energy Regulatory Commission to the Scheduling Coordinator who provides transmission service to the Customer's ESP. The Customer's ESP must submit a Direct Access Service Request pursuant to the terms and conditions in Schedule #10.
(CONTINUED ON PAGE 3)
DA-GS1
A.C.C. No. XXXX
ON-SITE GENERATION TERMS AND CONDITIONS
Customers served under this rate schedule who have on-site generation connected to the Company's electrical delivery grid shall enter into an Agreement for Interconnection with the Company which shall establish all pertinent details related to interconnection and other required service standards. The Customer does not have the option to sell power and energy to the Company under this tariff.
CONTRACT PERIOD
0 - 1,999 kW: As provided in Company's standard agreement for service.
2,000 kW and above: Three (3) years, or longer, at Company's option for
initial period when construction is required. One
(1) year, or longer, at Company's option when
construction is not required.
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TERMS AND CONDITIONS
This rate schedule is subject to Company's Terms and Conditions for Standard Offer and Direct Access Service (Schedule #1) and the Company's Schedule #10. These Schedules have provisions that may affect customer's monthly bill.
EXHIBIT A
5/10/99
DA-GS10
ELECTRIC DELIVERY RATES
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. XXXX Phoenix, Arizona Tariff or Schedule No. DA-GS10 Filed by: Alan Propper Original Tariff Title: Director, Pricing and Regulation Effective: XXX XX, 1999 |
DIRECT ACCESS
EXTRA LARGE GENERAL SERVICE
AVAILABILITY
This rate schedule is available in all certificated retail delivery service 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
This rate schedule is applicable to customers receiving electric energy on a direct access basis from any certificated Electric Service Provider (ESP) as defined in A.A.C. R14-2-1603. This rate schedule is applicable only to customers whose monthly maximum demand is 3,000 kW or more for three (3) consecutive months in any continuous twelve (12) month period ending with the current month. Service must be supplied at one point of delivery and measured through one meter unless otherwise specified by individual customer contract. For those customers whose electricity is delivered through more than one meter, service for each meter shall be computed separately under this rate unless conditions in accordance with the Company's Schedule #4 (Totalized Metering of Multiple Service Entrance Sections At a Single Premise for Standard Offer and Direct Access Service) are met.
This rate schedule is not applicable to resale service.
This rate schedule shall become effective as defined in Company's Terms and Conditions for Direct Access (Schedule #10).
TYPE OF SERVICE
Service shall be three phase, 60 Hertz, at Company's standard voltages that are available within the vicinity of customer's premise.
METERING REQUIREMENTS
All customers shall comply with the terms and conditions for hourly metering specified in Schedule #10.
MONTHLY BILL
The monthly bill shall be the greater of the amount computed under A. or B. below, including the applicable Adjustments.
A. RATE
Basic Competitive
Delivery System Transition
Service Distribution Benefits Charge
------- ------------ -------- ------
$/month $2,430.00
per kW $3.53 $2.82
per kWh $0.00999 $0.00115
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PRIMARY AND TRANSMISSION LEVEL SERVICE:
1. For customers served at primary voltage (12.5kV to below 69kV), the Distribution charge will be discounted by 4.8%.
2. For customers served at transmission voltage (69kV or higher), the Distribution charge will be discounted 36.7%.
3. Pursuant to A.A.C. R14-2-1612.K.11, the Company shall retain ownership of Current Transformers (CT's) and Potential Transformers (PT's) for those customers taking service at voltage levels of more than 25 kV. For customers whose metering services are provided by an ESP, a monthly facilities charge will be billed, in addition to all other applicable charges shown above, as determined in the service contract based upon the Company's cost of CT and PT ownership, maintenance and operation.
DETERMINATION OF KW
The kW used for billing purposes shall be the greater of:
1. The kW used for billing purposes shall be the average kW supplied during the 15minute period (or other period as specified by individual customer's contract) of maximum use during the month, as determined from readings of the delivery meter.
2. The minimum kW specified in the agreement for service or individual customer contract.
(CONTINUED ON REVERSE SIDE)
DA-GS10
A.C.C. No. XXXX
B. MINIMUM
$2,430.00 per month plus $1.74 per kW per month.
ADJUSTMENTS
1. When Metering, Meter Reading or Consolidated Billing are provided by the Customer's ESP, the monthly bill will be credited as follows:
Meter $ 55.00 per month Meter Reading $ 0.30 per month Billing $ 0.30 per month |
2. The monthly bill is also 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 service sold and/or the volume of energy delivered or purchased for sale and/or sold hereunder.
SERVICES ACQUIRED FROM CERTIFICATED ELECTRIC SERVICE PROVIDERS
Customers served under this rate schedule are responsible for acquiring their own generation and any other required competitively supplied services from an ESP. T he Company will provide and bill its transmission and ancillary services on rates approved by the Federal Energy Regulatory Commission to the Scheduling Coordinator who provides transmission service to the Customer's ESP. The Customer's ESP must submit a Direct Access Service Request pursuant to the terms and conditions in Schedule #10.
ON-SITE GENERATION TERMS AND CONDITIONS
Customers served under this rate schedule who have on-site generation connected to the Company's electrical delivery grid shall enter into an Agreement for Interconnection with the Company which shall establish all pertinent details related to interconnection and other required service standards. The Customer does not have the option to sell power and energy to the Company under this tariff.
CONTRACT PERIOD
For service locations in:
a) Isolated Areas: Ten (10) years, or longer, at Company's option, with standard seven (7) year termination period.
b) Other Areas: Three (3) years, or longer, at Company's option.
TERMS AND CONDITIONS
This rate schedule is subject to Company's Terms and Conditions for Standard Offer and Direct Access Service (Schedule #1) and the Company's Schedule #10. These schedules have provisions that may affect customer's monthly bill.
EXHIBIT A
5/13/99
DA-GS11
ELECTRIC DELIVERY RATES
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. XXXX
Phoenix, Arizona Tariff or Schedule No. DA-GS11
Filed by: Alan Propper Original Tariff
Title: Director, Pricing and Regulation Effective: XXX XX, 1999
DIRECT ACCESS
RALSTON PURINA
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AVAILABILITY
This rate schedule is available in all certificated retail delivery service 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
This rate schedule is applicable only to Ralston Purina (Site #863970289) when it receives electric energy on a direct access basis from any certificated Electric Service Provider (ESP) as defined in A.A.C. R14-2-1603. Service must be supplied as specified by individual customer contract and the Company's Schedule #4 (Totalized Metering of Multiple Service Entrance Sections At a Single Premise for Standard Offer and Direct Access Service).
This rate schedule is not applicable to resale service.
This rate schedule shall become effective as defined in Company's Terms and Conditions for Direct Access (Schedule #10).
TYPE OF SERVICE
Service shall be three phase, 60 Hertz, at 12.5 kV.
METERING REQUIREMENTS
Customer shall comply with the terms and conditions for hourly metering specified in Schedule #10.
MONTHLY BILL
The monthly bill shall be the greater of the amount computed under A. or B. below, including the applicable Adjustments.
A. RATE
Basic Competitive
Delivery System Transition
Service Distribution Benefits Charge
------- ------------ -------- ------
$/month $2,430.00
per kW $2.58 $1.86
per kWh $0.00732 $0.00115
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DETERMINATION OF KW
The kW used for billing purposes shall be the greater of:
1. The kW used for billing purposes shall be the average kW supplied during the 15minute period (or other period as specified by individual customer's contract) of maximum use during the month, as determined from readings of the delivery meter.
2. The minimum kW specified in the agreement for service or individual customer contract.
B. MINIMUM
$2,430.00 per month plus $1.74 per kW per month.
ADJUSTMENTS
1. When Metering, Meter Reading or Consolidated Billing are provided by the Customer's ESP, the monthly bill will be credited as follows:
Meter $ 55.00 per month Meter Reading $ 0.30 per month Billing $ 0.30 per month |
2. The monthly bill is also 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 service sold and/or the volume of energy delivered or purchased for sale and/or sold hereunder.
(CONTINUED ON REVERSE SIDE)
DA-GS11
A.C.C. No. XXXX
SERVICES ACQUIRED FROM CERTIFICATED ELECTRIC SERVICE PROVIDERS
Customer is responsible for acquiring its own generation and any other required competitively supplied services from an ESP. T he Company will provide and bill its transmission and ancillary services on rates approved by the Federal Energy Regulatory Commission to the Scheduling Coordinator who provides transmission service to the Customer's ESP. The Customer's ESP must submit a Direct Access Service Request pursuant to the terms and conditions in Schedule #10.
ON-SITE GENERATION TERMS AND CONDITIONS
If Customer has on-site generation connected to the Company's electrical delivery grid, it shall enter into an Agreement for Interconnection with the Company which shall establish all pertinent details related to interconnection and other required service standards. The Customer does not have the option to sell power and energy to the Company under this tariff.
TERMS AND CONDITIONS
This rate schedule is subject to Company's Terms and Conditions for Standard Offer and Direct Access Service (Schedule #1) and the Company's Schedule #10. These schedules have provisions that may affect customer's monthly bill.
EXHIBIT A
5/13/99
DA-GS12
ELECTRIC DELIVERY RATES
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. XXXX
Phoenix, Arizona Tariff or Schedule No. DA-GS12
Filed by: Alan Propper Original Tariff
Title: Director, Pricing and Regulation Effective: XXX XX, 1999
DIRECT ACCESS
BHP COPPER
|
AVAILABILITY
This rate schedule is available in all certificated retail delivery service 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
This rate schedule is applicable only to BHP Copper (Site #774932285) when it receives electric energy on a direct access basis from any certificated Electric Service Provider (ESP) as defined in A.A.C. R14-2-1603. Service must be supplied as specified by individual customer contract and the Company's Schedule #4 (Totalized Metering of Multiple Service Entrance Sections At a Single Premise for Standard Offer and Direct Access Service).
This rate schedule is not applicable to resale service.
This rate schedule shall become effective as defined in Company's Terms and Conditions for Direct Access (Schedule #10).
TYPE OF SERVICE
Service shall be three phase, 60 Hertz, at 12.5 kV or higher.
METERING REQUIREMENTS
Customer shall comply with the terms and conditions for hourly metering specified in Schedule #10.
MONTHLY BILL
The monthly bill shall be the greater of the amount computed under A. or B. below, including the applicable Adjustments.
A. RATE
Basic Distribution Distribution Competitive
Delivery at Primary at Transmission System Transition
Service Voltage Voltage Benefits Charge
------- ------- ------- -------- ------
$/month $2,430.00
per kW $2.35 $1.22 $1.54
per kWh $0.00665 $0.00346 $0.00115
|
PRIMARY AND TRANSMISSION LEVEL SERVICE:
Pursuant to A.A.C. R14-2-1612.K.11, the Company shall retain ownership of Current Transformers (CT's) and Potential Transformers (PT's) for those customers taking service at voltage levels of more than 25 kV. For customers whose metering services are provided by an ESP, a monthly facilities charge will be billed, in addition to all other applicable charges shown above, as determined in the service contract based upon the Company's cost of CT and PT ownership, maintenance and operation.
DETERMINATION OF KW
The kW used for billing purposes shall be the greater of:
1. The kW used for billing purposes shall be the average kW supplied during the 30minute period (or other period as specified by individual customer's contract) of maximum use during the month, as determined from readings of the delivery meter.
2. The minimum kW specified in the agreement for service or individual customer contract.
B. MINIMUM
$2,430.00 per month plus $1.74 per kW per month.
(CONTINUED ON REVERSE SIDE)
DA-GS12
A.C.C. No. XXXX
ADJUSTMENTS
1. When Metering, Meter Reading or Consolidated Billing are provided by the Customer's ESP, the monthly bill will be credited as follows:
Meter $ 55.00 per month Meter Reading $ 0.30 per month Billing $ 0.30 per month |
2. The monthly bill is also 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 service sold and/or the volume of energy delivered or purchased for sale and/or sold hereunder.
SERVICES ACQUIRED FROM CERTIFICATED ELECTRIC SERVICE PROVIDERS
Customer is responsible for acquiring its own generation and any other required competitively supplied services from an ESP. T he Company will provide and bill its transmission and ancillary services on rates approved by the Federal Energy Regulatory Commission to the Scheduling Coordinator who provides transmission service to the Customer's ESP. The Customer's ESP must submit a Direct Access Service Request pursuant to the terms and conditions in Schedule #10.
ON-SITE GENERATION TERMS AND CONDITIONS
If Customer has on-site generation connected to the Company's electrical delivery grid, it shall enter into an Agreement for Interconnection with the Company which shall establish all pertinent details related to interconnection and other required service standards. The Customer does not have the option to sell power and energy to the Company under this tariff.
TERMS AND CONDITIONS
This rate schedule is subject to Company's Terms and Conditions for Standard Offer and Direct Access Service (Schedule #1) and the Company's Schedule #10. These schedules have provisions that may affect customer's monthly bill.
EXHIBIT A
5/13/99
DA-GS13
ELECTRIC DELIVERY RATES
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. XXXX
Phoenix, Arizona Tariff or Schedule No. DA-GS13
Filed by: Alan Propper Original Tariff
Title: Director, Pricing and Regulation Effective: XXX XX, 1999
DIRECT ACCESS
CYPRUS BAGDAD
|
AVAILABILITY
This rate schedule is available in all certificated retail delivery service 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
This rate schedule is applicable only to Cyprus Bagdad (Site #120932284) when it receives electric energy on a direct access basis from any certificated Electric Service Provider (ESP) as defined in A.A.C. R14-2-1603. Service must be supplied as specified by individual customer contract and the Company's Schedule #4 (Totalized Metering of Multiple Service Entrance Sections At a Single Premise for Standard Offer and Direct Access Service).
This rate schedule is not applicable to resale service.
This rate schedule shall become effective as defined in Company's Terms and Conditions for Direct Access (Schedule #10).
TYPE OF SERVICE
Service shall be three phase, 60 Hertz, at 115 kV or higher.
METERING REQUIREMENTS
Customer shall comply with the terms and conditions for hourly metering specified in Schedule #10.
MONTHLY BILL
The monthly bill shall be the greater of the amount computed under A. or B. below, including the applicable Adjustments.
A. RATE
Basic Competitive
Delivery System Transition
Service Distribution Benefits Charge
------- ------------ -------- ------
$/month $2,430.00
per kW $1.05 $1.34
per kWh $0.00298 $0.00115
|
PRIMARY AND TRANSMISSION LEVEL SERVICE:
Pursuant to A.A.C. R14-2-1612.K.11, the Company shall retain ownership of Current Transformers (CT's) and Potential Transformers (PT's) for those customers taking service at voltage levels of more than 25 kV. For customers whose metering services are provided by an ESP, a monthly facilities charge will be billed, in addition to all other applicable charges shown above, as determined in the service contract based upon the Company's cost of CT and PT ownership, maintenance and operation.
DETERMINATION OF KW
The kW used for billing purposes shall be the greater of:
1. The kW used for billing purposes shall be the average kW supplied during the 30minute period (or other period as specified by individual customer's contract) of maximum use during the month, as determined from readings of the delivery meter.
2. The minimum kW specified in the agreement for service or individual customer contract.
B. MINIMUM
$2,430.00 per month plus $1.74 per kW per month, until June 30, 2004 when this minimum will no longer be applicable.
(CONTINUED ON REVERSE SIDE)
DA-GS13
A.C.C. No. XXXX
ADJUSTMENTS
1. When Metering, Meter Reading or Consolidated Billing are provided by the Customer's ESP, the monthly bill will be credited as follows:
Meter $ 55.00 per month Meter Reading $ 0.30 per month Billing $ 0.30 per month |
2. The monthly bill is also 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 service sold and/or the volume of energy delivered or purchased for sale and/or sold hereunder.
SERVICES ACQUIRED FROM CERTIFICATED ELECTRIC SERVICE PROVIDERS
Customer is responsible for acquiring its own generation and any other required competitively supplied services from an ESP. T he Company will provide and bill its transmission and ancillary services on rates approved by the Federal Energy Regulatory Commission to the Scheduling Coordinator who provides transmission service to the Customer's ESP. The Customer's ESP must submit a Direct Access Service Request pursuant to the terms and conditions in Schedule #10.
ON-SITE GENERATION TERMS AND CONDITIONS
If Customer has on-site generation connected to the Company's electrical delivery grid, it shall enter into an Agreement for Interconnection with the Company which shall establish all pertinent details related to interconnection and other required service standards. The Customer does not have the option to sell power and energy to the Company under this tariff.
TERMS AND CONDITIONS
This rate schedule is subject to Company's Terms and Conditions for Standard Offer and Direct Access Service (Schedule #1) and the Company's Schedule #10. These schedules have provisions that may affect customer's monthly bill.
ARIZONA PUBLIC SERVICE COMPANY Exhibit A Competitive Transition Charges 5/13/99 By Direct Access Rate Classes Schedule A |
Line Competition Transition Charges Effective January 1 of ---- ------------------------------------------------------------ # Direct Access Rate Class 1999 2000 2001 2002 2003 2004 ---- ------------------------ ---- ---- ---- ---- ---- ---- 1 Residential, DA-R1 (per kWh) $0.0093 $0.0084 $0.0063 $0.0056 $0.0050 $0.0036 2 Under 3 mW, DA-GS1, (per kW/mo.) $ 2.43 $ 2.20 $ 1.66 $ 1.46 $ 1.30 $ 0.94 3 3 mW and Above, DA-GS10 (per kW/mo.) $ 2.82 $ 2.55 $ 1.89 $ 1.72 $ 1.51 $ 1.09 4 BHP Copper (per kW/mo.) $ 1.54 $ 1.53 $ 1.06 $ 0.95 $ 0.83 $ 0.61 5 Cyprus Copper (per kW/mo.) $ 1.34 $ 1.46 $ 1.05 $ 0.94 $ 0.82 $ 0.61 6 Ralston Purina (per kW/mo.) $ 1.86 $ 1.98 $ 1.50 $ 1.34 $ 1.18 $ 0.87 7 Average Retail (per kWh) $0.0067 $0.0061 $0.0054 $0.0048 $0.0043 $0.0031 |
Charges are based upon recovery of $350 million NPV derived from APS' Compliance Filing of 8/21/98 as adjusted to synchronize Direct Access and Standard Offer revenue decreases.
ARIZONA PUBLIC SERVICE COMPANY Exhibit A Distribution Charges 5/13/99 By Direct Access Rate Classes Schedule B |
Distribution Charges Effective January 1 of
Line ------------------------------------------------------------
# Direct Access Rate Class 1999 2000 2001 2002 2003 2004a/
---- ------------------------ ---- ---- ---- ---- ---- ------
RESIDENTIAL, DA-R1
1 Summer per kWh $0.04158 $0.04041 $0.03934 $0.03837 $0.03748 $0.03689
2 Winter per kWh $0.03518 $0.03419 $0.03329 $0.03247 $0.03172 $0.03122
DA-GS1 (UNDER 3 MW)
Summer Rates
3 per kW for all kW over 5 $0.721 $0.691 $ 0.663 $ 0.638 $ 0.615 $ 0.600
4 per kWh for the first 2,500 kWh $0.04255 $0.04075 $0.03912 $0.03763 $0.03627 $0.03537
5 per kWh for the next 100 kWh per kW over 5 $0.04255 $0.04075 $0.03912 $0.03763 $0.03627 $0.03537
6 per kWh for the next 42,000 kWh $0.02901 $0.02779 $0.02667 $0.02565 $0.02473 $0.02411
7 per kWh for all additional kWh $0.01811 $0.01735 $0.01665 $0.01602 $0.01544 $0.01506
Winter Rates
8 per kW for all kW over 5 $0.652 $ 0.624 $ 0.599 $ 0.576 $ 0.555 $ 0.541
9 per kWh for the first 2,500 kWh $0.03827 $0.03666 $0.03519 $0.03385 $0.03263 $0.03182
10 per kWh for the next 100 kWh per kW over 5 $0.03827 $0.03666 $0.03519 $0.03385 $0.03263 $0.03182
11 per kWh for the next 42,000 kWh $0.02600 $0.02490 $0.02390 $0.02299 $0.02216 $0.02161
12 per kWh for all additional kWh $0.01614 $0.01546 $0.01484 $0.01427 $0.01376 $0.01342
Voltage Discounts
13 Primary Voltage 11.6% 12.1% 12.6% 13.1% 13.6% 13.9%
14 Transmission Voltage 52.6% 54.9% 57.2% 59.5% 61.7% 63.3%
DA-GS10 (3 MW AND ABOVE)
15 per kW $ 3.53 $ 3.33 $ 3.15 $ 2.98 $ 2.83 $ 2.73
16 per kWh $0.00999 $0.00943 $0.00892 $0.00845 $0.00802 $0.00774
Voltage Discounts
17 Primary Voltage Discount 4.8% 5.1% 5.3% 5.6% 5.9% 6.2%
18 Transmission Voltage Discount 36.7% 38.9% 41.1% 43.4% 45.8% 47.4%
DA-GS11 (RALSTON PURINA)
19 per kW $ 2.58 $ 2.71 $ 2.57 $ 2.44 $ 2.32 $ 2.25
20 per kWh $0.00732 $0.00767 $0.00727 $0.00691 $0.00657 $0.00635
DA-GS12 (BHP COPPER)
21 Primary Voltage Delivery per kW $ 2.35 $ 2.30 $ 2.16 $ 2.07 $ 1.99 $ 1.93
22 per kWh $0.00665 $0.00651 $0.00611 $0.00585 $0.00561 $0.00546
23 Transmission Voltage Delivery per kW $ 1.22 $ 1.17 $ 1.03 $ 0.94 $ 0.85 $ 0.80
24 per kWh $0.00346 $0.00332 $0.00292 $0.00266 $0.00242 $0.00227
DA-GS13 (CYPRUS BAGDAD)
25 per kW $ 1.05 $ 1.21 $ 1.03 $ 0.94 $ 0.85 $ 0.80
26 per kWh $0.00297 $0.00343 $0.00292 $0.00266 $0.00242 $0.00227
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a/ Transmission voltage customers will not pay Distribution Charges after June 30, 2004
Exhibit A 5/14/99 Schedule C
ARIZONA PUBLIC SERVICE COMPANY
Regulatory Asset Amortization Schedule
(Millions of Dollars)
1/1 - 6/30
1999 2000 2001 2002 2003 2004 1/ Total 2/
---- ---- ---- ---- ---- ------- --------
164 158 145 115 86 18 686
|
1/ Amortization ends 6/30/2004
2/ Includes the disallowance from Section 3.3
Annual ACC Jurisdictional Sales of Delivered kWh or kW X % then eligible for access x Applicable CTC
2 3
(cents/kWh or $/kW ) = Annual Recovery
1999 Residential 20 .93
General Service less than 3MW 20 2.43
General Service greater than 3MW 20 2.82
BHP Copper 20 1.54
Cyprus Copper 20 1.34
Ralston Purina 20 1.86
2000 Residential 20 .84
General Service less than 3MW 20 2.20
General Service greater than 3MW 20 2.55
BHP Copper 20 1.53
Cyprus Copper 20 1.46
Ralston Purina 20 1.98
2001 Residential 100 .63
General Service less than 3MW 100 1.66
General Service greater than 3MW 100 1.89
BHP Copper 100 1.06
Cyprus Copper 100 1.05
Ralston Purina 100 1.50
2002 Residential 100 .56
General Service less than 3MW 100 1.46
General Service greater than 3MW 100 1.72
BHP Copper 100 .95
Cyprus Copper 100 .94
Ralston Purina 100 1.34
2003 Residential 100 .50
General Service less than 3MW 100 1.30
General Service greater than 3MW 100 1.51
BHP Copper 100 .83
Cyprus Copper 100 .82
Ralston Purina 100 1.18
2004 Residential 100 .36
General Service less than 3MW 100 .94
General Service greater than 3MW 100 1.09
BHP Copper 100 .61
Cyprus Copper 100 .61
Ralston Purina 100 .87
----------
|
1 This formula assumes no change in APS' distribution service territory. In the event of any material change (e.g. by purchase, sale, expansion, condemnation, etc.) the formula will be adjusted such that APS receives the same opportunity to recover the agreed upon level of costs.
2 General Service unmetered loads will have a demand calculated for CTC purposes based on contract energy.
3 At the end of 2004 the net present value will be calculated to compare to the $350 million.
5/7/99
EXHIBIT C
Generation assets include, but are not limited to, APS' interest in the following generating stations:
Palo Verde
Four Corners
Navajo
Cholla
Saguaro
Ocotillo
West Phoenix
Yucca
Douglas
Childs
Irving
Including allocated common and general plant, support assets, associated land, fuel supplies and contracts, etc. Generation assets will not include facilities included in APS' FERC transmission rates.
EXHIBIT D
AFFILIATE RULES WAIVERS
R14-2-801(5) and R14-2-803, such that the term "reorganization" does not include, and no Commission approval is required for, corporate restructuring that does not directly involve the utility distribution company ("UDC") in the holding company. For example, the holding company may reorganize, form, buy or sell non-UDC affiliates, acquire or divest interests in non-UDC affiliates, etc., without Commission approval.
R14-2-804(A)
R14-2-805(A) shall apply only to the UDC
R14-2-805(A)(2)
R14-2-805(A)(6)
R14-2-805(A)(9), (10), and (11)
RECISION OF PRIOR COMMISSION ORDERS
Section X.C of the "Cogeneration and Small Power Production Policy" attached to Decision No. 52345 (July 27, 1981) regarding reporting requirements for cogeneration information.
Decision No. 55118 (July 24, 1986) - Page 15, Lines 5-1/2 through 13-1/2; Finding of Fact No. 24 relating to reporting requirements under the abolished PPFAC.
Decision No. 55818 (December 14, 1987) in its entirety. This decision related to APS Schedule 9 (Industrial Development Rate) which was terminated by the Commission in Decision No. 59329 (October 11, 1995).
9th and 10th Ordering Paragraphs of Decision No. 56450 (April 13, 1989) regarding reporting requirements under the abolished PPFAC.
DOCKET NO. E-01345A-98-0473 ET AL.
ATTACHMENT 2
ARIZONA PUBLIC SERVICE COMPANY
Informational Unbundling for Standard Offer Proposed Standard Offer Bill
Sample Summer Bill on Rate E-12 at the Proposed 7/1/99 Rate Level 1.5% Overall Residential Class Decrease
(1.68% decrease in energy charges from 9/1/98 Rate Level)
The following information is proposed to be shown on the customer's monthly bill:
PAGE 1, STANDARD OFFER BILL CALCULATION:
Your total energy usage this month is: 991 kWh
Basic Service Charge $ 7.50
Charge for kWh used 100.09
Regulatory Assessment 0.20
Sales Tax 7.06
-------
TOTAL $114.85
|
PAGE 2, INFORMATIONAL UNBUNDLING:
Your total energy usage for this month is: 991 kWh
Your Standard Offer Bill is (see page 1): $114.85
IF YOU CHOOSE TO RECEIVE COMPETITIVE SERVICES FROM
AN ELECTRIC SERVICE PROVIDER, YOUR APS BILL ON
RATE DA-R1 FOR DELIVERY SERVICE WOULD INCLUDE:
Metering Service: $ 1.30
Meter Reading Service: 0.30
Billing Service: 0.30
Distribution Service: 49.30
System Benefits: 1.14
Competitive Transition Charge: 9.22
Regulatory Assessment: 0.12
Sales Tax: 4.04
------
TOTAL CHARGES FOR APS DELIVERY SERVICE ONLY: $ 65.72
Transmission and Ancillary Services
billed to your Electric Service
Provider: $ 5.09
Generation Services: $ 44.04
-------
Shopping Credit to purchase competitively $ 49.13 or,
supplied Generation and Transmission Service, 4.96 cents/
including any applicable taxes and regulatory kWh
assessments
|
BEFORE THE ARIZONA CORPORATION COMMISSION
CARL J. KUNASEK
CHAIRMAN
JIM IRVIN
COMMISSIONER
WILLIAM A. MUNDELL
COMMISSIONER
IN THE MATTER OF COMPETITION IN THE DOCKET NO. RE-00000C-94-0165
PROVISION OF ELECTRIC SERVICES
THROUGHOUT THE STATE OF ARIZONA. DECISION NO. 61969
OPINION AND ORDER
DATES OF PUBLIC COMMENT HEARINGS: June 14, 17, 21, and 23, 1999
PLACES OF HEARINGS: Phoenix and Tucson, Arizona
PRESIDING OFFICERS: Jane Rodda and Teena Wolfe
IN ATTENDANCE: Carl J. Kunasek, Chairman
Jim Irvin, Commissioner
William A. Mundell, Commissioner
APPEARANCES: Mr. Paul A. Bullis, Chief Counsel,
and Ms. Janet Wagner, Staff
Attorney, Legal Division, on behalf
of the Utilities Division of the
Arizona Corporation Commission.
|
BY THE COMMISSION:
On December 26, 1996, in Decision No. 59943, the Arizona Corporation Commission ("Commission") adopted rules which provided the framework for the introduction of retail electric competition in Arizona. These rules are codified at A.A.C. R14-2-1601 et seq. ("Rules" or "Electric Competition Rules"). Under the Rules adopted in December 1996, competition in the retail electric industry was to be phased-in beginning in January 1999.
The Commission adopted certain modifications to the Electric Competition Rules on an emergency basis on August 10, 1998, in Decision No. 61071 (the "Emergency Rules"). On December 11, 1998, in Decision No. 61272, the Commission adopted the Emergency Rules on a permanent basis. On January 11, 1999, the Commission issued Decision No. 61311 which stayed
1 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
the effectiveness of the Rules and related Decisions, and ordered the Hearing Division to begin consideration of further comment and actions in the Docket. On April 23, 1999, the Commission issued Decision No. 61634, in which the Commission adopted modifications to the Electric Competition Rules ("Revised Rules").
The Revised Rules were published in the Arizona Administrative Register on May 14, 1999. By Procedural Order dated April 21, 1999, public comment sessions were scheduled in Phoenix on June 14, and 23, 1999, and in Tucson on June 17, and 21, 1999. The April 21, 1999 Procedural Order also ordered interested parties to file written comments to the Revised Rules no later than May 14, 1999, and to file responsive comments no later than June 4, 1999. After consideration of the filed written comments and oral comments received in the public comment hearings, the Hearing Division recommends the modification of the Revised Rules as set forth in Appendix A ("Proposed Modifications").
The Proposed Modifications are not substantive. Adoption of the Proposed Modifications will allow the Commission to more effectively implement the restructuring of the retail electric market by providing stakeholders with details of the structure and process of the introduction of competition into Arizona's electric industry.
The Proposed Modifications include the following provisions:
The modifications to R14-2-203 and -209 are clarifications necessitated to conform to the revisions to Article 16 and to clarify who pays charges for meter rereads, respectively.
The modifications to R14-2-1601 provide definitions for "Aggregation" and "Self-Aggregation", "Ancillary Services" and "Public Power Entity" which were needed to clarify terms utilized in the Revised Rules. The definition of Utility Distribution Company ("UDC") was amended to reinstate the word "constructs".
R14-2-1602 is not modified.
The modification of R14-2-1603 clarifies that distribution cooperatives that provide Competitive Services within their distribution service territories do not need to apply for a Certificate of Convenience and Necessity ("CC&N"), and clarifies that applicants affiliated with an Affected
2 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
Utility must demonstrate that they have a Commission-approved Code of Conduct as a requisite of certification.
The modifications to R14-2-1604 clarify that small users are eligible to aggregate their loads and are eligible to participate in the competitive market subject to the limitations of the phase-in period. The proposed modification also provides that a waiting list of residential customers interested in participating in the competitive market be made available to certificated Electric Service Providers upon request.
The modification of R14-2-1605 clarifies that distribution cooperatives providing services within their service territories do not require a CC&N.
The modifications to R14-2-1606 define the term "open market" and further delineate the elements that must be unbundled in the Standard Offer Service tariffs.
There are no proposed modifications to R14-2-1607(Recovery of Standard Cost) or -1608 (System Benefits Charges).
The modification to R14-2-1609 clarifies that the UDC retains the obligation to assure adequate transmission import and distribution capability to meet the needs of all distribution customers within its service territory. The proposed changes were based upon parties' comments that additional guidance regarding a UDC's obligation concerning transmission import capability would be beneficial. The modifications do not alter the obligation established in the Revised Rules.
No change was proposed for R14-2-1610 concerning in-state reciprocity.
In R14-2-1611(C), the word "terms" is changed to "provisions" to avoid confusion about the Commission's obligation concerning the confidentiality of special contracts.
The modifications to R14-2-1612(C) add protections contained in A.R.S. ss.
40-202 regarding the authorization to switch electric providers. In addition,
Section 1612(I) was revised to clarify confusion about the timeframe for
terminating competitive service and returning a customer to Standard Offer
Service. Section 1612(K) was revised slightly to provide that each competitive
point of delivery shall be assigned a Universal Node Identifier and that the
Load-Serving Entity developing the load profile determines if a load is
predictable. Section 1612(N) was revised to provide the
3 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
minimum elements that should appear on every bill.
R14-2-1613 was modified to remove the word "and" from Section 1613(A) and to correct the numbering of section 1613(B).
There is no proposed change to R14-2-1614.
The proposed modifications to R14-2-1615 replace the reference to "meters"
in Section 1615(B) with "Meter Services and Meter Reading Services" and replace
the reference to service territory at the time of these rules with "its
distribution service territory" in section 1615(C). Also, the reference in
Section 1615(C) to the generation cooperative is removed.
The modification to R14-2-1616 clarifies that this section, requiring a Code of Conduct, applies to Affected Utilities, including cooperatives, that plan to offer Competitive Services through an affiliate and also provides minimum guidelines for the content of the required Codes of Conduct. Further, the modification clarifies that the Code of Conduct is subject to Commission approval after a hearing.
The modifications to R14-2-1617 add language to Sections 1617(A) and (B) to clarify that Load-Serving Entities providing either generation service or Standard Offer Service must prepare the consumer information label, and correct a typo in Section 1617(D).
* * * * * * * * * *
Having considered the entire record herein and being fully advised in the premises, the Commission finds, concludes, and orders that:
FINDINGS OF FACT
1. Decision No. 59943 enacted R14-2-1601 through -1616, the Retail Electric
Competition Rules.
2. Decision No. 61071 (August 10, 1998) adopted certain modifications to the Retail Electric Competition Rules and conforming changes to R14-2-203, R14-2-204 and R14-2-208 through R14-2-211 on an emergency basis.
3. Decision No. 61272 (December 11, 1998) adopted the Emergency Rules on a permanent basis, including Staff's additional changes proposed on November 24, 1998.
4 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
4. Decision No. 61311 stayed the effectiveness of the Emergency Rules and related Decisions, and ordered the Hearing Division to conduct further proceedings in this Docket.
5. In Decision No. 61634 (April 23, 1999), the Commission adopted the Revised Rules, which revised R14-2-201 through -207, -210 and -212 and R14-2-1601 through -1617.
6. The Revised Rules and the Economic, Small Business and Consumer Impact Statement were sent to the Secretary of State and published in the Arizona Administrative Register on May 14, 1999.
7. Pursuant to Procedural Order dated April 21, 1999, public comment sessions on the Revised Rules were held in Phoenix on June 14, and 23, 1999, and in Tucson on June 17 and 21, 1999, and interested parties filed written comments to the Revised Rules by May 14, 1999, and filed responsive comments by June 4, 1999.
8. After consideration of the filed written comments and oral comments received in the public comment hearings, the Hearing Division recommended the Proposed Modifications set forth in Appendix A, and incorporated herein by reference. The Proposed Modifications amend R14-2-203 and -209, and R14-2-1601, -1603 through -1606, -1609, -1611 through -1613, and -1615 through -1617.
9. The Concise Explanatory Statement for the Proposed Modifications is set forth in Appendix B, attached hereto and incorporated herein by reference.
10. We believe that in the interest of economic efficiency, transaction processing methods used by market participants should be standardized and coordinated statewide, and that Commission Staff, market participants, and the Residential Utility Consumer Office should participate in a process to achieve the goal of consistent statewide application of transaction processing methods by the time that the Arizona market is open to full retail electric competition. To achieve this goal, a Process Standardization Working Group, coordinated by the Director, Utilities Division or Director's designee, should be formed; and the Process Standardization Working Group should, as soon as practicable, submit a Report to the Commission containing Standardized Operating Procedures to be used by all market participants. The Report should also contain any additional Staff
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recommendations based on the Process Standardization Working Group's review of transaction processing methods.
CONCLUSIONS OF LAW
1. The Commission has the authority for the Proposed Modifications pursuant
to Article XV of the Arizona Constitution and A.R.S. ss.ss. 40-202 , 40-203,
40-250, 40-321, 40-322, 40-331, 40-332, 40-336, 40-361, 40-365, 40-367 and
A.R.S. Title 40, generally.
2. Notice of rulemaking and of the hearing was given in the manner prescribed by law.
3. The Proposed Modifications are not substantive in nature.
4. Adoption of the Proposed Modifications is in the public interest, and should be approved.
5. The Concise Explanatory Statement set forth in Appendix B should be adopted.
6. Formation of a Process Standardization Working Group and submission of a Report as outlined in Findings of Fact No. 10 above will serve the public interest.
ORDER
IT IS THEREFORE ORDERED that A.A.C. R14-2-201 et seq. and R14-2-1601 et seq. as set forth in Appendix A and the Concise Explanatory Statement, as set forth in Appendix B are hereby adopted.
IT IS FURTHER ORDERED that the Commission's Utilities Division shall submit the adopted amended Rules A.A.C. R14-2-201 et seq. and R14-2-1601 et seq. to the Office of the Secretary of State.
IT IS FURTHER ORDERED that within thirty days of the effective date of this Order, a Process Standardization Working Group shall be formed, which shall consist of Commission Staff, market participants, and the Residential Utility Consumer Office; and shall be coordinated by the Director, Utilities Division or the Director's designee.
IT IS FURTHER ORDERED that the Process Standardization Working Group shall meet as necessary to review transaction processing methods used by market participants, for the purpose of standardizing and coordinating those methods.
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IT IS FURTHER ORDERED that on or before June 15, 2000, the Director, Utilities Division, or the Director's designee, shall file with the Commission a Process Standardization Working Group Report, which shall contain Standardized Operating Procedures to be used by all market participants. The Report may also contain additional Staff recommendations based on the Process Standardization Working Group's review of transaction processing methods.
IT IS FURTHER ORDERED that this Decision shall become effective immediately.
BY ORDER OF THE ARIZONA CORPORATION COMMISSION.
IN WITNESS WHEREOF, I, BRIAN C. McNEIL,
Executive Secretary of the Arizona
Corporation Commission, have hereunto set
my hand and caused the official seal of the
Commission to be affixed at the Capitol, in
the City of Phoenix, this 29th day of
September, 1999.
BRIAN C. McNEIL
-------------------------------------------
BRIAN C. McNEIL
EXECUTIVE SECRETARY
DISSENT _________________
JR:dap
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SERVICE LIST FOR: ELECTRIC COMPETITION RULES
DOCKET NO. RE-00000C-94-0165
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Copies mailed to the Service List of RE-00000C-94-0165
Paul A. Bullis, Chief Counsel
LEGAL DIVISION
1200 W. Washington Street
Phoenix, Arizona 85007
Utilities Division Director
ARIZONA CORPORATION COMMISSION
1200 W. Washington Street
Phoenix, Arizona 85007
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APPENDIX A
TITLE 14. PUBLIC SERVICE CORPORATIONS; CORPORATIONS
AND ASSOCIATIONS; SECURITIES REGULATION
CHAPTER 2. CORPORATION COMMISSION - FIXED UTILITIES
ARTICLE 2. ELECTRIC UTILITIES
R14-2-201. Definitions - No Change
R14-2-202. Certificate of Convenience and Necessity for electric utilities;
filing requirements on certain new plants - No Change
R14-2-203. Establishment of service - Modified
R14-2-204. Minimum customer information requirements - No Change
R14-2-205. Master metering - No Change
R14-2-206. Service lines and establishments - No Change
R14-2-207. Line Extensions - No Change
R14-2-208. Provision of service - No Change
R14-2-209 Meter reading - Modified
R14-2-210. Billing and collection - No Change
R14-2-211 Termination of service - No Change
R14-2-212. Administrative and hearing requirements - No Change
R14-2-213 Conservation - No Change
ARTICLE 16. RETAIL ELECTRIC COMPETITION
R14-2-1601. Definitions - Modified
R14-2-1602. Commencement of Competition - No Change
R14-2-1603. Certificates of Convenience and Necessity - Modified
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Competitive Phases - Modified
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R14-2-1605. Competitive Services - Modified
R14-2-1606. Services Required To Be Made Available - Modified
R14-2-1607. Recovery of Stranded Cost of Affected Utilities - No Change
R14-2-1608. System Benefits Charges - No Change
R14-2-1609. Transmission and Distribution Access - Modified
R14-2-1610. In-state Reciprocity - No Change
R14-2-1611. Rates - Modified
R14-2-1612. Service Quality, Consumer Protection, Safety, and Billing
Requirements - modified
R14-2-1613. Reporting Requirements - Modified
R14-2-1614 Administrative Requirements - No Change
R14-2-1615 Separation of Monopoly and Competitive Services - Modified
R14-2-1616. Code of Conduct - Modified
R14-2-1617 Disclosure of Information - Modified
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ARTICLE 2. ELECTRIC UTILITIES
R14-2-201. DEFINITIONS - No change
R14-2-202. CERTIFICATE OF CONVENIENCE AND NECESSITY FOR ELECTRIC UTILITIES;
FILING REQUIREMENTS ON CERTAIN NEW PLANTS - No change
R14-2-203. ESTABLISHMENT OF SERVICE
A. No change.
B. No change.
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C. No change.
D. Service establishments, re-establishments or reconnection charge
1. Each utility may make a charge as approved by the Commission for the establishment, reestablishment, or reconnection of utility services, including transfers between Electric Service Providers.
2. Should service be established during a period other than regular working hours at the customer's request, the customer may be required to pay an after-hour charge for the service connection. Where the utility scheduling will not permit service establishment on the same day requested, the customer can elect to pay the after-hour charge for establishment that day or his service will be established on the next available normal working day.
3. For the purpose of this rule, the definition of service establishments are where the customer's facilities are ready and acceptable to the utility and the utility needs only to install a meter, read a meter, or turn the service on.
4. Service establishments with an Electric Service Provider will be scheduled for the next regular meter read date if the direct access service request is provided 15 calendar days prior to that date and appropriate metering equipment is in place. If a direct access service request is made in less than 15 days prior to the next regular read date, service will be established at the next regular meter read date thereafter. The utility may offer after-hours or earlier service for a fee.
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This section shall not apply to the establishment of new service, but is limited to a change of providers of existing electric service.
E. No change. R14-2-204. MINIMUM CUSTOMER INFORMATION REQUIREMENTS - No change R14-2-205. MASTER METERING - No change R14-2-206. SERVICE LINES AND ESTABLISHMENTS - NO CHANGE R14-2-207. LINE EXTENSIONS - NO CHANGE R14-2-208. PROVISION OF SERVICE - NO CHANGE R14-2-209 METER READING A. No change. |
B. No change.
C. Meter rereads
1. Each utility or Meter Reading Service Provider shall at the request of a customer, or the customer's Electric Service Provider, Utility Distribution Company (as defined in A.A.C. R14-2-1602) or billing entity reread that customer's meter within 10 working days after such a request.
2. Any reread may be charged to the customer, or the customer's Electric Service Provider, Utility Distribution Company (as defined in A.A.C. R14-2-1601) or billing entity making the request at a rate on file and approved by the Commission, provided that the original reading was not in error.
3. When a reading is found to be in error, the reread shall be at no charge to the customer, or the customer's Electric Service Provider, Utility Distribution Company (as defined in A.A.C. R14-2-1601) or billing entity.
D. No change.
E. No change.
F. No change.
R14-2-210. BILLING AND COLLECTION - No change
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R14-2-211 TERMINATION OF SERVICE - No change
R14-2-212. ADMINISTRATIVE AND HEARING REQUIREMENTS - No change
R14-2-213 CONSERVATION - No change
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ARTICLE 16. RETAIL ELECTRIC COMPETITION
R14-2-1601. DEFINITIONS
In this Article, unless the context otherwise requires:
1. "Affected Utilities" means the following public service corporations providing electric service: Tucson Electric Power Company, Arizona Public Service Company, Citizens Utilities Company, Arizona Electric Power Cooperative, Trico Electric Cooperative, Duncan Valley Electric Cooperative, Graham County Electric Cooperative, Mohave Electric Cooperative, Sulphur Springs Valley Electric Cooperative, Navopache Electric Cooperative, Ajo Improvement Company, and Morenci Water and Electric Company.
2. "Aggregator" means an Electric Service Provider that, as part of its business, combines retail electric customers into a purchasing group.
3. "Aggregation means the combination and consolidation of loads of multiple customers.
4. "Ancillary Services" means those services designated as ancillary services in Federal Energy Regulatory Commission Order 888, including the services necessary to support the transmission of electricity from resource to load while maintaining reliable operation of the transmission system in accordance with good utility practice.
5. "Bundled Service" means electric service provided as a package to the consumer including all generation, transmission, distribution, ancillary and other services necessary to deliver and measure useful electric energy and power to consumers.
6. "Competition Transition Charge" (CTC) is a means of recovering Stranded Costs.
7. "Competitive Services" means all aspects of retail electric service except those services
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specifically defined as "Noncompetitive Services" pursuant to R14-2-1601(27) or noncompetitive services as defined by the Federal Energy Regulatory Commission.
8. "Control Area Operator" is the operator of an electric system or systems, bounded by interconnection metering and telemetry, capable of controlling generation to maintain its interchange schedule with other such systems and contributing to frequency regulation of the interconnection.
9. "Consumer Education" is the provision of impartial information to consumers about competition or Competitive and Noncompetitive Services and is distinct from advertising and marketing.
10. "Current Transformer" (CT) is an electrical device used in conjunction with an electric meter to provide a measurement of energy consumption for metering purposes.
11. "Direct Access Service Request" (DASR) means a form that contains all necessary billing and metering information to allow customers to switch electric service providers. This form must be submitted to the Utility Distribution Company by the customer's Electric Service Provider.
12. "Delinquent Accounts" means customer accounts with outstanding past due payment obligations that remain unpaid after the due date.
13. "Distribution Primary Voltage" is voltage as defined under the
Affected Utility's Federal Energy Regulatory Commission (FERC) Open
Access Transmission Tariff, except for Meter Service Providers, for
which Distribution Primary Voltage is voltage at or above 600 volts
(600V) through and including 25 kilovolts (25 kV).
14. "Distribution Service" means the delivery of electricity to a retail consumer through wires, transformers, and other devices that are not classified as transmission services subject to the jurisdiction of the Federal Energy Regulatory Commission; Distribution Service excludes Metering Service, Meter Reading Service, and billing and collection services, as those terms are used herein.
15. "Electronic Data Interchange" (EDI) is the computer-to-computer electronic exchange of business
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documents using standard formats which are recognized both nationally and internationally.
16. "Electric Service Provider" (ESP) means a company supplying, marketing, or brokering at retail any Competitive Services pursuant to a Certificate of Convenience and Necessity.
17. "Electric Service Provider Service Acquisition Agreement" or "Service Acquisition Agreement" means a contract between an Electric Service Provider and a Utility Distribution Company to deliver power to retail end users or between an Electric Service Provider and a Scheduling Coordinator to schedule transmission service.
18. "Generation" means the production of electric power or contract rights to the receipt of wholesale electric power.
19. "Green Pricing" means a program offered by an Electric Service Provider where customers elect to pay a rate premium for electricity generated by renewable resources.
20. "Independent Scheduling Administrator" (ISA) is an entity, independent of transmission owning organizations, intended to facilitate nondiscriminatory retail direct access using the transmission system in Arizona.
21. "Independent System Operator" (ISO) is an independent organization whose objective is to provide nondiscriminatory and open transmission access to the interconnected transmission grid under its jurisdiction, in accordance with the Federal Energy Regulatory Commission principles of independent system operation.
22. "Load Profiling" is a process of estimating a customer's hourly energy consumption based on measurements of similar customers.
23. "Load-Serving Entity" means an Electric Service Provider, Affected Utility or Utility Distribution Company, excluding a Meter Service Provider, and Meter Reading Service Provider.
24. "Meter Reading Service" means all functions related to the collection and storage of consumption data.
25. "Meter Reading Service Provider" (MRSP) means an entity providing Meter Reading Service, as
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that term is defined herein and that reads meters, performs validation, editing, and estimation on raw meter data to create billing-ready meter data; translates billing-ready data to an approved format; posts this data to a server for retrieval by billing agents; manages the server; exchanges data with market participants; and stores meter data for problem resolution.
26. "Meter Service Provider" (MSP) means an entity providing Metering Service, as that term is defined herein.
27. "Metering and Metering Service" means all functions related to measuring electricity consumption.
28. "Must-Run Generating Units" are those local generating units that are required to run to maintain distribution system reliability and to meet load requirements in times of congestion on certain portions of the interconnected transmission grid.
29. "Noncompetitive Services" means Distribution Service, Standard Offer Service, transmission and any ancillary services deemed to be non-competitive by the Federal Energy Regulatory Commission, Must-Run Generating Units services, provision of customer demand and energy data by an Affected Utility or Utility Distribution Company to Electric Service Providers, and those aspects of Metering Service set forth in R14-2-1612(K).
30. "OASIS" is Open Access Same-Time Information System, which is an electronic bulletin board where transmission-related information is posted for all interested parties to access via the Internet to enable parties to engage in transmission transactions.
31. "Operating Reserve" means the generation capability above firm system demand used to provide for regulation, load forecasting error, equipment forced and scheduled outages, and local area protection to provide system reliability.
32. "Potential Transformer" (PT) is an electrical device used to step down primary voltages to 120V for metering purposes.
33. "Provider of Last Resort" means a provider of Standard Offer Service to customers within the
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provider's certificated area whose annual usage is 100,000 kWh or less and who are not buying competitive services.
34. "Public Power Entity" incorporates by reference the definition set forth in A.R.S. ss. 30-801.16.
35. "Retail Electric Customer" means the person or entity in whose name service is rendered.
36. "Scheduling Coordinator" means an entity that provides schedules for power transactions over transmission or distribution systems to the party responsible for the operation and control of the transmission grid, such as a Control Area Operator, Arizona Independent Scheduling Administrator or Independent System Operator.
37. "Self-Aggregation" is the action of a retail electric customer or group of customers who combine their own metered loads into a single purchase block.
38. "Standard Offer Service" means Bundled Service offered by the Affected Utility or Utility Distribution Company to all consumers in the Affected Utility's or Utility Distribution Company's service territory at regulated rates including metering, meter reading, billing and collection services, demand side management services including but not limited to time-of-use, and consumer information services. All components of Standard Offer Service shall be deemed noncompetitive as long as those components are provided in a bundled transaction pursuant to R14-2-1606(A).
39. "Stranded Cost" includes:
a. The verifiable net difference between:
i. The net original cost of all the prudent jurisdictional assets and obligations necessary to furnish electricity (such as generating plants, purchased power contracts, fuel contracts, and regulatory assets), acquired or entered into prior to December 26, 1996, under traditional regulation of Affected Utilities; and
ii. The market value of those assets and obligations directly attributable to the introduction of competition under this Article;
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b. Reasonable costs necessarily incurred by an Affected Utility to effectuate divestiture of its generation assets;
c. Reasonable employee severance and retraining costs necessitated by electric competition, where not otherwise provided; and
d. Other transition and restructuring costs as approved by the Commission as part of the Affected Utility's Stranded Cost determination pursuant to R14-2-1607.
40. "System Benefits" means Commission-approved utility low income, demand side management, Consumer Education, environmental, renewables, long-term public benefit research and development and nuclear fuel disposal and nuclear power plant decommissioning programs, and other programs that may be approved by the Commission from time to time.
41. "Transmission Primary Voltage" is voltage above 25 kV as it relates to metering transformers.
42. "Transmission Service" refers to the transmission of electricity to retail electric customers or to electric distribution facilities and that is so classified by the Federal Energy Regulatory Commission or, to the extent permitted by law, so classified by the Arizona Corporation Commission.
43. "Unbundled Service" means electric service elements provided and priced separately, including, but not limited to, such service elements as generation, transmission, distribution, Must Run Generation, metering, meter reading, billing and collection and ancillary services. Unbundled Service may be sold to consumers or to other Electric Service Providers.
44. "Utility Distribution Company" (UDC) means the electric utility entity regulated by the Commission that operates, constructs and maintains the distribution system for the delivery of power to the end user point of delivery on the distribution system.
45. "Utility Industry Group" (UIG) refers to a utility industry association that establishes national standards for data formats.
46. "Universal Node Identifier" is a unique, permanent, identification number assigned to each service
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delivery point.
R14-2-1602. COMMENCEMENT OF COMPETITION - No change
R14-2-1603. CERTIFICATES OF CONVENIENCE AND NECESSITY
A. Any Electric Service Provider intending to supply Competitive Services shall obtain a Certificate of Convenience and Necessity from the Commission pursuant to this Article. An Affected Utility need not apply for a Certificate of Convenience and Necessity to continue to provide electric service in its service area during the transition period set forth in R14-2-1604. A Utility Distribution Company providing Standard Offer Service, or services authorized in R14-2-1615, after January 1, 2001, need not apply for a Certificate of Convenience and Necessity. All other Affected Utility affiliates created in compliance with R14-2-1615(A) shall be required to apply for appropriate Certificates of Convenience and Necessity.
B. Any company desiring such a Certificate of Convenience and Necessity shall file with the Docket Control Center the required number of copies of an application. In support of the request for a Certificate of Convenience and Necessity, the following information must be provided:
1. A description of the electric services which the applicant intends to offer;
2. The proper name and correct address of the applicant, and
a. The full name of the owner if a sole proprietorship,
b. The full name of each partner if a partnership,
c. A full list of officers and directors if a corporation, or
d. A full list of the members if a limited liability corporation;
3. A tariff for each service to be provided that states the maximum rate and terms and conditions that will apply to the provision of the service;
4. A description of the applicant's technical ability to obtain and deliver electricity if appropriate and to provide any other proposed services;
5. Documentation of the financial capability of the applicant to provide the proposed services, including the most recent income statement and balance sheet, the most recent projected income
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statement, and other pertinent financial information. Audited information shall be provided if available;
6. A description of the form of ownership (for example, partnership, corporation);
7. {For an applicant which is an affiliate of an Affected Utility, a statement of whether the Affected Utility has complied with the requirements of R14-2-1616, including the Commission Decision approving the Code of Conduct, where applicable; and} [An explanation of how the applicant intends to comply with the requirements of R14-2-1616, or a request for waiver or modification thereof with an accompanying justification for any such requested waiver or modification.]
8. Such other information as the Commission or the staff may request.
C. No change.
D. No change.
E. No change.
F. No change.
G. No change.
H. No change.
I. No change.
J. No change.
K. No change.
R14-2-1604. COMPETITIVE PHASES
A. At the date established pursuant to R14-2-1602(A), each Affected Utility shall make available at least 20% of its 1995 system retail peak demand for competitive generation supply on a first-come, first-served basis as further described in this rule. First-come, first-served for the purpose of this rule, shall be determined for non-residential customers by the date and time of an Electric Service Provider's filing of a Direct Access Service Request with the Affected Utility or Utility Distribution Company. The effective date of the Direct Access Service Request must be within 60 days of the filing date of the Direct Access Service Request.
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Residential customer selection will be determined under approved residential phase-in programs as specified in R14-2-1604.
1. All Affected Utility customers with single premise non-coincident peak demand load of 1 MW or greater will be eligible for competitive electric services upon the commencement of competition. Customers meeting this requirement shall be eligible for competitive services until at least 20% of the Affected Utility's 1995 system peak demand is served by competition.
2. Any class of customer may aggregate into a minimum combined load of 1 MW or greater within an Affected Utility's service territory and be eligible for competitive electric services. From the commencement of competition pursuant to R14-2-1602 through December 31, 2000, aggregation of new competitive customers will be allowed until such time as at least 20% of the Affected Utility's 1995 peak demand is served by competitors.
3. Affected Utilities shall notify customers eligible under this subsection of the terms of the subsection no later than 60 days prior to the start of competition within its service territory.
4. {Effective January 1, 2001, all Affected Utility customers irrespective of size will be eligible for Aggregation and Self-Aggregation. Aggregation and Self-Aggregation customers purchasing their electricity and related services at any time after the effective date of these rules must do so from a certificated Electric Service Provider as provided for in these rules.}
B. As part of the minimum 20% of 1995 system peak demand set forth in R14-2-1604(A), each Affected Utility shall reserve a residential phase-in program that provides an increasing minimum percentage of residential customers with access to competitive electric services according to the following schedule:
1. January 1, 1999 1 1/4%
April 1, 1999 2 1/2%
July 1, 1999 3 3/4%
October 1, 1999 5%
January 1, 2000 6 1/4%
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April 1, 2000 7 1/2% July 1, 2000 8 3/4% October 1, 2000 10% |
2. Access to the residential phase-in program will be on a first-come, first-served basis. The Affected Utility shall create and maintain a waiting list to manage the residential phase-in program, {which list shall promptly be made available to any certificated Load-Serving Electric Service Provider upon request.}
3. Residential customers participating in the residential phase-in program shall be permitted to use load profiling to satisfy the requirements for hourly consumption data; however, they may choose other metering options offered by their Electric Service Provider consistent with the Commission's rules on Metering.
4. If not already done, each Affected Utility shall file a residential phase-in program proposal to the Commission for approval by Director, Utilities Division by September 15, 1999. Interested parties will have until September 30, 1999, to comment on any proposal. At a minimum, the residential phase-in program proposal will include specifics concerning the Affected Utility's proposed:
a. Process for customer notification of residential phase-in program;
b. Selection and tracking mechanism for customers based on first-come, first-served method;
c. Customer notification process and other education and information services to be offered;
d. Load Profiling methodology and actual load profiles, if available; and
e. Method for calculation of reserved load.
5. After the commencement of competition pursuant to R15-2-1602, each Affected Utility shall file quarterly residential phase-in program reports within 45 days of the end of each quarter. The 1st such report shall be due within 45 days of the 1st quarter ending after the start
of the phase-in of
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competition for that Affected Utility. The final report due under this rule shall be due within 45 days of the quarter ending December 31, 2002. As a minimum, these quarterly reports shall include:
a. The number of customers and the load currently enrolled in residential phase-in program by Energy Service Provider;
b. The number of customers currently on the waiting list;
c. A description and examples of all customer education programs and other information services including the goals of the education program and a discussion of the effectiveness of the programs; and
d. An overview of comments and survey results from participating residential customers.
6. {Aggregation or Self-Aggregation of residential customers is allowed subject to the limitations of the phase-in percentages in this rule.}
C. No change.
D. No change.
E. No change.
F. No Change
R14-2-1605. COMPETITIVE SERVICES
{Except as provided in R14-2-1615(C)}, Competitive Services shall require a Certificate of Convenience and Necessity and a tariff as described in R14-2-1603. A properly certificated Electric Service Provider may offer Competitive Services under bilateral or multilateral contracts with retail consumers.
R14-2-1606. SERVICES REQUIRED TO BE MADE AVAILABLE
A. No change.
B. After January 1, 2001, power purchased by an investor owned Utility Distribution Company {for Standard Offer Service shall be acquired from the competitive market through prudent, arm's-length transactions, and with at least fifty percent through a competitive bid process.} [to provide Standard Offer Service shall be]
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[acquired through the open market.]
C. Standard Offer Tariffs
1. By July 1, 1999, or pursuant to Commission Order, whichever occurs first, each Affected Utility shall file proposed tariffs to provide Standard Offer Service. Such rates shall not become effective until approved by the Commission. Any rate increase proposed by an Affected Utility or Utility Distribution Company for Standard Offer Service must be fully justified through a rate case proceeding.
2. Standard Offer Service tariffs shall include the following elements, {each of which shall be clearly unbundled and identified in the filed tariffs:}
a. Competitive Services: [Electricity:]
(1) Generation, {which shall include all transaction costs and line losses;}
(2) Competition Transition Charge, {which shall include recovery of generation related regulatory assets;}
(3) {Generation-related billing and collection;} [Must-Run Generating Units]
{(4) Transmission Services;}
{(5) Metering Services;
(6) Meter Reading Services; and
(7) Optional Ancillary Services, which shall include spinning reserve service, supplemental reserve, regulation and frequency response service, and energy imbalance service.}
b. {Non-Competitive Services}: [Delivery]
(1) {Distribution services};
(2) {Required Ancillary services, which shall include scheduling, system control and dispatch service, and reactive supply and voltage control from generation sources service;} [Transmission services]
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(3) {Must-Run Generating Units};[Ancillary services]
{(4) System Benefit Charges; and}
{(5) Distribution-related billing and collection.}
[c. Other:
(1) Metering Service
(2) Meter Reading Service
(3) Billing and collection
d. System Benefits
The Competition Transition Charge shall be included in the Standard Offer Service tariffs for the purpose of clearly showing that portion of Standard Offer Service charges being collected to pay Stranded Cost.]
3. Affected Utilities and Utility Distribution Companies may file proposed revisions to such rates Any rate increase proposed by an Affected Utility or Utility Distribution Company for Standard Offer Service must be fully justified through a rate case proceeding, which may be expedited at the discretion of the Utilities Division Director.
4. Such rates shall reflect the costs of providing the service.
5. Consumers receiving Standard Offer Service are eligible for potential future rate reductions as authorized by the Commission.
6. After January 2, 2001, tariffs for Standard Offer Service shall not include any special discounts or contracts with terms, or any tariff which prevents the customer from accessing a competitive option, other than time-of-use rates, interruptible rates or self-generation deferral rates.
D. {By the effective date of these rules},[July 1, 1999] or pursuant to Commission Order, whichever occurs first, each Affected Utility or Utility Distribution Company shall file an Unbundled Service tariff which shall include a Noncompetitive Services tariff. {The Unbundled Service tariff shall calculate the items listed in R14-2-1602(C)(2)(b) on the same basis as those items are calculated in the Standard Offer Service tariff.}
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E. No change.
F. No change.
G. No change.
H. No change.
I. No change.
R14-2-1607. RECOVERY OF STRANDED COST OF AFFECTED UTILITIES - No Change
R14-2-1608. SYSTEM BENEFITS CHARGES - No Change
R14-2-1609. TRANSMISSION AND DISTRIBUTION ACCESS
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A. No change.
B. Utility Distribution Companies shall retain the obligation to assure that adequate transmission import capability is available to meet the load requirements of all distribution customers within their service areas. {Utility Distribution Companies shall retain the obligation to assure that adequate distribution system capacity is available to meet the load requirements of all distribution customers within their service areas.}
C. No change.
D. No change.
E. The Affected Utilities that own or operate Arizona transmission facilities shall file a proposed Arizona Independent Scheduling Administrator implementation plan with the Commission within 30 days of the Commission's adoption of final rules herein. The implementation plan shall address Arizona Independent Scheduling Administrator governance, incorporation, financing and staffing; the acquisition of physical facilities and staff by the Arizona Independent Scheduling Administrator; the schedule for the phased development of Arizona Independent Scheduling Administrator functionality {and proposed transition to a regional ISO or Regional Transmission Organization;} contingency plans to ensure that critical functionality is in place no later than 3 months following adoption of final rules herein by the Commission; and any other significant issues related to the timely and successful implementation of the Arizona Independent Scheduling Administrator.
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F. No change.
G. No change.
H. No change.
I. No change.
J. No change.
R14-2-1610. IN-STATE RECIPROCITY - No change.
R14-2-1611. RATES
A. No change.
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B. No change.
C. Prior to January 1, 2001, competitively negotiated contracts governed by this Article customized to individual customers which comply with approved tariffs do not require further Commission approval. However, all such contracts whose term is 1 year or more and for service of 1 MW or more must be filed with the Director, Utilities Division as soon as practicable. If a contract does not comply with the provisions of the Load Serving Entity's approved tariffs, it shall not become effective without a Commission order. The {provisions} [terms] of such contracts shall be kept confidential by the Commission.
D. No change.
E. No change.
F. No change.
R14-2-1612. SERVICE QUALITY, CONSUMER PROTECTION, SAFETY, AND BILLING
REQUIREMENTS
A. No change.
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B. No change.
C. No consumer shall be deemed to have changed providers of any service authorized in this Article (including changes from the Affected Utility to another provider) without written authorization by the consumer for service from the new provider. If a consumer is switched to a different ("new") provider without such written authorization, the new provider shall cause service by the previous provider to be
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resumed and the new provider shall bear all costs associated with switching the consumer back to the previous provider. {A new provider who switches a customer without written authorization shall also refund to the retail electricity customer the entire amount of the customer's electricity charges attributable to the electric generation service from the new provider for 3 months, or the period of the unauthorized service, whichever is more.} A Utility Distribution Company {may request the Commission's Consumer Services Section} [has the right] to review or audit written authorizations to assure a customer switch was properly authorized. A written authorization that is obtained by deceit or deceptive practices shall not be deemed a valid written authorization. Electric Service Providers shall submit reports within 30 days of the end of each calendar quarter to the Commission itemizing the direct complaints filed by customers who have had their Electric Service Providers changed without their authorization. Violations of the Commission's rules concerning unauthorized changes of providers may result in penalties, or suspension or revocation of the provider's certificate. {The following requirements and restrictions shall apply to the written authorization form requesting electric service from the new provider:
1. The authorization shall not contain any inducements;
2. The authorization shall be in legible print with clear and plain language confirming the rates, terms, conditions and nature of the service to be provided;
3. The authorization shall not state or suggest that the customer must take action to retain the customer's current electricity supplier;
4. The authorization shall be in the same language as any promotional or inducement materials provided to the retail electric customer; and
5. No box or container may be used to collect entries for sweepstakes or a contest that, at the same time, is used to collect authorization by a retail electric customer to change their electricity supplier or to subscribe to other services.}
D. No change.
E. No change.
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F. No change.
G. No change.
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H. No change.
I. Electric Service Providers shall give at least 5 days notice to their customer [and to the appropriate Utility Distribution Company] of scheduled return to Standard Offer Service.[but that return of that customer to the Standard Offer Service would be at the next regular billing cycle if appropriate metering equipment is in place, and the request is processed 15 calendar days prior to the next regular read date.] {Electric Service Providers shall provide 15 calendar days notice prior to the next scheduled meter read date to the appropriate Utility Distribution Company regarding the intent to terminate a service agreement. Return of that customer to Standard Offer Service will be at the next regular billing cycle if appropriate metering equipment is in place and the request is provided 15 calendar days prior to the next regular meter read date.} Responsibility for charges incurred between the notice and the next scheduled read date shall rest with the Electric Service Provider.
J. No change.
K. Additional Provisions for Metering and Meter Reading Services
1. {When authorized by the consumer, an Electric Service Provider who provides metering or meter reading services pertaining to a particular consumer shall provide appropriate meter reading data via standardized EDI formats to all applicable Electric Service Providers serving that same consumer.}[An Electric Service Provider who provides metering or meter reading services pertaining to a particular consumer shall provide access using EDI formats to meter reading data to other Electric Service Providers serving that same consumer when authorized by the consumer.]
2. Any person or entity relying on metering information provided by an
[another] Electric Service Provider may request a meter test according
to the tariff on file and approved by the Commission. However, if the
meter is found to be in error by more than 3%, no meter testing fee
will be charged.
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3. Each competitive {point of delivery} [customer] shall be assigned a Universal Node Identifier [for each service delivery point] by the Affected Utility or the Utility Distribution Company whose distribution system serves the customer.
4. Unless the Commission grants a specific waiver, all competitive metered and billing data shall be translated into consistent, statewide Electronic Data Interchange (EDI) formats based on standards approved by the Utility Industry Group (UIG) that {shall} [can] be used by the Affected Utility or the Utility Distribution Company and the Electric Service Provider.
5. Unless the Commission grants a specific waiver, an Electronic Data Interchange Format shall be used for all data exchange transactions from the Meter Reading Service Provider to the Electric Service Provider, Utility Distribution Company, and Schedule Coordinator. This data will be transferred via the Internet using a secure sockets layer or other secure electronic media.
6. Minimum metering requirements for competitive customers over 20 kW, or 100,000 kWh annually, should consist of hourly consumption measurement meters or meter systems. Predictable loads will be permitted to use load profiles to satisfy the requirements for hourly consumption data. {The Load-Serving Entity developing the load profile shall determine if a load is predictable.} [The Affected Utility or Electric Service Provider will make the determination if a load is predictable.]
7. Competitive customers with hourly loads of 20 kW (or 100,000 kWh annually) or less, will be permitted to use Load Profiling to satisfy the requirements for hourly consumption data, however, they may choose other metering options offered by their Electric Service Provider consistent with the Commission rules on Metering.
8. Metering equipment ownership will be limited to the Affected Utility, Utility Distribution Company, and the Electric Service Provider or their representative, or the customer, who must obtain the metering equipment through the Affected Utility, Utility Distribution Company or an Electric Service Provider.
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9. Maintenance and servicing of the metering equipment will be limited to the Affected Utility, Utility Distribution Company and the Electric Service Provider or their representative.
10. Distribution primary voltage Current Transformers and Potential Transformers may be owned by the Affected Utility, Utility Distribution Company or the Electric Service Provider or their representative.
11. Transmission primary voltage Current Transformers and Potential Transformers may be owned by the Affected Utility or Utility Distribution Company only.
12. North American Electric Reliability Council recognized holidays will be used in calculating "working days" for meter data timeliness requirements.
13. By May 1, 1999, the Director, Utilities Division shall approve operating procedures be used by the Utility Distribution Companies and the Meter Service Providers for performing work on primary metered customers.
14. By May 1, 1999, the Director, Utilities Division shall approve operating procedures be used by the Meter Reading Service Provider for validating, editing, and estimating metering data.
15. By May 1, 1999, the Director, Utilities Division shall approve performance metering specifications and standards to be used by all entities performing metering.
L. No change.
M. No change.
N. Billing Elements. After the commencement of competition within a service territory pursuant to R14-2-1602, all customer bills, including bills for Standard Offer Service customers within that service territory, will list, at a minimum, the following billing cost elements:
1. {Competitive Services:}[Electricity Costs]
a. Generation, {which shall include generation-related billing and} collection;
b. Competition Transition Charge, and
c. {Transmission and Ancillary Services;} [Fuel or purchased power
adjustor, if applicable]
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d. {Metering Services; and
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e. Meter Reading Services.
2. Non-Competitive Services:} [Delivery costs]
a. Distribution services, {including distribution-related billing and collection, required Ancillary Services and Must-Run Generating Units; and
b. System Benefit Charges.} [Transmission services;]
3. {Regulatory assessments;} and [Other Costs
a. Metering Service,
b. Meter Reading Service,
c. Billing and collection, and
d. System Benefits charge.]
{4. Applicable taxes.}
O. No change.
R14-2-1613. REPORTING REQUIREMENTS
A. Reports covering the following items, as applicable, shall be submitted to the Director, Utilities Division by Affected Utilities or Utility Distribution Companies and all Electric Service Providers granted a Certificate of Convenience and Necessity pursuant to this Article. These reports shall include the following information pertaining to Competitive Service offerings, Unbundled Services, and Standard Offer services in Arizona:
1. Type of services offered;
2. kW and kWh sales to consumers, disaggregated by customer class (for example, residential, commercial, industrial);
3. Revenues from sales by customer class (for example, residential, commercial, industrial);
4. Number of retail customers disaggregated as follows: residential, commercial under 40 kW, commercial 41 to 999 kW, commercial 1000 kW or more, industrial less than 1000 kW, industrial
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1000 kW or more, agricultural (if not included in commercial), and other;
5. Retail kWh sales and revenues disaggregated by term of the contract (less than 1 year, 1 to 4 years, longer than 4 years), and by type of service (for example, firm, interruptible, other);
6. Amount of [and] revenues from each type of Competitive Service, and, if applicable, each type of Noncompetitive Service provided;
7. Value of all assets used to serve Arizona customers and accumulated depreciation;
8. Tabulation of Arizona electric generation plants owned by the Electric Service Provider broken down by generation technology, fuel type, and generation capacity;
9. The number of customers aggregated and the amount of aggregated load;
10. Other data requested by staff or the Commission.
{B.}[A.] Reporting Schedule
1. For the period through December 31, 2003, semi-annual reports shall be due on April 15 (covering the previous period of July through December) and October 15 (covering the previous period of January through June). The 1st such report shall cover the period January 1 through June 30, 1999.
2. For the period after December 31, 2003, annual reports shall be due on April 15 (covering the previous period of January through December). The 1st such report shall cover the period January 1 through December 31, 2004.
C. No change.
D. No change.
E. No change.
F. No change.
G. No change.
R14-2-1614. ADMINISTRATIVE REQUIREMENTS - No change
R14-2-1615. SEPARATION OF MONOPOLY AND COMPETITIVE SERVICES
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A. No change.
B. Beginning January 1, 2001, an Affected Utility or Utility Distribution Company shall not provide Competitive Services. as defined in R14-2-1601.
1. This Section does not preclude an Affected Utility or Utility Distribution Company from billing its own customers for distribution service, or from providing billing services to Electric Service Providers in conjunction with its own billing, or from providing {Meter Services and Meter Reading Services} [meters] for Load Profiled residential customers. Nor does this Section preclude an Affected Utility or Utility Distribution Company from providing billing and collections, Metering and Meter Reading Service as part of the Standard Offer Service tariff to Standard Offer Service customers.
2. This Section does not preclude an Affected Utility or Utility Distribution Company from owning distribution and transmission primary voltage Current Transformers and Potential Transformers.
C. An Electric Distribution Cooperative is not subject to the provisions of R14-2-1615 unless it offers competitive electric services outside of {its distribution service territory.} [the service territory it had as of the effective date of these rules. A Generation Cooperative shall be subject to the same limitations to which its member Distribution Cooperatives are subject.]
R14-2-1616. CODE OF CONDUCT
A. No later than 90 days after adoption of these Rules, each Affected Utility which plans to offer Noncompetitive Services and {which plans to offer} Competitive Services through its competitive electric affiliate shall propose a {Code} [code] of {Conduct} [conduct] to prevent anti-competitive activities. {Each Affected Utility that is an electric cooperative, that plans to offer Noncompetitive Services, and that is a member of any electric cooperative that plans to offer Competitive Services shall also submit a Code of Conduct to prevent anti-competitive activities. All} [The] Codes of Conduct shall be subject to Commission approval {after a hearing.}
B. {The Code of Conduct shall address the following subjects:}
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{1. Appropriate procedures to prevent cross subsidization between the Utility Distribution Company and any competitive affiliates, including but not limited to the maintenance of separate books, records and accounts;
2. Appropriate procedures to ensure that the Utility Distribution Company's competitive affiliate does not have access to confidential utility information that is not also available to other market participants;
3. Appropriate guidelines to limit the joint employment of personnel by both a Utility Distribution Company and its competitive affiliate;
4. Appropriate guidelines to govern the use of the Utility Distribution Company's name or logo by the Utility Distribution Company's competitive affiliate;
5. Appropriate procedures to ensure that the Utility Distribution Company does not give its competitive affiliate any preferential treatment such that other market participants are unfairly disadvantaged or discriminated against;
6. Appropriate policies to eliminate joint advertising, joint marketing, or joint sales by a Utility Distribution Company and its competitive affiliate;
7. Appropriate procedures to govern transactions between a Utility Distribution Company and its competitive affiliate; and
8. Appropriate policies to prevent the Utility Distribution Company and its competitive affiliate from representing that customers will receive better service as a result of the affiliation.
9. Complaints concerning violations of the Code of Conduct shall be processed under the procedures established in R14-2-212.}
R14-2-1617. DISCLOSURE OF INFORMATION
A. Each Load-Serving Entity {providing either generation service or Standard Offer Service shall} prepare a consumer information label that sets forth the following information:
1. Price to be charged for generation services,
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2. Price variability information,
3. Customer service information,
4. Time period to which the reported information applies.
B. Each Load-Serving Entity {providing either generation service or Standard Offer Service} shall provide, upon request, the following information (to the extent reasonably known):
1. Composition of resource portfolio,
2. Fuel mix characteristics of the resource portfolio,
3. Emissions characteristics of the resource portfolio.
C. No change.
D. Each Load-Serving Entity shall include the information disclosure label in
a prominent position in all written marketing materialsspecifically
{targeted} [target] to Arizona. When a Load-Serving Entity advertises in
non-print media, or in written materials not specifically {targeted}
[target] to Arizona, the marketing materials shall indicate that the
Load-Serving Entity shall provide the consumer information label to the
public upon request.
E. No change.
F. No change.
G. No change.
H. No change.
I. No change.
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APPENDIX B
CONCISE EXPLANATORY STATEMENT
I. CHANGES IN THE TEXT OF THE PROPOSED RULES FROM THAT CONTAINED IN DECISION NO. 61634 (PUBLISHED ON MAY 14, 1999, IN THE ARIZONA ADMINISTRATIVE REGISTER).
The following sections have been modified as indicated in the text of the rules set forth in Appendix A hereto, and incorporated herein by reference.
ARTICLE 2 ELECTRIC UTILITIES
R14-2-201 Definitions - No Change
R14-2-202 Certificate of Convenience and Necessity for electric utilities;
filing requirements on certain new plants - No Change
R14-2-203 Establishment of service - Modified
R14-2-204 Minimum customer information requirements - No Change
R14-2-205 Master metering - No Change
R14-2-206 Service lines and establishments - No Change
R14-2-207 Line Extensions - No Change
R14-2-208 Provision of service - No Change
R14-2-209 Meter reading - Modified
R14-2-210 Billing and collection - No Change
R14-2-211 Termination of service - No Change
R14-2-212 Administrative and hearing requirements - No Change
ARTICLE 16. RETAIL ELECTRIC COMPETITION
R14-2-1601 Definitions - Modified
R14-2-1602 Commencement of Competition - No Change
R14-2-1603 Certificates of Convenience and Necessity - Modified
R14-2-1604 Competitive Phases - Modified
R14-2-1605 Competitive Services - Modified
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R14-2-1606 Services Required To Be Made Available - Modified
R14-2-1607 Recovery of Stranded Cost of Affected Utilities - No Change
R14-2-1608 System Benefits Charges - No Change
R14-2-1609 Transmission and Distribution Access - Modified
R14-2-1610 In-state Reciprocity - No Change
R14-2-1611 Rates - Modified
R14-2-1612 Service Quality, Consumer Protection, Safety, and Billing
Requirements - modified
R14-2-1613 Reporting Requirements - Modified
R14-2-1614 Administrative Requirements - No Change
R14-2-1615 Separation of Monopoly and Competitive Services - Modified
R14-2-1616 Code of Conduct - Modified
R14-2-1617 Disclosure of Information - Modified
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II. EVALUATION OF THE ARGUMENTS FOR AND AGAINST THE PROPOSED AMENDMENTS TO THE RULES.
R14-2-203 - ESTABLISHMENT OF SERVICE
203(B)
ISSUE: New West Energy ("NEW") recommended that a provision be added to
Section 203(B)(6) to clarify that deposits for residential and nonresidential
customers would be estimated using average monthly usage for Noncompetitive
Services. The Arizona Corporation Commission ("Commission") Staff ("Staff")
responded that the existing Section already contains the word "estimated" and
argued no change was required.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
ISSUE: Commonwealth Energy Corporation ("Commonwealth") stated that Section 203(B)(9) should be deleted because Utility Distribution Companies ("UDCs") may attempt to dissuade customers from seeking competitive services by claiming customer deposits may be raised if the
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customers are dissatisfied with the alternative provider and return to Standard Offer Service. Staff responded that it is clear that the only reason a UDC can increase a deposit is for the return to Standard Offer Service, which may be more expensive than competitors' service. Staff argued that this provision should motivate customers to choose another Electric Service Provider ("ESP") and not return to Standard Offer Service.
ANALYSIS: This Section allows the deposit to be raised only in proportion to the expected increase in monthly billing, and also requires a refund of the deposit for non-delinquent customers when a customer switches to competitive services. This Section is not anti-competitive and requires no change.
RESOLUTION: No change is necessary.
203(D)(1)
ISSUE: NWE recommended that the language "including transfers between Electric Service Providers" in Section 203(D)(1) be deleted. Staff responded that no change is necessary because the Rules already contemplate a charge for transfers between ESPs.
ANALYSIS: This Section requires Commission approval of such charges. ESPs may object if they believe the amount of such a charge is unreasonable.
RESOLUTION: No change is necessary.
203(D)(4)
ISSUE: The City of Tucson ("Tucson") advocated rewriting Section 203(D)(4) regarding service establishments to clearly set time limits for actions by each party and to avoid incentives to delay processing Direct Access Service Requests ("DASRs") or meter changes.
ANALYSIS: We agree that the language "if the direct access service request is processed 15 calendar days prior to that date" does not provide a sufficiently clear time limit, and does not avoid incentives to delay processing DASRs. As explained in our analysis of Section 1612(I), whether appropriate metering equipment is in place is an important concern in some circumstances, and that language should remain unchanged.
RESOLUTION: Modify the first sentence of this Section as follows:
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Service establishments with an Electric Service Provider will be scheduled for the next regular meter read date if the direct access service request is PROVIDED 15 calendar days prior to that date and appropriate metering equipment is in place.
Such change merely clarifies the intent of this provision and is not substantive.
R14-2-204 - MINIMUM CUSTOMER INFORMATION REQUIREMENTS
ISSUE: Arizona Consumers Council ("AZCC") objected to the language in this
Section on the grounds that an ESP might sign consumers up for new service
without being obligated to provide adequate information regarding the offered
services.
ANALYSIS: Our modification to Section 1612(C) addresses this concern by requiring that the written authorization to switch providers confirm the rates, terms, conditions and nature of the service to be provided. This Section requires Load-Serving Entities to provide further information to residential consumers who request it.
RESOLUTION: No change is required.
R14-2-205 - MASTER METERING
ISSUE: In late-filed comments, the Arizona Multihousing Association ("AMA") advocated for the deletion of Section 205(B) which limits master metering for newly constructed apartment complexes. The AMA asserted that the prohibition was counterproductive to achieving the critical mass necessary to benefit from aggregation. AMA also recommended that the issue of aggregation be clarified.
ANALYSIS: The AMA raised this issue for the first time very late in the rule revision process and other parties have not had opportunity to respond. We do not believe revision of this existing rule is warranted, especially without input from other parties. We believe that at least some of AMA's concerns are addressed by our clarifications to the process of aggregation in Section 1604.
RESOLUTION: No change is required.
R14-2-209 - METER READING
ISSUE: The AZCC raised a concern that under this Section a customer may be charged for a meter re-read when the customer had nothing to do with the request for a re-read.
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ANALYSIS: Section 209(C)(1) provides that a customer, ESP, UDC, or billing entity may request a re-read of a meter. Section 209(C)(2) provides that a re-read may be charged to the customer, ESP, UDC or billing entity at the tariff rate. It is implicit in this Section that the requesting party will be the party to be charged. However, we will modify this Section to clarify that it is the requesting party that may be charged for the re-read.
Such modification merely clarifies this provision and is not substantive.
RESOLUTION: Insert "MAKING THE REQUEST" after "or billing entity" in
Section 209(C)(2).
R14-2-210 - BILLING AND COLLECTION
210(A)
ISSUE: Tucson Electric Power Company ("TEP") recommended deleting Section 210(A)(5)(c) which prohibits estimated bills for direct access customers requiring load data because the utility or billing entity has the ability to do it and such bills can be estimated in accordance with Sections 209(A)(8) and 1612(K)(14). Staff responded that as a general rule, direct access customers' bills should not be estimated, and argued against changing this provision.
ANALYSIS:. We concur with Staff.
RESOLUTION: No change is necessary.
ISSUE: NWE states that the terms "utility" and "customer" are not defined in Section 210(A)(2). Staff noted that these terms are defined in Section 201.
ANALYSIS: The definitions in Section 201 are sufficient.
RESOLUTION: No change is necessary.
ISSUE: NWE states that the rules for estimated meter readings should be developed by the working group and should not be included in Sections 210(A)(3) through (6). Staff stated that this Section sets forth conditions which the working groups have previously developed and therefore no change is warranted.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
210(C-I)
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ISSUE: NWE states that Sections 210(C) through (I) should be stricken in their entirety because it believes they do not apply to ESPs, and that to the extent they apply to UDCs, they should be covered by the UDCs' tariffs. Staff responded that these rules apply to UDCs and ESPs.
ANALYSIS: As the term "utility" is defined in Section 201, these Sections apply to both UDCs and ESPs. It is preferable that the issues covered in these Sections be prescribed by general rule rather than be provided in individual tariffs.
RESOLUTION: No change is necessary.
R14-2-211 - TERMINATION OF SERVICE
ISSUE: Commonwealth recommended the deletion of the opening sentences in Sections 211(B) and (C), which prohibit an ESP from ordering disconnection of service for nonpayment. Staff responded that ESPs can terminate service to customers for nonpayment through terminating their contract with customers.
ANALYSIS: This Section does not preclude an ESP from terminating a contract for nonpayment. Commonwealth's concerns about its ability to terminate contracts expediently are addressed by our revisions to Section 1612(I).
RESOLUTION: No change required.
R14-2-213 - CONSERVATION
ISSUE: TEP proposed deleting this Section because it is premature; the issue will be addressed when revisiting the Resource Planning Rules; it should apply to all utilities and ESPs; and it should be delayed until there is 100 percent statewide competition. Staff responded that this rule has been in effect for several years and there is no justification for deleting it at this time.
ANALYSIS: We remain unconvinced that a change in this provision is warranted.
RECOMMENDATION: No change is necessary.
R14-2-1601 - DEFINITIONS
1601(2) "AGGREGATOR"
ISSUE: The Land and Water Fund of the Rockies and the Grand Canyon Trust (collectively, the "LAW Fund") and the AZCC expressed concern that the Rules do not sufficiently encourage
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aggregation of smaller users. Commonwealth concurred. The Arizona Transmission Dependent Utility Group ("ATDUG") suggested deleting the term "Aggregator" and adding a new definition of "Aggregation." Staff responded that the definition of "Aggregator" was placed in the Rules, as originally drafted, to address businesses that choose to provide "aggregation" as an electric service to customers. Staff noted that apparently, that definition has created confusion, causing some to believe that in order for a group of customers to combine or "aggregate" their load, they would have to become an ESP. Staff stated that was not the intent of the Rule as originally drafted. Staff noted that in addition, there have been questions raised about whether residential customers are able to aggregate their load, either through self-aggregation or through the services of an Aggregator. Staff believed that clarification of this issue would be helpful. Staff therefore proposed new language to clarify that only entities which perform aggregation services as part of their business are required to obtain ESP certification; to provide new definitions of "Aggregation" and "Self-Aggregation"; to clarify that residential customers may also aggregate or self-aggregate their loads, subject to the phase-in percentage limitations; and to clarify that eligible residential and non-residential customers may be aggregated together. Staff proposed the following new definition of "Aggregator":
"2. `AGGREGATOR' MEANS AN ELECTRIC SERVICE PROVIDER THAT, AS PART OF ITS
BUSINESS, COMBINES RETAIL ELECTRIC CUSTOMERS INTO A PURCHASING GROUP."
Staff also suggested a new definition of "Aggregation" similar to that suggested by ATDUG:
"3. `AGGREGATION' MEANS THE COMBINATION AND CONSOLIDATION OF LOADS OF
MULTIPLE CUSTOMERS."
Staff proposed that a revised version of the definition of "Self-Aggregation" be included in the Rules:
"SELF-AGGREGATION IS THE ACTION OF A RETAIL ELECTRIC CUSTOMER OR GROUP OF CUSTOMERS WHO COMBINE THEIR OWN METERED LOADS INTO A SINGLE PURCHASE BLOCK."
In addition, Staff proposed additional clarifying modifications to Sections 1604(A)(2) and (4) and 1604(B)(6) concerning aggregation and self-aggregation, which are discussed in our analysis of those Sections.
ANALYSIS: Staff's recommended modifications to this Section are not substantive, but provide clarity and should be adopted.
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RESOLUTION: Modify Section 1601 in accordance with Staff's recommendations and renumber accordingly.
1601(3) "ANCILLARY SERVICES"
ISSUE: Staff noted that although the Proposed Rules contain several references to the term "Ancillary Services," they do not include a definition for that term, and suggested that the following definition be added to the Rules:
"ANCILLARY SERVICES" MEANS THOSE SERVICES DESIGNATED AS ANCILLARY SERVICES IN FEDERAL ENERGY REGULATORY COMMISSION ORDER 888, INCLUDING THE SERVICES NECESSARY TO SUPPORT THE TRANSMISSION OF ELECTRICITY FROM RESOURCE TO LOAD WHILE MAINTAINING RELIABLE OPERATION OF THE TRANSMISSION SYSTEM IN ACCORDANCE WITH GOOD UTILITY PRACTICE.
ANALYSIS: The proposed definition provides clarity and is not a substantive change to the Rules.
RESOLUTION: Add the definition as proposed and renumber accordingly.
1601(5) - COMPETITIVE SERVICES
ISSUE: Arizona Public Service Company ("APS") argued that the Commission should not define "Competitive Services" simply by negative reference to another definition because it is vague. APS proposed that the definition of "Competitive Services" should be replaced with the following:
5. "Competitive Services" means RETAIL ELECTRIC GENERATION, METER SERVICE
(OTHER THAN THOSE ASPECTS OF METER SERVICE DESCRIBED IN R14-2-1612(K)),
METER READING SERVICE, AND BILLING AND COLLECTION FOR SUCH SERVICES (OTHER
THAN JOINT OR CONSOLIDATED BILLING PROVIDED PURSUANT TO A TARIFF). IT DOES
NOT INCLUDE STANDARD OFFER SERVICE OR ANY OTHER ELECTRIC SERVICE DEFINED BY
THIS ARTICLE AS NONCOMPETITIVE. [all aspects of retail electric service
except those services specifically defined as "Noncompetitive Services"
pursuant to R14-2-1601(27) or noncompetitive services as defined by the
Federal Energy Regulatory Commission.]
Arizona Electric Power Cooperative, Inc., Duncan Valley Electric Cooperative, Inc. and Graham County Electric Cooperative, Inc. ("AEPCO, Duncan and Graham") supported APS' modification of the definition. Commonwealth and Arizonans for Electric Choice and Competition ("AECC") opposed APS' proposal. In its responsive comments, Staff noted that Competitive and Noncompetitive Services as defined by the Rules are mutually exclusive, and argued that APS appears to be attempting to create a third category of services: Competitive Services that may be provided by Affected Utilities or Utility Distribution Companies. Staff believed that the existing
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definition is sufficiently clear, and maintains the proper distinction between services that may be provided by Affected Utilities or UDCs, and those services that may not.
ANALYSIS: APS' proposal could narrow the competitive environment by excluding other energy-related services. The distinction between Competitive and Noncompetitive Services is sufficiently clear without modification.
RESOLUTION: No change is required.
1601(4) "COMPETITION TRANSITION CHARGE"
ISSUE: Navopache Electric Cooperative, Inc. ("Navopache") and Mohave Electric Cooperative, Inc. ("Mohave") commented that the definition of Competition Transition Charge ("CTC") should include costs incurred by the Affected Utilities in implementing these Rules. Navopache and Mohave argued that these costs would not be incurred but for customers electing to switch to competitive providers, and therefore customers who switch should bear the associated costs, rather than the customers who remain on Standard Offer Service.
Staff stated that because many of Navopache's and Mohave's concerns are already addressed by the proposed modification to the definition of Stranded Cost to include "other transition and restructuring costs," it is unnecessary to make the modification Navopache and Mohave recommend.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is required.
1601(13) (NEWLY PROPOSED) "ECONOMIC DEVELOPMENT TARIFFS"
ISSUE: Staff proposed to add a new definition for "Economic Development Tariffs" as "those discounted tariffs used to attract new business expansions in Arizona" to comport with its recommendation to add language to Section 1606(C)(6), referring to "economic development tariffs that clearly mitigate Stranded Costs."
ANALYSIS: As explained in our discussion under Section 1606(C) below, due to insufficient evidence in the record to support the implementation of the proposed "Economic Development Tariff", we will not revise Section 1606(C) as proposed by Staff at this time. Therefore, this proposed definition is not needed.
RESOLUTION: No change is required.
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1601(15) "ELECTRIC SERVICE PROVIDER SERVICE ACQUISITION AGREEMENT"
ISSUE: NWE recommends that the Electric Service Provider Service Acquisition Agreement be a standardized, Commission-approved agreement between an Affected Utility and an ESP because NWE believes that the rule as written creates an uncertain process that may deter potential ESPs from competing in Arizona. NWE also argues that a standardized, Commission-approved agreement is the most efficient mechanism for controlling the technical and financial viability of competitors. Commonwealth supported the approach of a Commission pre-approved agreement for all service areas.
Staff stated it agreed with the Commission's conclusion in Decision No. 61634 on this issue, that the certification process is not overly burdensome or anti-competitive.
ANALYSIS: We believe that the certification process as currently structured is not such an uncertain or burdensome process as to deter potential ESPs from competing in Arizona, and that the current process provides adequate oversight of ESPs' technical and financial viability.
RESOLUTION: No change is required.
1601(27) "NONCOMPETITIVE SERVICES"
ISSUE: Navopache and Mohave argued that it is necessary for customer-owned distribution cooperatives to maintain the relationships and communications links with their members/owners for membership, voting and other purposes. To achieve that goal, Navopache and Mohave recommended that the definition of Noncompetitive Services be modified to state that metering, meter ownership, meter reading, billing, collections and information services are deemed to be Noncompetitive Services in the service territories of the distribution cooperatives.
Staff responded that the provisions of Section 1615(B)(1) allow distribution cooperatives to maintain sufficient links with their members/owners.
ANALYSIS: We agree with Staff that Section 1615(B)(1) explicitly allows an Affected Utility or UDC to bill its own customers for distribution service and to provide billing services to ESPs in conjunction with its own billing, and also allows an Affected Utility or UDC to provide billing and collections, Metering and Meter Reading Service as part of its Standard Offer Service tariff to Standard Offer Service customers.
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RESOLUTION: No change is required.
ISSUE: ATDUG suggested that the definition of Noncompetitive Services should be amended to add "Aggregation Service."
ANALYSIS: Although the actual delivery of electricity sold to aggregated customers will be a Noncompetitive Service, there is no reason to differentiate the generation services provided to aggregated customers from generation services provided to non-aggregated customers. Both aggregated and non-aggregated competitive generation services should remain classified as Competitive Services.
RESOLUTION: No change is required.
ISSUE: Commonwealth asserted that ESPs should not have to pay the utility for customer data when the customer requests its release. Commonwealth recommended that the definition of Noncompetitive Services should be amended by deleting "provision of customer demand and energy data by an Affected Utility or Utility Distribution Company to an Electric Service Provider" so that the utility cannot impose a charge on these services. Alternatively, Commonwealth argued that the Rules should provide that the data will be provided to the customer (or its authorized representative) at no charge.
ANALYSIS: Because customers who switch providers will be the "cost-causers," it is appropriate that they should bear the administrative costs associated with switching providers. We share Commonwealth's concern, however, that such charges may be prohibitively high and discourage new market entrants. As this will be a tariffed item, the Commission will oversee the reasonableness of such a charge. If an ESP finds the tariffed charge unreasonable, the ESP is free to protest the tariff.
RESOLUTION: No change is required.
1601(28) (FORMER) "NET METERING OR NET BILLING"
ISSUE: Tucson recommended not deleting the definition of Net Metering or Net Billing from the Rules, as the potential for customer-sited generation using any sort of generation is still possible, even if not mandated. Tucson recommended striking the word "solar electric" from the definition.
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ANALYSIS: The terms "Net Metering or Net Billing" are not referenced in the Rules and consequently, their inclusion in the definitions is not necessary and could be confusing.
RESOLUTION: No change is required.
1601 (34) (NEWLY PROPOSED) "PUBLIC POWER ENTITY"
ISSUE: Staff noted that although the Rules have added the term "Public Power Entity" they do not include a definition for that term. Staff recommend that the definition parallel that set forth by the legislature in A.R.S. ss. 30-801.16. Trico Electric Cooperative ("Trico") and Commonwealth concurred.
ANALYSIS: This definition is needed because prior revisions of Section 1610 introduced this term, however, the change is not substantive.
RESOLUTION: Add the following definition to Section 1601 and renumber
accordingly: "`PUBLIC POWER ENTITY' INCORPORATES BY REFERENCE THE DEFINITION SET
FORTH IN A.R.S. SS. 30-801.16."
1601(35) "STRANDED COST"
ISSUE: TEP argued that the Proposed Rules' replacement of the word "value" with "net original cost" is not appropriate because the new term may be inconsistent with assets held under lease arrangements and with various regulatory assets. AECC disagreed with TEP. Staff responded that it concurs with the change made in Decision No. 61634 to replace "value" with "net original cost," and that this language will not preclude TEP from seeking what it believes to be an appropriate level of recovery for its Stranded Costs.
Trico recommended adding "and distribution assets" after "regulatory assets" in Section 1601(35)(a)(i), because distribution electric public service corporations are also entitled to recover their Stranded Costs. ATDUG and Commonwealth responded to Trico's recommendation by questioning how distribution assets could be considered "stranded" since they remain with the regulated entity. Staff responded that due to the difficulty in calculating distribution cooperatives' Stranded Costs prior to competition, it is more appropriate to deal with those costs in rate cases for distribution electric public service corporations. Staff therefore recommends that the definition of Stranded Costs not be changed.
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ANALYSIS: We concur with Staff that the term "net original cost" will not preclude TEP from recovering appropriate Stranded Costs. We also concur that the recovery of costs related to distribution assets are appropriately handled in a rate case.
RESOLUTION: No change is necessary.
1601(36) "SYSTEM BENEFITS"
ISSUE: NWE states that the definition of "System Benefits" is "vague and fails to specify who will determine what specific costs qualify as System Benefits." Staff responded that it believes that testimony on System Benefit charges will be taken in the Stranded Cost and Unbundled Tariff hearings that will commence in August 1999, and that based on that testimony, the Commission will determine the specific costs to be included in the System Benefits Charges in the Decisions rendered in those proceedings. Staff therefore believes that no change to this definition is necessary.
TEP recommended that non-nuclear plant decommissioning costs be included in the System Benefits charge because generating plants other than nuclear will also have decommissioning costs in the future. AEPCO, Duncan and Graham supported and Commonwealth opposed TEP's suggestion. Staff asserted that non-nuclear decommissioning costs should not be included in System Benefits, for two reasons. First, nuclear decommissioning costs are already being collected in rates, in part because nuclear utilities are required by the Nuclear Regulatory Commission to begin accumulating funds for decommissioning while the nuclear plants are operating. This is not the case with non-nuclear facilities. Staff pointed out that in addition, nuclear decommissioning costs are of such a great magnitude that it is reasonable to attempt to spread them over the operating life of the plant, but that it is unlikely that the costs to decommission non-nuclear plants will be as large.
ANALYSIS: We concur with Staff's reasoning.
RESOLUTION: No change is necessary.
1601(40) "UTILITY DISTRIBUTION COMPANY"
ISSUE: The Arizona State Association of Electrical Workers ("ASAEW") urged the Commission to insert the word "constructs" as part of the definition of a Utility Distribution Company so that the definition would include an entity that "operates, CONSTRUCTS and maintains the distribution system . . . ." TEP also argued for the inclusion of the word "constructs" in the definition
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because it will be the responsibility of the UDC to construct the transmission and distribution systems to ensure consistent, safe and reliable service. Staff agrees that "construction" is an integral part of the provision of electrical distribution service, and recommends adoption of TEP and ASAEW's recommendation.
ANALYSIS: We concur with ASAEW, TEP and Staff. This is not a substantive change.
RESOLUTION: Add the word "constructs" after "operates" in the definition of "Utility Distribution Company."
R14-2-1602 "COMMENCEMENT OF COMPETITION"
ISSUE: AEPCO proposed that statewide competition commence at the same time,
subject to the phase-in schedule in Section 1604. Commonwealth made a proposal
that full competition commence immediately upon the conclusion of the scheduled
Stranded Cost/Unbundling proceeding. Staff believes that both proposals would
delay the commencement of competition until all the Stranded Cost/Unbundling
proceedings are concluded, rather than bringing the benefits of competition to
the citizens of Arizona as quickly as possible at the conclusion of each
Affected Utility's proceedings, and that further, phasing in competition under
Section 1604 establishes a workable timetable to implement competition to
various customer classes. APS argued that at this date, the Commission should
not make additional adjustments to start dates or phase-in schedules.
ANALYSIS: We believe that the current timetable for bringing competition to the state is an expeditious and achievable means of implementing competition.
RESOLUTION: No change is required.
R14-2-1603 "CERTIFICATES OF CONVENIENCE AND NECESSITY"
1603(A)
ISSUE: AEPCO, Duncan and Graham proposed modifying the third sentence of
Section 1603(A) as follows:
A Utility Distribution Company providing Standard Offer Service OR SERVICES AUTHORIZED IN R14-2-1615 after January 1, 2001 need not apply for a Certificate of Convenience and Necessity.
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Staff agreed with AEPCO that this change is needed to remedy the conflict between Sections 1603 and 1605 which might result if one were to conclude that a distribution cooperative needs to acquire a new Certificate of Convenience and Necessity ("CC&N") to provide competitive services pursuant to Section 1615.
ANALYSIS: We concur that this clarification is needed. The change is not substantive.
RESOLUTION: Amend Section 1603(A) as recommended by AEPCO, Duncan, and Graham.
1603(B)
ISSUE: Arizona Community Action Association ("ACAA") proposes to insert new language in R14-2-1603(B)(1). The new language would require the CC&N applicant to provide information as follows:
1. A description of the electric services which the applicant intends to offer; including a plan to enroll and serve at least 15% of the total residential consumers eligible on October 1, 2000;
Staff responded that although it understands that ACAA's goal in making this proposal is to encourage an equitable and robust market, this proposal directly conflicts with efforts to develop a competitive market that will attract the maximum number of potential provider applicants. Staff further commented that if implemented, this proposal might in fact discourage some competitors from entering the Arizona market, and therefore would not serve the public interest.
ANALYSIS: We agree with Staff that requiring competitive ESPs to provide services to the residential market as a prerequisite to being allowed entry to the industrial and commercial markets may impede, rather than encourage the development of a truly competitive market and therefore would not serve the public interest.
RESOLUTION: No change is necessary.
1603(B)(3-6)
ISSUE: NWE recommended that Section 1603(B)(3), which requires the CC&N applicant to file a tariff for each service to be provided, be modified in the following manner:
3. A tariff for each service to be provided that states the [maximum rate and] terms and conditions that will apply to the provision of the service.
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NWE believes this change would be appropriate because Section 1611(A) deems market rates just and reasonable, and market forces may cause an ESP's rate to temporarily surpass its filed maximum rate. NWE requested that if maximum rates must be filed with the Commission, the Commission should clarify that those maximum rates are deemed approved when the Commission grants a CC&N. NWE claims that items (4), (5), (6), and (8) relating to CC&N application information concerning the applicant's technical ability, financial capability, description of form of ownership, and requiring any other information the Commission or Staff may request are vague and should be deleted. Staff stated that Section 1603(B)(3)'s requirement that maximum rates be filed should remain intact because it is necessary for the Commission to have this information in order to fulfill its constitutional responsibility to evaluate the service rates of public service utilities. Staff also stated that the information required in items (4), (5), (6), and (8) are consistent with requirements for CC&Ns for other services regulated by the Commission, that CC&N and certification authority is required not only by Commission rules but by HB2663, and that the specifics of what the Commission means by technical capability, financial capability, and other information is obvious in the CC&N application form.
ANALYSIS: We concur with Staff. It is in the public interest to have maximum rates and the other information included in the CC&N application as required by Section 1603(B)(3-6) and (8) for the Commission to evaluate in the course of considering the CC&N application. Approval of a CC&N application that includes maximum rates in the tariff required by Section 1603(B)(3) constitutes approval of those maximum rates, unless the Order approving the application conditions approval upon the filing of different maximum rates.
RESOLUTION: No change is required.
1603(B)(7)
ISSUE: NWE suggested the following change:
7. An explanation of how AN APPLICANT WHICH IS AN AFFILIATE OF AN AFFECTED UTILITY [the applicant] intends to comply with the requirements of R14-2-1616, or a request for waiver or modification thereof with an accompanying justification for any such requested waiver or modification.
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Staff agrees with NWE that Section 1603(B)(7) should be modified to reflect the
fact that Section 1616 by its terms applies only to Affected Utilities planning
to provide Competitive Services through a competitive electric affiliate, and
that the applicant which is an affiliate of an Affected Utility should be
required to provide a statement of whether the Affected Utility has complied
with the requirements of Section 1616. Staff therefore recommended replacing
Section 1603(B)(7) in its entirety with the following:
7. FOR AN APPLICANT WHICH IS AN AFFILIATE OF AN AFFECTED UTILITY, A STATEMENT OF WHETHER THE AFFECTED UTILITY HAS COMPLIED WITH THE REQUIREMENTS OF R14-2-1616, INCLUDING THE COMMISSION DECISION NUMBER APPROVING THE CODE OF CONDUCT, WHERE APPLICABLE.
ANALYSIS: We concur with Staff. It is in the public interest for entities that are required to have an approved Code of Conduct to be required to demonstrate compliance with this requirement as part of the certification process. This modification is not substantive.
RESOLUTION: Modify Section 1603(B)(7) as recommended by Staff.
1603(E)
ISSUE: NWE proposed to delete the entire Section concerning the requirement of the CC&N applicant to provide notice of its application to each of the respective Affected Utilities, Utility Distribution Companies or an electric utility not subject to the jurisdiction of the Commission in whose service territories it wishes to offer service. NWE claims that this provision protects the Affected Utilities' market share and invites unfair business practices. Staff responded that proper notice is required for any CC&N application.
ANALYSIS: This formal notice requirement is not unduly burdensome to new CC&N applicants, who, in order to serve their customers, must establish a working relationship with the UDCs. It is in the public interest to insure that the CC&N applicant provides proper notice.
RESOLUTION: No change is necessary.
1603(F)
ISSUE: NWE proposes to delete this Section which states that the Commission may issue a CC&N for a specific period of time. NWE feels this provision would add a further obstacle to market entry by some ESPs and would deter some entrants from competing in Arizona. NWE feels that the
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necessary security provisions can be efficiently achieved through an ESP Service Agreement in lieu of this provision. Staff responded that this Section is necessary to provide the Commission with needed flexibility in certificating ESPs who have little or no experience, and that an ESP certificated under this provision may apply for an extension of the effectiveness the CC&N.
ANALYSIS: Instead of creating an obstacle to market entry by ESPs with little or no experience, this provision allows the Commission to provisionally certificate such companies, and thus is pro-competitive.
RESOLUTION: No change is necessary.
1603(G)(2), (4), AND (5)
ISSUE: NWE proposes to delete Sections 1603(G)(2), (4), and (5). According to NWE, Section 1603(G)(2) should be deleted because the technical and financial capabilities of an ESP can be controlled through the ESP Service Agreement with the UDC, and that Section 1603(G)(4) should not be a precondition to certification, as explained in NWE's comment to Section 1603(I). NWE also opined that Section 1603(G)(5) is not necessary. Staff stated that it would not be in the public interest to issue competitive retail electric CC&Ns without explicitly addressing the public interest and consumer protection issues contained in these Sections.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is required.
1603(G)(7)
ISSUE: ACAA proposed to insert a new Section 1603(G)(7) to provide an additional condition for the Commission to deny certification to any CC&N applicant as follows:
7. FAILS TO PROVIDE A PLAN TO ENROLL AND SERVE RESIDENTIAL CONSUMERS
PURSUANT TO R14-2-1603(B)(1).
ACAA makes this recommendation in conjunction with its proposed new language for
Section 1603(B)(1) that would require a CC&N applicant to provide a plan to
enroll and serve at least 15% of the total residential consumers eligible for
competitive services on October 1, 2000. Staff stated that although ACAA
suggested this Section to help make the residential market an equitable and
robust
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market, this proposal is too restrictive and may keep potential service providers from viewing Arizona's retail market as being entirely open to providers offering competitive service to those customers they wish to initially target.
ANALYSIS: We agree with Staff. Adopting the provision ACAA suggests could discourage potential competitive ESP applicants who might find the associated costs prohibitive. Instead of leading to a more robust market, this would actually lessen the chances of developing a truly competitive market. Adoption of this recommendation would therefore not ultimately serve the public interest.
RESOLUTION: No change is necessary.
1603(I)(4)
ISSUE: NWE recommends the following change to this Section:
4. The Electric Service Provider shall maintain on file with the Commission all current tariffs;[and any service standards that the Commission shall require;]
NWE argues that the term "service standards" is not defined in the rules and the requirement in this Section does not provide adequate notice of the requirements for remaining certificated in Arizona. Staff stated that it is in the public interest for the Commission to require ESPs to file any service standards the Commission deems necessary to serve its customers.
ANALYSIS: We concur with Staff
RESOLUTION: No change is required.
1603(I)(6)
ISSUE: NWE recommended deletion of Section 1603(I)(6), which conditions a CC&N on the ESP obtaining all necessary permits and licenses including relevant tax licenses. NWE believes that the Commission has no authority to police state-law permit and license requirements. Staff believes the item should remain in the rule because it is in the public interest.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
1603(I)(9)
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ISSUE: ACAA proposed to insert a new Section 1603(I)(9) that contains the following additional condition for an ESP to obtain a CC&N:
9. THE ELECTRIC SERVICE PROVIDER SHALL COMPLY WITH THE PROVISIONS OF R14-2-1603(B)(1) ON OR BEFORE SEPTEMBER 1, 1999.
Staff disagreed with the propriety of this proposal because it is too restrictive and may keep potential service providers from viewing Arizona's retail market as being entirely open to providers offering competitive service to those customers they are targeting to serve, which could result in fewer competitors seeking to provide service in Arizona.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
ISSUE: Navopache and Mohave recommended the addition of a new Section 1603(I)(9) as follows:
9. AN ELECTRIC SERVICE PROVIDER CERTIFICATED PURSUANT TO THIS ARTICLE SHALL BE SUBJECT TO THE JURISDICTION OF THE ARIZONA CORPORATION COMMISSION.
Staff responded that because the Rules are specific in regard to which entities are governed by the competitive retail electric rules, and HB2663 describes the CC&N jurisdictional authority of the Commission for public power entities, this change is not necessary.
ANALYSIS: We concur with Staff that this proposed amendment is unnecessary as it is addressed throughout the Rules and by HB2663.
RESOLUTION: No change is necessary.
1603(K)
ISSUE: NWE recommended deletion of Section 1603(K), which allows the Commission to require in appropriate circumstances, as a precondition to certification, the procurement of a performance bond sufficient to cover any advances or deposits the applicant may collect from its customers, or order that such advances or deposits be held in escrow or trust. NWE objected to this provision because the amount of the performance bond or escrow can only be based on estimations before the ESP commences to do business in the state. Staff responded that a bond requirement is just one option the ESP has to address customer protection in the certification process, and that this
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provision is needed to provide the Commission flexibility in having the CC&N applicant address customer protection concerns prior to being certificated.
ANALYSIS: We agree with Staff that Section 1603(K) provides the Commission with a means of protecting consumers. The Commission has flexibility to adjust the amount of the performance bond, escrow or trust after the ESP commences doing business. While it is true that the amount of the performance bond, escrow or trust must initially be based on estimates, the amount required, or indeed whether the bond, escrow or trust is required at all, is an issue that the CC&N applicant is free to address in the proceedings on the application.
RESOLUTION: No change is necessary.
R14-2-1604 "COMPETITIVE PHASES"
1604(A)
ISSUE: Commonwealth and Tucson requested that the phase-in of load be eliminated, and that a "flash cut" be substituted. Commonwealth stated that it wants to serve commercial loads of all sizes, but cannot because this Section does not include smaller customers with loads less than 1 MW or who cannot aggregate 40 kW loads into 1 MW during the phase-in to competition. Tucson stated that it desires to have its entire load served competitively, but that it cannot because the phase-in rule precludes facilities less than 40 kW, which includes many City premises, from obtaining Competitive Services. Tucson further stated that the original reason for the phase-in, to limit the exposure of Affected Utilities to the technical problems that could result from a large number of customers suddenly switching to competitive generation providers, is no longer valid because based on the experience in California, few customers are likely to initially participate in the competitive market. APS, AEPCO, Duncan and Graham opposed a flashcut. Staff agreed that a flash-cut would eliminate many of the inequities and other problems associated with a phase-in, but noted that the current phase-in is much shorter than the one in the 1996 version of the rules.
NWE commented that the rule is unclear in regard to aggregation of loads and the definition of "customer," and recommended that the rule clarify that, if a single site is over 1MW, all lesser sites for the same entity also become eligible for competitive generation. NWE also noted that this Section does not allow any further aggregation once 20 percent of an Affected Utility's 1995 system
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peak demand is reached, although more 1 MW customers could be allowed, and that
this provision favors large ESPs that can provide incentives for aggregation at
the earliest possible date while penalizing customers who might not be prepared
to aggregate in the early phases of competition. Staff conceded that this
Section currently does not require Affected Utilities to allow small commercial
customers to participate in the competitive market during the phase-in, but
pointed out that all classes of customers will be eligible by January 1, 2001.
Staff stated that this Section makes clear that the eligibility of a customer's
load is to be determined at a single premise, and that smaller loads at other
premises for the same entity are not eligible. Staff agreed with NWE that this
Section as currently written appears to favor 1 MW customers over aggregated 40
kWh customers, but that the intent of this Section was to give both groups of
customers equal opportunity to participate. Staff recommended that in order to
clarify that 1MW customers should not be favored over aggregated 40 kW
customers, the sentence stating that additional aggregated customers must wait
until 2001 to obtain competitive service should be deleted.
TEP asserted that only customers with a 1 MW minimum demand should be
eligible for direct access under Section 1604(A)(1) and (2), and that utilizing
a single non-coincident peak has the consequence of expanding direct access
eligibility beyond 20 percent of TEP's 1995 system retail peak demand, thereby
excluding some customers with loads in excess of 1MW. TEP also suggested that
Section 1604 (A)(2) be modified to read that the 40 kWh criterion shall be met
if the customer's usage exceeds 16,500 kWh in any six months, instead of in any
month, in the event peak load data are not available. TEP believes that this
would better characterize a customer whose load usage is more consistently at
least 40 MW or 16,500 kWh. Staff responded to TEP's recommendations by stating
that minimum demands should not be used to determine eligibility, which could
exclude a customer because of one particular month having a lower demand than
usual. Staff also disagreed with TEP's proposal to change one month to six
months to determine eligibility of 40 kW customers because Staff believes there
should be no increased restrictions on the eligibility of medium-size commercial
customers.
In its responsive comments, TEP disagreed with Tucson regarding a flashcut and regarding the 40kW minimum requirement for aggregation.
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ANALYSIS: We concur with Staff that TEP's proposal to change one month to six months to determine eligibility of 40 kW customers should not be adopted.
We do not agree with Tucson that the phase-in should be eliminated based on California's experience that a only a limited number of customers are likely to initially participate in the competitive market. The current phase-in schedule is not unreasonable and will allow the Affected Utilities to continue their current course of preparation for the commencement of full competition.
We agree with Staff that deleting the last sentence of Section 1604(A)(2) would clarify that 1MW customers should not be favored over aggregated 40 kW customers. This deletion is not substantive.
RESOLUTION: Delete the last sentence of Section 1604(A)(2). No other change is required.
1604(A)(2) AND (4) AND 1604(B)(6)
ISSUE: In response to comments filed by ATDUG on June 23, 1999, and to the numerous oral comments made at the public comment hearing on June 23, 1999, Staff proposed that these Sections be clarified regarding the ability of customers to aggregate or self-aggregate their loads, subject to the phase-in percentage limitations; and to clarify that eligible residential and non-residential customers may be aggregated together. Staff recommended modifying the first sentence of Section 1604(A)(2) as follows:
"During 1999 and 2000, an Affected Utility's customers with single premise non-coincident peak load demands of 40 kW or greater aggregated by an Electric Service Provider WITH OTHER SUCH CUSTOMERS OR ELIGIBLE RESIDENTIAL CUSTOMERS into a combined load of 1 MW or greater within the Affected Utility's service territory will be eligible for competitive electric services."
Staff also recommended reinserting the following after "competitive electric services":
"SELF-AGGREGATION IS ALSO ALLOWED PURSUANT TO THE MINIMUM AND COMBINED LOAD
DEMANDS SET FORTH IN THIS RULE.";
and adding the following sentence after the foregoing:
"CUSTOMERS CHOOSING SELF-AGGREGATION MUST PURCHASE THEIR ELECTRICITY AND RELATED SERVICES FROM A CERTIFICATED ELECTRIC SERVICE PROVIDER AS PROVIDED FOR IN THESE RULES."
Staff recommended adding a new Section 1604(A)(4) as follows:
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"EFFECTIVE JANUARY 1, 2001, ALL AFFECTED UTILITY CUSTOMERS IRRESPECTIVE OF SIZE WILL BE ELIGIBLE FOR AGGREGATION AND SELF-AGGREGATION. THOSE CUSTOMERS MUST PURCHASE THEIR ELECTRICITY AND RELATED SERVICES FROM A CERTIFICATED ELECTRIC SERVICE PROVIDER AS PROVIDED FOR IN THESE RULES."
Staff also recommended a new Section 1604(B)(6) as follows:
"AGGREGATION OR SELF-AGGREGATION OF RESIDENTIAL CUSTOMERS IS ALLOWED SUBJECT TO THE LIMITATIONS OF THE PHASE-IN PERCENTAGES IN THIS RULE. CUSTOMERS CHOOSING SELF-AGGREGATION MUST PURCHASE THEIR ELECTRICITY AND RELATED SERVICES FROM A CERTIFICATED ELECTRIC SERVICE PROVIDER AS PROVIDED FOR IN THESE RULES."
Staff believed that the above changes would help clarify the original intent of the Rules to require certification of businesses that choose to provide Aggregation services, while also allowing customers to combine load ("Self-Aggregation") in a manner that will facilitate obtaining favorable competitive bids from ESP. Staff stated that the practice of Self-Aggregation could cut costs to competitors by having the customers themselves perform the functions of combining loads and developing purchase blocks.
ATDUG replied that some of Staff's proposed language additions to Section 1604 "are written as to regulate the conduct of customers" and make it "appear that the Commission is trying to prevent retail electric customers from buying power through aggregation or self-aggregation from Salt River Project and other legitimate electricity suppliers that are not regulated by the Commission." ATDUG suggested that the Sections in question be rewritten so as to require ESPs to sell electricity to aggregated customers, instead of requiring that aggregated customers must purchase their electricity from certificated ESPs.
ANALYSIS: We agree with Staff's recommended changes. However, as written,
proposed Section 1604(A) and Section 1604(B)(6) are redundant, as both state the
requirement that customers choosing Self-Aggregation must purchase electricity
from a certificated provider. Consequently, we will adopt Staff's
recommendation, with the exception of the second sentence in newly proposed
Section 1604(B)(6). We do not agree that these changes will have the effect that
ATDUG suggests, because in order to ensure system reliability and consumer
protection, all ESPs providing competitive retail electric services in the
service territories of the Affected Utilities must be certificated by the
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Commission. Further, we do not believe that requiring ESPs to provide designated services to designated customers would encourage competition.
The changes merely clarify the original intent of the Rules and are not substantive.
RESOLUTION: Modify Sections 1604(A)(2) and (4), and Section 1604(B)(6) as recommended by Staff, with the exception of the second sentence of Staff's proposed Section 1604(B)(6) which is redundant.
1604(B)
ISSUE: NWE suggested that the proposed limitations on residential participation will make the residential market unattractive to potential ESPs, but NWE did not make a specific recommendation other than that the Section should be "entirely revised." ACAA proposed that the minimum percentages for participation of residential customers be increased. Commonwealth believes that it should not have to obtain a customer list from its competing utility in order to market its services, and that the waiting list of interested residential customers should be distributed to all ESPs. Staff responded that the percentage increases ACAA proposed are probably too small to have a major impact on participation of residential customers. Staff stated that any lists of interested customers should be readily available to ESPs if the customers have given permission for their names and other information to be released, and stated that this Section does not preclude availability of such lists.
ANALYSIS: We concur with Staff. This Section should be clarified with respect to the release of customer lists to ESPs. Such modification is not substantive.
RESOLUTION: Add the following to Section 1604(B)(2) after "manage the residential phase-in program":
", WHICH LIST SHALL PROMPTLY BE MADE AVAILABLE TO ANY CERTIFICATED
LOAD-SERVING ESP UPON REQUEST"
1604(C)
ISSUE: APS recommended that the words "such as" replace "including" when
referring to rate reductions in this Section in order to clarify that this
Section does not require a rate reduction. NWE commented that a mandatory rate
reduction would be anti-competitive unless applied to all customers and that
information about a rate reduction must be made available before competition
begins.
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ANALYSIS: This Section as written does not require a rate reduction.
RESOLUTION: No change is necessary.
R14-2-1605 "COMPETITIVE SERVICES"
ISSUE: Section 1605 requires a CC&N for all competitive services. AEPCO, Duncan, Graham, Trico, Navopache, and Mohave (collectively, "Cooperatives") argue that this requirement conflicts with Section 1615(C), which allows distribution cooperatives to provide Competitive Services within their distribution service territories after January 1, 2001. The Cooperatives believe that it was not the intent of Section 1615(C) to require them to obtain a CC&N in order to provide competitive services within their distribution service territories. Staff agreed with these comments, and recommended the following addition to Section 1605:
"EXCEPT AS PROVIDED IN R14-2-1615(C), Competitive Services shall require a Certificate of Convenience and Necessity and a tariff as described in R14-2-1603."
ANALYSIS: We concur with the Cooperatives and Staff that this Section should be modified to clarify that the Cooperatives do not have to apply for a CC&N to provide Competitive Services within their distribution service territories. Such modification adds clarity and is not substantive.
RESOLUTION: Revise Section 1605(C) as recommended by Staff.
R14-2-1606 - SERVICES REQUIRED TO BE MADE AVAILABLE
1606(A)
ISSUE: APS proposed that a sentence be added to state that a UDC, at its option, may provide Standard Offer Service to customers whose annual usage is more than 100,000 kWh. Navopache and Mohave proposed additional language to state that the UDC shall offer Standard Offer Service to the larger customers if the tariff covers the cost of providing the service and that the UDC could seek Commission approval for additional rate schedules to provide such service. Commonwealth suggested that ESPs be allowed to bid on services furnished to Standard Offer customers. Staff stated that the Rules already allow UDCs to provide Standard Offer Service to customers with usage greater than 100,000 kWh, but UDCs will not be Providers of Last Resort for those customers, and that
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because the Commission has determined that Standard Offer Service is a Noncompetitive Service, ESPs cannot bid on Standard Offer Service.
ANALYSIS: UDCs may offer Standard Offer Service to any customer, but as Staff pointed out, are not required to offer Standard Offer Service to customers whose annual usage exceeds 100,000 kWh. Competitive bidding on Provider of Last Resort services is not currently contemplated in the Rules, but the Commission may consider implementing such a process in the future when the competitive generation market has developed.
RESOLUTION: No change is necessary at this time.
1606(B)
ISSUE: Commonwealth proposed that power for Standard Offer Service be acquired through a competitive bid process instead of through the "open market." In addition, Commonwealth proposed that cooperatives not be excluded from the requirement of this Section. Tucson feels that the meaning of "open market" is not clear and proposed that power for Standard Offer Service be acquired "through a competitive procurement with prudent management of market risks, including management of price fluctuations." TEP proposed that a purchased power adjustment mechanism should be allowed as a means for UDCs to recover costs of procuring power for Standard Offer Service. Staff agreed with Commonwealth and Tucson that power for Standard Office Service should be acquired through competitive bidding, and agreed with Tucson's proposed language. Staff opposed the use of a purchased power adjustment mechanism because it would reduce the incentive for the utility to obtain reliable power sources at reasonable rates. Staff recommended that the following sentence be added to Section 1606(B):
"STANDARD OFFER SERVICE POWER SHALL BE ACQUIRED THROUGH A COMPETITIVE PROCUREMENT WITH PRUDENT MANAGEMENT OF MARKET RISKS, INCLUDING MANAGEMENT OF PRICE FLUCTUATIONS.
Staff further recommended that if the Commission does not adopt a competitive bid process, then the term "open market" should be defined in the Rules.
ANALYSIS: There appears to be some confusion concerning the meaning of the term "open market." We do not wish to impose the constraints on energy procurement that would be associated
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with a competitive bid process. Consequently, we will modify Section 1606(B) to clarify the term "open market". Our clarification is not substantive.
RESOLUTION: Revise Section 1606(B) by replacing "open market" with "an open, fair and arms-length transaction with prudent management of market risks, including management of price fluctuations."
1606(C)
ISSUE: Navopache and Mohave proposed adding language to Section 1606(C)(2) which would provide an exception to the requirement that Standard Offer Service be unbundled when wholesale power supplies are obtained on a bundled basis. Trico made a similar comment. APS recommended that the prohibition of "contracts with term" in Section 1606(C)(6) be deleted or at least limited to customers whose annual usage is 100,000 kWh or less because the prohibition restricts customer options and imposes burdens on the UDC when large customers leave from or return to Standard Offer Service. Commonwealth suggested that UDCs be prohibited from offering any discount, special contract, or unique tariff to any particular customer, as these services would in effect constitute Competitive Services. Commonwealth also opposed Trico's proposal because it would prevent potential customers and competitors from easily calculating Commonwealth's proposed "Generation Shopping Credit."
APS also recommended that an Affected Utility be allowed to submit for Commission approval a plan for unbundling Standard Offer Service that varies from the requirements of this Section. Commonwealth vigorously opposed APS' suggestion that the utility develop its own unbundling and billing plan because a unified billing format should be available to all customers. Commonwealth proposed addition of the new definition "Generation Shopping Credit" to Section 1601 and a new provision 1606(C)(3) to require that the "Generation Shopping Credit" appear on the bills of those customers who opt for competitive generation as follows:
"SIMULTANEOUSLY WITH THE START DATE FOR THE IMPLEMENTATION OF RETAIL CHOICE, EACH AFFECTED UTILITY SHALL PROVIDE A GENERATION SHOPPING CREDIT ON THE BILL OF EACH RETAIL CUSTOMER OF AN AFFECTED UTILITY THAT CHOOSES TO PURCHASE ITS ELECTRIC GENERATION SERVICE FROM AN ENTITY OTHER THAN THE AFFECTED UTILITY THAT PROVIDES ITS DISTRIBUTION SERVICE. THE GENERATION SHOPPING CREDIT SHALL BE BASED ON THE AFFECTED UTILITY'S FULL COST TO
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PROVIDE RETAIL ELECTRIC GENERATION SERVICE TO EACH CUSTOMER CLASS, INCLUDING BUT NOT LIMITED TO THE COST OF ENERGY, CAPACITY, ANCILLARY SERVICES, MUST-RUN GENERATING UNITS, ALL RELEVANT TAXES, RESERVES, TRANSMISSION SERVICE (OR THE APPLICABLE INDEPENDENT SYSTEM ADMINISTRATOR OR INDEPENDENT SYSTEMS OPERATOR), MARKETING, ADMINISTRATION AND GENERAL COSTS, AND THE APPLICABLE RATE OF RETURN ON THE ENERGY, CAPACITY, ANCILLARY SERVICES, RESERVES, MUST-RUN GENERATING UNITS, MARKETING, ADMINISTRATIVE AND GENERAL COSTS. THE COMMISSION SHALL DETERMINE THE APPROPRIATE LEVEL OF GENERATION SHOPPING CREDITS FOR EACH AFFECTED UTILITY."
Commonwealth proposed the following definition be added to Section 1601:
"`GENERATION SHOPPING CREDIT' MEANS THE BILL CREDIT THAT WILL BE AFFORDED TO EACH CUSTOMER OF AN AFFECTED UTILITY THAT CHOOSES TO PURCHASE ITS ELECTRIC GENERATION SERVICE FROM AN ENTITY OTHER THAN THE AFFECTED UTILITY THAT PROVIDES ITS DISTRIBUTION SERVICE."
Commonwealth also proposed that 1606(C)(2)(a)(1) and 1612(N)(1)(a) be amended to read: "Generation Shopping Credit", and that Must-Run Generating Units should be deleted from 1606(C)(2)(a)(3) as that cost component should be part of the Generation Shopping Credit.
Staff argued that when possible, unbundled elements need to be standard across companies so that comparisons can be made, and that APS' suggested changes to Section 1606(C)(2) are unnecessary because an Affected Utility can file for Commission approval of a waiver, if necessary. Staff stated that the intent of Section 1606(C)(6) is to prohibit tariffs for Standard Offer Service that prevent customers from accessing a competitive option, and believes that the prohibition against "contracts with term" is consistent with that intent. Staff stated that this Section should be made consistent with Section 1612(N), which identifies billing elements. Staff also stated that ancillary services should be identified as either variable costs or fixed costs. Staff therefore recommended that Section 1606(C)(2) be amended as follows:
"a. Electricity:
(1). Generation INCLUDING ANCILLARY SERVICES (VARIABLE COSTS)
(2) Competition Transition Charge
(3) Must-Run Generating Units
b. Delivery:
(1) Distribution services
(2) Transmission services
(3) Ancillary Services (FIXED COSTS)
c. Other:
(1) Metering Service
(2) Meter Reading Service
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(3) Billing and collection
d. System Benefits"
Staff also recommended that the date in Section 1606(C)(6) be made consistent with dates appearing elsewhere in the Rules.
In its responsive comments, Commonwealth stated that it is unclear what Staff means by "variable" ancillary services which are part of generation costs and "fixed" ancillary services, which are included in delivery costs. Commonwealth contended that all ancillary services relating to generation, both variable and fixed, should be included in the computation of the "Generation Shopping Credit." Commonwealth argued that under its proposal, the distinction between a fixed and variable ancillary service would not be a pathway for cost shifting from generation to delivery charges. Commonwealth recommended that all ancillary services be included in both the Standard Offer Service tariff provision (Section 1606(C)(2)) and the Billing provision (Section 1612(N)), under "Generation Shopping Credit." APS argued that because FERC classifies all ancillary services as transmission related costs, they should be included in the "delivery" category of unbundled bills. APS contended that to modify Section 1606(C) as Staff proposed would be confusing and an unnecessary complication.
In its responsive written comments, NWE proposed the following changes to
Section 1606(C)(2):
1. Standard offer tariffs shall include the following elements, {each of which shall be clearly unbundled and identified in the filed tariffs:}
a. [Electricity] {Competitive Services}
(1) Generation, {which shall include all transaction costs and line losses}
(2) Competition Transition Charge, {which shall include recovery of generation related regulatory assets}
(3) [Must Run Generating Units] {Generation-related billing and collection}
(4) {Transmission Services}
(5) {Metering services}
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(6) {Meter reading service
(7) Optional Ancillary Services, which shall include spinning reserve service, supplemental reserve service, regulation and frequency response service, and energy imbalance service
b. [Delivery] Non-Competitive Services
(1) Distribution services}
(2) [Transmission services]
(2) {Required} Ancillary services, {which shall include scheduling, system control and dispatch service, and reactive supply and voltage control from generation sources service
(3) Use of generating units for must-run purposes
(4) System Benefit Charges
(5) Distribution-related billing and collection}
c. [Other
(2) Meter Reading Service
(3) Billing and Collection
The Competition Transition Charge shall be include in the Standard Offer Service tariffs for the purpose of clearly showing the portion of Standard Offer Service charges being collected to pay Stranded Cost.] {Each of these unbundled elements of the standard offer price shall be clearly identified on each customer bill.}
{Each of these unbundled elements of the standard offer price shall be clearly identified on each customer bill.}
ANALYSIS: Standard Offer Service tariffs must be unbundled in a manner that
permits a meaningful comparison for consumers but not be cost prohibitive.
Section 1606(C)(4) provides that unbundled Standard Offer Service tariffs be
cost-based. If an entity is not able to comply with the unbundling provisions,
it may seek a waiver after notice and a hearing.
For the most part, NWE' s proposal concerning unbundled Standard Offer Service appears reasonable and appropriately categorizes the various elements. NWE's proposed unbundled tariff elements present the existing categories in a logical manner and recognize that Ancillary Services may be either generation- or transmission-related. The Rule provides that the Commission must
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approve all Standard Offer Service tariffs, and it is through the approval process that the Affected Utility must demonstrate that costs are appropriately allocated. The process of unbundling tariff elements with Commission oversight and after public hearing, should alleviate Commonwealth's concerns that costs may be unfairly shifted from generation to transmission.
We believe, however, that the last sentence in NWE's proposal requiring that each of the unbundled elements shall be identified on the customer bill is more appropriately addressed in Section 1613(K) regarding billing elements. While we agree that customer bills for Standard Offer Service must reflect all of the unbundled elements, we do not believe that the bill format must exactly parallel the detail of the tariff because of the potential confusion for consumers. As long as all bill formats are identical for all providers, and billing elements reflect the same underlying costs to permit comparisons, bills should be as simple as possible to read while providing the consumer with adequate information to make informed choices.
Our modification provides additional guidance and detail into how tariffs should be unbundled, but it does not substantively alter the original provision that requires unbundled tariffs.
RESOLUTION: Replace "After January 2, 2001" with "Beginning January 1, 2001". Modify 1606(C)(2) as follows:
2. Standard Offer Service tariffs shall include the following elements, EACH OF WHICH SHALL BE CLEARLY UNBUNDLED AND IDENTIFIED IN THE FILED TARIFFS:
a. COMPETITIVE SERVICES: [Electricity]
(1) Generation, WHICH SHALL INCLUDE ALL TRANSACTION COSTS AND LINE LOSSES;
(2) Competition Transition Charge, WHICH SHALL INCLUDE RECOVERY
OF GENERATION RELATED REGULATORY ASSETS;
(3) GENERATION-RELATED BILLING AND COLLECTION; [Must-Run
Generating Units]
(4) TRANSMISSION SERVICES;
(5) METERING SERVICES;
(6) METER READING SERVICES; AND
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(7) OPTIONAL ANCILLARY SERVICES, WHICH SHAL INCLUDE SPINNING RESERVE SERVICE, SUPPLEMENTAL RESERVE, REGULATION AND FREQUENCY RESPONSE SERVICE, AND ENERGY IMBALANCE SERVICE.
b. NON-COMPETITIVE SERVICES: [Delivery]
(1) DISTRIBUTION SERVICES;
(2) REQUIRED ANCILLARY SERVICES, WHICH SHALL INCLUDE SCHEDULING,
SYSTEM CONTROL AND DISPATCH SERVICE, AND REACTIVE SUPPLY AND
VOLTAGE CONTROL FROM GENERATION SOURCES SERVICE;
[Transmission services]
(3) MUST-RUN GENERATING UNITS; [Ancillary services]
(4) SYSTEM BENEFIT CHARGES; AND
(5) DISTRIBUTION-RELATED BILLING AND COLLECTION.
[c. Other:
(1) Metering Service
(2) Meter Reading Service
(3) Billing and collection
d. System Benefits
The Competition Transition Charge shall be included in the Standard Offer Service tariffs for the purpose of clearly showing that portion of Standard Offer Service charges being collected to pay Stranded Cost.]
ISSUE: Staff recommended that Section 1606(C)(6) be modified to allow "economic development tariffs that clearly mitigate stranded costs" to be included in Standard Offer Service. AECC urged the Commission to broaden the definition of Economic Development Tariff to provide discounted tariffs to businesses for whom a discounted tariff would provide an economic benefit that would be in the public interest and ensure continued availability of jobs for Arizona citizens. At the public comment sessions, consumer and low-income groups expressed reservations about whether the implementation of such "Economic Development Tariffs" would be equitable. Commonwealth believes Staff's proposal merges the "wires" business with the "generation" business and retains the
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monopoly configuration of a utility. Commonwealth opposes utility generation discounts or any other special deals that drive up the distribution charges for all customers.
ANALYSIS: At the present time there is insufficient evidence in the record
to adopt the proposed "Economic Development Tariff" over the concerns and
reservations expressed by representatives of captive Standard Offer Service
ratepayers. It appears that if this tariff were allowed, it would be Standard
Offer Service ratepayers who would be subsidizing this economic development
program. We are therefore reluctant to implement such a program without the
guidance of a cost-benefit analysis, and none was presented in the record to
support this proposal. Furthermore, the benefits this proposal seeks to accord
should come as a natural consequence of a competition, with competitive rates
becoming available to businesses. Indeed, approval of such a tariff for UDCs
could thwart the growth of competition in the generation market and thereby
actually have an anticompetitive result. Absent the showing of any evidence to
the contrary, we find that the proposed "Economic Development Tariff" is neither
necessary nor beneficial at this time and consequently, we decline to revise
Section 1606(C) as proposed by Staff.
RESOLUTION: No change is necessary.
1606(D)
ISSUE: Trico recommended that the Unbundled Service tariff not include a Noncompetitive Service tariff, but that instead, two separate tariffs should be filed. Staff responded that the Unbundled Service tariff should reflect all components of services available, and that it will be less confusing to all parties if Noncompetitive Services are included in the Unbundled Service tariff rather than filing two separate tariffs.
In its responsive comments NWE recommended adding the following modification to Section 1606(D):
D. [By July 1, 1999,] BY THE EFFECTIVE DATE OF THESE RULES, or pursuant to Commission Order, whichever occurs first, each Affected Utility or Utility Distribution Company shall file an Unbundled Service tariff which shall include a Noncompetitive Services tariff. THE UNBUNDLED SERVICE TARIFF SHALL CALCULATE THE ITEMS LISTED IN 1606(C)(2)(B) ON THE SAME BASIS AS THOSE ITEMS ARE CALCULATED IN THE STANDARD OFFER TARIFF.
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ANALYSIS: NWE's recommended modifications add clarity and should be adopted. The proposed modification is not substantive.
RESOLUTION: Modify Section 1606(D) as recommended by NWE.
1606(G)
ISSUE: Commonwealth proposed that oral authorization, subject to third party verification, be allowed for the release of customer data. NWE commented that the customer should be able to give the data to whomever the customer wants, but did not suggest a change to the Section. Staff believes it is important that customer information not be released without written consent from the customer, because written authorization minimizes the possibility of third parties receiving customer information without customer consent. The AZCC, in public comments, opposed oral third-party verification, stating that it hasn't been of benefit to residential consumers of telephone service.
ANALYSIS: Because customer data belongs to the customer, we agree with NWE that the customer should be able to give the data to whomever the customer wants. For the reasons given by Staff, however, it is important that customer information not be released without the customer's written authorization. The required written authorization to switch providers as required by Section 1612(C) can also specify the customer's consent for the release of the customer's demand and energy data. For the reasons explained below under Section 1612(C), we are not convinced at this time that permitting oral authorization for the release of customer data with third party verification should be allowed.
RESOLUTION: No change is necessary at this time.
1606(H)
ISSUE: Section 1606(H)(2) provides that rates for Competitive Services and for Noncompetitive Services shall reflect the costs of providing the services. Trico suggested amending Section 1606(H)(2) to clarify that cost has nothing to do with competitive rates. Trico also suggested amending Section 1606(H)(3) to clarify that flexible rates are limited to Competitive Services. Trico further stated that Sections 1606(H)(2) and (H)(3) discriminate between UDCs and ESPs. Staff asserted that it is unreasonably restrictive to limit flexible pricing to Competitive Services. Staff noted that adjuster mechanisms, which are commonly used in monopoly regulation, are a form of
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flexible pricing, with the maximum rates subject to Commission approval. Staff stated that because Section 1606(H) by its terms applies to both Competitive and Noncompetitive Services, there is no discrimination.
ANALYSIS: We concur with Staff. Competitive tariffs are required to state a maximum rate, and the minimum rate cannot be below marginal cost. Accordingly, competitive rates are clearly related to cost. Section 1606(H)(3) allows downwardly flexible pricing if the tariff is approved by the Commission. This approval process provides a forum in which Trico may address any particular concerns.
RESOLUTION: No change is necessary.
R14-2-1607 - RECOVERY OF STRANDED COST OF AFFECTED UTILITIES
1607(A)
ISSUE: TEP urged the Commission to delete the reference to "expanding wholesale or retail markets or offering a wider scope of permitted regulated utility services for profit, among others" as a mechanism for mitigating Stranded Cost. TEP believes that most, if not all, new products and services will develop in the unregulated, competitive market, and because the profits therefrom will be unregulated, the Commission will not require those profits to be used to offset Affected Utilities' Stranded Cost. APS contends that the definition of "Competitive Services" in Section 1601 "all but eliminates the possibility of an Affected Utility offering such additional services" as are referred to in this Section. Staff concurs with the resolution of this issue in Decision No. 61634 when TEP's argument was not adopted, and believes that TEP's concern was adequately addressed in our earlier revision to this provision.
ANALYSIS: This provision requires the Affected Utilities to take every reasonable, cost-effective measure to mitigate or offset Stranded Cost. It does not, however, mandate any particular method for doing so. We agree with APS that the definition of "Competitive Services" precludes the Affected Utilities from offering those competitive services that their competitive affiliates may offer for profit. We also agree with TEP that unsubsidized profits from the activities of competitive affiliates of Affected Utilities will not be required to offset Affected Utilities' Stranded Cost.
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However, we do not believe that the inclusion in this Section of various options for mitigating Stranded Cost disadvantages the UDCs.
RESOLUTION: No change is required.
1607(B)
ISSUE: Trico asked the Commission to insert the word "all" before "unmitigated Stranded Costs" to clarify that Affected Utilities are entitled to recover all of their unmitigated Stranded Costs.
ANALYSIS: This issue was raised and rejected in earlier revisions of the Rules. We stand by our earlier decision to reject this argument. We believe that the inclusion of the word "all" may infer that Affected Utilities are entitled to recover all Stranded Costs in all circumstances.
RESOLUTION: No change is required.
1607(C)
ISSUE: Trico recommended that, after competition has been implemented, Affected Utilities be required to file on an annual basis the amount of the actual unmitigated distribution Stranded Cost incurred. Staff responded that although distribution electric public service corporations may experience distribution Stranded Cost from competition, due to the difficulty in calculating such Stranded Cost prior to competition, it would be more appropriate to deal with those costs in rate cases for distribution electric public service corporations.
ANALYSIS: We concur with Staff that there is no need for distribution electric public service corporations to make a distribution-related Stranded Cost filing with the Commission outside the confines of a rate case.
RESOLUTION: No change is required.
1607(F-G)
ISSUE: TEP urged the Commission to remove the exclusion of self-generated power from the calculation of recovery of Stranded Cost from a customer. TEP believes that this Section as written will increase uneconomic self-generation while increasing cost burdens on customers who purchase their power in the competitive marketplace. Staff disagreed with TEP that this Section will create significant problems, noting that although self-generation has been an option for customers even prior
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to competition, significant problems of cost-shifting have not developed. TEP also requested adding the following language to the end of Section 1607(G):
"SUBJECT TO COMMISSION APPROVAL, NEITHER SECTION F OR G OF THIS RULE SHALL PRECLUDE AN AFFECTED UTILITY FROM IMPLEMENTING STAND-BY TARIFFS THAT RECOVER APPROPRIATE STRANDED COSTS OR FROM PROVIDING OTHER OPPORTUNITIES TO RECOVER SUCH RESULTANT STRANDED COSTS."
TEP argued this language is necessary to allow an Affected Utility, with Commission approval, to implement stand-by tariffs or other mechanisms to recover Stranded Costs in the event there are Stranded Cost recovery shortfalls resulting from conditions completely outside the control of the Affected Utility. Staff opposed TEP's proposal, characterizing it as transforming an opportunity to recover Stranded Costs into a guarantee of recovery. In public comments, TEP explained that it wishes for customers who self-generate, but will be taking back-up service from TEP, to come under a maintenance and backup tariff, which would include some Stranded Cost recovery. In the event self-generation raises a UDC's distribution costs, such increase is appropriately addressed in the context of a rate case.
ANALYSIS: We concur with Staff that TEP's recommended language is not necessary. Sections 1607(F) and (G) do not preclude an Affected Utility from filing tariffs that apply to maintenance and backup customers who may self-generate but will remain connected to the system in order to receive backup power. It is reasonable for such customers to pay a CTC based on the amount of generation purchased from any Load-Serving Entity.
RESOLUTION: No change is required.
R14-2-1609 - TRANSMISSION AND DISTRIBUTION ACCESS
ISSUE: NWE suggested numerous language changes throughout this Section to emphasize that an Independent System Operator ("ISO") will be "regional" in form and that the Arizona Independent Scheduling Administrator ("AISA") is an "interim" organization. Staff responded that because Section 1609(F) adequately describes the support of an ISO being regional and the intent to transition from the AISA to an ISO, NWE's suggested addition of the descriptive terms "regional" and "interim" in the numerous locations throughout this Section would be redundant.
ANALYSIS: NWE's concerns are adequately addressed by Section 1609(F).
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RESOLUTION: No change is necessary.
1609(B)
ISSUE: Navopache, Mohave, Trico, and APS contended that UDCs should not be
required to ensure that adequate transmission import capability is available to
meet the load requirements of all distribution customers within their service
areas. Trico contended that such a requirement should apply only to customers
receiving Standard Offer Service from the UDC. Navopache and Mohave contended
that the Section as written places an obligation with the UDC but fails to
address cost and revenue responsibility. AEPCO, Duncan and Graham supported the
modification or deletion of Section 1609(B). Navopache, Mohave and APS question
Commission jurisdictional authority to regulate a FERC jurisdictional
transmission issue. As a solution, Navopache and Mohave suggested replacing the
words "transmission import" with "distribution." APS suggested deletion of this
Section altogether because it "arguably extends to extra-high voltage ("EHV")
and other FERC-regulated transmission systems as well." APS further contended
that a rule requiring UDCs to ensure adequate EHV transmission import capability
could eliminate or mask market forces that rightly drive plant-siting decisions
by new market entrants or merchant generators.
ATDUG suggested that additional clarity would result from the substitution of the words "transmission and distribution import, export, and local operation", for the words "transmission import" noting this would require a UDC to construct facilities to accommodate load growth. ATDUG noted that facilities subject to FERC jurisdiction would have regulations in place to determine available transfer capability ("ATC") and assigned costs for increased system transfer requirements, but that this Section is silent as to how these issues will be faced for facilities subject to Commission jurisdiction. ATDUG contended that additional safeguards are required to guarantee that ATC calculations are not used as a shield against competition.
Staff responded that the advent of electric retail competition does not remove, eliminate or diminish the obligation of UDCs to ensure reliable delivery of distribution service to all retail customers and that this obligation does not extend exclusively to only Standard Offer Service customers, because the UDC is the Provider of Last Resort for competitive retail consumers as well. Staff stated that because the ability of a UDC to meet this obligation depends upon the adequacy of
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its distribution system, local generation and its interconnections with the bulk transmission system, this Section's reference to transmission import capability is proper.
Staff also pointed out that because the cost of distribution system improvements is recovered via the UDC's distribution delivery charge, ensuring that such system adequacies are achieved does not imply that the UDC must absorb the full cost for required system improvements, and that transmission providers recover transmission system improvement costs via a transmission delivery charge. Staff stated that although such charges may be regulated by different jurisdictional authorities, adequate system delivery obligation remains a composite responsibility of the UDC and its interconnected transmission providers.
For those reasons, Staff did not agree with suggestions to delete this
Section or eliminate use of the words "transmission import" therein. Staff did
note, however, that the current rule fails to speak to the obligation of the UDC
to provide an adequate distribution system as well as transmission capabilities,
and recommended that this Section be amended to read as follows:
"Utility Distribution Companies shall retain the obligation to assure that adequate transmission import capability AND DISTRIBUTION SYSTEM CAPACITY is available to meet the load requirements of all distribution customers within their services areas."
ANALYSIS: We concur with Staff that the advent of electric retail competition does not remove, eliminate or diminish the obligation of UDCs to ensure reliable distribution service to all retail customers, and not exclusively to Standard Offer Service customers. Because the ability of a UDC to meet this obligation depends upon the adequacy of its distribution system, local generation, and interconnections with the bulk transmission system, this Section's reference to transmission import capability does not exceed the Commission's jurisdiction. As in the past, the cost of distribution system improvements are recoverable via the UDC's distribution delivery charge, and transmission providers can recover transmission system improvement costs via transmission delivery charges.
We will adopt Staff's recommended modification. We will not delete this
Section as requested by APS, or eliminate the use of the words "transmission
import" as suggested by Navopache and Mohave, because the Commission has the
authority and the obligation to mandate
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that all distribution ratepayers in UDC service territories have access to generation provided by the certificated ESP of their choice. However, we agree that distribution issues are closely tied to transmission issues, and that ideally market forces, and not UDC decisions, should drive plant-siting decisions by new market entrants or merchant generators. We will therefore modify this Section to indicate that eventually, the obligation to assure adequate transmission import capabilities should rest with the ISO, or in the event the ISO does not become operational, by default with the AISA. Our modifications do not substantively modify this Section.
RESOLUTION: Modify this Section as follows:
"UNTIL SUCH TIME THAT THE TRANSMISSION PLANNING PROCESS MANDATED BY R14-2-1609(D)(5) IS FULLY IMPLEMENTED, OR UNTIL SUCH TIME THAT A FERC-APPROVED AND OPERATIONAL INDEPENDENT SYSTEM OPERATOR ASSUMES THE OBLIGATIONS OF THE AISA AS IS CONTEMPLATED BY R14-2-1609(F), Utility Distribution Companies shall retain the obligation to assure that adequate transmission import capability is available to meet the load requirements of all distribution customers within their services areas. UTILITY DISTRIBUTION COMPANIES SHALL RETAIN THE OBLIGATION TO ASSURE THAT ADEQUATE DISTRIBUTION SYSTEM CAPACITY is available to meet the load requirements of all distribution customers within their services areas."
1609(D)
ISSUE: TEP proposed that transmission-owning Affected Utilities'
participation in AISA formation be made optional instead of mandatory, and that
the resulting optional-participation AISA should be given the latitude to
determine whether the functional characteristics of the AISA contemplated by
this Section are "appropriate." To this end, TEP suggested that, because the
AISA should determine what functions it must carry out as circumstances change
over time, the word "shall" should be replaced with the word "may" throughout
this Section. NWE proposed revised language that would limit the AISA role to
that of a monitor or auditor without developing and operating an overarching
statewide Open Access Same-Time Information System ("OASIS"). APS stated that
the AISA should be limited to verifying rather than calculating the Available
Transmission Capacity ("ATC") for Arizona transmission facilities. Staff
responded that the functional characteristics outlined for the AISA in this
Section describe what is required to assure non-
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discriminatory retail access in a robust and efficient electricity market, and that reducing or changing such functional characteristics could jeopardize the effective achievement of a fair and non-discriminatory retail market. Staff further stated that by filing with FERC, the AISA will become a regulated entity that cannot indiscriminately change its functionality.
Staff explained that two stages of development are envisioned for AISA: an initial implementation and an ultimate implementation, and that the ultimate implementation includes an overarching statewide OASIS that will provide AISA with the technical ability to take an active role in the calculation and allocation of the ATC for the Arizona transmission system. Staff explained that this Section by necessity defines a fully developed AISA providing the necessary functional requirements in the absence of an ISO, and that the pace of ISO implementation will dictate to what extent the AISA becomes fully developed before handing over its responsibilities and functions to the regional ISO as contemplated by Section 1609(F). Staff therefore believes that the language changes suggested by TEP and NWE are not appropriate.
ANALYSIS: It is essential that the Rules assure, in the event of any delay in the implementation of the planned regional ISO, the fair and non-discriminatory transmission access that is essential to the development of a robust and efficient electricity market. We agree with Staff's characterization of the two stages of implementation of the AISA, and that this Section should remain in place as written. The role of the AISA should not be limited at this time in reliance on the planned regional ISO, which has as yet has not been officially formed and is awaiting FERC approval.
RESOLUTION: No change is necessary.
1609(D)(5)
ISSUE: APS and TEP contend that the transmission planning function required of AISA by this Section is unnecessary, duplicates the efforts of the Southwest Regional Transmission Association ("SWRTA") and the Western States Coordinating Council ("WSCC"), and should be deleted. Staff stated that Affected Utilities historically assumed the responsibility to plan transmission expansion requirements, and that although SWRTA and WSCC do study the interconnected EHV transmission system's capability to perform reliably under various forecast operating conditions, the transmission system analysis functions currently performed by SWRTA and
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WSCC do not consider transmission alternatives to solve local transmission problems. Staff further stated that it should not be assumed that the transmission planning function accompanying a regional ISO will address the transmission interface with local UDC distribution systems. Staff agreed with APS' and TEP's assessment that because Section 1609(B) places that obligation with the UDC and its transmission providers, AISA implementation of a transmission planning process as required by Section 1609(D)(5) would be redundant and unnecessary. Staff therefore recommended that this Section be deleted.
ANALYSIS: Due to our modification of Section 1609(B), this Section is not redundant, but is essential to assure that the transmission interface with local UDC distribution systems is addressed. Otherwise, we concur with Staff.
RESOLUTION: No change is necessary.
1609(E)
ISSUE: APS contended that because APS has already filed a proposed AISA
implementation plan on behalf of itself, AEPCO, TEP, and Citizens, Section
1609(E) is moot and should be deleted. NWE recommended inclusion of language in
Section 1609(E) to require a proposed schedule for the phased development of a
regional ISO. Staff agreed that a proposed schedule for the staged development
of the AISA and its transition to a regional ISO is needed, and that the AISA
implementation plan should be updated and re-filed with the Commission following
final adoption of these rules, and recommended the following language changes to
Section 1609(E):
"... the schedule for the phased development of Arizona Independent Scheduling Administrator functionality AND PROPOSED TRANSITION TO A REGIONAL ISO; ..."
ANALYSIS: We concur with Staff's recommendation. This modification is not substantive.
RESOLUTION: Make the changes to Section 1609(E) as suggested by Staff to require a proposed regional ISO transition schedule in the AISA implementation plan.
1609(F)
ISSUE: Tucson expressed doubts as to the necessity of a regional ISO, which Tucson states may be more expensive than originally anticipated, and therefore recommended deletion of Section 1609(F).
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ANALYSIS: Section 1609(F) directs the Affected Utilities to make good-faith efforts to develop a regional ISO. The FERC has provided guidelines for ISO formation to ensure nondiscriminatory access to the transmission grid. Section 1609(C) expresses the Commission's support for a regional ISO. We do not believe that this provision as written overly burdens the Affected Utilities, nor does it mandate the creation of an ISO if it is not economically feasible to do so.
RESOLUTION: No change is required.
1609(G)
ISSUE: APS wanted assurances that the Commission "will" authorize Affected Utilities to recover costs for establishing and operating the AISA or regional ISO if FERC fails to do so within 90 days of application with FERC. Staff recognized that the cost of organizing and implementing AISA and Desert STAR has been partially assumed by Arizona's Affected Utilities, and that their timely recovery of such costs is a reasonable expectation. Staff stated, however, that this Section already accommodates such a cost recovery and therefore did not support wording changes in Section 1609(G).
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
1609(I)
ISSUE: NWE recommended removal of language requiring AISA development of
protocols for pricing and availability of Must-Run Generating Units, their
presentation to the Commission for review and approval prior to filing with
FERC, provision of such services by UDCs, and recovery of such fixed-costs via a
regulated charge that is part of the distribution service charge. APS opposed
NWE's proposal. Staff recommended that this Section should be left intact, as
the AISA is developing such protocols and is proceeding to comply with this
Section as it is written.
ANALYSIS: NWE's comments do not provide the basis upon which its proposed changes are premised, and do not suggest an alternative method of developing protocols for the availability of services from Must-Run Generating Units. Generation from Must-Run Generating Units is essential
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to maintain system reliability, and should therefore remain a Noncompetitive Service. Must-Run Generating Units should operate on a regulated cost-of-service basis.
RESOLUTION: No change is necessary.
1609(J)
ISSUE: APS suggested deletion of this Section on the basis that the AISA
will not address settlement protocols. Staff responded that the AISA is in fact
addressing protocols for settlement of Ancillary Services, Must-Run Generation,
Energy Imbalance, and After-the-Fact Checkout in order to shape and manage
Scheduling Coordinators' expectations of the settlement process, and that this
Section should remain as written.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
FORMER R14-2-1609 - SOLAR PORTFOLIO STANDARD
ISSUE: Photovoltaics International, LLC encouraged the Commission to retain the Solar Portfolio Standard and further stated that in selecting a location for its next solar manufacturing plant, it would look for a state with "appropriate encouragements for adoption of solar electricity generation." Similarly, the ACAA, Golden Genesis Company, and Robert Annan recommended the reinstatement or retention of the Solar Portfolio Standard (R14-2-1609). Tucson also recommended that the Solar Portfolio Standard be retained, but indicated that it "... may be desirable to modify the standard to make it more practical, but complete elimination of the solar requirements is poor public policy." Tucson expressed support of the Environmental Portfolio Standard as outlined in Commissioner Kunasek's April 8, 1999, letter "as a substitute for the Solar Portfolio Standard." Tucson suggested that the Environmental Portfolio Standard "be formulated to follow the intent of the Solar Portfolio Standard." The LAW Fund also recommended reinstatement of the Solar Portfolio Standard. However, the LAW Fund applauded the opening of a new docket on an Environmental Portfolio Standard (E-00000A-99-0205), and stated that it will participate in the new docket. The Arizona Solar Energy Industries Association ("ARISEIA") stated that the Solar Portfolio Standard "should have been retained in the Rules." ARISEIA further stated, however that it
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supports the new Environmental Portfolio Standard docket, which will "provide significant economic development opportunities, cleaner air and a brighter future for Arizona."
Staff provided the following comments: "Staff has been supportive of the Solar Portfolio Standard since its inception in 1996. However, since the Amended Rules approved in Decision No. 61634 on April 23, 1999, did not include the Solar Portfolio Standard, it is problematic to attempt to reintroduce the standard at this point in the rule amendment process. To do so would be a "substantive" change in the rules, in Staff's opinion, necessitating a re-commencement of the rule amendment process that might delay the start of competition. Staff believes that delaying the entire rules package would be neither prudent nor wise.
"Staff does, however, agree with Tucson, the LAW Fund and ARISEIA that the new docket for the Environmental Portfolio Standard, as suggested by Commissioner Kunasek's April 8, 1999, letter is an excellent vehicle to incorporate solar and other clean technologies into the new competitive market. In fact, Staff believes that the Environmental Portfolio Standard process, if promptly handled, and followed by a supplemental rulemaking process, could add Environmental Portfolio Standard rules that could be in effect by January 1, 2000."
Staff recommended no change to the rules at this time, but a continuation of the Environmental Portfolio Standard proceedings in the new docket.
ANALYSIS: We believe that the Environmental Portfolio Standard docket constitutes the proper forum for consideration of the costs and benefits of renewable energy requirements, and that the start of competition should not be delayed pending such consideration.
RESOLUTION: No change is required.
R14-2-1611 - RATES
1611(B)
ISSUE: NWE opposed the language in Section 1611(B) regarding the filing of maximum rates, stating that the market will set the price of electric services and that in certain cases, the maximums may need to be exceeded. NWE also pointed out that this provision does not establish any time limitations for the Commission to approve such rates. Staff responded that the filing of maximum
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rates is an established rate/regulatory practice in Arizona, and that the Commission has approved maximum rates in conjunction with its approval of ESP applications.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
1611(C)
ISSUE: NWE stated that Section 1611(C) is an unnecessary remnant of the regulatory regime that Arizona is now abandoning, and that it should be stricken in its entirety, but that if retained, strict time limitations for such review should be required, and submitted contracts should be presumed valid unless disapproved under clear criteria within the established time period. Staff stated that this Section requires a Commission Order for contract approval only if the contract terms deviate from a Load Serving Entity's approved tariffs. Tucson stated that this Section should be deleted because it is unclear why competitively negotiated contracts should be treated differently before January 1, 2001, than after that date. Trico recommended that because the word "terms" is ambiguous, the word "terms" should be replaced by the word "provisions" in the last sentence of Section 1611(C). Commonwealth joined in the concerns of Tucson and Trico. Staff agreed that the word "terms" may be misconstrued to mean the length of the contract and recommended adoption of Trico's proposed modification.
ANALYSIS: This Section places a reasonable requirement on Load-Serving Entities in order to allow the Commission's Utilities Division to monitor the referenced contracts during the phase-in of competition. After January 1, 2001 all customers will have access to contracts with competitive suppliers, and this monitoring will no longer be necessary for contracts that comply with the provisions of approved tariffs. It is reasonable that a Commission Order be required for approval of contracts that deviate from approved tariffs, because to approve such contracts without Commission Order would render Commission approval of tariffs meaningless. We concur with Staff regarding the substitution of the word "provisions" for the word "terms."
RESOLUTION: Replace the word "terms" with the word "provisions" in the last sentence of this Section. No other change is necessary.
1611(D)
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ISSUE: Tucson recommended deletion of the first sentence of this Section. Staff responded that this Section affirms the fact that the referenced contracts no longer need to be filed with the Director, Utilities Division on or after January 1, 2001, and recommended no change.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
R14-2-1612 - SERVICE QUALITY, CONSUMER PROTECTION, SAFETY, AND BILLING REQUIREMENTS
1612(A-B)
ISSUE: Trico recommended that words "each paragraph" be replaced by the words "the applicable provisions" in the last sentence of Section 1612(A) because in this Section as well as Section 1612(B), there are numerous provisions of Sections 201 through 212 that are not applicable to ESPs. Staff responded that ESPs are subject to all of the provisions of Sections 201 through 212, and therefore no change to Sections 1612(A) or (B) is necessary.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
1612(C)
ISSUE: Commonwealth proposed that oral authorization, subject to third party verification, be allowed for the switching of service providers in lieu of the requirement of a written authorization, and that this Section be modified accordingly. Commonwealth argued that allowing third party oral verification would reduce costs for ESPs. Staff responded that a customer's service provider should not be changed without written consent from the customer, because written authorization minimizes the possibility of being switched to other service providers without customer consent, and that there is no reason that this requirement would result in a delay of the transaction. In their oral comments, ACAA informed the Commission that it and other consumer groups have been communicating with Commonwealth regarding this issue, but that the consumer groups cannot yet endorse Commonwealth's proposal. At the public comment session, Staff stated that written confirmation is
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the best way to avoid any potential unauthorized switching of providers, or "slamming" problems that may occur, and recommended no change.
ANALYSIS: Arizona's electricity consumers must be protected from the practice of "slamming" that is unfortunately an ongoing problem in the deregulated long-distance telecommunications industry. In that industry, the third-party oral verification process is known not to be completely effective in preventing slamming. We do not believe that requiring written authorization rather than third-party oral verification will necessarily result in higher market entry costs for competitive ESPs. On the contrary, the requirement of written customer authorization will provide protection for ESPs as well as for consumers, because it will result in fewer erroneous switches, which are costly for ESPs. In keeping with the intent of A.R.S. ss. 40-202(C)(4), we will not modify this Section as Commonwealth requests.
RESOLUTION: No change is necessary.
ISSUE: A.R.S. ss. 40-202(C)(4) confirms the Commission's authority to adopt consumer protection requirements related to switching service providers. Several of the requirements appearing in A.R.S. ss. 40-202(C)(4) are embodied in Section 1612(C), but some are not.
ANALYSIS: For consistency, clarity and certainty, Section 1612(C) should include the specific requirements and prohibitions relating to written authorizations to switch service providers that appear in A.R.S. ss. 40-202(C)(4). Such additions to the Rules are not substantive.
RESOLUTION: Modify Section 1612(C) by adding the following after "switching the consumer back to the previous provider.":
"A NEW PROVIDER WHO SWITCHES A CUSTOMER WITHOUT WRITTEN AUTHORIZATION SHALL ALSO REFUND TO THE RETAIL ELECTRICITY CUSTOMER THE ENTIRE AMOUNT OF THE CUSTOMER'S ELECTRICITY CHARGES ATTRIBUTABLE TO ELECTRIC GENERATION SERVICE FROM THE NEW PROVIDER FOR THREE MONTHS, OR THE PERIOD OF THE UNAUTHORIZED SERVICE, WHICHEVER IS LESS."
Add the following after "the provider's certificate.":
"THE FOLLOWING REQUIREMENTS AND RESTRICTIONS SHALL APPLY TO THE WRITTEN AUTHORIZATION FORM REQUESTING ELECTRIC SERVICE FROM THE NEW PROVIDER:
1. THE AUTHORIZATION SHALL NOT CONTAIN ANY INDUCEMENTS;
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2. THE AUTHORIZATION SHALL BE IN LEGIBLE PRINT WITH CLEAR AND PLAIN LANGUAGE CONFIRMING THE RATES, TERMS, CONDITIONS AND NATURE OF THE SERVICE TO BE PROVIDED;
3. THE AUTHORIZATION SHALL NOT STATE OR SUGGEST THAT THE CUSTOMER MUST TAKE ACTION TO RETAIN THE CUSTOMER'S CURRENT ELECTRICITY SUPPLIER;
4. THE AUTHORIZATION SHALL BE IN THE SAME LANGUAGE AS ANY PROMOTIONAL OR INDUCEMENT MATERIALS PROVIDED TO THE RETAIL ELECTRIC CUSTOMER; AND
5. NO BOX OR CONTAINER MAY BE USED TO COLLECT ENTRIES FOR SWEEPSTAKES OR A CONTEST THAT, AT THE SAME TIME, IS USED TO COLLECT AUTHORIZATION BY A RETAIL ELECTRIC CUSTOMER TO CHANGE THEIR ELECTRICITY SUPPLIER OR TO SUBSCRIBE TO OTHER SERVICES.
ISSUE: Commonwealth objected to the language in Section 1612(C) that authorizes UDCs to audit ESPs written authorizations to switch providers in order to assure that a customer switch was properly authorized.
ANALYSIS: We agree that this provision could unnecessarily delay the switching process. The penalties for unauthorized switching should be adequate to deter intentional unauthorized switching, which should preclude any need to audit written authorizations. However, the Commission's Consumer Services Division has the regulatory authority to conduct such audits, and if a UDC believes such an audit is necessary, the UDC should request that the Commission conduct an audit. A UDC, especially one with a competitive ESP affiliate, should not have the authority to conduct such audits itself.
RESOLUTION: Replace "HAS THE RIGHT" with "may request that the Commission's Consumer Services Division". Such modification does not substantively affect any entity's right to an audit.
1612(E)
ISSUE: NWE recommended that this Section be redrafted to clarify that compliance with applicable reliability standards is the responsibility of the scheduling coordinator, the ISO or the ISA, and that notification of scheduled outages is the responsibility of the UDC and should not apply to ESPs. Staff responded that ESPs should remain subject to the same applicable reliability standards as UDCs and recommended no change.
ANALYSIS: We concur with Staff.
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RESOLUTION: No change is necessary.
1612(G-H)
ISSUE: NWE stated that the provisions found in Sections 1612(G) and (H) should apply only to UDCs. Staff responded that ESPs should remain subject to the same service quality provisions as the UDCs, and recommended no change.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
1612(I)
ISSUE: Tucson requested that Section 1612(I) be modified to clarify the time frames and conditions that a customer that is being served by an ESP may return to Standard Offer Service. Staff stated that it will be necessary for both the ESP and UDC to coordinate a customer returning to Standard Offer Service through the Termination of Service Agreement Direct Access Service Request (DASR) process, because once properly notified by the ESP, the UDC has the responsibility to ensure that the proper metering equipment is in place to serve a customer who is returning to Standard Offer Service. Staff stated that the time frames and the conditions that are included in Section 1612(I) are therefore necessary and reasonable. Further, APS responded that Tucson's suggestion fails to recognize the timing and coordination that may be necessary to return some customers to Standard Offer if it is necessary to replace meter equipment.
ANALYSIS: We concur with Tucson that the timeframes in this Section are ambiguous concerning the timing for providing notice to return a customer to Standard Offer Service. We agree with Staff and APS, however, that in certain situations, whether appropriate metering equipment is in place can affect the transfer of service. Provided that the appropriate metering equipment is in place, we believe 15 days notice is adequate for a UDC to return a customer to Standard Offer Service. Consequently, we adopt Tucson's proposed modification, with the exception of Tucson's proposed deletion of the reference concerning the placement of appropriate metering equipment.
RESOLUTION: Revise Section 1612(I) as follows:
Electric Service Providers shall give at least 5 days notice to their customer [and to the appropriate Utility Distribution Company] of scheduled return to Standard Offer Service [but that return of that customer to Standard Offer Service would be at the next regular billing cycle, if appropriate metering equipment is in place and the request is processed 15 calendar days prior to the next scheduled meter read date]. ELECTRIC SERVICE PROVIDERS SHALL PROVIDE 15 CALENDAR
DAYS NOTICE PRIOR TO THE NEXT SCHEDULED METER READING DATE TO THE
APPROPRIATE UTILITY DISTRIBUTION COMPANY REGARDING THE INTENT TO
TERMINATE A SERVICE AGREEMENT. RETURN OF THAT CUSTOMER TO STANDARD
OFFER SERVICE
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WILL BE AT THE NEXT REGULAR BILLING CYCLE IF APPROPRIATE METERING EQUIPMENT IS IN PLACE AND THE REQUEST IS PROVIDED 15 CALENDAR DAYS PRIOR TO THE NEXT REGULAR READ DATE. Responsibility for charges incurred between the notice and the next scheduled read date shall rest with the Electric Service Provider.
1612(K)(1)
ISSUE: Navopache and Mohave proposed adding a sentence to Section 1612(K)(1) to allow UDCs to recover costs associated with collecting and distributing metering data when UDCs provide metering data to an ESP or customer, and proposed adding the words "Utility Distribution Companies shall make available to the Customer or Electric Service Provider all metering information and may charge a fee for that service. The charge or fee shall reflect the cost of providing such information." Staff pointed out that UDCs may request that the Commission approve this type of charge as a tariff item, and recommended no change to this Section.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
1612(K)(2)
ISSUE: NWE contended that the Commission should not approve tariffs for
meter testing, and that rather than establishing a set percentage of error, this
Section should refer to a Commission-approved standard. NWE also suggested
replacing "another" with "an".
ANALYSIS: This Section contains the Commission-approved standard of + 3 percent as provided by Section 209(F). Tariffs for meter testing should be filed for approval by the Commission. NWE's suggestion that "another" be replaced by "an" provides clarity and should be adopted.
RESOLUTION: Replace "another" with "AN [another]". No other change is required.
1612(K)(3)
ISSUE: Staff stated that at the June 2, 1999 Metering Committee meeting it was proposed that the word "customer" be removed after the word "competitive" and be replaced with "point of delivery," and deletion of the words "for each service delivery point." Staff stated that the Metering
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Committee had previously determined that each point of delivery be assigned a Universal Node Identifier ("UNI"), and that because a customer could have more than one point of delivery, a UNI must be assigned to each point of delivery. Staff recommended that this Section be modified using the wording developed by the Metering Committee.
ANALYSIS: We concur with Staff. This modification is not substantive.
RESOLUTION: Modify this Section as follows:
3. Each competitive [customer] POINT OF DELIVERY shall be assigned a Universal Node Identifier [ for each service delivery point] by the Affected Utility or the Utility Distribution Company whose distribution system serves the customer.
1612(K)(4)
ISSUE: NWE contended that the Utility Industry Group ("UIG") should be required to complete its standards at least 60 days before competition begins, and therefore proposed deleting the words "standards approved by the Utility Industry Group (UIG) that can be used by the Affected Utility or the Utility Distribution Company and the Electric Service Provider." and replacing them with "UIG standards in effect at least 60 days before the onset of competition." NWE alternatively proposed that in the penultimate line of this Section, "can" should be changed to "shall." Staff responded that because the use of EDI formats approved by UIG has been discussed by the Metering Committee, and all formats that are being used were already in effect earlier this year, NWE's first proposed change is unnecessary.
ANALYSIS: We concur with Staff's reasoning regarding the first proposed change, and agree with NWE regarding its alternative proposal. This modification is not substantive.
RESOLUTION: Change "can" to "shall" in the penultimate line of this Section. No other change is necessary.
1612(K)(6)
ISSUE: TEP proposed deleting the words "Predictable loads will be permitted to use load profiles to satisfy the requirement of hourly consumption data. The Affected Utility or Electric Service Provider will make the determination if a load is predictable." APS did not oppose allowing some "predictable load" to use load profiling in lieu of hourly consumption data, but believed that
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this Section is unclear as to who may waive the requirements for hourly consumption data. APS recommended changing the last sentence of Section 1612(K)(6) to provide that the "entity developing the load profile shall determine if a load is predictable." Staff responded that ESPs and UDCs are responsible for developing the load profiles for their respective customers and if they do not estimate the load profile correctly, the AISA will require them to pay scheduling penalties. Staff believed that APS' proposed language appropriately clarifies where this responsibility resides, and recommended that APS' wording be used.
Commonwealth disagreed with Staff's and APS' proposed modification as an additional barrier to entry and supported keeping the original language. Commonwealth argued that any ESP should be able to make its independent determination of whether or not a customer has a load it desires to serve. TEP did not agree with the modifications proposed by Staff, Tucson and APS on the basis that they do not address the concerns TEP raised. TEP argued that loads are determined by an Affected Utility's unmetered tariffs, so only the Affected Utility is in a position to determine whether load is predictable. TEP maintained that there are many reasons why load profiling fails to adequately address issues such as economic efficiency, system reliability, proper allocation of costs to customers and proper allocation of costs to third-party suppliers. TEP strongly contended that until these issues are resolved, there is no justification to avoid the use of interval metering in favor of load profiling.
ATDUG believed that some types of loads such as irrigation and other water pumping loads are inherently predictable and suggested the following sentence be added: "The Commission will identify categories of loads that are deemed predictable."
ANALYSIS: TEP states there are unresolved issues that argue against the use of load profiling in lieu of interval metering. However, TEP did not provide the rationale why these issues should prevent the use of profiling for predictable loads. We concur with Tucson, Staff and APS that it is reasonable to allow predictable loads to use load profiling in lieu of hourly consumption data. We agree with Staff that because the entity determining whether a load is predictable or not will bear the responsibility of paying any scheduling penalties stemming from inaccurate predictions, that
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APS' proposed language should be adopted. We do not believe that ATDUG's suggestion that the Commission should identify categories of loads to be deemed predictable is necessary at this time.
RESOLUTION: Delete the last sentence of Section 1612(K)(6) and replace with "THE LOAD-SERVING ENTITY DEVELOPING THE LOAD PROFILING SHALL DETERMINE IF A LOAD IS PREDICTABLE." Such modification is not substantive.
1612(K)(6) AND (7)
ISSUE: Commonwealth proposed that instead of the current 20 kW and 100,000 kWh limit for hourly interval meters, that a limit of 50 kW and 250,000 kWh be imposed for the use of hourly interval meters. Tucson proposed that the 20 kW demand threshold be re-evaluated. Staff responded that 20kW was the appropriate cut-off for requiring hourly interval meters because customers over 20 kW do not have easily predictable load profiles and use of load profiling for such customers can result in higher scheduling errors and cause the Load-Serving Entities to pay scheduling penalties which would be passed on to both the Standard Offer Service and competitive consumers. APS asserted that Commonwealth has not provided a compelling argument why the threshold of 20kW, developed by the working group, is not appropriate. Staff argued that the lower limit reduces scheduling errors and results in lower costs to the Standard Offer Service and competitive customers.
ANALYSIS: Section 1612(K)(6) provides a means for loads over 20 kW determined to be predictable by Load-Serving Entities developing load profiles to use those load profiles in lieu of interval meters. We concur that the 20 kW threshold, that was developed by the working group, should remain unchanged.
RESOLUTION: No change is necessary.
1612(M)
ISSUE: NWE recommended that Section 1612(M) be stricken in its entirety because the Electric Power Competition Act (HB 2663) requires substantial statewide consumer outreach and education, and further informational programs by ESPs is unnecessary. Staff responded that the Commission has a duty to ensure that all customers throughout the state are well informed regarding electric competition and recommended that this provision remain.
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ANALYSIS: This provision provides the Commission with the ability to ensure that consumers receive information about competition.
RESOLUTION: No change is necessary.
1612(N)
ISSUE: Trico, Navopache and Mohave recommend that the language in Section 1612(N) be modified to clarify that UDCs are not required to segregate Wholesale Power Contract bills which combine generation and transmission services. Staff responded that the Commission recognizes that distribution cooperatives may not have the ability to segregate Wholesale Power Contract bills which bundle generation and transmission services. Staff believed the proper remedy would be for the affected distribution cooperatives to seek a waiver from this Rule.
ANALYSIS: We believe that the proper way to address the distribution cooperatives' concerns is through the waiver process rather than the revision of this Rule.
RESOLUTION: No change is necessary.
ISSUE: NWE states that if an ESP is mandated by Section 1612(N) to provide the listed information on their billing statements, then Affected Utilities and UDCs should be mandated to provide such information that is in their control to the ESP in order to permit the ESP to meet its requirements. Staff responded that the billing entity will be responsible for providing this information on customer bills, and that the billing entity for direct access customers will be responsible for coordinating with UDCs, ESPs, and Meter Reader Service Providers to provide this information. Staff therefore recommended no change to this Section.
ANALYSIS: We concur with Staff. This information exchange should be covered in the Electric Service Provider Service Acquisition Agreement between the ESP and the UDC.
RESOLUTION: No change is necessary.
ISSUE: Most commentators who addressed the issue of bill elements opined
that they should be consistent with the unbundled tariff elements established in
Section 1606(C)(2).
ANALYSIS: Bills should provide information to customers in a manner that is easily understood and that permits customers to compare the price of the various services. We believe that the format established in our revised Section 1606(C)(2) concerning unbundled tariffs provides a
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good framework for delineating bill elements. We agree with the Residential Utility Consumer Office's comments to a past version of these Rules that consumers likely are not interested in and may be confused by too much detail on the bill. Consequently, we believe that certain elements that are broken down for tariff purposes are better combined when presented on the bill.
Our modifications to this Section, while providing additional direction to the affected entities and clarity for consumers, are not substantive changes from the original provision.
RESOLUTION: Revise Section 1612(N) as follows:
1. COMPETITIVE SERVICES:[Electricity Costs]
a. Generation, WHICH SHALL INCLUDE GENERATION-RELATED BILLING AND COLLECTION;
b. Competition Transition Charge, and
c. TRANSMISSION AND ANCILLARY SERVICES; [Fuel or purchased power adjustor, if applicable]
d. METERING SERVICES; AND
e. METER READING SERVICES.
2. NON-COMPETITIVE SERVICES:[Delivery costs]
a. Distribution services, INCLUDING DISTRIBUTION-RELATED BILLING AND COLLECTION, REQUIRED ANCILLARY SERVICES AND MUST-RUN GENERATING UNITS; AND
b. SYSTEM BENEFIT CHARGES. [Transmission services;]
3. REGULATORY ASSESSMENTS; AND [Other Costs:
a. Metering Service,
b. Meter Reading Service,
c. Billing and collection, and
d. System Benefits charge.]
4. APPLICABLE TAXES.
R14-2-1613 - REPORTING REQUIREMENTS
ISSUE: NWE recommended that this entire Section be deleted because NWE believed that the reporting requirements are regulatory in nature with no pro-competitive justification, and that the
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requirements will harm consumers by raising costs, as ESPs will be forced to hire employees whose sole purpose is to fulfill these reporting requirements. TEP questioned the need for the amount of information this Section requires, arguing that the amount of information will be difficult to compile and will increase the costs that, ultimately, customers will be required to pay.
Staff responded that the reporting requirements are necessary for the Commission to monitor and determine that the bond and insurance coverage amounts are adequate to protect consumers, including customer deposits and advances. Staff contended that the reports required by this Section will also furnish the Commission with valuable information in assessing the competitiveness of the electricity market in Arizona.
ANALYSIS: We agree with Staff that the information required by this Section is very valuable to the Commission, especially in the early stages of competition, and that the information is also needed to ensure continued consumer protection via bonds and insurance.
RESOLUTION: No change is necessary.
R14-2-1614 - ADMINISTRATIVE REQUIREMENTS
1614(A-C)
ISSUE: NWE repeated its suggestion that there should be no requirement to file maximum rates, and therefore proposed deletion of these Sections 1614 (A), (B), and (C). Staff responded that ESPs are public service corporations, for whom the Commission is lawfully authorized to establish just and reasonable rates. Staff contended that the filing of maximum rates, subject to discount, and the filing of contracts are the means by which the Commission has decided to exercise its jurisdiction.
EVALUATION: We concur with Staff.
RESOLUTION: No change is necessary.
1614(E)
ISSUE: ACAA suggested additional language which would further define
specifics surrounding the Consumer Education Program. ACAA would have this
Section specifically reference adoption of a funding plan, specify that the
adopted Consumer Education Program is to be a model, and require Affected
Utilities to conform to the adopted plan. Staff responded that this
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Section as currently written will accommodate the concerns addressed by ACAA, and recommended no change.
ANALYSIS: We believe that ACAA's concerns will be addressed when the Commission adopts the Consumer Education Program required by this Section.
RESOLUTION: No change is necessary.
R14-2-1615 - SEPARATION OF MONOPOLY AND COMPETITIVE SERVICES
1615(A)
ISSUE: Section 1615(A) requires all competitive generation and Competitive Services to be separated from an Affected Utility prior to January 1, 2001. Such separation shall either be to an unaffiliated party or to a separate corporate affiliate or affiliates. Commonwealth asserted that all generation assets, except for Must Run Generating Units, should be sold at market value to third parties. Commonwealth also suggested that an Affected Utility's competitive affiliate should be precluded from acquiring generation assets unless it is the highest bidder at auction. Commonwealth believes that, without the requirement of a sale at market value, the UDCs will be able to manipulate values and shift costs from Competitive Services to Noncompetitive Services.
Staff responded that Commonwealth's proposal to require generation assets to be divested through a market auction is in direct conflict with Decision No. 61677, the Commission's Stranded Cost order, which treats divestiture as an option, not a requirement. Staff pointed out that pursuant to Section 1615(A), the asset transfer shall be at a value determined by the Commission to be fair and reasonable, and that accordingly, the asset transfer will not occur outside of Commission oversight. Staff further stated that Commonwealth's concerns regarding cost shifting between UDCs and their affiliates may be addressed through the Code of Conduct required by Section 1616 and through subsequent UDC rate cases governing Noncompetitive Services.
Commonwealth asserted that Section 1615(A) should be clarified by deleting the word "competitive", thereby requiring all generation assets except for Must-Run Generating Units to be separated from Affected Utilities prior to January 1, 2001. Staff responded that the definition of "Noncompetitive Services" clearly excludes generation services, except for Must-Run Generating
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Units, and that it is therefore clear that competitive generation includes all generation except for Must-Run Generating Units. Staff recommended against adoption of Commonwealth's suggested modifications to this Section.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
ISSUE: Section 1615(A) requires Affected Utilities to transfer their generation assets by January 1, 2001. TEP suggested changing this date to January 1, 2003 to accommodate lease and bond restrictions that may interfere with TEP's ability to comply with the 2001 deadline. Staff responded that the Rules already provide an avenue in which a public service corporation may request a waiver to the rules, and that while TEP's individual circumstances may justify a case-specific waiver from the proposed deadline, these circumstances do not justify an amendment to the Rules.
ANALYSIS: We believe that TEP's concerns are best addressed through a waiver rather than a redrafting of this rule.
RESOLUTION: No change is necessary.
ISSUE: Section 1615(A) allows Affected Utilities to transfer competitive generation assets to affiliates. TEP suggested adding the word "subsidiary" because it believes that transfer to a subsidiary may under some circumstances be less costly than transfer to an affiliate. Staff responded that in Decision No. 61669, the Commission clearly indicated its intent to require transfer to an affiliate, instead of a subsidiary, and that TEP's suggestion conflicts with the Commission's clearly established intent. Staff therefore recommended no change. ATDUG expressed grave concerns about the effectiveness of "separation" if the transfer of generation assets is allowed to affiliates.
ANALYSIS: We agree that the requirement that competitive generation assets and Competitive Services be separated to an unaffiliated party or to a separate corporate affiliate or affiliates, will provide greater protection against cross-subsidization than would separation to a subsidiary.
RESOLUTION: No change is necessary.
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ISSUE: APS argued that the separation from the UDC of metering, meter reading, billing, and collection required by Section 1615 is not necessary, appropriate, or to the benefit of consumers or the competitive market. APS proposed amending Section 1615 to allow UDCs to offer non-generation related Competitive Services without divesting such functions to affiliates. AECC opposed APS' proposal. Staff responded that Affected Utilities, such as APS, currently have substantial market power by virtue of their status as incumbent monopolists, and that the prospective competitive market will benefit by the creation of a level playing field for new market entrants so that competitors will have an incentive to enter the market. Staff therefore recommended no change to this Section.
ANALYSIS: We concur that separation of monopoly and competitive services by the incumbent Affected Utilities must take place in order to foster development of a competitive market in Arizona.
RESOLUTION: No change is necessary.
1615(B)
ISSUE: Section 1615(B)(1) recognizes that UDCs may provide meters for Load Profiled customers. APS proposed clarifying this Section by substituting the phrase "Meter Services and Meter Reading Services" for the word "meters." Staff supported APS' proposal as it uses defined terms in place of an undefined term.
ANALYSIS: We concur with Staff. This modification eliminates ambiguity and is not substantive.
RESOLUTION: Delete "meters" and replace with "Meter Services and Meter Reading Services".
1615(C)
ISSUE: Section 1615(C) allows distribution cooperatives to provide competitive electric services in areas in which they currently provide service. AEPCO, Duncan, Graham, and Trico suggested amending this Section to allow the distribution cooperatives to provide competitive services in any areas in which they will be providing Noncompetitive Services now or in the future. Staff responded that Section 1615(C) was intended to allow distribution cooperatives to provide
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competitive services within areas in which they are providing distribution services, and that because distribution service territories change, it would be sensible to draft the rule in a manner that recognizes this. Staff therefore recommended deleting the phrase "the service territory it had as of the effective date of these rules" and replace it with "its distribution service territory."
ANALYSIS: We agree with this nonsubstantive modification.
RESOLUTION: Replace "the service territory it had as of the effective date of these rules" with "ITS DISTRIBUTION SERVICE TERRITORY."[the service territory it had as of the effective date of these rules.]
ISSUE: Section 1615(C) states that a generation cooperative shall be subject to the same limitations to which its member cooperatives are subject. AEPCO argues that a generation cooperative, such as AEPCO, does not have a geographic service territory and does not have distribution customers. AEPCO further argued that, because it is not a distribution cooperative, it is not eligible for the exemption contained in this Section, and is therefore subject to all the requirements contained in Sections 1615(A) and (B). AEPCO therefore recommended deleting the last sentence of Section 1615(C). Staff agreed with AEPCO.
ANALYSIS: The intent of this provision was to preclude a generation cooperative or its competitive affiliate from providing power in the competitive market before the territories of its member distribution cooperatives were open to competition. The reference here is misplaced and we agree it should be removed. The timing for AEPCO's competitive affiliate to begin providing Competitive Services will be addressed by Commission order in AEPCO's Stranded Cost/Unbundled tariff proceeding.
RESOLUTION: Delete the last sentence of Section 1615(C). This change is not substantive.
R14-2-1616 - CODE OF CONDUCT
ISSUE: Commonwealth, Tucson, AECC and Enron Corp. ("Enron") opposed the Commission's elimination of the Affiliate Transaction rules (formerly R14-2-1617). AECC joined in and fully supported the separately filed comments of Enron and submits that the Electric Competition Rules must contain Affiliate Transaction rules to provide consumers appropriate safeguards in the competitive marketplace. Enron claimed that the Affiliate Transaction rules should be designed to prevent Affected Utilities from abusing or unfairly exerting market
power due to their inherent and
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historical monopoly positions in Arizona. Enron argued that at a minimum, the above concerns would be reduced if Affected Utilities and their marketing affiliates are required to operate as separate corporate entities, keeping separate books and records. Enron indicated that market power concerns have been heightened recently because of the Commission's approach to Stranded Cost which does not require Affected Utilities to divest generation assets, thereby leaving Affected Utilities with tremendous competitive advantage and market power. Enron identified the potential absence of uniformity among the Affected Utilities' Codes of Conduct as a problem resulting in the ESPs having to guess which types of activities are allowed for each individual Affected Utility and its affiliates. Commonwealth recommended that the Code of Conduct should preclude any Affected Utility from offering competitive services through an affiliate until a Code of Conduct has been approved by the Commission, after notice, comment, and hearing. Tucson urged the Commission to promulgate Affiliate Transaction rules with sufficient detail to assure the public that there is adequate Commission oversight of these relationships. Commonwealth stated that the Code of Conduct should not displace Affiliate Transaction rules or guidelines. Commonwealth suggested that, if the Affiliate Transactions rule is not reinserted back into the rules, an alternative seven pages of guidelines for Affected Utilities and their competitive affiliates should be incorporated within the Codes of Conduct of each Affected Utility.
TEP disagreed with the comments of AECC, Tucson and Commonwealth regarding the re-adoption of the Affiliate Transaction rules, preferring the flexibility of a Code of Conduct. TEP argued that contrary to Enron's assertion, the requirements that Affected Utilities transfer their generation assets to a separate affiliate and that Standard Offer Service generation be procured in the open market, will make it impossible for the Affected Utility to favor its generation affiliates to the detriment of other ESPs. Trico and AEPCO, Duncan and Graham believed that each entity that would be subject to the Affiliate Transaction rules is unique and the parties advocating their reinstatement have not provided adequate reasons why an individually tailored Code of Conduct subject to Commission review and approval is not a satisfactory solution. ATDUG believed that Affected Utilities should not draft their own Code of Conduct without, at a minimum, a guideline or standard.
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Staff responded that a Code of Conduct for Affected Utilities and their affiliates is necessary in order to ensure the development of a robust competitive market. Staff believed that, while it is not essential for all Affected Utilities to have identical Codes of Conduct, it is desirable for each Code of Conduct to address certain significant issues. Staff stated that in the absence of some minimal degree of uniformity, parties will be uncertain as to the rules governing the Arizona market, and enforcement of these issues will be difficult. Staff therefore supported amending Section 1616 to require each Affected Utility to address certain minimum standards in its Code of Conduct.
Staff recommended making the following changes to Section 1616:
No later than 90 days after adoption of these Rules, each Affected Utility which plans to offer Noncompetitive Services and WHICH PLANS TO OFFER Competitive Services through its competitive electric affiliate shall propose a Code of Conduct to prevent anti-competitive activities. EACH AFFECTED UTILITY THAT IS AN ELECTRIC COOPERATIVE, THAT PLANS TO OFFER NONCOMPETITIVE SERVICES, AND THAT IS A MEMBER OF ANY ELECTRIC COOPERATIVE THAT PLANS TO OFFER COMPETITIVE SERVICES SHALL ALSO SUBMIT A CODE OF CONDUCT TO PREVENT ANTI-COMPETITIVE ACTIVITIES. ALL [The] Codes of Conduct shall be subject to Commission approval.
THE CODE OF CONDUCT SHALL ADDRESS THE FOLLOWING SUBJECTS:
1. APPROPRIATE PROCEDURES TO PREVENT CROSS SUBSIDIZATION BETWEEN THE UTILITY DISTRIBUTION COMPANY AND ANY COMPETITIVE AFFILIATES;
2. APPROPRIATE PROCEDURES TO ENSURE THAT THE UTILITY DISTRIBUTION COMPANY'S COMPETITIVE AFFILIATE DOES NOT HAVE ACCESS TO CONFIDENTIAL UTILITY INFORMATION THAT IS NOT ALSO AVAILABLE TO OTHER MARKET PARTICIPANTS;
3. APPROPRIATE GUIDELINES TO LIMIT THE JOINT EMPLOYMENT OF PERSONNEL BY BOTH A UTILITY DISTRIBUTION COMPANY AND ITS COMPETITIVE AFFILIATE;
4. APPROPRIATE GUIDELINES TO GOVERN THE USE OF THE UTILITY DISTRIBUTION COMPANY'S NAME OR LOGO BY THE UTILITY DISTRIBUTION COMPANY'S COMPETITIVE AFFILIATE;
5. APPROPRIATE PROCEDURES TO ENSURE THAT THE UTILITY DISTRIBUTION COMPANY DOES NOT GIVE ITS COMPETITIVE AFFILIATE ANY UNREASONABLY PREFERENTIAL TREATMENT SUCH THAT OTHER MARKET PARTICIPANTS ARE UNFAIRLY DISADVANTAGED;
6. APPROPRIATE POLICIES TO ELIMINATE JOINT ADVERTISING, JOINT MARKETING, OR JOINT SALES BY A UTILITY DISTRIBUTION COMPANY AND ITS COMPETITIVE AFFILIATE;
7. APPROPRIATE PROCEDURES TO GOVERN TRANSACTIONS BETWEEN A UTILITY DISTRIBUTION COMPANY AND ITS COMPETITIVE AFFILIATE; AND
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8. APPROPRIATE POLICIES TO PREVENT THE UTILITY DISTRIBUTION COMPANY AND ITS COMPETITIVE AFFILIATE FROM REPRESENTING THAT CUSTOMERS WILL RECEIVE BETTER SERVICE AS A RESULT OF THE AFFILIATION.
ANALYSIS: Nearly all parties providing comments on this issue suggest that the entire Affiliate Transactions rule (formerly R14-2-1617) be reinserted back into the proposed rules. Others suggested rewriting the current Code of Conduct, R14-2-1616, to include specific appropriate Affiliate Transactions rules. We believe that to promote competition it is critical to have a statewide standard for the Codes of Conduct. We believe that Staff's recommended guideline for Code of Conduct content is reasonable and will promote competition within the state while at the same time providing flexibility for individual Affected Utilities.
RESOLUTION: Modify Section 1616 as recommended by Staff, adding clarification that approval shall occur after a notice and a hearing. Staff's recommended modification provides additional detail as to what is expected in a Code of Conduct, but does not substantively change the affect of this section.
R14-2-1617 - DISCLOSURE OF INFORMATION
ISSUE: NWE and TEP proposed that this entire Section be deleted. APS proposed that only Load-Serving ESPs, and not UDCs, should be required to disclose information to consumers. Trico proposed that a new Section be added stating that the UDC would not be required to furnish the same information as provided by a Load-Serving Entity. AEPCO, Duncan and Graham believed that mandating a "guess" about the characteristics of the resource portfolio will not improve the value of data provided to the customer.
ACAA proposed that information about the resource mix be readily available to residential consumers without any acquisition barriers. Tucson expressed concern that this Section requires information about the resource portfolio to be provided only upon request and stated that experience in other states has shown that consumers "prefer a more environmentally sound mix of resources than traditional suppliers have in their portfolios." Tucson believes that since the information would have to be developed in case someone requested it, the only rationale for not providing it automatically would be to hide the resource mix. The LAW Fund pointed out that by not requiring disclosure about resources, Arizona consumers will be not be informed about their choices and will be at a
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disadvantage in comparison to those in other western states. Commonwealth asserts that it has found that many customers desire the option to purchase generation from environmentally-compatible sources. Commonwealth supported the disclosure requirements and urged that it be reinstated in the Rules. APS believed that market forces would operate to provide consumers with information concerning resource mix, and that mandatory disclosure adds unnecessary costs
Staff stated that consumers are entitled to receive information so that they can make informed choices, and that research conducted in other states indicates that consumers want information on generation resources. Staff argued that all ESPs providing generation service and UDCs providing Standard Offer Service should be required to disclose generation resource information as part of the consumer information label, and not only upon request. Staff recommended restoring Sections 1617(A)(4),(5) and (6), and deleting Section 1617(B). Staff also recommended inserting "PROVIDING EITHER GENERATION SERVICE OR STANDARD OFFER SERVICE" after "Load-Serving Entity" in Section 1617(A).
ANALYSIS: We agree with those entities who advocate for the disclosure of a Load-Serving Entities' resource portfolio characteristics. However, we are also concerned about the costs to Load-Serving Entities and question the need to include this information, which may or may not be available, in all marketing materials. There are going to be a significant number of customers who are interested in this information. Because Load-Serving Entities will have to prepare the information concerning the resource portfolio in anticipation of customer requests, we do not believe that they will be able to hide the information, and further, market forces will work to disseminate this information.
RESOLUTION: Except to add Staff's clarifying language, we do not believe that further modification is necessary. Insert "PROVIDING EITHER GENERATION SERVICE OR STANDARD OFFER SERVICE" after Load-Serving Entity in Section 1617(A). This modification is not substantive.
1617(G)
ISSUE: Commonwealth proposed that the word "written" be deleted from
Section 1617(G)(2) because it believes third-party orally verified customer
authorizations should suffice. Staff reiterated its belief that a customer's
service provider should not be changed without written consent from the
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customer because written authorization minimizes the possibility of being switched to other service providers without customer consent, and therefore recommended no change to this Section.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is required.
| ARTICLE UT |
| MULTIPLIER: 1,000 |
| PERIOD TYPE | 9 MOS |
| FISCAL YEAR END | DEC 31 1999 |
| PERIOD START | JAN 01 1999 |
| PERIOD END | SEP 30 1999 |
| BOOK VALUE | PER BOOK |
| TOTAL NET UTILITY PLANT | 4,727,441 |
| OTHER PROPERTY AND INVEST | 212,517 |
| TOTAL CURRENT ASSETS | 556,630 |
| TOTAL DEFERRED CHARGES | 757,162 |
| OTHER ASSETS | 0 |
| TOTAL ASSETS | 6,253,750 |
| COMMON | 178,162 |
| CAPITAL SURPLUS PAID IN | 1,196,804 |
| RETAINED EARNINGS | 565,230 |
| TOTAL COMMON STOCKHOLDERS EQ | 1,940,196 |
| PREFERRED MANDATORY | 0 |
| PREFERRED | 0 |
| LONG TERM DEBT NET | 1,812,262 |
| SHORT TERM NOTES | 0 |
| LONG TERM NOTES PAYABLE | 0 |
| COMMERCIAL PAPER OBLIGATIONS | 223,500 |
| LONG TERM DEBT CURRENT PORT | 114,542 |
| PREFERRED STOCK CURRENT | 0 |
| CAPITAL LEASE OBLIGATIONS | 0 |
| LEASES CURRENT | 0 |
| OTHER ITEMS CAPITAL AND LIAB | 2,163,250 |
| TOT CAPITALIZATION AND LIAB | 6,253,750 |
| GROSS OPERATING REVENUE | 1,792,921 |
| INCOME TAX EXPENSE | 166,945 |
| OTHER OPERATING EXPENSES | 1,309,603 |
| TOTAL OPERATING EXPENSES | 1,476,548 |
| OPERATING INCOME LOSS | 316,373 |
| OTHER INCOME NET | 20,966 |
| INCOME BEFORE INTEREST EXPEN | 337,339 |
| TOTAL INTEREST EXPENSE | 104,495 |
| NET INCOME | 92,959 |
| PREFERRED STOCK DIVIDENDS | 1,016 |
| EARNINGS AVAILABLE FOR COMM | 91,943 |
| COMMON STOCK DIVIDENDS | 127,500 |
| TOTAL INTEREST ON BONDS | 81,594 |
| CASH FLOW OPERATIONS | 532,129 |
| EPS BASIC | 0 |
| EPS DILUTED | 0 |