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