FORM 10-Q
Securities and Exchange Commission
Washington, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 1996
---------------------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
--------------- ----------------
Commission file number 1-4473
-------------
ARIZONA PUBLIC SERVICE COMPANY
------------------------------------------------------
(Exact name of registrant as specified in its charter)
Arizona 86-0011170
- ------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona 85072-3999
- --------------------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (602) 250-1000
- --------------------------------------------------------------------------------
(Former name, former address and former fiscal year, if changed since
last report)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
----- -----
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Number of shares of common stock, $2.50 par value,
outstanding as of May 14, 1996: 71,264,947
<PAGE>
-i-
Glossary
--------
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
AFUDC - Allowance for funds used during construction
Company - Arizona Public Service Company
EPA - Environmental Protection Agency
ITC - Investment tax credit
1995 10-K - Arizona Public Service Company Annual Report on Form 10-K for the
fiscal year ended December 31, 1995
Palo Verde - Palo Verde Nuclear Generating Station
Pinnacle West - Pinnacle West Capital Corporation
PRP's - Potentially Responsible Parties
SEC - Securities and Exchange Commission
Superfund - Comprehensive Environmental Response,
Compensation, and Liability Act
<PAGE>
INDEPENDENT ACCOUNTANTS' REPORT
Arizona Public Service Company:
We have reviewed the accompanying condensed balance sheet of Arizona Public
Service Company as of March 31, 1996 and the related condensed statements of
income for the three-month and twelve-month periods ended March 31, 1996 and
1995 and cash flows for the three-month periods ended March 31, 1996 and 1995.
These condensed financial statements are the responsibility of the Company's
management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and of making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with generally accepted auditing standards, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that
should be made to such condensed financial statements for them to be in
conformity with generally accepted accounting principles.
We have previously audited, in accordance with generally accepted auditing
standards, the balance sheet of Arizona Public Service Company as of December
31, 1995 and the related statements of income, retained earnings, and cash
flows for the year then ended (not presented herein); and in our report dated
March 1, 1996, we expressed an unqualified opinion on those financial
statements. In our opinion, the information set forth in the accompanying
condensed balance sheet as of December 31, 1995, is fairly stated, in all
material respects, in relation to the balance sheet from which it has been
derived.
DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Phoenix, Arizona
May 2, 1996
<PAGE>
-2-
PART I - FINANCIAL INFORMATION
------------------------------
Item 1. Financial Statements
----------------------------
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
------------------------------
(Unaudited)
<TABLE>
<CAPTION>
Three Months
Ended March 31,
-------------------------------------
1996 1995
---------------- -----------------
(Thousands of Dollars)
<S> <C> <C>
ELECTRIC OPERATING REVENUES . . . . . . . . . . . . . . . $ 345,261 $ 336,968
---------------- -----------------
FUEL EXPENSES:
Fuel for electric generation . . . . . . . . . . . . . . 42,334 46,710
Purchased power . . . . . . . . . . . . . . . . . . . . 13,938 8,210
---------------- -----------------
Total . . . . . . . . . . . . . . . . . . . . . . . . 56,272 54,920
---------------- -----------------
OPERATING REVENUES LESS FUEL EXPENSES . . . . . . . . . . 288,989 282,048
---------------- -----------------
OTHER OPERATING EXPENSES:
Operations excluding fuel expenses . . . . . . . . . . . 63,769 65,566
Maintenance . . . . . . . . . . . . . . . . . . . . . . 23,974 25,866
Depreciation and amortization . . . . . . . . . . . . . 58,386 60,426
Income taxes . . . . . . . . . . . . . . . . . . . . . . 31,359 21,622
Other taxes . . . . . . . . . . . . . . . . . . . . . . 33,979 35,354
---------------- -----------------
Total . . . . . . . . . . . . . . . . . . . . . . . . 211,467 208,834
---------------- -----------------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . 77,522 73,214
---------------- -----------------
OTHER INCOME (DEDUCTIONS):
AFUDC - equity . . . . . . . . . . . . . . . . . . . . 1,675 1,186
Other - net . . . . . . . . . . . . . . . . . . . . . . (291) 4,784
Income taxes . . . . . . . . . . . . . . . . . . . . . 5,650 1,722
---------------- -----------------
Total . . . . . . . . . . . . . . . . . . . . . . . . 7,034 7,692
---------------- -----------------
INCOME BEFORE INTEREST DEDUCTIONS . . . . . . . . . . . . 84,556 80,906
---------------- -----------------
INTEREST DEDUCTIONS:
Interest on long-term debt . . . . . . . . . . . . . . . 37,400 41,872
Interest on short-term borrowings . . . . . . . . . . . 2,670 1,224
Debt discount, premium and expense . . . . . . . . . . . 2,117 1,974
AFUDC - debt . . . . . . . . . . . . . . . . . . . . . (3,237) (1,996)
---------------- -----------------
Total . . . . . . . . . . . . . . . . . . . . . . . . 38,950 43,074
---------------- -----------------
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 45,606 37,832
PREFERRED STOCK DIVIDEND REQUIREMENTS . . . . . . . . . . 4,477 4,807
---------------- -----------------
EARNINGS FOR COMMON STOCK . . . . . . . . . . . . . . . . $ 41,129 $ 33,025
================ =================
</TABLE>
See Notes to Condensed Financial Statements.
<PAGE>
-3-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
------------------------------
(Unaudited)
<TABLE>
<CAPTION>
Twelve Months
Ended March 31,
-------------------------------------
1996 1995
---------------- -----------------
(Thousands of Dollars)
<S> <C> <C>
ELECTRIC OPERATING REVENUES . . . . . . . . . . . . . . . $ 1,623,245 $ 1,617,087
---------------- -----------------
FUEL EXPENSES:
Fuel for electric generation . . . . . . . . . . . . . . 204,552 225,845
Purchased power . . . . . . . . . . . . . . . . . . . . 66,598 61,733
---------------- -----------------
Total . . . . . . . . . . . . . . . . . . . . . . . . 271,150 287,578
---------------- -----------------
OPERATING REVENUES LESS FUEL EXPENSES . . . . . . . . . . 1,352,095 1,329,509
---------------- -----------------
OTHER OPERATING EXPENSES:
Operations excluding fuel expenses . . . . . . . . . . . 283,045 291,522
Maintenance . . . . . . . . . . . . . . . . . . . . . . 114,080 114,210
Depreciation and amortization . . . . . . . . . . . . . 240,058 238,624
Income taxes . . . . . . . . . . . . . . . . . . . . . 188,602 168,688
Other taxes . . . . . . . . . . . . . . . . . . . . . . 140,248 141,965
---------------- -----------------
Total . . . . . . . . . . . . . . . . . . . . . . . . 966,033 955,009
---------------- -----------------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . 386,062 374,500
---------------- -----------------
OTHER INCOME (DEDUCTIONS):
AFUDC - equity . . . . . . . . . . . . . . . . . . . . 5,471 4,281
Palo Verde accretion income . . . . . . . . . . . . . -- 13,616
Other - net . . . . . . . . . . . . . . . . . . . . . . (22,107) 21,195
Income taxes . . . . . . . . . . . . . . . . . . . . . 41,526 (527)
---------------- -----------------
Total . . . . . . . . . . . . . . . . . . . . . . . . 24,890 38,565
---------------- -----------------
INCOME BEFORE INTEREST DEDUCTIONS . . . . . . . . . . . . 410,952 413,065
---------------- -----------------
INTEREST DEDUCTIONS:
Interest on long-term debt . . . . . . . . . . . . . . . 155,560 162,236
Interest on short-term borrowings . . . . . . . . . . . 9,589 5,834
Debt discount, premium and expense . . . . . . . . . . . 8,765 8,416
AFUDC - debt . . . . . . . . . . . . . . . . . . . . . (10,306) (6,271)
---------------- -----------------
Total . . . . . . . . . . . . . . . . . . . . . . . . 163,608 170,215
---------------- -----------------
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 247,344 242,850
PREFERRED STOCK DIVIDEND REQUIREMENTS . . . . . . . . . . 18,804 22,571
---------------- -----------------
EARNINGS FOR COMMON STOCK . . . . . . . . . . . . . . . . $ 228,540 $ 220,279
================ =================
</TABLE>
See Notes to Condensed Financial Statements.
<PAGE>
-4-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
------------------------
ASSETS
(Unaudited)
<TABLE>
<CAPTION>
March 31, December 31,
1996 1995
-------------- --------------
(Thousands of Dollars)
<S> <C> <C>
UTILITY PLANT:
Electric plant in service and held for future use . . . $ 6,559,022 $ 6,544,860
Less accumulated depreciation and amortization . . . . . 2,279,736 2,231,614
---------------- -----------------
Total . . . . . . . . . . . . . . . . . . . . . . . . 4,279,286 4,313,246
Construction work in progress . . . . . . . . . . . . . 300,552 281,757
Nuclear fuel, net of amortization . . . . . . . . . . . 59,788 52,084
---------------- -----------------
Utility plant - net . . . . . . . . . . . . . . . . . 4,639,626 4,647,087
---------------- -----------------
INVESTMENTS AND OTHER ASSETS :. . . . . . . . . . . . . . . 104,355 97,742
---------------- -----------------
CURRENT ASSETS:
Cash and cash equivalents . . . . . . . . . . . . . . . 20,300 18,389
Accounts receivable:
Service customers . . . . . . . . . . . . . . . . . . 86,595 100,433
Other . . . . . . . . . . . . . . . . . . . . . . . . 18,753 28,107
Allowance for doubtful accounts . . . . . . . . . . . (1,288) (1,656)
Accrued utility revenues . . . . . . . . . . . . . . . . 44,090 53,519
Materials and supplies, at average cost . . . . . . . . 77,660 78,271
Fossil fuel, at average cost . . . . . . . . . . . . . 21,284 21,722
Deferred income taxes . . . . . . . . . . . . . . . . . 5,637 5,653
Other . . . . . . . . . . . . . . . . . . . . . . . . . 17,412 17,839
---------------- -----------------
Total current assets . . . . . . . . . . . . . . . . 290,443 322,277
---------------- -----------------
DEFERRED DEBITS:
Regulatory asset for income taxes . . . . . . . . . . . 546,881 548,464
Palo Verde Unit 3 cost deferral . . . . . . . . . . . . 281,135 283,426
Palo Verde Unit 2 cost deferral . . . . . . . . . . . . 164,358 165,873
Unamortized costs of reacquired debt . . . . . . . . . . 67,431 63,518
Unamortized debt issue costs . . . . . . . . . . . . . . 17,483 17,772
Other . . . . . . . . . . . . . . . . . . . . . . . . . 273,713 272,103
---------------- -----------------
Total deferred debits . . . . . . . . . . . . . . . . 1,351,001 1,351,156
---------------- -----------------
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . $ 6,385,425 $ 6,418,262
================ =================
</TABLE>
See Notes to Condensed Financial Statements.
<PAGE>
-5-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
------------------------
LIABILITIES
(Unaudited)
<TABLE>
<CAPTION>
March 31, December 31,
1996 1995
-------------- --------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION:
Common stock . . . . . . . . . . . . . . . . . . . . . . $ 178,162 $ 178,162
Premiums and expense - net . . . . . . . . . . . . . . . 1,039,515 1,039,550
Retained earnings . . . . . . . . . . . . . . . . . . . 402,472 403,843
---------------- -----------------
Common stock equity . . . . . . . . . . . . . . . . . 1,620,149 1,621,555
Non-redeemable preferred stock . . . . . . . . . . . . . 174,089 193,561
Redeemable preferred stock . . . . . . . . . . . . . . . 72,000 75,000
Long-term debt less current maturities . . . . . . . . . 1,961,679 2,132,021
---------------- -----------------
Total capitalization . . . . . . . . . . . . . . . . . 3,827,917 4,022,137
---------------- -----------------
CURRENT LIABILITIES:
Commercial paper . . . . . . . . . . . . . . . . . . . . 159,600 177,800
Current maturities of long-term debt . . . . . . . . . . 153,512 3,512
Accounts payable . . . . . . . . . . . . . . . . . . . . 73,457 106,583
Accrued taxes . . . . . . . . . . . . . . . . . . . . . 146,474 82,827
Accrued interest . . . . . . . . . . . . . . . . . . . . 29,430 41,549
Customer deposits . . . . . . . . . . . . . . . . . . . 32,819 32,746
Other . . . . . . . . . . . . . . . . . . . . . . . . . 30,377 21,134
---------------- -----------------
Total current liabilities . . . . . . . . . . . . . . 625,669 466,151
---------------- -----------------
DEFERRED CREDITS AND OTHER:
Deferred income taxes . . . . . . . . . . . . . . . . . . 1,429,059 1,429,482
Deferred investment tax credit . . . . . . . . . . . . . 109,898 115,353
Unamortized gain - sale of utility plant . . . . . . . . 90,371 91,514
Customer advances for construction . . . . . . . . . . . 20,730 19,846
Other . . . . . . . . . . . . . . . . . . . . . . . . . 281,781 273,779
---------------- -----------------
Total deferred credits and other . . . . . . . . . . 1,931,839 1,929,974
---------------- -----------------
COMMITMENTS AND CONTINGENCIES (Notes 6 and 7)
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . $ 6,385,425 $ 6,418,262
================ =================
</TABLE>
See Notes to Condensed Financial Statements.
<PAGE>
-6-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
----------------------------------
(Unaudited)
<TABLE>
<CAPTION>
Three Months
Ended March 31,
-------------------------------------
1996 1995
---------------- -----------------
(Thousands of Dollars)
<S> <C> <C>
Cash Flows from Operating Activities:
Net income . . . . . . . . . . . . . . . . . . . . . . . $ 45,606 $ 37,832
Items not requiring cash:
Depreciation and amortization . . . . . . . . . . . . 58,386 60,426
Nuclear fuel amortization . . . . . . . . . . . . . . 8,357 7,723
AFUDC - equity . . . . . . . . . . . . . . . . . . . . (1,675) (1,186)
Deferred income taxes - net . . . . . . . . . . . . . 1,176 4,531
Deferred investment tax credit - net . . . . . . . . . (5,455) (3,858)
Changes in certain current assets and liabilities:
Accounts receivable - net . . . . . . . . . . . . . . 22,824 26,895
Accrued utility revenues . . . . . . . . . . . . . . . 9,429 9,885
Materials, supplies and fossil fuel . . . . . . . . . 1,049 (1,035)
Other current assets . . . . . . . . . . . . . . . . . 427 (2,829)
Accounts payable . . . . . . . . . . . . . . . . . . . (29,941) (26,184)
Accrued taxes . . . . . . . . . . . . . . . . . . . . 63,647 53,529
Accrued interest . . . . . . . . . . . . . . . . . . . (12,119) (10,719)
Other current liabilities . . . . . . . . . . . . . . 9,617 10,302
Other - net . . . . . . . . . . . . . . . . . . . . . . 12,608 (12,566)
---------------- -----------------
Net cash flow provided by operating activities . . . 183,936 152,746
---------------- -----------------
Cash Flows from Investing Activities:
Capital expenditures . . . . . . . . . . . . . . . . . . (60,138) (69,548)
Sale of Property . . . . . . . . . . . . . . . . . . . . 2,824 --
AFUDC - debt . . . . . . . . . . . . . . . . . . . . . . (3,237) (1,996)
Other . . . . . . . . . . . . . . . . . . . . . . . . . (6,613) (1,449)
---------------- -----------------
Net cash flow used for investing activities. . . . . (67,164) (72,993)
---------------- -----------------
Cash Flows from Financing Activities:
Long-term debt . . . . . . . . . . . . . . . . . . . . . 25,006 73,811
Short-term borrowings - net . . . . . . . . . . . . . . (18,200) (51,000)
Dividends paid on common stock . . . . . . . . . . . . . (42,500) (42,500)
Dividends paid on preferred stock . . . . . . . . . . . (4,778) (4,827)
Repayment of preferred stock . . . . . . . . . . . . . . (23,410) (4)
Repayment and reacquisition of long-term debt . . . . . (50,979) (51,867)
---------------- -----------------
Net cash flow used for financing activities . . . . (114,861) (76,387)
---------------- -----------------
Net increase in cash and cash equivalents . . . . . . . . 1,911 3,366
Cash and cash equivalents at beginning of period . . . . . 18,389 6,532
---------------- -----------------
Cash and cash equivalents at end of period . . . . . . . . $ 20,300 $ 9,898
================ =================
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest) . . . . . . $ 48,444 $ 51,900
Income taxes . . . . . . . . . . . . . . . . . . . . . $ -- $ --
</TABLE>
See Notes to Condensed Financial Statements.
<PAGE>
-7-
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS
1. In the opinion of the Company, the accompanying unaudited condensed financial
statements contain all adjustments (consisting of normal recurring accruals)
necessary to present fairly the financial position of the Company as of March
31, 1996, the results of operations for the three months and twelve months ended
March 31, 1996 and 1995, and the cash flows for the three months ended March 31,
1996 and 1995. It is suggested that these condensed financial statements and
notes to condensed financial statements be read in conjunction with the
financial statements and notes to financial statements included in the 1995
10-K. Certain prior year balances have been restated to conform to the current
year presentation.
2. The Company's operations are subject to seasonal fluctuations, with
variations occurring in energy usage by customers from season to season and from
month to month within a season, primarily as a result of changing weather
conditions. For this and other reasons, the results of operations for interim
periods are not necessarily indicative of the results to be expected for the
full year.
3. All the outstanding shares of common stock of the Company are owned by
Pinnacle West. Pursuant to a Pledge Agreement, dated as of January 31, 1990, and
as part of a restructuring of substantially all of its outstanding indebtedness,
Pinnacle West granted certain of its lenders a security interest in all of the
Company's outstanding common stock.
4. See "Liquidity and Capital Resources" in Part I, Item 2 of this report for
changes in capitalization for the three months ended March 31, 1996.
5. Regulatory Matters
Regulatory Agreement
In April 1996, the ACC approved a regulatory agreement between the
Company and the ACC Staff. This agreement is substantially the same as the
agreement proposed by the Company and the ACC Staff in December 1995. The major
provisions of the 1996 regulatory agreement are:
* An annual rate reduction of approximately $48.5 million ($29 million after
income taxes), or an average 3.4% for all customers except certain
contract customers, effective July 1, 1996.
* Recovery of substantially all of the Company's present regulatory assets
through accelerated amortization over an eight-year period beginning July
1, 1996, increasing annual amortization by approximately $120 million ($72
million after income taxes).
* A formula for sharing future cost savings between customers and
shareholders, referencing a return on equity (as defined) of 11.25%.
<PAGE>
-8-
* A moratorium on filing for permanent rate changes, except under the
sharing formula and under certain other limited circumstances, prior to
July 2, 1999.
* Infusion of $200 million of common equity into the Company by Pinnacle
West, in annual increments of $50 million starting in 1996.
In recognition of evolving competition in the electric utility industry
and an ongoing investigation by the ACC Staff into industry restructuring in an
open competition docket involving many parties, the agreement also includes an
element setting out a number of issues which the Company and the ACC Staff agree
the ACC should be requested to consider in developing restructuring policies.
See Note 3 of Notes to Financial Statements in Part II, Item 8 of the 1995 10-K
for further discussion of the industry restructuring element of the agreement.
1994 Settlement Agreement
In May 1994, the ACC approved a retail rate settlement agreement which
provided for a net annual retail rate reduction of approximately $32 million
($19 million after income taxes), or 2.2% on average, effective June 1, 1994. As
part of the settlement, in 1994 the Company reversed approximately $20 million
of depreciation ($15 million after income taxes) related to a 1991 Palo Verde
write-off. The 1994 rate settlement also provided for the accelerated
amortization of substantially all deferred ITCs over a five-year period
beginning in 1995, resulting in a decrease in annual income tax expense of
approximately $21 million.
6. The Palo Verde participants have insurance for public liability payments
resulting from nuclear energy hazards to the full limit of liability under
federal law. This potential liability is covered by primary liability insurance
provided by commercial insurance carriers in the amount of $200 million and the
balance by an industry-wide retrospective assessment program. If losses at any
nuclear power plant covered by this program exceed the accumulated funds for
this program, the Company could be assessed retrospective premium adjustments.
The maximum assessment per reactor under the program for each nuclear incident
is approximately $79 million, subject to an annual limit of $10 million per
incident. Based upon the Company's 29.1% interest in the three Palo Verde units,
the Company's maximum potential assessment per incident is approximately $69
million, with an annual payment limitation of approximately $9 million.
The Palo Verde participants maintain "all risk" (including nuclear
hazards) insurance for property damage to, and decontamination of, property at
Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of
which must first be applied to stabilization and decontamination. The Company
has also secured insurance against portions of any increased cost of generation
or purchased power and business interruption resulting from a sudden and
unforeseen outage of any of the three units. The insurance coverage discussed in
this and the previous paragraph is subject to certain policy conditions and
exclusions.
7. The Company has encountered tube cracking in the Palo Verde steam generators
and has taken, and will continue to take, remedial actions that
<PAGE>
-9-
it believes have slowed the rate of tube degradation. The projected service life
of the steam generators is reassessed periodically in conjunction with
inspections made during scheduled outages of the Palo Verde units. The Company's
ongoing analyses indicate that it will be economically desirable for the Company
to replace the Unit 2 steam generators, which have been most affected by tube
cracking, in five to ten years. The Company expects that the steam generator
replacement can be accomplished within financial parameters established before
replacement was a consideration, and the Company estimates that its share of the
replacement costs (in 1996 dollars and including installation and replacement
power costs) will be between $30 million and $50 million, most of which will be
incurred after the year 2000. The Company expects that the replacement would be
performed in conjunction with a normal refueling outage in order to limit
incremental outage time to approximately 50 days. Based on the latest available
data, the Company estimates that the Unit 1 and Unit 3 steam generators should
operate for the license periods (until 2025 and 2027, respectively), although
the Company will continue its normal periodic assessment of these steam
generators.
<PAGE>
-10-
ARIZONA PUBLIC SERVICE COMPANY
Item 2. Management's Discussion and Analysis of Financial Condition and Results
-----------------------------------------------------------------------
of Operations.
- --------------
Operating Results
- -----------------
The following table summarizes the Company's revenues and earnings for the
three-month and twelve-month periods ended March 31, 1996 and 1995:
<TABLE>
<CAPTION>
Periods ended March 31
(Thousands of Dollars)
Three Months Twelve Months
---------------------------------- ----------------------------------------
1996 1995 1996 1995
----------------- ---------------- ------------------- --------------------
<S> <C> <C> <C> <C>
Operating revenues $345,261 $336,968 $1,623,245 $1,617,087
Earnings for common stock $ 41,129 $ 33,025 $ 228,540 $ 220,279
</TABLE>
Operating Results - Three-month period ended March 31, 1996 compared
-----------------------------------------------------------------------
with three-month period ended March 31, 1995
--------------------------------------------
Earnings increased in the three-month period ended March 31, 1996
primarily due to customer growth, lower operations and maintenance expenses, and
lower interest expense. Operations and maintenance expenses decreased due to
fewer nuclear refueling outage days. Interest expense decreased due to lower
rates and lower average debt balances. Partially offsetting these positive
factors was a decrease in other income caused by the recognition of a gain on
the sale of a small subsidiary in 1995.
Operating Results - Twelve-month period ended March 31, 1996 compared
-----------------------------------------------------------------------
with twelve-month period ended March 31, 1995
---------------------------------------------
Earnings increased in the twelve-month period ended March 31, 1996
primarily due to customer growth, accelerated investment tax credit
amortization, lower fuel costs, and lower operations and maintenance expenses.
The accelerated investment tax credit amortization was a result of the 1994 rate
settlement (see Note 5 of Notes to Condensed Financial Statements in Part I,
Item 1 of this report) and is reflected as a decrease in income tax expense.
Fuel expense decreased due largely to lower fuel prices. Operations and
maintenance expenses decreased due to employee severance costs incurred in 1994,
lower fossil plant overhaul costs, and improved nuclear operations.
Partially offsetting these positive factors were milder weather, the
reversal in 1994 of certain previously-recorded depreciation related to Palo
Verde, the absence of non-cash accretion income and revenue refund reversals
related to a 1991 rate settlement (see Note 1 of Notes to Financial Statements
in Part II, Item 8 of the 1995 10-K), write-downs of an office building and
certain inventory, and a decrease in other income
<PAGE>
-11-
caused by the recognition of a gain on the sale of a small subsidiary in the
first quarter of 1995.
Other Income
------------
Other income reflects accounting practices required for regulated
public utilities and represents a composite of cash and non-cash items,
including AFUDC and accretion income on Palo Verde Unit 3, which the Company
completed recording in May 1994. See Note 1 of Notes to Financial Statements in
Part II, Item 8 of the 1995 10-K.
Regulatory Agreement
- --------------------
See Note 5 of Notes to Condensed Financial Statements in Part I, Item 1
of this report and Note 3 of Notes to Financial Statements in Part II, Item 8 of
the 1995 10-K for a discussion of the Company's regulatory agreement.
Liquidity and Capital Resources
- -------------------------------
For the three months ended March 31, 1996, the Company incurred
approximately $58 million in capital expenditures, accounting for approximately
24% of the most recently estimated 1996 capital expenditures. The Company has
estimated total capital expenditures for the years 1996, 1997 and 1998 to be
approximately $246 million, $242 million, and $244 million, respectively. These
amounts include about $30 million each year for nuclear fuel expenditures.
Obligations for redemptions of preferred stock and long-term debt, a
capitalized lease obligation, and certain actual and anticipated early
redemptions, including premiums thereon, are expected to total approximately
$123 million, $164 million, and $114 million for the years 1996, 1997, and 1998,
respectively. During the three months ended March 31, 1996, the Company redeemed
approximately $51 million of its long-term debt and approximately $23 million of
its preferred stock, and incurred $25 million of long-term debt under a
revolving credit agreement. It is the Company's present intention over the next
several years to use excess cash flow to retire debt and preferred stock.
Although provisions in the Company's bond indenture, articles of
incorporation, and financing orders from the ACC restrict the issuance of
additional first mortgage bonds and preferred stock, management does not expect
any of these restrictions to limit the Company's ability to meet its capital
requirements.
<PAGE>
-12-
PART II - OTHER INFORMATION
---------------------------
ITEM 1. Legal Proceedings
------------------------------
Property Taxes
--------------
As previously reported, in November 1995, the Arizona Court of Appeals
held that an Arizona state property tax law, effective December 31, 1989, is
unconstitutional and a lawsuit filed by the Palo Verde participants, including
the Company, was returned to the Arizona Tax Court for determination of the
appropriate remedy consistent with that decision. See "Property Taxes" in Part
I, Item 3 of the 1995 10-K. On April 23, 1996, the parties reached an agreement
to settle the pending litigation. Pursuant to the tentative settlement, the
Company will relinquish its claims for relief with respect to prior years and
the defendants will not challenge the Court of Appeals' decision concerning
prospective relief (for tax years 1996 and thereafter). The Company does not
expect this matter to have a material impact on its financial position or
results of operations.
ITEM 5. Other Information
------------------------------
Palo Verde Nuclear Generating Station
-------------------------------------
See Note 7 of Notes to Condensed Financial Statements in Part I, Item 1
of this report for a discussion of issues regarding the Palo Verde steam
generators.
Construction and Financing Programs
-----------------------------------
See "Liquidity and Capital Resources" in Part I, Item 2 of this report
for a discussion of the Company's construction and financing programs.
Environmental Matters
---------------------
The Comprehensive Environmental Response, Compensation, and Liability
Act ("Superfund") establishes liability for the cleanup of hazardous substances
found contaminating the soil, water, or air. Those who generated, transported or
disposed of hazardous substances at a contaminated site are among those who are
potentially responsible parties ("PRP's") and may be each strictly, and often
jointly and severally, liable for the cost of any necessary remediation of the
substances. The EPA had previously advised the Company that the EPA considers
the Company to be a PRP in the Indian Bend Wash Superfund Site, South Area,
where the Company's Ocotillo Power Plant is located. The Company is in the
process of conducting a voluntary investigation to determine the extent and
scope of contamination at the Plant site. Based on the information to date, the
Company does not expect this matter to have a material impact on its financial
position or results of operations.
<PAGE>
-13-
ITEM 6. Exhibits and Reports on Form 8-K
-----------------------------------------
(a) Exhibits
Exhibit No. Description
----------- -----------
10.1 Arizona Corporation Commission Order dated April 24, 1996
15.1 Letter in Lieu of Consent Regarding Unaudited Interim Financial
Information
27.1 Financial Data Schedule
(b) Reports on Form 8-K
During the quarter ended March 31, 1996, and the period ended May 14,
1996, the Company did not file any reports on Form 8-K.
<PAGE>
-14-
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the Company has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ARIZONA PUBLIC SERVICE COMPANY
(Registrant)
Dated: May 14, 1996 By Jaron B. Norberg
---------------------------- ----------------
Jaron B. Norberg
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer
and Officer Duly Authorized
to sign this Report)
EXHIBIT 10.1
BEFORE THE ARIZONA CORPORATION COMMISSION
RENZ D. JENNINGS
CHAIRMAN
MARCIA WEEKS
COMMISSIONER
CARL J. KUNASEK
COMMISSIONER
IN THE MATTER OF ARIZONA PUBLIC ) DOCKET NO. U-1345-95-491
SERVICE COMPANY'S RATE REDUCTION )
AGREEMENT. ) DECISION NO. 59601
)
_________________________________________) ORDER
Arizona Corporation Commission
Open Meeting DOCKETED
April 18, 1996 APR 24 1996
Phoenix, Arizona Docketed by
SS
FINDINGS OF FACT
----------------
1. Arizona Public Service Company ("APS") is an Arizona corporation
providing electric utility service within the State of Arizona.
2. The rates and charges currently in effect for APS were determined to
be just and reasonable in Decision No. 58644, dated June 1, 1994. That decision
approved a Settlement Agreement between Staff and APS which reduced rates.
3. Since Decision No. 58644, APS has continued its cost containment
efforts, and has experienced customer growth well above the national average,
and has recorded improved performance from nuclear and fossil-fueled generating
units.
4. APS is also faced with increasing competition and the uncertainty of
fundamental industry restructuring.
5. As a result of these events, and in order to prepare for the
transition to a more competitive marketplace, APS and Staff concluded that the
rates and charges previously authorized by the Commission for APS should be
reduced, accelerated amortization of regulatory assets should be allowed, and
additional incentives created for efficient operation. Staff and APS also
reached agreement on a number of interrelated issues.
6. The particulars of the agreement are memorialized in a written Rate
Reduction Agreement ("Agreement") dated December 4, 1995. On December 5, 1995,
Staff filed the Agreement with the Commission.
7. On January 5 and February 26, 1996, Procedural Orders governing the
conduct of this proceeding were issued. The Procedural Orders, inter alia, did
the following: required that APS provide notice by publication of the hearing in
this matter and provide copies of the Agreement to all parties of record in APS'
1994 rate reduction proceeding (Docket No. U-1345-94-120); established
procedures for intervention; established procedures for discovery; established
dates for Staff, APS and intervenors to file testimony or comments; and set a
hearing date at which all parties would be able to present witnesses and
evidence and cross-examine the witnesses of other parties.
8. Requests for intervention were filed by the Residential Utility
Consumer Office (January 8, 1996), Cyprus Bagdad Copper Corporation (January 19,
1996), the Department of the Navy (February 9, 1996), Southwest Gas Corporation
(February 12, 1996), Citizens Utilities Company (February 12, 1996), Arizona
Electric Power Cooperative, Inc. (February 13, 1996), Arizona Cotton Growers
Association (February 14, 1996), Tucson Electric Power Company (February 15,
1996), Lor-D's Ranch Mineso Dairy (February 15, 1996), Nordic Power of
Southpoint I, LP (February 15, 1996), Arizona Interfaith Coalition on Energy
(February 15, 1996), Maricopa County (February 15, 1996), Arizona Community
Action Association (February 16, 1996), Arizonans for Sustainable Growth
(February 16, 1996), Salt River Project Agricultural Improvement and Power
District (February 16, 1996), Arizona Association of Industries (February 16,
1996) and Arizona Cogeneration Association (February 16, 1996).
9. Intervention was granted by Procedural Order dated January 10, 1996
for the Residential Utility Consumer Office; by Procedural Order dated January
29, 1996, for Cyprus Bagdad Copper Corporation; by Procedural Order dated
February 14, 1996, for Department of the Navy, Southwest Gas Corporation, and
Citizens Utilities Company; by Procedural Order dated February 21, 1996, for
Arizona Electric Power Cooperative, Inc., Arizona Cotton Growers Association,
Lor-D's Ranch Mineso Dairy, Arizona Interfaith Coalition on Energy, Maricopa
County, Arizona Community Action Association, Arizonans for Sustainable Growth,
Salt River Project Agricultural Improvement and Power District, Arizona
Association of Industries, and Arizona Cogeneration Association; and by
Procedural Order dated February 29, 1996, for Tucson Electric Power Company.
10. All intervenors had the opportunity to file comments regarding the
Agreement, to file written testimony, and to present witnesses and exhibits and
to cross-examine witnesses presented by other parties.
11. Beginning on April 9, 1996, a hearing was held on this matter at
the Commission's offices in Phoenix, Arizona.
12. On April 11, 1996, Staff and APS submitted a Restated and Amended
Rate Reduction Agreement, which addressed certain of theintervenor comments and
corrected certain errors and omissions in the earlier Agreement.
13. On April 18, 1996, APS and Staff submitted a Second Restated and
Amended Rate Reduction Agreement ("Amended Agreement"), which addressed
additional concerns of intervenors and made other minor corrections to the
Agreement. The Amended Agreement also adopted certain proposed changes to the
Agreement from each of the Commissioners.
14. Staff and APS believe that the Amended Agreement they have reached
is consistent with the best interests of the parties and the public interest
generally. A copy of the Amended Agreement is attached hereto as Exhibit 1.
15. Pursuant to the Amended Agreement, Staff and APS have agreed to the
following:
A. APS will implement a first year rate decrease of
$48.5 million, or 3.26%. Base rates will be reduced
by $39.3 million, and the EEASE surcharge will be
abolished resulting in a further decrease of $9.2
million. The rate decrease is based on retail sales
to and revenues from eligible customers for the
adjusted test year ended June 30, 1995. See Revised
Attachment 1 to the Amended Agreement for details of
the calculation. Such rate reduction will become
effective July 1, 1996 or immediately upon a
Commission order approving the Plan, whichever is
later. Such rate reduction will be allocated among
customers as shown in Revised Attachment 1 to the
Amended Agreement.
B. In order to provide customers with the opportunity
for further price reductions, while maintaining its
financial stability, the Company must continue to
lower its average cost/kWh. To the extent the
Company is successful, customers and shareholders
will benefit. Each year following the initial rate
reduction described in Paragraph A, above, through
and including July 1, 1999 (the "Moratorium
Period"), APS rates would be subject to a reduction
in base rates determined as follows: if the average
price/kWh exceeds the average cost/kWh, as defined
in Attachment 3 to the Amended Agreement, based on
results of operations for the preceding calendar
year, then 55% of the difference will be reflected
as a reduction in base rates effective July 1 of the
current year. However, if APS experiences a decrease
in Property Tax Expense from the previous year, then
APS should identify that amount and include the
following calculation in its filing of its annual
rate incentive filing pursuant to Paragraph 4 of
this Amended Agreement: if the UPR (as defined in
Attachment 3) exceeds the UCR (as also defined in
Attachment 3), APS should adjust the 55 percent
ratepayer share to reflect inclusion of the
Company's 45% share of such Property Tax Expense
decrease that would otherwise result from the
Amended Agreement's calculation of the rate
incentive mechanism described in this Paragraph.
After giving effect to the consolidation,
elimination and restructuring of certain existing
rate offerings as discussed below, any net revenue
decrease would be allocated among customers by means
of a uniform percent reduction in the demand and
energy charges for all current APS rate schedules,
except those set forth in Attachment 2 to the
Amended Agreement. In any year, if the average
cost/kWh is equal to or exceeds the average
price/kWh, there would be no further change in base
rates (neither a decrease nor an increase in base
rates for that year).
C. Under this Amended Agreement, certain regulatory
assets will be recovered by accelerating their
amortization over an eight year period commencing
July 1, 1996. These assets are primarily cost
deferrals from Palo Verde Units 2 and 3, that were
recorded under ACC approved accounting orders, and
regulatory assets to cover future income tax
liabilities recorded in 1993 as a result of
implementing Financial Accounting Standard No. 109
with respect to deferred income taxes. This
amortization will be included in the calculation of
the average cost/kWh. The accelerated amortization
approved in this proceeding is for the purpose of
settlement and anticipates the transition period
toward a more competitive marketplace. Further, APS
agrees that the accelerated amortization of these
regulatory assets cannot be used as a separate
justification for a net rate increase in any future
rate proceeding. Finally, at the end of the
Moratorium Period, the accelerated rate of
amortization will continue until further order of
the Commission.
D. The determination of the reduction to base rates for
the succeeding years will be determined pursuant to
the Company's calculation of the average price and
cost/kWh using data from the prior calendar year. A
filing of this calculation will be made on or about
March 1 of each year for Staff review. Such filing
will also be made available to the Arizona
Residential Consumer Office ("RUCO") for its review
and comment. Any reduction for the current year will
become effective for usage on or after July 1, if
and only if such reduction is approved by the
Commission. If the Commission orders a hearing on
such decrease, this would automatically delay the
effective date of any decrease until a final order
is issued.
E. To improve the Company's equity ratio in
anticipation of greater competition, Pinnacle West
Capital Corporation will infuse $200 million of
common equity, in $50 million increments, by each
year-end beginning in 1996, into APS with such
infusion to be included in calculating each year's
average cost/kWh under the Amended Agreement.
F. During the Moratorium Period, no party shall seek to
change the rates except as set forth specifically in
the Amended Agreement. However, neither APS nor
Staff shall be prevented from seeking a change in
rates prior to July 2, 1999 in the event of: (a)
conditions or circumstances which constitute an
emergency, such as the inability to finance on
reasonable terms, or (b) material changes in the
Company's cost of service as a result of federal,
tribal, state or local laws, regulatory
requirements, judicial decisions, actions, or
orders.
G. The parties agree to the following revisions of
current rate schedules and new tariffs:
i. A flexible pricing tariff provision as was
suggested by the Company in Revised
Attachment 4 should be considered in the
Commission's electric competition docket
(Docket No. U-0000-94-165).
ii. The Company shall retain the right to
propose for Commission approval during the
Moratorium Period new or revised rate
designs. Examples of this type of filing
might be:
a. Revised time-of-use (TOU) pricing
periods and prices (both residential
and general service) once advanced
meter communications systems are in
place. APS agrees to submit such a
TOU proposal before December 31,
1996.
b. A real-time pricing experiment or
operational program.
c. Unbundled retail rates to provide
customers alternative service options.
H. The parties agree to the following changes to
current rate schedules. These changes are designed
to more accurately reflect the costs to serve,
promote fairness among similar customer groups, and
improve customer understanding and acceptability of
the pricing, terms and conditions of the tariffs.
i. Revise Schedule #1, General Terms and
Conditions of Service, so that credit and
collections practices and charges fairly and
properly collect costs from customers who
impose those costs on APS without subsidies
from other customers. The parties also agree
to other minor changes to clarify current
practices and service specifications. These
proposed changes are summarized in Revised
Attachment 5 to the Agreement.
ii. Revise partial requirements provisions of
the tariff to consistently and fairly charge
for services provided. APS has a variety of
rates applicable to various types of partial
requirements customers and these are
proposed to be revised to apply market-based
charges for standby, and cost-based charges
for supplemental and maintenance service.
The proposed tariffs (Schedules E-55 and
E-52) are attached as Revised Attachment 6.
Schedules E-55 and E-52 shall:
* indicate that the customer
designates the amount of standby
capacity he or she wants in setting
the contract standby capacity and
that the capacity could be less than
the capacity of the self generation
facility.
In addition, APS shall review whether the
potential for lower rates for a customer
with a capacity factor consistently below 75
percent (relative to a customer with a
higher capacity factor) is in need of
correction or clarification.
Schedule E-51 shall be frozen to new and
reconnecting customers.
Schedule E-50 shall be cancelled.
iii. EPR-1, -2, and -3, purchase rates for small
qualified cogeneration customers, would be
revised to reflect current buy-back rates,
current metering technology and establish
consistency among the rates. Schedule EPR-4
shall reference schedules for sales to the
customer. In addition, Schedule EPR-2 shall
offer an option for the incremental cost of
the bidirectional meter to be paid in a lump
sum or in monthly installments over a
specified time period. Schedule EPR-1 will
be canceled. Proposed tariffs (Schedules
EPR-2, EPR-3, and EPR-4) are attached as
Attachment 7 to the Amended Agreement.
iv. Eliminate extra-small general service Rate
E-31 and incorporate E-31 into Schedule E-32
so that the monthly service charge under the
new Schedule E-32 is $12.50, and the energy
charge (prior to application of the rate
decrease) is increased by $0.00024 per kWh
for all kWh.
v. APS shall also submit a new rate (E-20)
applicable only to "houses of worship." Said
rate shall be open to all qualified
customers and shall in all other respects be
identical to E-21, which latter rate shall
be frozen. A copy of proposed E-20 is
attached as Attachment 10.
vi. APS shall revise Schedule E-3 so that when
an otherwise eligible customer uses more
than 1200 kWh in any month, such customer
will continue to receive a discount under
E-3 for that month, but that discount will
be a flat $10. A copy of revised Schedule
E-3 is attached as Attachment 11 to the
Amended Agreement.
vii. APS shall revise Schedule E-4 so that when
an otherwise eligible customer uses more
than 2000 kWh in any month, such customer
will continue to receive a discount under
E-4 for that month, but that discount will
be a flat $20. A copy of revised Schedule
E-4 is attached as Attachment 12 to the
Amended Agreement.
I. The electric base rates proposed to be effective in
1996 include the costs associated with depreciation
and decommissioning expense schedules currently being
used by APS. The results of any future Palo Verde
decommissioning cost or plant depreciation studies
completed during the Moratorium Period would be
reflected in the average cost/kWh used in the
calculation of additional base rate reductions
described in Paragraph B, above. Any depreciation or
decommissioning study would be reviewed by Staff and
RUCO, and the new schedules derived therefrom would
be authorized and approved in accordance with the
procedure established in Section 13.H of Decision No.
58644.
J. APS' commitment to foster investment in DSM and
renewables continues and shall be implemented as
follows:
i. The EEASE fund shall be eliminated. Any
over-recovery shall be refunded to customers
through a one-time refund within 120 days of
the effective date of the Commission's
order. APS will work with Staff and RUCO on
a procedure to effectuate this provision.
ii. A total of $7 million will be included in
base rates for demand side management (DSM)
and renewables. Of the $7 million total, APS
shall undertake at least $3 million of
renewables programs per year on average and
at least $3 million of DSM per year on
average.
APS shall spend at least $7 million per year
on DSM and renewables projects consistent
with this Paragraph J. Moreover, APS shall
attempt to identify and shall be authorized
to expend and include in its calculation of
UCR up to an additional $3 million per year
on additional direct DSM program costs
and/or renewables. If APS spends less than
the $7 million included in base rates on
renewables and DSM per year on average, the
Commission, at the next rate case, shall
review these expenditures and may order
appropriate refunds to ratepayers taking
into consideration any sharing that has
occurred as a result of paragraph B, above.
iii. APS shall move to phase out consumer rebate
DSM programs for customers and instead
substitute shareholder-funded, market-based
DSM programs for larger customers and, for
all customers, develop and implement
ratepayer-funded market transformation
activities (such as trade ally programs or
consumer education programs). However, costs
(including incentives and net lost revenues)
for existing and approved customer rebate
programs shall be included in the
calculation of the Company's $7 million
obligation under this paragraph until such
programs have been phased out. APS shall
evaluate the effectiveness of market
transformation programs.
iv. APS shall continue its low income DSM
program (at least at current levels),
complete current monitoring and evaluation
commitments, and fulfill outstanding
commitments under existing rebate programs.
v. APS shall prepare an administrative and
implementation plan for Staff review and
approval for its DSM and renewables programs
within six months of the effective date of
this decision. APS shall prepare proposals
for new DSM and renewables programs for
Staff review and approval.
vi. APS shall file detailed semi-annual reports
with Staff and in Docket Control on all DSM
and renewables activities, although
confidential information need not be filed
in Docket Control.
K. APS recognizes that the jurisdictional portion of any
net refund that it receives as a result of
disposition of the property tax lawsuit (Tucson
Electric Power v. Apache County, 175 Ariz. 485 (App.
1995)) is owed to its customers, since these taxes
were collected from and paid by customers to APS
through rates. Therefore, APS will refund to its
customers the net jurisdictional amount of
overcollected property taxes that are refunded to APS
by the State of Arizona. APS agrees to work
cooperatively with Staff and RUCO to determine the
amount of any refund and method for returning the
refund to customers.
L. The rates and charges authorized herein fully include
a return on the recorded book original cost of all
jurisdictional APS assets (net of depreciation,
amortization, and deferred income taxes and other
deferred credits) as of June 30, 1995, excepting
construction work in progress as of such date.
However, nothing in this Amended Agreement shall be
construed as prohibiting Staff or any other party
from pursuing new issues related to expenditures made
or actions taken after June 30, 1995.
M. Staff and APS stipulate to the adoption of the fair
value rate base and fair rate of return and agree
that the resultant revenue decrease, as reflected in
Paragraph A above, results in just and reasonable
rates for the Company. The determinations made in
this Paragraph are made solely for the purpose of the
stipulation contained in this Amended Agreement.
N. Each provision of the Amended Agreement is in
consideration and support of all the other
provisions. The Amended Agreement shall not become
effective until the issuance of a final Commission
Order approving the Amended Agreement without change
or alteration on or before July 1, 1996 in the form
of a Proposed Order agreed to by the parties. In the
event that the Commission fails to adopt the Amended
Agreement according to its terms on or before July 1,
1996, the Amended Agreement shall be deemed
automatically withdrawn, the rate reduction
provisions of the Amended Agreement shall not take
effect, and APS and Staff shall be free to pursue
their respective positions without prejudice. In
addition, if any appeal is taken or other judicial
review is sought of a final Commission Order
approving the Amended Agreement, then the parties
shall no longer be bound by the terms of the Amended
Agreement and the Amended Agreement shall
automatically become null and void, in which case:
(1) the rate reduction specified in Paragraph A,
above, shall immediately cease; (2) all bills
rendered on or after that date shall be at the rates
existing immediately prior to the Commission's
approval of the Amended Agreement; and (3) the
revenue reduction theretofore experienced by APS
pursuant to Paragraph A, above, shall be recovered
through a surcharge mechanism.
O. The terms and provisions of the Amended Agreement
apply solely to and are binding only in the context
of the purposes and results of the Amended Agreement
and none of the positions taken herein by APS may be
referred to, cited or relied upon by any other party
in any fashion as precedent or otherwise in any other
proceeding before this Commission or any other
regulatory agency or before any court of law for any
purpose except in furtherance of the purposes and
results of the Amended Agreement. Nothing in the
Amended Agreement shall be construed as imposing a
cap on the Company's otherwise reasonable and prudent
cost of service for purposes of setting just and
reasonable rates.
P. The Amended Agreement represents an attempt to
compromise and settle issues regarding the
prospective just and reasonable rate levels for APS
in a manner consistent with the public interest and
applicable legal requirements. Nothing contained in
the Amended Agreement is an admission by APS that its
current rate levels or rate design are unjust or
unreasonable.
Q. APS' agreement to the matters contained herein is
predicated on a national movement toward competition
in the electricity industry. That movement raises a
number of policy and legal issues in Arizona which
are summarized (not necessarily completely) in the
Points of Agreement (Attachment 8 to the Amended
Agreement). APS has its own views, independent of any
the Staff may have, of the proper resolution of
certain of the issues presented in the Points of
Agreement. Such views are summarized in Attachment 9
to the Amended Agreement.
16. Neither the Amended Agreement nor this Order purports to resolve
the issues identified in Attachments 8 and 9 to the Agreement, nor does the
Amended Agreement or this Order bind the parties or the Commission to take or
adopt any particular substantive position with regard to those issues.
17. The Commission's approval of the Amended Agreement, and the
implementation of the rate reduction and other matters contained in the Amended
Agreement, are not conditioned upon the resolution of the issues identified in
Attachments 8 and 9 to the Amended Agreement.
18. Paragraph 9 of the Amended Agreement, as submitted, contemplates
the filing and approval of depreciation or decommissioning studies without
explicitly stating a requirement that those studies be submitted to the
Commission for consideration in Open Meeting. Under Paragraph 9 of the Amended
Agreement, as submitted, changes in depreciation or decommissioning costs as a
result of such studies may affect base rates by virtue of their inclusion in the
calculation of average cost/kWh in connection with Paragraph 2 of the Amended
Agreement.
CONCLUSIONS OF LAW
------------------
1. APS is a public service corporation within the meaning of Article 15
of the Arizona Constitution and Title 40 of the Arizona Revised Statutes.
2. The Commission has jurisdiction over APS, over the subject matter of
this proceeding, and over the Amended Agreement submitted by the Staff and APS.
3. APS provided notice of this matter in accordance with law.
4. The Amended Agreement resolves all matters contained therein in a
manner which is just and reasonable, and which promotes the public interest.
5. The Commission's acceptance and approval of the terms of the Amended
Agreement between Staff and APS are in the public interest.
6. Based on the Amended Agreement of APS and Staff, for purposes of
this proceeding, APS' fair value rate base as of June 30, 1995, is
$4,890,018,000, and a fair and reasonable rate of return on that fair value rate
base is 5.34%.
7. Based on the Amended Agreement between APS and Staff, it is
appropriate to reduce APS' authorized revenues by $48.5 million from July 1,
1995 sales as adjusted, to be allocated among customers by means of the
reduction as shown in Revised Attachment 1 to the Amended Agreement.
8. APS should be directed to file revised tariffs consistent with the
Amended Agreement and the findings contained herein.
9. The rates and charges authorized herein are just and reasonable.
10. Neither the Amended Agreement nor this Order resolves the issues
identified in Attachments 8 and 9 to the Amended Agreement, nor does the Amended
Agreement or this Order bind the parties or the Commission to take or adopt any
particular substantive position with regard to those issues.
11. It is not in the public interest to approve the provisions of
Paragraph 9 of the Amended Agreement, insofar as those provisions contemplate
the filing and approval of changes in depreciation or decommissioning costs,
which could affect base rates without explicitly requiring that those changes in
depreciation or decommissioning costs be submitted to the Commission for
consideration in Open Meeting.
ORDER
-----
IT IS THEREFORE ORDERED that APS shall decrease its rates and
charges for all usage on or after July 1, 1996, consistent with the Findings of
Fact and Conclusions of Law contained herein so as to result in an annual
decrease of $48.5 million based on June 30, 1995 sales as adjusted, to be
allocated among customers by means of the reduction shown in Revised Attachment
1 to the Amended Agreement.
IT IS FURTHER ORDERED that this Order incorporates the Amended
Agreement executed April 18, 1996, between APS and Staff, and such Order is
expressly conditioned thereon.
IT IS FURTHER ORDERED that the terms and conditions of the
Amended Agreement be and the same are hereby adopted and approved.
IT IS FURTHER ORDERED that this Order shall not resolve the
issues identified in Attachments 8 and 9 to the Amended Agreement, and that this
Order shall not bind the parties or the Commission to take or adopt any
particular substantive position with regard to those issues.
IT IS FURTHER ORDERED that APS is authorized and directed to
file revised schedules of rates and charges consistent with the Findings and
Conclusions of this Order.
IT IS FURTHER ORDERED that APS is authorized to accelerate the
amortization of its regulatory assets in the manner, to the extent and for the
purposes set forth in the Amended Agreement.
IT IS FURTHER ORDERED that the EEASE fund be, and is hereby,
eliminated, and that any over-recovery shall be refunded to customers through a
one-time refund within 120 days of the effective date of this Order.
IT IS FURTHER ORDERED that neither APS nor Commission Staff
shall file any application to change the rates of APS prior to July 2, 1999,
except as set forth specifically in the Amended Agreement.
IT IS FURTHER ORDERED rejecting the provisions of Paragraph 9
of the Amended Agreement, insofar as those provisions contemplate the filing and
approval of changes in depreciation or decommissioning costs, which could affect
base rates without explicitly requiring that those changes in depreciation or
decommissioning costs be submitted to the Commission for consideration in Open
Meeting. No changes in depreciation or decommissioning costs pursuant to the
Amended Agreement, or this Decision, shall be effective absent consideration and
approval by the Commission in Open Meeting. To the extent this provision
conflicts with the procedure established in Section 13.H of Decision No. 58644,
the provisions of this Decision shall be followed.
IT IS FURTHER ORDERED that this Order shall become effective immediately.
BY ORDER OF THE ARIZONA CORPORATION COMMISSION
Renz D. Jennings Marcia Weeks Carl J. Kunasek
- ----------------------- --------------------- -------------------
CHAIRMAN COMMISSIONER COMMISSIONER
IN WITNESS WHEREOF, I, JAMES
MATTHEWS, Executive Secretary
of the Arizona Corporation
Commission, have hereunto, set
my hand and caused the
official seal of this
Commission to be affixed at
the Capitol, in the City of
Phoenix, this 24 day of April,
1996.
James Matthews
------------------------------
JAMES MATTHEWS
Executive Secretary
DISSENT____________________
<PAGE>
EXHIBIT 1
SECOND RESTATED AND AMENDED RATE REDUCTION AGREEMENT
----------------------------------------------------
Staff of the Arizona Corporation Commission (Staff) and Arizona Public
Service Company (APS or Company) hereby further restate and amend the Rate
Reduction Agreement dated December 4, 1995 and amended April 10, 1996, as
follows:
1. APS will implement a first year rate decrease of $48.5
million, or 3.26%. Base rates will be reduced by $39.3
million, and the EEASE surcharge will be abolished resulting
in a further decrease of $9.2 million. The rate decrease is
based on retail sales to and revenues from eligible customers
for the adjusted test year ended June 30, 1995. See Revised
Attachment 1 for details of the calculation. Such rate
reduction will become effective July 1, 1996 or immediately
upon a Commission order approving the Plan, whichever is
later. Such rate reduction will be allocated among customers
as shown in Revised Attachment 1.
2. In order to provide customers with the opportunity for further
price reductions, while maintaining its financial stability,
the Company must continue to lower its average cost/kWh. To
the extent the Company is successful, customers and
shareholders will benefit. Each year following the initial
rate reduction described in Paragraph 1, through and including
July 1, 1999 (the "Moratorium Period"), APS rates would be
subject to a reduction in base rates determined as follows: if
the average price/kWh exceeds the average cost/kWh, as defined
in Attachment 3, based on results of operations for the
preceding calendar year, then 55% of the difference will be
reflected as a reduction in base rates effective July 1 of the
current year. However, if APS experiences a decrease in
Property Tax Expense from the previous year, then APS should
identify that amount and include the following calculation in
its filing of its annual rate incentive filing pursuant to
Paragraph 4 of this Amended Agreement: if the UPR (as defined
in Attachment 3) exceeds the UCR (as also defined in
Attachment 3), APS should adjust the 55 percent ratepayer
share to reflect inclusion of the Company's 45% share of such
Property Tax Expense decrease that would otherwise result from
the Amended Agreement's calculation of the rate incentive
mechanism described in this Paragraph. After giving effect to
the consolidation, elimination and restructuring of certain
existing rate offerings as discussed below, any net revenue
decrease would be allocated among customers by means of a
uniform percentage reduction in the demand and energy charges
for all current APS rate schedules, except those set forth in
Attachment 2. In any year, if the average cost/kWh is equal to
or exceeds the average price/kWh, there would be no further
change in base rates (neither a decrease nor an increase in
base rates for that year).
3. Under this Amended Agreement, certain regulatory assets will
be recovered by accelerating their amortization over an eight
year period commencing July 1, 1996. These assets are
primarily cost deferrals from Palo Verde Units 2 and 3, that
were recorded under ACC approved accounting orders, and
regulatory assets to cover future income tax liabilities
recorded in 1993 as a result of implementing Financial
Accounting Standard No. 109 with respect to deferred income
taxes. This amortization will be included in the calculation
of the average cost/kWh. The accelerated amortization approved
in this proceeding is for the purpose of settlement and
anticipates the transition period toward a more competitive
marketplace. Further, APS agrees that the accelerated
amortization of these regulatory assets cannot be used as a
separate justification for a net rate increase in any future
rate proceeding. Finally, at the end of the Moratorium Period,
the accelerated rate of amortization will continue until
further order of the Commission.
4. The determination of the reduction to base rates for the
succeeding years will be determined pursuant to the Company's
calculation of the average price and cost/kWh using data from
the prior calendar year. A filing of this calculation will be
made on or about March 1 of each year for Staff review. Such
filing will also be made available to the Arizona Residential
Consumer Office ("RUCO") for its review and comment. Any
reduction for the current year will become effective for usage
on or after July 1, if and only if such reduction is approved
by the Commission. If the Commission orders a hearing on such
decrease, this would automatically delay the effective date of
any decrease until a final order is issued.
5. To improve the Company's equity ratio in anticipation of
greater competition, Pinnacle West Capital Corporation will
infuse $200 million of common equity, in $50 million
increments, by each year-end beginning in 1996, into APS with
such infusion to be included in calculating each year's
average cost/kWh under this Amended Agreement.
6. During the Moratorium Period, no party shall seek to change
the rates except as set forth specifically in this Amended
Agreement. However, neither APS nor Staff shall be prevented
from seeking a change in rates prior to July 2, 1999 in the
event of: (a) conditions or circumstances which constitute an
emergency, such as the inability to finance on reasonable
terms, or (b) material changes in the Company's cost of
service as a result of federal, tribal, state or local laws,
regulatory requirements, judicial decisions, actions, or
orders.
7. The parties agree to the following revisions of current rate
schedules and new tariffs:
a. Any flexible pricing tariff provision as was
suggested by APS in Revised Attachment 4 should be
considered in the Commission's electric competition
docket (Docket No. U-0000-94-165).
b. The Company shall retain the right to propose for
Commission approval during the Moratorium Period new
or revised rate designs. Examples of this type of
filing might be:
i. Revised time-of-use (TOU) pricing periods
and prices (both residential and general
service) once advanced meter communications
systems are in place. APS agrees to submit
such a TOU proposal before December 31,
1996.
ii. A real-time pricing experiment or
operational program.
iii. Unbundled retail rates to provide customers
alternative service options.
8. The parties agree to the following changes to current rate
schedules. These changes are designed to more accurately
reflect the costs to serve, promote fairness among similar
customer groups, and improve customer understanding and
acceptability of the pricing, terms and conditions of the
tariffs.
a. Revise Schedule #1, General Terms and Conditions of
Service, so that credit and collections practices and
charges fairly and properly collect costs from
customers who impose those costs on APS without
subsidies from other customers. The parties also
agree to other minor changes to clarify current
practices and service specifications. These proposed
changes are summarized in Revised Attachment 5.
b. Revise partial requirements provisions of the tariff
to consistently and fairly charge for services
provided. APS has a variety of rates applicable to
various types of partial requirements customers and
these are proposed to be revised to apply
market-based charges for standby, and cost-based
charges for supplemental and maintenance service. The
proposed tariffs (Schedules E-55 and E-52) are
attached as Revised Attachment 6.
Schedules E-55 and E-52 shall:
* indicate that the customer designates the
amount of standby capacity he or she wants
in setting the contract standby capacity and
that the capacity could be less than the
capacity of the self generation facility.
In addition, APS shall review whether the potential
for lower rates for a customer with a capacity factor
consistently below 75 percent (relative to a customer
with a higher capacity factor) is in need of
correction or clarification.
Schedule E-51 shall be frozen to new and reconnecting
customers.
Schedule E-50 shall be cancelled.
c. EPR-1, -2, and -3, purchase rates for small qualified
cogeneration customers, would be revised to reflect
current buy-back rates, current metering technology
and establish consistency among the rates. Schedule
EPR-4 shall reference schedules for sales to the
customer. In addition, Schedule EPR-2 shall offer an
option for the incremental cost of the bidirectional
meter to be paid in a lump sum or in monthly
installments over a specified time period. Schedule
EPR-1 will be cancelled. Proposed tariffs (Schedules
EPR-2, EPR-3, and EPR-4) are attached as Attachment
7.
d. Eliminate extra-small general service Rate E-31 and
incorporate E-31 into Schedule E-32 so that the
monthly service charge under the new Schedule E-32 is
$12.50, and the energy charge (prior to application
of the rate decrease) is increased by $0.00024 per
kWh for all kWh.
e. APS shall submit a new rate (E-20) applicable only to
"houses of worship." Said rate shall be open to all
qualified customers and shall in all other respects
be identical to E-21, which latter rate shall be
frozen. A copy of proposed E-20 is attached as
Attachment 10.
f. APS shall revise Schedule E-3 so that when an
otherwise eligible customer uses more than 1200 kWh
in any month, such customer will continue to receive
a discount under E-3 for that month, but that
discount will be a flat $10. A copy of revised
Schedule E-3 is attached as Attachment 11.
g. APS shall revise Schedule E-4 so that when an
otherwise eligible customer uses more than 2000 kWh
in any month, such customer will continue to receive
a discount under E-4 for that month, but that
discount will be a flat $20. A copy of revised
Schedule E-4 is attached as Attachment 12.
9. The electric base rates proposed to be effective in 1996
include the costs associated with depreciation and
decommissioning expense schedules currently being used by APS.
The results of any future Palo Verde decommissioning cost or
plant depreciation studies completed during the Moratorium
Period would be reflected in the average cost/kWh used in the
calculation of additional base rate reductions described in
Paragraph 2. Any depreciation or decommissioning study would
be reviewed by Staff and RUCO, and the new schedules derived
therefrom would be authorized and approved in accordance with
the procedure established in Section 13.H of Decision No.
58644.
10. APS' commitment to foster investment in DSM and renewables
continues and shall be implemented as follows:
a. The EEASE fund shall be eliminated. Any over-recovery
shall be refunded to customers through a one-time
refund within 120 days of the effective date of the
Commission's order. APS will work with Staff and RUCO
on a procedure to effectuate this provision.
b. A total of $7 million will be included in base rates
for demand side management (DSM) and renewables. Of
the $7 million total, APS shall undertake at least $3
million of renewables programs per year on average
and at least $3 million of DSM per year on average.
APS shall spend at least $7 million per year on DSM
and renewables projects consistent with this
Paragraph 10. Moreover, APS shall attempt to
identify, and be authorized to expend and include in
its calculation of UCR, up to an additional $3
million per year on additional direct DSM program
costs and/or renewables. If APS spends less than the
$7 million included in base rates on renewables and
DSM per year on average, the Commission, at the next
rate case, shall review these expenditures and may
order appropriate refunds to ratepayers taking into
consideration any sharing that has occurred as a
result of Paragraph 2.
c. APS shall move to phase out consumer rebate DSM
programs for customers and instead substitute
shareholder-funded, market-based DSM programs for
larger customers and, for all customers, develop and
implement ratepayer-funded market transformation
activities (such as trade ally programs or consumer
education programs). However, costs (including
incentives and net lost revenues) for existing and
approved customer rebate programs shall be included
in the calculation of the Company's $7 million
obligation under this Paragraph until such programs
have been phased out. APS shall evaluate the
effectiveness of market transformation programs.
d. APS shall continue its low income DSM program (at
least at current levels), complete current monitoring
and evaluation commitments, and fulfill outstanding
commitments under existing rebate programs.
e. APS shall prepare an administrative and
implementation plan for Staff review and approval for
its DSM and renewables programs within six months of
the effective date of this decision. APS shall
prepare proposals for new DSM and renewables programs
for Staff review and approval.
f. APS shall file detailed semi-annual reports with
Staff and in Docket Control on all DSM and renewables
activities, although confidential information need
not be filed in Docket Control.
11. APS recognizes that the jurisdictional portion of any net
refund that it receives as a result of disposition of the
property tax lawsuit (Tucson Electric Power v. Apache County,
175 Ariz. 485 (App. 1995)) is owed to its customers, since
these taxes were collected from and paid by customers to APS
through rates. Therefore, APS will refund to its customers the
net jurisdictional amount of overcollected property taxes that
are refunded to APS by the State of Arizona. APS agrees to
work cooperatively with Staff and RUCO to determine the amount
of any refund and method for returning the refund to
customers.
12. The rates and charges authorized herein fully include a return
on the recorded book original cost of all jurisdictional APS
assets (net of depreciation, amortization, and deferred income
taxes and other deferred credits) as of June 30, 1995,
excepting construction work in progress as of such date.
However, nothing in this Amended Agreement shall be construed
as prohibiting Staff or any other party from pursuing new
issues related to expenditures made or actions taken after
June 30, 1995.
13. Staff and APS stipulate to the adoption of the fair value rate
base and fair rate of return and agree that the resultant
revenue decrease, as reflected in Paragraph 1 above, results
in just and reasonable rates for the Company. The
determinations made in this Paragraph are made solely for the
purpose of the stipulation contained in this Amended
Agreement.
14. Each provision of this Amended Agreement is in consideration
and support of all the other provisions. This Amended
Agreement shall not become effective until the issuance of a
final Commission Order approving this Amended Agreement
without change or alteration on or before July 1, 1996 in the
form of a Proposed Order to be agreed to by the parties. In
the event that the Commission fails to adopt this Amended
Agreement according to its terms on or before July 1, 1996,
this Agreement shall be deemed automatically withdrawn, the
rate reduction provisions of this Amended Agreement shall not
take effect, and APS and Staff shall be free to pursue their
respective positions without prejudice. In addition, if any
appeal is taken or other judicial review is sought of a final
Commission Order approving this Amended Agreement, then the
parties shall no longer be bound by the terms of this Amended
Agreement and this Amended Agreement shall automatically
become null and void, in which case: (1) the rate reduction
specified in Paragraph 1 shall immediately cease; (2) all
bills rendered on or after that date shall be at the rates
existing immediately prior to the Commission's approval of
this Amended Agreement; and (3) the revenue reduction
theretofore experienced by APS pursuant to Paragraph 1 shall
be recovered through a surcharge mechanism.
15. The terms and provisions of this Amended Agreement apply
solely to and are binding only in the context of the purposes
and results of this Amended Agreement and none of the
positions taken herein by APS may be referred to, cited or
relied upon by any other party in any fashion as precedent or
otherwise in any other proceeding before this Commission or
any other regulatory agency or before any court of law for any
purpose except in furtherance of the purposes and results of
this Agreement. Nothing in this Amended Agreement shall be
construed as imposing a cap on the Company's otherwise
reasonable and prudent cost of service for purposes of setting
just and reasonable rates.
16. This Amended Agreement represents an attempt to compromise and
settle issues regarding the prospective just and reasonable
rate levels for APS in a manner consistent with the public
interest and applicable legal requirements. Nothing contained
in this Amended Agreement is an admission by APS that its
current rate levels or rate design are unjust or unreasonable.
17. APS' agreement to the matters contained herein is predicated
on a national movement toward competition in the electricity
industry. That movement raises a number of policy and legal
issues in Arizona which are summarized (not necessarily
completely) in the Points of Agreement (Attachment 8). APS has
its own views, independent of any the Staff may have, of the
proper resolution of certain of the issues presented in the
Points of Agreement. Such views are summarized in Attachment
9.
Dated at Phoenix, Arizona, this 18th day of April, 1996.
STAFF OF ARIZONA ARIZONA PUBLIC SERVICE
CORPORATION COMMISSION COMPANY
By: Gary Yaquinto By: William J. Post
----------------------- -----------------------
Title: Director, Utilities Division Title: SVP & COO
---------------------------- ---------
<PAGE>
Attachment 1
<PAGE>
Page 1 of 2
REVISED ATTACHMENT 1
Calculation of Rate Reduction
Adjusted Test Year 12 Months Ended June 30, 1995
<TABLE>
<CAPTION>
(a) (b) (c) (d) (e)
Average Base Revenue Total Revenue
Ln. No. of at 5/27/94 W/ EEASE Factor Base Revenue
# Rate Customers Rate Level @ $0.00057/kWh Less B.S.C.
----------------- --------- -------------- -------------- --------------
<C> <C> <C> <C> <C>
1 Residential Class 629,423 $ 666,809,056 $ 670,737,289 $ 596,409,819
2 Commercial &
Industrial 78,948 $ 741,101,257 $ 746,327,818 $ 727,789,547
3 Outdoor Lighting 8,573 $ 15,701,309 $ 15,755,725 $ 15,701,309
--------- -------------- -------------- --------------
4 Base Revenues
Subject to Decrease 716,944 $1,423,611,622 $1,432,820,832 $1,339,900,675
5 Revenue Not
Subject to Decrease 6 $ 61,523,908 $ 62,086,338 $ 61,435,918
========= ============== ============== ==============
6 Retail Totals 716,950 $1,485,135,530 $1,494,907,170 $1,401,336,593
(L4 + L5)
</TABLE>
<TABLE>
<CAPTION>
(a) (f) (g) (h) (i) (j)
Revenue Decrease
-------------------------------------------------------------------
Base Rate Decrease
Ln. Excluding B.S.C. Total Decrease Ln.
EEASE ------------------------ ---------------------
# Rate Decrease ($/Yr) % ($/Yr) % #
----------------- ---------- ----------- -------- ----------- ---------
(d) - (c) (e) x (h) (f) + (g) (i) / (c)
<C> <C> <C> <C> <C> <C> <C>
1 Residential Class $3,928,233 $18,771,708 3.147% $22,699,941 3.40% 1
2 Commercial &
Industrial $5,226,561 $19,998,980 2.748% $25,225,541 3.40% 2
3 Outdoor Lighting $ 54,416 $ 480,098 3.058%$ 534,514 3.40% 3
---------- ----------- -----------
4 Base Revenues
Subject to Decrease $9,209,210 $39,250,786 $48,459,996 3.40% 4
5 Revenue Not
Subject to Decrease $ - $ - 0.000 $ - 0.00% 5
========== =========== ===========
6 Retail Totals $9,209,210 $39,250,786 $48,459,996 3.26% 6
(L4 + L5)
</TABLE>
Notes:
1. Includes customer annualization, weather normalization, and rate
annualization.
2. The non-firm portion of Stone Southwest (Papermill) is not subject to
the decrease.
The firm portion of their load is included with the Other Contracts.
3. EEASE factor of $0.00057/kWh was authorized by the ACC effective
11/1/95.
4. The EEASE decrease of $9,209,210 excludes the special contracts listed
in Attachment 2.
<PAGE>
Page 2 of 2
REVISED ATTACHMENT 1
Detailed Calculation of Reductions by Rate
Adjusted Test Year 12 Months Ended June 30, 1995
<TABLE>
<CAPTION>
(a) (b) (c) (d) (e)
Average Base Revenue Total Revenue
Ln. No. of at 5/27/94 W/ EEASE Factor Base Revenue
# Rate Customers Rate Level @ $0.00057/kWh Less B.S.C.
---------------------- ----------- ------------------- -----------------------------------------
<S> <C> <C> <C> <C> <C>
Residential Class
-----------------
1 E-10 173,276 $ 150,992,011 $ 151,847,207 $ 135,397,194
2 E-12 268,602 $ 213,357,415 $ 214,499,943 $ 189,183,235
3 EC-1 52,133 $ 97,322,262 $ 97,943,953 $ 91,066,362
4 ET-1 103,016 $ 141,855,712 $ 142,726,499 $ 123,312,817
5 ECT-1R 32,397 $ 63,281,656 $ 63,719,687 $ 57,450,211
--------- -------------- -------------- --------------
6 Class Totals 629,423 $ 666,809,056 $ 670,737,289 $ 596,409,819
General Service Class
---------------------
7 E-21 82 $ 346,180 $ 348,131 $ 319,666
8 E-22 11 $ 520,650 $ 523,507 $ 517,086
9 E-23 18 $ 663,376 $ 667,532 $ 650,906
10 E-24 22 $ 9,960,509 $ 10,053,133 $ 9,693,509
11 E-30 2,951 $ 1,529,919 $ 1,535,734 $ 1,308,575
12 E-31 18,290 $ 13,276,445 $ 13,332,218 $ 10,532,983
13 E-32 55,499 $ 598,376,967 $ 602,324,754 $ 590,052,192
14 E-34 37 $ 56,733,442 $ 57,285,705 $ 55,654,522
15 E-35 5 $ 14,573,343 $ 14,744,198 $ 14,426,343
16 E-40 37 $ 33,423 $ 33,451 $ 33,423
17 E-51 3 $ 547,604 $ 552,652 $ 546,452
18 E-67 255 $ 185,337 $ 188,144 $ 185,337
19 E-221 826 $ 14,073,150 $ 14,177,352 $ 13,924,530
20 BHP Minerals 1 $ 3,581,217 $ 3,615,797 $ 3,581,217
21 Cyprus Bagdad 1 $ 21,510,570 $ 21,510,570 $ 21,510,570
22 EPNG (Leupp) 1 $ 1,000,000 $ 1,000,000 $ 970,660
23 EPNG (Seligman) 1 $ 1,000,000 $ 1,000,000 $ 970,660
24 Magma Copper 1 $ 36,701,430 $ 37,263,860 $ 36,672,270
25 Phelps Dodge 1 $ 194,220 $ 194,220 $ 194,220
26 Stone Southwest 1 $ 1,117,688 $ 1,117,688 $ 1,117,538
27 Other Contracts 15 $ 16,771,704 $ 16,946,331 $ 16,594,878
--------- -------------- -------------- --------------
28 Class Totals 78,057 $ 792,697,174 $ 798,414,976 $ 779,457,537
Irrigation Class
----------------
29 E-31 19 $ 6,198 $ 6,215 $ 3,311
30 E-32 24 $ 55,005 $ 55,284 $ 51,355
31 E-38 336 $ 3,330,901 $ 3,356,027 $ 3,270,346
32 E-221 517 $ 6,535,887 $ 6,581,654 $ 6,442,917
--------- -------------- -------------- --------------
33 Class Totals 897 $ 9,927,991 $ 9,999,180 $ 9,767,929
Street Lighting Class
---------------------
34 E-58 471 $ 6,479,599 $ 6,494,434 $ 6,479,599
35 Share the Light 0 $ 160,263 $ 160,739 $ 160,263
36 Dept. of Trans. 35 $ 420,022 $ 423,252 $ 420,022
37 City Contracts 13 $ 4,054,925 $ 4,078,327 $ 4,054,925
--------- -------------- -------------- --------------
38 Class Totals 518 $ 11,114,809 $ 11,156,753 $ 11,114,809
Dusk to Dawn Lighting Class
---------------------------
39 Residential 2,333 $ 458,497 $ 459,814 $ 458,497
40 General Service 5,722 $ 4,128,003 $ 4,139,158 $ 4,128,003
--------- -------------- -------------- --------------
41 Class Totals 8,055 $ 4,586,500 $ 4,598,973 $ 4,586,500
$ -
--------- -------------- -------------- --------------
42 Retail Totals 716,950 $1,485,135,530 $1,494,907,170 $1,401,336,593
</TABLE>
<TABLE>
<CAPTION>
(a) (f) (g) (h) (i) (j)
Revenue Decrease
---------------------------------------------------------------------------
Base Rate Decrease
Ln. EEASE Excluding B.S.C. Total Decrease Ln.
---------------------------- ----------------------------
# Rate Decrease ($/Yr) % ($/Yr) % #
---------------------- --------------- ----------------- ---------- ---------------- ----------
(d) - (c) (e) x (h) (f) + (g) (i) / (c)
<S> <C> <C> <C> <C> <C> <C> <C>
Residential Class
-----------------
1 E-10 $ 855,196 $ 4,261,561 3.147% $ 5,116,756 3.39% 1
2 E-12 $ 1,142,528 $ 5,954,450 3.147% $ 7,096,978 3.33% 2
3 EC-1 $ 621,691 $ 2,866,269 3.147% $ 3,487,960 3.58% 3
4 ET-1 $ 870,787 $ 3,881,211 3.147% $ 4,751,997 3.35% 4
5 ECT-1R $ 438,031 $ 1,808,217 3.147% $ 2,246,248 3.55% 5
----------- ------------ ------------
6 Class Totals $ 3,928,233 $ 18,771,708 $ 22,699,941 3.40% 6
General Service Class
---------------------
7 E-21 $ 1,951 $ 8,786 2.749% $ 10,738 3.10% 7
8 E-22 $ 2,857 $ 14,213 2.749% $ 17,070 3.28% 8
9 E-23 $ 4,156 $ 17,891 2.749% $ 22,047 3.32% 9
10 E-24 $ 92,624 $ 266,436 2.749% $ 359,060 3.60% 10
11 E-30 $ 5,815 $ 35,968 2.749% $ 41,783 2.73% 11
12 E-31 $ 55,773 $ 289,510 2.749% $ 345,283 2.60% 12
13 E-32 $ 3,947,787 $ 16,218,216 2.749% $ 20,166,002 3.37% 13
14 E-34 $ 552,263 $ 1,529,724 2.749% $ 2,081,987 3.67% 14
15 E-35 $ 170,855 $ 396,523 2.749% $ 567,379 3.89% 15
16 E-40 $ 28 $ 919 2.749% $ 947 2.83% 16
17 E-51 $ 5,048 $ 15,020 2.749% $ 20,068 3.66% 17
18 E-67 $ 2,807 $ - 0.000% $ 2,807 1.51% 18
19 E-221 $ 104,202 $ 382,731 2.749% $ 486,932 3.46% 19
20 BHP Minerals $ 34,580 $ 98,434 2.749% $ 133,013 3.71% 20
21 Cyprus Bagdad $ - $ - 0.000% $ - 0.00% 21
22 EPNG (Leupp) $ - $ - 0.000% $ - 0.00% 22
23 EPNG (Seligman) $ - $ - 0.000% $ - 0.00% 23
24 Magma Copper $ - $ - 0.000% $ - 0.00% 24
25 Phelps Dodge $ - $ - 0.000% $ - 0.00% 25
26 Stone Southwest $ - $ - 0.000% $ - 0.00% 26
27 Other Contracts $ 174,627 $ 456,128 2.749% $ 630,755 3.76% 27
----------- ------------ ------------
28 Class Totals $ 5,155,372 $ 19,730,498 $ 24,885,870 3.14% 28
Irrigation Class
29 E-31 $ 17 $ 91 2.749% $ 108 1.74% 29
30 E-32 $ 279 $ 1,412 2.749% $ 1,691 3.07% 30
31 E-38 $ 25,126 $ 89,889 2.749% $ 115,015 3.45% 31
32 E-221 $ 45,767 $ 177,090 2.749% $ 222,858 3.41% 32
----------- ------------ ------------
33 Class Totals $ 71,189 $ 268,482 $ 339,671 3.42% 33
Street Lighting Class
---------------------
34 E-58 $ 14,835 $ 196,131 3.027% $ 210,966 3.26% 34
35 Share the Light $ 476 $ 4,851 3.027% $ 5,327 3.32% 35
36 Dept. of Trans. $ 3,230 $ 12,714 3.027% $ 15,944 3.80% 36
37 City Contracts $ 23,402 $ 122,738 3.027% $ 146,140 3.60% 37
----------- ------------ ------------
38 Class Totals $ 41,944 $ 336,434 $ 378,377 3.40% 38
Dusk to Dawn Lighting Class
---------------------------
39 Residential $ 1,317 $ 14,362 3.132% $ 15,679 3.42% 39
40 General Service $ 11,155 $ 129,302 3.132% $ 140,458 3.40% 40
----------- ------------ ------------
41 Class Totals $ 12,473 $ 143,664 $ 156,137 3.40% 41
----------- ------------ ------------
42 Retail Totals $ 9,209,210 $ 39,250,786 $ 48,459,996 3.26% 42
</TABLE>
Notes:
1. Includes customer annualization, weather normalization, and rate
annualization.
2. The non-firm portion of Stone Southwest (Papermill) is not subject to
the decrease. The firm portion of their load is included with the Other
Contracts.
3. EEASE factor of $0.00057/kWh was authorized by the ACC effective
11/1/95.
4. The EEASE decrease of $9,209,210 excludes the special contracts listed
in Attachment 2.
<PAGE>
Attachment 2
<PAGE>
Attachment 2
Rates and Contracts Exempt
From General Rate Decreases
1. Rate E-67, Municipal Lighting Service -- City of Phoenix
2. Cyprus Copper Company Contract
3. El Paso Natural Gas (Leupp and Seligman) Contract
4. Magma Copper Company Contract
5. Phelps Dodge Contract
6. Stone Southwest Contract
7. Future ACC approved contracts with pricing provisions that
exempt them from general rate decreases.
These rates and contracts are already discounted or have fixed rate provisions
and will not be subject to the general price decreases resulting from the
operation of the Plan unless so specified by contract.
<PAGE>
Attachment 3
<PAGE>
Attachment 3
Unit Cost Ratio and Unit Price Ratio Definitions
(The revenues and costs to be utilized in this calculation will be derived from
the actual audited financial statements of the Company)
Unit Cost Ratio (UCR): Annual cents-per-kilowatt-hour average cost of electric
services.
UCR = Annual total electric costs (1)
--------------------------------
Annual total Company kwh sales(2)
Unit Price Ratio (UPR): Annual cents-per-kilowatt-hour average price of
electric services.
UPR = Annual electric revenues (3)
----------------------------------
Annual total Company kwh sales (2)
1. Excludes sales taxes (as in the case of the income statement), all ITC
amortization (as required by federal tax laws), annual Pinnacle West
charges net of costs for shareholder services, fuel expenses for
non-traditional and interchange sales (generally defined as opportunity
sales which are cost justified on an incremental basis), and
non-utility income or deductions and related income tax effects.
Includes fuel, operations and maintenance, depreciation and
amortization (including the accelerated amortization of regulatory
assets), property and other taxes, cost of capital (consisting of
long-term interest; debt discount, premium and expense; preferred stock
dividend requirements; and a return on equity of 11.25% applied to the
average annual equity balance), the gross profit margin on
non-traditional and interchange sales, DSM and renewable expenditures
(including net lost revenues and incentives), and income taxes on
Operating Income including adjustments to income taxes for the above
exclusions and inclusions.
2. Excludes kwh sales for non-traditional and interchange sales.
3. Includes miscellaneous revenues. Excludes sales taxes (as in the case
of the income statement) and non-traditional and interchange revenues.
<PAGE>
ATTACHMENT 4
<PAGE>
REVISED ATTACHMENT 4
(April 10, 1996)
ELECTRIC RATES E-36
--------------
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5223
Phoenix, Arizona Tariff or Schedule No. E-36
Filed by: Gary J. Volkenant Original Filing
Title: Director, Business Financial Services Effective:
Original Effective Date:
FLEXIBLE CONTRACTING
--------------------
AVAILABILITY
- ------------
In all territory served by Company at all points where facilities of adequate
capacity and the required and suitable voltage are adjacent to the premise
served.
APPLICATION
- -----------
This Schedule shall not be used to displace certain natural gas applications
installed as of the effective date of this schedule. These applications consist
of natural gas boilers, chillers, or cogeneration facilities.
Qualified customers must:
1. Maintain a single billing account with an annual average metered demand
greater than 2,000 kW, or
2. Have single billing accounts with annual average metered demands greater
than 50 kW that, when summed, are greater than 2,000 kW, and
3. Agree to an energy audit or review, unless the customer has recently
completed a significant demand side management program or energy
audit/review and provides APS with adequate documentation concerning
demand side management activities or audit/review, and
4. Have or may acquire a competitive alternative to receiving electric
service at APS' otherwise effective price for each billing account, or
5. Have the ability to acquire all or part of their electric service
requirements from an alternate supplier, or
6. Desire a long-term contract for electric service.
SERVICE BILLING
- ---------------
Only customers meeting the above criteria can be served under Rate E-36. The
negotiated price must be commensurate with the costs to the customer of that
customer's current or potential alternative(s). Prices may be revised
periodically as specified in the service contract to account for changing
conditions, costs, and individual customer requirements. The revenue from the
customer shall exceed the marginal cost of serving that customer. For contracts
whose terms extend beyond the date when APS will need to add capacity, marginal
cost shall mean long run marginal cost.
SERVICE CONTRACT
- ----------------
The contract terms and conditions will be at the Company's option, based on its
assessment of the qualified customer's competitive alternative. The contract may
be for varying lengths of time as determined by individual customer or Company
requirements. Each executed contract will be submitted to the Commissioners and
Commission Staff, on a confidential basis, at least thirty days prior to the
effective date of the proposed contract and Staff shall determine whether the
contract complies with the tariff prior to the effective date. Such contract
will also be provided to the Arizona Residential Utility Consumer Office on a
confidential basis. APS must provide adequate documentation on each element of
the tariff (for example, the customer's alternatives) before the thirty day
review period commences. If no action is taken within 30 days of the filing, the
contract is deemed approved by the Commission. Nothing in this tariff is
intended to limit the Arizona Corporation Commission's power to order recovery
of costs determined to be attributable to the customer either prior to or after
termination of the contract.
<PAGE>
ATTACHMENT 5
<PAGE>
REVISED ATTACHMENT 5
PROPOSED CHANGES TO SCHEDULE #1
2. ESTABLISHMENT OF SERVICE
2.2 Add to first sentence, "or to make a special read without a
disconnect and calculate a bill for a partial month."
2.2 Change last sentence "Billing for the service charge will be rendered
as a part of service bill, but not later than the second service
bill."
2.3 GROUNDS FOR REFUSAL OF SERVICE
2.3.8 Change wording to "Service is requested by an Applicant and a prior
Customer living with the Applicant owes a delinquent bill."
2.3.9 Change wording to "Applicant is acting as an agent for a prior
Customer who is deriving benefits of the electric service and who
owes a delinquent bill."
2.4 ESTABLISHMENT OF CREDIT OR SECURITY DEPOSIT
2.4.1.3 Delete Letter of Guarantee. Add ..."Company receives deposit
guarantee notification from a social or governmental agency
acceptable to the Company"
2.6 SECURITY DEPOSITS
2.6.3 Add "effective on the first business day of each year".
2.6.5.1 Change bankruptcy from within last 6 months to within the last 12
months.
2.6.6 Change to "...Customer's maximum monthly billing as estimated by the
Company."
4.2 BILLING AND COLLECTION
4.2.1 Add "All past due charges will be" ...Change late charge from 12% to
"18%"
4.4 RETURNED CHECKS
4.4.1 Change $10 to "$15"
4.5 Change collection charge to "field charge", change amount from $9.50
to "$15.00" and add "or terminate the service if not reconnected.
This charge will only be applied for field calls resulting from the
termination process."
4.5.2 Change acceptable to "satisfactory to Company."
5.3 COMPANY ACCESS TO CUSTOMER PREMISES
5.3 Add requirement of "unassisted" access in two sentences
5.3 Expand remedy for inaccessibility. Add ", or denial of any existing
rate options where access is required." Add "All existing conditions
shall be grandfathered, i.e. tariff shall apply only to services
established after XXXXXX, 1996"
5.5 Add "a minimum standard is IEEE 519" and simplify language to "shall
not impair service"
6. METERING AND METERING EQUIPMENT
6.1.1 Add "and/or Electric Service Requirements manual" and "All updates to
the Electric Service Requirements manual shall be provided to Staff
in a timely manner."
7. TERMINATION
7.1.5 Add "satisfactory and unassisted" and "All existing conditions shall
be grandfathered, i.e., tariff shall apply only to services
established after XXXXXX, 1996."
<PAGE>
Attachment 6
<PAGE>
ELECTRIC RATES
--------------
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5215
Phoenix, Arizona Tariff or Schedule No. E-52
Filed by: Gary J. Volkenant Original Filing
Title: Director, Business Financial Services Effective Date:
Original Effective Date:
ELECTRIC SERVICE FOR PARTIAL REQUIREMENTS SERVICE
-------------------------------------------------
OF LESS THAN 3,000 KW
---------------------
I. AVAILABILITY
------------
In all territory served by Company at all points where facilities of
adequate capacity and the required phase and suitable voltage are adjacent to
the premises served and when all applicable provisions described herein have
been met.
II. APPLICATION
-----------
Applicable to any non-residential customer requiring Partial
Requirements services, Supplemental Power, Standby Power or Maintenance Energy
with an aggregate Partial Requirements service load of less than 3,000 kW.
Customer may elect to take any of the Partial Requirements services offered
hereunder, Supplemental Power, Standby Power and Maintenance Power independently
of one another or in combination with one another as required.
Each customer shall be allowed to designate the specific periods and
hours within a month for which utilization of Standby Service is required (see
Designated Standby Service Hours).
III. TYPE OF SERVICE
---------------
Single or three phase, 60 Hertz, at one standard voltage as may be
selected by Customer subject to availability at Customer's premise.
IV. MONTHLY BILL
------------
The monthly bill shall be the sum of the amounts computed under A., B.,
C., and D. below, including the applicable Adjustments:
A. Basic Service
-------------
$ 106.79 per month Basic Service Charge, plus
$ 17.06 per month for each Generator Meter
B. Supplemental Service
--------------------
In accordance with the rate levels contained in General
Service Rate Schedule E-32 excluding the monthly Basic Service
Charge.
C. Standby Service
---------------
The monthly charge for Standby Service shall be the sum of the
amounts computed in accordance with sections 1 and 2 below:
1. Monthly Reservation Charge of either a, b or c:
a. $5.54 per kW of Contract Standby Capacity for
Standby Service customers with alternate supply
resources demonstrating an aggregate Capacity Factor
of 90% or greater during the billing month.
b. $7.29 per kW of contract Standby Capacity for
Standby Service customers with alternate supply
resources demonstrating an aggregate Capacity Factor
between 80% - 89.9% during the billing month.
c. Standby Service customers whose alternate supply
resource(s) achieved an aggregate capacity factor of
less than 80% during a billing month shall be
assessed the same charge as set forth in Section VIII
of this rate schedule.
(CONTINUED ON NEXT PAGE)
<PAGE>
2. Standby Energy Charge:
June - October $0.0202 per kWh on-peak
Billing Cycles $0.0140 per kWh off-peak
(Summer)
November - May $0.0168 per kWh on-peak
Billing Cycles $0.0124 per kWh off-peak
(Winter)
The charges for Standby Service contained in Section C herein
reflect the Company's costs to serve Standby Service loads.
For applications where the charges for Standby Service stated
herein are not competitive with customer installed standby
resource alternatives, the Company may negotiate alternate
Monthly Reservation Charges from those contained in this rate
schedule; however, the maximum discount allowed shall not be
greater than fifty percent (50%) of the Reservation Charges
stated herein; however, such discount shall not result in a
reservation charge lower than the Company's long run capacity
costs associated with this service. No changes to the Standby
Energy Charge rate component shall be allowed.
To be eligible for negotiated Monthly Reservation Charges
different than those contained herein, the customer must
demonstrate to the Company's satisfaction and provide
conclusive documentation (e.g., engineering studies, analysis,
etc.) that the customer's on-site self-generation resource(s)
would be a lower cost option over the life of the equipment
than had the customer subscribed to Standby Service from the
Company. Notwithstanding the potential competitiveness of the
customer's self generation standby facilities, the Company in
its sole opinion, shall have the option of not offering any
discounts to the otherwise applicable Reservation Charge.
D. Maintenance Service
-------------------
$0.0168 per kWh on-peak
$0.0124 per kWh off-peak
E. Energy Rates
------------
The energy rates in Sections C and D above are based on the
Company's estimated marginal costs and will be updated
annually to reflect changes in the Company's fuel costs.
V. DETERMINATION OF SUPPLEMENTAL SERVICE
-------------------------------------
Supplemental service shall be defined as demand and energy contracted
by Customer to augment the power and energy generated by Customer's generation
facility.
Supplemental demand shall be the highest 15-minute interval during the
billing month which shall equal the (a) 15-minute integrated kW demand
calculated for every 15-minute interval as recorded on the Supply Meter, plus
(b) the simultaneous 15 minute integrated kW demand as recorded on the Generator
Meter(s), less (c) the aggregate Contract Standby Capacity of all the customer's
generating units; however, the result shall never be less than zero (0) for
purposes of determining Supplemental Demand. If Company authorized scheduled
maintenance was being performed on any of the customer's generators at the time
of the highest 15 minute interval during the billing month, the amount of demand
recorded on the Supply Meter shall be reduced by the applicable Maintenance
Power Level (as determined in Section VII hereof) of the generator unit(s)
undergoing authorized scheduled maintenance for purposes of calculating
supplemental demand used for billing.
Customer's maximum Supplemental Service kW requirements shall not
exceed that established in the Electric Supply Agreement.
Supplemental energy shall be equal to all energy supplied to Customer
as determined from readings of the Supply Meter, less any energy determined to
be either Standby or Maintenance energy as defined in this Schedule.
VI. DETERMINATION OF STANDBY ENERGY
-------------------------------
Standby Energy shall be defined to be electric energy supplied by
Company to replace power ordinarily generated by Customer's generation facility
during unscheduled full and partial outages of said facility.
(CONTINUED ON NEXT PAGE)
<PAGE>
When the sum of the energy measured on both the Supply and Generator(s)
Meters during simultaneous periods is greater than the maximum energy output of
the generator(s) at Contract Standby Capacity, the Standby Energy shall be equal
to the summation of the differences between the maximum energy output of the
generator(s) at Contract Standby Capacity and the energy measured on the
Generator Meter(s) for every 15-minute interval of the month, except when
maintenance power is being utilized or those intervals where energy measured on
the Supply Meter is zero. When the sum of the energy measured on both the Supply
and Generator(s) Meter is equal to or less than the maximum energy output of the
generator(s) at Contract Standby Capacity, then the Standby energy shall be that
energy measured on the Supply Meter.
VII. DETERMINATION OF MAINTENANCE ENERGY
-----------------------------------
Maintenance energy shall be defined as energy supplied to Customer to
replace energy normally supplied by the Customer's generator(s) during an
authorized Scheduled Maintenance period.
Maintenance periods shall not exceed 30 days per cogeneration unit
during any consecutive 12-month period and must be scheduled during the
non-Summer billing months. Customer shall provide Company with its planned
maintenance schedule 12 months in advance of any planned maintenance in order
for the Company to coordinate customer's scheduled maintenance with that of the
Company. Upon review, Company shall either approve customer's planned
maintenance schedule or notify customer of alternate acceptable periods.
Customer, in turn, shall notify the Company of an acceptable alternate
maintenance period(s), and shall also confirm with the Company its intention to
perform its planned maintenance 45 days prior to the actual commencement date of
the planned maintenance period.
Any energy used in excess of a 30-day period or unauthorized
maintenance energy shall be billed on either the Standby or Supplemental Rate as
specified in this Schedule.
Maintenance energy, during a Company authorized period of scheduled
maintenance to a customer's generation unit(s), shall be determined as follows:
Maintenance Power Level = (Contract Standby Capacity) X (Generating
Unit(s) Capacity Factor for the most recent 12 months)
The maintenance power level as determined by the above formula shall
not exceed any actual 15 minute interval of integrated kW demand as
recorded on the supply meter.
If customer has less than 12 months of billing history on Standby
Service, use the capacity factor demonstrated to date; however, not
less than one full month.
Maintenance Energy = (Maintenance Power Level) X (hours of maintenance
authorized by Company during billing month)
VIII. CAPACITY FACTOR STANDARDS
-------------------------
Customer's generating unit(s) must maintain a Capacity Factor of no
less than 75% over a continuous rolling 18 month period to remain eligible to
receive Standby Service under this rate schedule. The calculation of the
Capacity Factor is designed so that the customer shall not be subject to this
Capacity Factor Standard provision for any purpose other than substandard
operational performance of the customer's generating unit(s) recognizing that
the customer's load profile may not require the full output capability of such
generation unit(s). If the Capacity Factor falls below 75%, in lieu of the
otherwise applicable Reservation Charge for Standby Service, the customer shall
be assessed a monthly Reservation Charge the greater of:
1. $20.78 per kW/month X 2/3 X Contract Standby Capacity; or
2. $20.78 per kW/month X Maximum Standby Capacity
(If customer's system is directly interconnected with the
Company's bulk transmission system, the applicable Reservation
Charge shall be $15.90 per kW per month.)
Maximum Standby Capacity is intended to represent the maximum 15-minute
interval of Standby Power provided the customer by the Company during the
billing month. Maximum Standby Capacity shall equal the highest 15-minute
interval during the billing month of the following calculation:
MSC = (SIGMA)CSC - Maint.
Where:
MSC = Maximum 15-minute interval during the billing month of Standby
Power (kW) being supplied by Company.
(SIGMA)CSC = The aggregate Contract Standby Capacity of all the
customer's self-generation units.
Maint = The simultaneous 15-minute interval of any Maintenance Power
(kW) being supplied to customer by the Company.
(CONTINUED ON NEXT PAGE)
<PAGE>
IX. METERING
--------
The Company will install a Supply Meter at its point of delivery to
Customer and a Generator Meter(s) at the point(s) of output from each of
Customer's generators. All meters will record integrated demand and energy on
the same 15-minute interval basis as specified by Company.
X. DEFINITIONS
-----------
1. Contract Standby Capacity - for each specific customer generating unit for
which the Company is providing Standby Service, Contract Standby Capacity
shall be the greater of: a) the measured kW output of each customer
self-generation unit at time of start-up test, or b) the highest 15 minute
measured kW output of each generating unit, however, not to exceed
Customer's actual total load.
2. Generator Meter - the time-of-use meter used to measure in 15-minute
intervals the total power and energy output of each Customer's cogeneration
units.
3. Designated Standby Service Hours - Customers requiring Standby Service for
less than the total hours in a billing month shall be allowed to designate
those periods and hours of a month when Standby Service is required. These
Designated Standby Service Hours shall represent those hours within a
billing month during which the customer is authorized to utilize Standby
Service. Use during any period or hours other than Designated Standby
Service Hours shall represent an Unauthorized Use of Standby Service
subject to certain special provisions for determining the appropriate
Capacity Factor value during billing periods when unauthorized Standby
Service was utilized. Such hours shall be specified in whole hour intervals
beginning on an hour for each designated day of the week. Designated
Standby Service Hours shall never total less than 280 hours a billing
month.
4. Capacity Factor - for purposes of this rate schedule, capacity factor shall
mean the capacity factor of the customer's generating unit(s) and shall not
reflect any period of time during a billing month that Company authorized
Maintenance Power was being utilized. The Capacity factor shall be
calculated in accordance with the following formula:
Capacity Factor = Actual customer generated kWh's during the billing month
--------------------------------------------------------
A
For purposes of use in this rate schedule, the value of the
capacity factor calculation shall never exceed 100%.
Where:
A = The lesser of: a) [(Contract Standby Capacity) X (MH)]; or
b) CTL
MH = The number of Designated Standby Service Hours in the billing
month, exclusive of any hours during the billing month that
customer's unit(s) were non-operational during Company
authorized scheduled maintenance, for which the customer has
contracted for Standby Service (but not less than 280 hours
per billing month).
In the event the customer utilizes Standby Service in any
period other than during Designated Standby Service Hours, MH
shall be represented as the actual number of hours in the
billing month (exclusive of any hours during which the
customer was receiving Company authorized scheduled
Maintenance Energy).
Furthermore, in the event there is more than two (2) instances
in any 12 month rolling period of Unauthorized Use of Standby
Service, MH shall be represented as the actual number of hours
in the billing month (exclusive of any hours during which the
customer was receiving Company authorized scheduled
Maintenance Energy) for the month during which the third
breach of service occurred, and for the next three months
thereafter. At the end of any three month breach period, a new
twelve (12) month rolling period shall commence for
determining the number of instances of Unauthorized Use.
CTL = Customer's maximum total load during the billing month during
the Designated Standby Service Hours for which the Customer
has contracted for Standby Service (but not less than 280
hours per month).
(CONTINUED ON NEXT PAGE)
<PAGE>
CTL shall represent the customer's maximum total load during
the hours in the billing month for which use of Standby
Service has been authorized as set forth in the definition of
Designated Standby Service Hours. CTL shall be calculated by
first adding the maximum simultaneous 15-minute kW peak
periods as recorded on the Supply Meter and Generator Meter(s)
during authorized periods of Standby Service the sum of which
is then multiplied by MH.
In the event the customer utilizes Standby Service during any
period of a billing month other than those authorized, CTL
shall represent the customer's maximum total (peak demand)
load during the billing month calculated as the sum of the
maximum simultaneous 15-minute kW peak period during the
billing period recorded on the Supply Meter and the Generator
Meter(s) during all hours of the billing month. CTL shall be
similarly calculated for any other months during which the
provision for breach of service explained in the definition of
MH above is being assessed.
CTL shall only be used for calculating Capacity Factor in
those months where the customer's maximum kW load is less than
total Contract Standby Capacity.
4. Supply Meter - the time-of-use meter used to measure in 15-minute
intervals the total power and energy supplied by Company to Customer.
5. Time Periods - On-Peak Period: 9 a.m. - 9 p.m. Monday through Friday
Off-Peak Period: All Other Hours
Mountain Standard Time shall be used in the application of this rate
schedule. In addition, to prevent radical changes in the system loads
the beginning and ending hours for individual customers may be varied
by up to one hour (total hours in each time period to remain unchanged)
and because of potential differences of the timing devices, there may
be a variation of up to 15 minutes in timing for the pricing periods.
XI ADJUSTMENTS
-----------
The applicable proportionate part of any taxes or governmental
impositions which are or may in the future be assessed on the basis of gross
revenues of the Company and/or the price or revenue from the electric energy or
service sold and/or the volume of energy generated or purchased for sale and/or
sold hereunder.
XII. TERMINATION PROVISION
---------------------
Should Customer cease to operate his cogeneration unit(s) for 60
consecutive days during periods other than planned scheduled maintenance
periods, Company reserves the option to terminate the Agreement for service
under this rate schedule with Customer.
XIII. CONTRACT PERIOD
---------------
As provided in the Electric Supply Agreement between Company and
Customer.
XIV. TERMS AND CONDITIONS
--------------------
Customer must enter into an Agreement for the Interconnection and The
Sale of Power with Company and an Electric Supply Agreement which shall
establish all pertinent details related to interconnection and other required
service standards. Customer will not have the option to sell power and energy to
Company under this tariff. Should Customer desire to do so, Customer would be
required to enter into a new Service Agreement which would set forth the
applicable purchase rate in addition terms and conditions for interconnection
and for the sale of power to the Company.
Customer will be required to contract for adequate standby power to
cover the total output of all the customer's generators unless adequate
facilities have been installed, to the satisfaction of APS, that isolates
portions of the customer's load from APS' system so that APS will in no event be
providing standby service in excess of Contracted Standby Capacity.
XV. CHANGE IN DESIGNATED STANDBY SERVICE HOURS
------------------------------------------
Customers shall be allowed no more than one (1) change in their
Designated Standby Service Hours during any eighteen (18) month time period. In
no event shall the total of Designated Standby Service Hours during a month fall
below 280 hours.
<PAGE>
ELECTRIC RATES
--------------
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5214
Phoenix, Arizona Tariff or Schedule No. E-55
Filed by: Gary J. Volkenant Original Filing
Title: Director, Business Financial Services Effective Date:
Original Effective Date:
ELECTRIC SERVICE FOR PARTIAL REQUIREMENTS SERVICE
-------------------------------------------------
3,000 KW OR GREATER
-------------------
I. AVAILABILITY
------------
In all territory served by Company at all points where facilities of
adequate capacity and the required phase and suitable voltage are adjacent to
the premises served and when all applicable provisions described herein have
been met.
II. APPLICATION
-----------
Applicable to any customer requiring Partial Requirements services,
Supplemental Power, Standby Power or Maintenance Energy with an aggregate
Partial Requirements service load of no less than 3,000 kW. Customer may elect
to take any of the Partial Requirements services offered hereunder (Supplemental
Power, Standby Power and Maintenance Power) independently of one another or in
combination with one another as required.
Customers having Standby Service requirements not exceeding 2,999 kW
shall be allowed to designate specific periods and hours within a month for
which utilization of Standby Service is required (see Designated Standby Service
Hours).
III. TYPE OF SERVICE
---------------
Single or three phase, 60 Hertz, at one standard voltage as may be
selected by Customer subject to availability at Customer's premise.
IV. MONTHLY BILL
------------
The monthly bill shall be the sum of the amounts computed under A., B.,
C., and D. below, including the applicable Adjustments:
A. Basic Service
-------------
1. a) For applications no greater than 15,000 kW:
$ 1,671.39 per month Basic Service Charge; plus
b) For applications greater than 15,000 kW:
The monthly Basic Service Charge shall be $1,671.39
plus an applicable adder for recovery of non-standard
metering costs and related O&M expenses; plus
2. $ 62.51 per month for each Generator Meter
B. Supplemental Service
--------------------
In accordance with the rate levels contained in General
Service Rate Schedule E-32, excluding the monthly Basic
Service Charge (or E-34 if Supplemental Power requirements are
3,000 kW or more).
C. Standby Service
---------------
The monthly charge for Standby Service shall be the sum of the
amounts computed in accordance with sections 1, 2 and 3 below:
1. For customers taking service at voltage levels of less than
69 kV, a Monthly Reservation Charge of either a, b, c or d:
a. $ 4.53 per kW of Contract Standby Capacity for
Standby Service customers with alternate supply
resources demonstrating an aggregate Capacity Factor
of 95% or greater during the billing month.
b. $ 5.54 per kW of Contract Standby Capacity for
Standby Service customers with alternate supply
resources demonstrating an aggregate Capacity Factor
between 90% - 94.9% during the billing month.
c. $ 7.29 per kW of Contract Standby Capacity for
Standby Service customers with alternate supply
resources demonstrating an aggregate Capacity Factor
between 80% - 89.9% during the billing month.
d. Standby Service customers whose alternate supply
resource(s) achieved an aggregate capacity factor of
less than 80% during a billing month shall be
assessed the same charge as set forth in Section
VIII.A of this rate schedule.
(CONTINUED ON NEXT PAGE)
<PAGE>
2. For customers who take service at voltage levels of 69 kV
or greater, a Monthly Reservation Charge of either a, b, c
or d:
a. $ 1.56 per kW of Contract Standby Capacity for
Standby Service customers with alternate supply
resources demonstrating an aggregate Capacity Factor
of 95% or greater during the billing month.
b. $ 2.49 per kW of Contract Standby Capacity for
Standby Service customers with alternate supply
resources demonstrating an aggregate Capacity Factor
between 90% - 94%.9% during the billing month.
c. $ 4.42 per kW of Contract Standby Capacity for
Standby Service customers with alternate supply
resources demonstrating an aggregate Capacity Factor
between 80% - 89.9% during the billing month.
d. Standby Service customers whose alternate supply
resource(s) achieved an aggregate capacity factor of
less than 80% during a billing month shall be
assessed the same charge as set forth in Section
VIII.B of this rate schedule.
3. Standby Energy Charge:
June - October $0.0208 per kWh on-peak
Billing Cycles $0.0147 per kWh off-peak
(Summer)
November - May $0.0173 per kWh on-peak
Billing Cycles $0.0128 per kWh off-peak
(Winter)
The charges for Standby Service contained in Section C herein
reflect the Company's costs to serve Standby Service loads.
For applications where the charges for Standby Service stated
herein are not competitive with customer installed standby
resource alternatives, the Company may negotiate alternate
Monthly Reservation Charges from those contained in this rate
schedule; however, the maximum discount allowed shall not be
greater than fifty percent (50%) of the Reservation Charges
stated herein; however, such discount shall not result in a
reservation charge lower than the Company's long run capacity
costs associated with this service. No changes to the Standby
Energy Charge rate component shall be allowed.
To be eligible for negotiated Monthly Reservation Charges
different than those contained herein, the customer must
demonstrate to the Company's satisfaction and provide
conclusive documentation (e.g., engineering studies, analysis,
etc.) that the customer's on-site self-generation resource(s)
would be a lower cost option over the life of the equipment
than had the customer subscribed to Standby Service from the
Company. Notwithstanding the potential competitiveness of the
customer's self generation standby facilities, the Company in
its sole opinion, shall have the option of not offering any
discounts to the otherwise applicable Reservation Charge.
D. Maintenance Service
-------------------
$0.0173 per kWh on-peak
$0.0128 per kWh off-peak
E. Energy Rates
------------
The energy rates in Sections C and D above are based on the
Company's estimated marginal costs and will be updated
annually to reflect changes in the Company's fuel costs.
V. DETERMINATION OF SUPPLEMENTAL SERVICE
-------------------------------------
Supplemental service shall be defined as demand and energy contracted
by Customer to augment the power and energy generated by Customer's generation
facility.
Supplemental demand shall be the highest 15-minute interval during the
billing month which shall equal the (a) 15-minute integrated kW demand
calculated for every 15-minute interval as recorded on the Supply Meter, plus
(b) the simultaneous 15 minute integrated kW demand as recorded on the Generator
Meter(s), less (c) the aggregate Contract Standby Capacity of all the customer's
generating units; however, the result shall never be less than zero (0) for
purposes of determining Supplemental Demand. If Company authorized scheduled
maintenance was being performed on any of the customer's generators at the time
of the highest 15 minute interval during the billing month, the amount of demand
recorded on the Supply Meter shall be reduced by the applicable Maintenance
Power Level (as determined in Section VII hereof) of the generator unit(s)
undergoing authorized scheduled maintenance for purposes of calculating
supplemental demand used for billing.
Customer's maximum Supplemental Service kW requirements shall not
exceed that established in the Electric Supply Agreement.
Supplemental energy shall be equal to all energy supplied to Customer
as determined from readings of the Supply Meter, less any energy determined to
be either Standby or Maintenance energy as defined in this Schedule.
(CONTINUED ON NEXT PAGE)
<PAGE>
VI. DETERMINATION OF STANDBY ENERGY
-------------------------------
Standby Energy shall be defined to be electric energy supplied by
Company to replace power ordinarily generated by Customer's generation facility
during unscheduled full and partial outages of said facility.
When the sum of the energy measured on both the Supply and Generator(s)
Meters during simultaneous periods is greater than the maximum energy output of
the generator(s) at Contract Standby Capacity, the Standby Energy shall be equal
to the summation of the differences between the maximum energy output of the
generator(s) at Contract Standby Capacity and the energy measured on the
Generator Meter(s) for every 15-minute interval of the month, except when
maintenance power is being utilized or those intervals where energy measured on
the Supply Meter is zero. When the sum of the energy measured on both the Supply
and Generator(s) Meter is equal to or less than the maximum energy output of the
generator(s) at Contract Standby Capacity, then the Standby energy shall be that
energy measured on the Supply Meter.
VII. DETERMINATION OF MAINTENANCE ENERGY
-----------------------------------
Maintenance energy shall be defined as energy supplied to Customer to
replace energy normally supplied by the Customer's generator(s) during an
authorized Scheduled Maintenance period.
Maintenance periods shall not exceed 30 days per cogeneration unit
during any consecutive 12-month period and must be scheduled during the
non-Summer billing months. Customer shall provide Company with its planned
maintenance schedule 12 months in advance of any planned maintenance in order
for the Company to coordinate customer's scheduled maintenance with that of the
Company. Upon review, Company shall either approve customer's planned
maintenance schedule or notify customer of alternate acceptable periods.
Customer, in turn, shall notify the Company of an acceptable alternate
maintenance period(s), and shall also confirm with the Company its intention to
perform its planned maintenance 45 days prior to the actual commencement date of
the planned maintenance period.
Any energy used in excess of a 30-day period or unauthorized
maintenance energy shall be billed on either the Standby or Supplemental Rate as
specified in this Schedule.
Maintenance energy, during a Company authorized period of scheduled
maintenance to a customer's generation unit(s), shall be determined as follows:
Maintenance Power Level = (Contract Standby Capacity) X (Generating
Unit(s) Capacity Factor for the most recent 12 months)
The maintenance power level as determined by the above formula shall
not exceed any actual 15 minute interval of integrated kW demand as
recorded on the supply meter.
If customer has less than 12 months of billing history on Standby
Service, use the capacity factor demonstrated to date; however, not
less than one full month.
Maintenance Energy = (Maintenance Power Level) X (hours of maintenance
authorized by Company during billing month)
VIII. CAPACITY FACTOR STANDARDS
-------------------------
Customer's generating unit(s) must maintain a Capacity Factor of no
less than 75% over a continuous rolling 18 month period to remain eligible to
receive Standby Service under this rate schedule. The calculation of the
Capacity Factor is designed so that the customer shall not be subject to this
Capacity Factor Standard provision for any purpose other than substandard
operational performance of the customer's generating unit(s) recognizing that
the customer's load profile may not require the full output capability of such
generation unit(s). If the Capacity Factor falls below 75%, in lieu of the
otherwise applicable Reservation Charge for Standby Service, the customer shall
be assessed a monthly Reservation Charge the greater of:
A. For customers taking service at voltage levels of less than 69 kV:
1. $ 22.90 per kW/month X 2/3 X Contract Standby Capacity; or
2. $ 22.90 per kW/month X Maximum Standby Capacity
(If customer's system is directly interconnected with the
Company's bulk transmission system, the applicable Reservation
Charge shall be $ 19.45 per kW per month.)
B. For customers who take service at voltage levels of 69 kV or greater:
1. $ 20.38 per kW/month X 2/3 X Contract Standby Capacity; or
2. $ 20.38 per kW/month X Maximum Standby Capacity
(If customer's system is directly interconnected with the
Company's bulk transmission system, the applicable Reservation
Charge shall be $ 19.49 per kW per month.)
(CONTINUED ON NEXT PAGE)
<PAGE>
Maximum Standby Capacity is the maximum 15-minute interval of Standby
Power provided the customer by the Company during the billing month. Maximum
Standby Capacity shall equal the highest 15-minute interval during the billing
month of the following calculation:
MSC = (SIGMA)CSC - Maint.
Where:
MSC = Maximum 15-minute interval during the billing month of Standby
Power (kW) being supplied by Company.
(SIGMA)CSC = The aggregate Contract Standby Capacity of all the
customer's self-generation units.
Maint = The simultaneous 15-minute interval of any Maintenance Power
(kW) being supplied to customer by the Company.
IX. METERING
--------
The Company will install a Supply Meter at its point of delivery to
Customer and a Generator Meter(s) at the point(s) of output from each of
Customer's generators. All meters will record integrated demand and energy on
the same 15-minute interval basis as specified by Company.
X. DEFINITIONS
-----------
1. Contract Standby Capacity - for each specific customer generating unit for
which the Company is providing Standby Service, Contract Standby Capacity
shall be the greater of a) the measured kW output of each customer
self-generation unit at time of start-up test, or b) the highest 15 minute
measured kW output of each generating unit, however, not to exceed
Customer's actual total load.
2. Generator Meter - the time-of-use meter used to measure in 15-minute
intervals the total power and energy output of each Customer's cogeneration
units.
3. Designated Standby Service Hours - Customers requiring Standby Service for
less than the total hours in a billing month shall be allowed to designate
those periods and hours of a month when Standby Service is required. These
Designated Standby Service Hours shall represent those hours within a
billing month during which the customer is authorized to utilize Standby
Service. Use during any period or hours other than Designated Standby
Service Hours shall represent an Unauthorized Use of Standby Service
subject to certain special provisions for determining the appropriate
Capacity Factor value during billing periods when unauthorized Standby
Service was utilized. Such hours shall be specified in whole hour intervals
beginning on an hour for each designated day of the week. Designated
Standby Service Hours shall never total less than 365 hours a billing
month. This provision is applicable only to those customers whose Standby
Service requirements are less than 3,000 kW.
4. Capacity Factor - for purposes of this rate schedule, capacity factor shall
mean the capacity factor of the customer's generating unit(s) and shall not
reflect any period of time during a billing month that Company authorized
Maintenance Power was being utilized. The Capacity factor shall be
calculated in accordance with the following formula:
Capacity Factor = Actual customer generated kWh's during the billing month
--------------------------------------------------------
A
For purposes of use in this rate schedule, the value of the
capacity factor calculation shall never exceed 100%.
Where:
A = The lesser of: a) [(Contract Standby Capacity) X (MH)]; or
b) CTL
Customers having Standby Service Requirements of 3,000 kW or
greater:
MH = Hours in the billing month exclusive of any hours during
the billing month that customer's unit(s) were non-
operational during Company authorized scheduled maintenance.
CTL = Customer's maximum total load during the billing month
as determined by the total of energy generated on customer's
generating unit as recorded on the Generator Meter plus all
energy provided by Company during the billing month (exclusive
of maintenance energy) as recorded on the Supply Meter
(CONTINUED ON NEXT PAGE)
<PAGE>
Customers having Standby Service Requirements of less than 3,000
kW:
MH = The number of Designated Standby Service Hours in the billing
month, exclusive of any hours during the billing month that
customer's unit(s) were non-operational during Company
authorized scheduled maintenance, for which the customer has
contracted for Standby Service (but not less than 365 hours
per billing month).
In the event the customer utilizes Standby Service in any
period other than during Designated Standby Service Hours, MH
shall be represented as the actual number of hours in the
billing month (exclusive of any hours during which the
customer was receiving Company authorized scheduled
Maintenance Energy).
Furthermore, in the event there is more than two (2) instances
in any 12 month rolling period of Unauthorized Use of Standby
Service, MH shall be represented as the actual number of hours
in the billing month (exclusive of any hours during which the
customer was receiving Company authorized scheduled
Maintenance Energy) for the month during which the third
breach of service occurred, and for the next three months
thereafter. At the end of any three month period, a new twelve
(12) month rolling period shall commence for determining the
number of instances of Unauthorized Use.
CTL = Customer's maximum total load during the billing month during
the Designated Standby Service Hours for which the Customer
has contracted for Standby Service (but not less than 365
hours per month).as determined by the total of energy
generated on customer's generating unit as recorded on the
Generator Meter plus all energy provided by Company during the
billing month (exclusive of maintenance energy) as recorded on
the Supply Meter.
CTL shall represent the customer's maximum total load during
the hours in the billing month for which use of Standby
Service has been authorized as set forth in the definition of
Designated Standby Service Hours. CTL shall be calculated by
first adding the maximum simultaneous 15-minute kW peak
periods as recorded on the Supply Meter and Generator Meter(s)
during authorized periods of Standby Service the sum of which
is then multiplied by MH.
In the event the customer utilizes Standby Service during any
period of a billing month other than those authorized, CTL
shall represent the customer's maximum total load (peak
demand) during the billing month calculated as the sum of the
maximum simultaneous 15-minute kW peak period during the
billing period recorded on the Supply Meter and the Generator
Meter(s) during all hours of the billing month. CTL shall be
similarly calculated for any other months during which the
provision for breach of service explained in the definition of
MH above is being assessed.
CTL shall only be used for calculating Capacity Factor in
those months where the customer's maximum kW load is less than
total Contract Standby Capacity.
5. Supply Meter - the time-of-use meter used to measure in 15-minute intervals
the total power and energy supplied by Company to Customer.
6. Time Periods - On-Peak Period: 9 a.m. - 9 p.m. Monday through Friday
Off-Peak Period: All Other Hours
Mountain Standard Time shall be used in the application of this rate
schedule. In addition, to prevent radical changes in the system loads
the beginning and ending hours for individual customers may be varied
by up to one hour (total hours in each time period to remain unchanged)
and because of potential differences of the timing devices, there may
be a variation of up to 15 minutes in timing for the pricing periods.
7. Unauthorized Use - any period or hour of the month that the customer utilized
Standby Service other than Designated Standby Service Hours.
XI. ADJUSTMENTS
-----------
The applicable proportionate part of any taxes or governmental
impositions which are or may in the future be assessed on the basis of gross
revenues of the Company and/or the price or revenue from the electric energy or
service sold and/or the volume of energy generated or purchased for sale and/or
sold hereunder.
XII. TERMINATION PROVISION
---------------------
Should Customer cease to operate his cogeneration unit(s) for 60
consecutive days during periods other than planned scheduled maintenance
periods, Company reserves the option to terminate the Agreement for service
under this rate schedule with Customer.
XIII. CONTRACT PERIOD
---------------
As provided in the Electric Supply Agreement between Company and
Customer.
(CONTINUED ON NEXT PAGE)
<PAGE>
XIV. TERMS AND CONDITIONS
--------------------
Customer must enter into an Agreement for the Interconnection and The
Sale of Power with Company and an Electric Supply Agreement which shall
establish all pertinent details related to interconnection and other required
service standards. Customer will not have the option to sell power and energy to
Company under this tariff. Should Customer desire to do so, Customer would be
required to enter into a new Service Agreement which would set forth the
applicable purchase rate in addition terms and conditions for interconnection
and for the sale of power to the Company.
Customer will be required to contract for adequate standby power to
cover the total output of all the customer's generators unless adequate
facilities have been installed, to the satisfaction of APS, that isolates
portions of the customer's load from APS' system so that APS will in no event be
providing standby service in excess of Contracted Standby Capacity.
XV. CHANGE IN DESIGNATED STANDBY SERVICE HOURS
------------------------------------------
Customers for which Designated Standby Service Hours is applicable
shall be allowed no more than one (1) change in their Designated Standby Service
Hours during any eighteen (18) month time period. In no event shall the total of
Designated Standby Service Hours during a month fall below 365 hours.
<PAGE>
Attachment 7
<PAGE>
ELECTRIC RATES
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5216
Phoenix, Arizona Cancelling A.C.C. No. 5137
Filed by: Gary J. Volkenant Tariff or Schedule No. EPR-2
Title: Director, Business Financial Services Revision No. 4
Original Effective Date: October 25, 1981 Effective:
PURCHASE RATES FOR QUALIFIED COGENERATION AND SMALL POWER PRODUCTION
--------------------------------------------------------------------
FACILITIES UNDER 100 KW RECEIVING PARTIAL REQUIREMENTS OR INTERRUPTIBLE SERVICE
-------------------------------------------------------------------------------
AVAILABILITY
- ------------
In all territory served by Company.
APPLICATION
- -----------
To all cogeneration and small power production facilities 100 kW or
less where the facility's generator(s) and load are located at the same premise
and that otherwise meet qualifying status pursuant to the Arizona Corporation
Commission's Decision No. 52345 on cogeneration and small power production
facilities. Applicable only to qualifying facilities (QF's) electing to
configure their systems as to require only partial requirements or interruptible
service from the Company in order to meet their electric requirements.
TYPE OF SERVICE
- ---------------
Electric sales to the Company must be single or three phase, 60 Hertz,
at one standard voltage as may be selected by customer (subject to availability
at the premises). The qualifying facility will have the option to sell energy to
the Company at a voltage level different than that for purchases from the
Company; however, the QF will be responsible for all incremental costs incurred
to accommodate such an arrangement.
PAYMENT FOR PURCHASES FROM AND SALES TO THE CUSTOMER
- ----------------------------------------------------
Power sales and special services supplied by the Company to the
Customer in order to meet its supplemental or interruptible electric
requirements will be priced at the applicable retail rate or rates.
The Company will pay the Customer for any energy purchased as
calculated on the standard purchase rate (see below).
MONTHLY PURCHASE RATE
- ---------------------
Rate for pricing of energy, net of that for the customer's own use,
that is delivered to the Company:
Cents per kWh
--------------------------------------------
Non-Firm Power Firm Power
--------------------------------------------
On-Peak(1) Off-Peak(2) On-Peak(1) Off-Peak(2)
---------- ----------- ---------- -----------
Summer Billing Cycles 1.58 1.17 2.20 1.52
(June - October)
Winter Billing Cycles 1.25 1.08 1.74 1.38
(November - May)
(1) On-Peak Periods: 9 a.m. to 9 p.m., weekdays
(2) Off-Peak Periods: All other hours
These rates are based on the Company's estimated avoided energy costs and will
be updated annually to reflect changes in the Company's fuel costs.
(CONTINUED ON REVERSE SIDE)
<PAGE>
SERVICE CHARGE
- --------------
The monthly service charge shall be determined in accordance with the
type of customer service characteristics as set forth below:
Monthly Charge
--------------
Single Phase Service:
0-200 amp service $ 7.34
Three Phase Service:
0-200 amp service $ 8.87
201-400 amp service $ 18.31
CONTRACT PERIOD
- ---------------
As provided for in the Purchase Agreement.
DEFINITIONS
- -----------
1. Partial Requirements Service - A QF's system configuration
whereby the output from its electric generator(s) first go to
supply its own electric requirements with any excess energy
(over and above its own requirements at the time) then being
sold to the Company. The Company supplies the Customer's
supplemental electric requirements (those not met by the QF's
own generation facilities). This also may be referred to as
the "parallel mode" of operation.
2. Special Service(s) - The electric service(s) specified in this
section that will be provided by the Company in addition to or
in lieu of normal service(s).
* Interruptible Power - Electric energy or capacity
supplied by the Company subject to interruption by the
Company under specified conditions and under agreed upon
lead time requirements.
3. Non-Firm Power - Electric power which is supplied by the power
producer at the producer's option, where no firm guarantee is
provided, and the power can be interrupted by the power
producer at any time.
4. Firm Power - Power available, upon demand, at all times
(except for forced outages and scheduled maintenance) during
the period covered by the Purchase Agreement from the
Customer's facilities with an expected or demonstrated
reliability which is greater than or equal to the average
reliability of the Company's firm power sources.
5. Time Periods - Mountain Standard Time shall be used in the
application of this rate schedule. Because of potential
differences of the timing devices, there may be a variation of
up to 15 minutes in timing for the pricing periods.
TERMS AND CONDITIONS
- --------------------
Subject to Company's Terms and Conditions for Energy Purchases from
Qualified Cogeneration or Small Power Production Facilities, or as it may be
amended or modified from time to time by any supplemental or special Terms and
Conditions pursuant to Customer's Purchase Agreement with the Company.
Customer and Company will share in the cost of the bi-directional meter
used to record sales to the Customer and purchases from the Customer. Company
shall be responsible for all costs up to and equal to the installed cost of a
residential time-of-use meter, and Customer shall be responsible for the
difference between the installed cost of the bi-directional meter compared to a
standard residential time-of-use meter. Customer shall have the option to pay
the incremental metering costs initially or in monthly installements over a five
year time period.
(CONTINUED ON PAGE 3)
<PAGE>
METERING CONFIGURATION
- ----------------------
[GRAPHIC OMITTED]
(The omitted material is a diagram of a bidirectional meter which reads energy
flows from the Company into the customer for the customer's QF's load and also
reads the QF's generator's excess supply sold back to the Company.)
<PAGE>
ELECTRIC RATES
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5217
Phoenix, Arizona Cancelling A.C.C. No. 5159
Filed by: Gary J. Volkenant Tariff or Schedule No. EPR-3
Title: Director, Business Financial Services Revision No. 1
Original Effective Date: February 4, 1993 Effective:
PURCHASE RATES FOR QUALIFIED SOLAR/PHOTOVOLTAIC SMALL POWER PRODUCTION
----------------------------------------------------------------------
FACILITIES 10 KW OR LESS THAT RECEIVE FULL OR PARTIAL REQUIREMENTS
------------------------------------------------------------------
ELECTRIC SERVICE
----------------
FROZEN
AVAILABILITY
- ------------
In all territory served by Company.
APPLICATION
- -----------
To all small power production facilities with a nameplate rating of 10 kW or
less utilizing solar/photovoltaic technology where the customer's generator(s)
and load are located at the same premise and meet qualifying status pursuant to
the Arizona Corporation Commission's Decision No. 52345 on cogeneration and
small power production facilities. Applicable only to qualifying facilities
(QF's) either: a) operating in the simultaneous buy/sell mode (whereby all the
QF's generation output is fed directly into the Company's system and all of the
QF's electric requirements are met by sales from the Company) or; b) QF's
electing to configure their systems as to require only partial requirements or
interruptible service from the company in order to meet their electric
requirements.
Applicable only to those customers being served on the Company's Rate Schedule
EPR-3 prior to ____________________.
TYPE OF SERVICE
- ---------------
Electric sales to the Company must be single phase, 60 Hertz, at one standard
voltage as may be selected by customer (subject to availability at the
premises). The qualifying facility will have the option to sell energy to the
Company at a voltage level different than that for purchases from the Company;
however, the Customer will be responsible for all incremental costs incurred by
APS to accommodate such an arrangement.
BILLING OPTIONS FOR PURCHASES FROM AND SALES TO THE CUSTOMER
- ------------------------------------------------------------
The Customer will have the option of choosing either of the following two
methods for determining the bill for purchases and sales:
A. Net Bill Method:
The energy (kWh's) sold to the Company shall be subtracted from the
energy purchased from the Company. If the difference is positive, the
net energy received from the Company will be priced at the applicable
standard retail rate under which the Customer would otherwise purchase
its full requirements service. If the difference is negative, the net
energy delivered to the Company will be priced at the Monthly Purchase
Rate shown below.
B. Separate Bill Method:
All sales and purchases shall each be treated separately with sales to
the Customer billed on the applicable standard retail rate for full
requirements service, and purchases of energy from the Customer's QF
priced at the Monthly Purchase Rate shown below.
MONTHLY PURCHASE RATE
- ---------------------
Rate for pricing of energy, net of that for the customer's own use, that is
delivered to the Company under either Billing Option A or Option B:
Cents per kWh
----------------------------------------------
Non-Firm Power Firm Power
--------------------- -----------------------
On-Peak(1) Off-Peak(2) On-Peak(1) Off-Peak(2)
---------- ----------- ---------- -----------
Summer Billing Cycles 1.58 1.17 2.20 1.52
(June - October)
Winter Billing Cycles 1.25 1.08 1.74 1.38
(November - May)
(CONTINUED ON REVERSE SIDE)
<PAGE>
(1) On-Peak Periods: 9 a.m. to 9 p.m., weekdays
(2) Off-Peak Periods: All other hours
These rates are based on the Company's estimated avoided energy costs and will
be updated annually to reflect changes in the Company's fuel costs.
METERING
- --------
See pages 3 and 4 Metering Configurations & Options outlining the metering
options available to solar/photovoltaic QF Customers electing the simultaneous
buy/sell mode or the parallel mode of operation.
CONTRACT PERIOD
- ---------------
As provided for in the Purchase Agreement.
DEFINITIONS
- -----------
1. Full Requirements Service - Any instance whereby the Company provides
all the electric requirements of a Customer.
2. Partial Requirements Service - A QF's system configuration whereby the
output from its electric generator(s) first go to supply its own
electric requirements with any excess energy (over and above its own
requirements at the time) then being sold to the Company. The Company
supplies the Customer's supplemental electric requirements (those not
met by the QF's own-generation facilities). This also may be referred
to as the "parallel mode" of operation.
3. Special Service(s) - The electric service(s) specified in this section
that will be provided by the Company in addition to or in lieu of
normal service(s).
* Interruptible Power - Electric energy or capacity supplied by the
Company subject to interruption by the Company under specified
conditions and under agreed upon lead time requirements.
4. Non-Firm Power - Electric power which is supplied by the power producer
at the producer's option, where no firm guarantee is provided, and the
power can be interrupted by the power producer at any time.
5. Firm Power - Power available, upon demand, at all times (except for
forced outages and scheduled maintenance) during the period covered by
the Purchase Agreement from the Customer's facilities with an expected
or demonstrated reliability which is greater than or equal to the
average reliability of the Company's firm power sources.
6. Net Energy - The total kilowatthours (kWh's) sold to the Customer by
the Company less the total kWh's purchased by the Company from the
Customer's QF. "Net energy" applies only to those QF's operating in the
simultaneous buy/sell mode.
7. Time Periods - Mountain Standard Time shall be used in the application
of this rate schedule. Because of potential differences of the timing
devices, there may be a variation of up to 15 minutes in timing for the
pricing periods.
TERMS AND CONDITIONS
- --------------------
Subject to Company's Schedule No. 2, "Terms and Conditions for Energy Purchases
from Qualified Cogeneration or Small Power Production Facilities", or as it may
be amended or modified from time to time by any supplemental or special Terms
and Conditions pursuant to Customer's Purchase Agreement with the Company.
(CONTINUED ON PAGE 3)
<PAGE>
METERING CONFIGURATIONS & OPTIONS
FOR SOLAR/PHOTOVOLTAIC QF APPLICATIONS 10 KW OR LESS
(Simultaneous Buy/Sell Mode)
[GRAPHIC OMITTED]
(The omitted material is a diagram of the QF's generator which has meter 1 of
what is sold into the Company. The Company's line goes through meter 2 selling
to QF's load.)
METERING OPTIONS
- --------------------------------------------------------------------------------
Type of Meter Type of Meter
(Meter 1) (Meter 2)
------------- -------------
Qualifying Facilities Utilizing Solar/Photovoltaic
- ---------------------------------------------------
Technology 10 kW or less:
- -------------------------
f on an Energy Only (kWh) Type Rate* TOU(a) kWh(b)
f on a Time-of-Use Type Rate* TOU(c) TOU(d)
* Refers to the Customer's otherwise applicable standard retail rate for firm
purchases from the Company.
(a) A Time-of-use (TOU) meter that registers kWh's only during peak and
off-peak periods as specified in the "Monthly Purchase Rate" section of
this rate schedule.
(b) A non-timed watthour meter that registers kWh's only.
(c) A TOU meter that registers kWh's only during peak and off-peak periods
concurrent with those periods used in measuring energy for billing
purposes by Meter 2.
(d) As per applicable rate schedule.
NOTE: APS shall be responsible for providing all required meters for
the Simultaneous Buy/Sell Mode under the EPR-3 Metering
Configuration.
(CONTINUED ON REVERSE SIDE)
<PAGE>
METERING CONFIGURATIONS & OPTIONS
FOR SOLAR/PHOTOVOLTAIC QF APPLICATIONS 10 KW OR LESS
(Parallel Mode of Operation)
[GRAPHIC OMITTED]
(The omitted material is a diagram of two meters which are set between the
Company and QF's generator and load. Meter 1 registers sales by the Company and
meter 2 represents sales to the Company.)
METERING OPTIONS
- --------------------------------------------------------------------------------
Type of Meter Type of Meter
(Meter 1) (Meter 2)
Qualifying Facilities Utilizing Solar/Photovoltaic
Technology 10 kW or less:
If on an Energy Only (kWh) Type Rate* kWh(a) TOU(b)
If on a Time-of-Use Type Rate* TOU(c) TOU(d)
*Refers to the Customer's otherwise applicable standard retail rate for
firm purchases from the Company.
(a) A non-timed watthour meter that registers kWh's only.
(b) A Time-of-use (TOU) meter that registers kWh's only during peak and
off-peak periods as specified in the "Monthly Purchase Rate" section of
this rate schedule.
(c) As per applicable rate schedule.
NOTE: APS shall be responsible for providing all required meters for
the parallel mode of operation under the EPR-3 Metering
Configuration.
<PAGE>
ELECTRIC RATES
--------------
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5188
Phoenix, Arizona Tariff or Schedule No.
Filed by: Gary J. Volkenant Original Filing
Title: Director, Business Financial Services Effective:
Original Effective Date:
PURCHASE RATES FOR QUALIFIED SMALL POWER PRODUCTION FACILITIES 10 KW OR LESS
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UTILIZING RENEWABLE RESOURCE TECHNOLOGIES THAT RECEIVE PARTIAL REQUIREMENTS
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ELECTRIC SERVICE
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AVAILABILITY
- ------------
In all territory served by Company.
APPLICATION
- -----------
To all small power production facilities with a nameplate rating of 10 kW or
less utilizing renewable resource technologies where the customer's generator(s)
and load are located at the same premise and meet qualifying status pursuant to
the Arizona Corporation Commission's Decision No. 52345 on cogeneration and
small power production facilities. Applicable only to qualifying facilities
(QF's) electing to configure their systems as to require only partial
requirements or interruptible service from the Company in order to meet their
electric requirements.
TYPE OF SERVICE
- ---------------
Electric sales to the Company must be single phase, 60 Hertz, at one standard
voltage as may be selected by customer (subject to availability at the
premises). The qualifying facility will have the option to sell energy to the
Company at a voltage level different than that for purchases from the Company;
however, the Customer will be responsible for all incremental costs incurred by
APS to accommodate such an arrangement.
PAYMENT FOR PURCHASES FROM AND SALES TO THE CUSTOMER
- ----------------------------------------------------
Power sales and special services supplied by the Company to the Customer in
order to meet its supplemental or interruptible electric requirements will be
priced at the applicable retail rate or rates.
The Company will pay the Customer for any energy purchased as calculated on the
standard purchase rate (see below).
MONTHLY PURCHASE RATE
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Rate for pricing of energy, net of that for the customer's own use, that is
delivered to the Company:
Cents per kWh
---------------------------------------------
Non-Firm Power Firm Power
---------------------- ----------------------
On-Peak(1) Off-Peak(2) On-Peak(1) Off-Peak(2)
---------- ----------- ---------- -----------
Summer Billing Cycles 1.58 1.17 2.20 1.52
(June - October)
Winter Billing Cycles 1.25 1.08 1.74 1.38
(November - May)
(1) On-Peak Periods: 9 a.m. to 9 p.m., weekdays
(2) Off-Peak Periods: All other hours
These rates are based on the Company's estimated avoided energy costs and will
be updated annually to reflect changes in the Company's fuel costs.
CONTRACT PERIOD
- ---------------
As provided for in the Purchase Agreement.
(CONTINUED ON REVERSE SIDE)
<PAGE>
DEFINITIONS
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1. Partial Requirements Service - A QF's system configuration whereby the
output from its electric generator(s) first go to supply its own
electric requirements with any excess energy (over and above its own
requirements at the time) then being sold to the Company. The Company
supplies the Customer's supplemental electric requirements (those not
met by the QF's own-generation facilities). This also may be referred
to as the "parallel mode" of operation.
2. Special Service(s) - The electric service(s) specified in this section
that will be provided by the Company in addition to or in lieu of
normal service(s).
* Interruptible Power - Electric energy or capacity supplied by the
Company subject to interruption by the Company under specified
conditions and under agreed upon lead time requirements (Non-Firm
Power).
3. Non-Firm Power - Electric power which is supplied by the power producer
at the producer's option, where no firm guarantee is provided, and the
power can be interrupted by the power producer at any time.
4. Firm Power - Power available, upon demand, at all times (except for
forced outages and scheduled maintenance) during the period covered by
the Purchase Agreement from the Customer's facilities with an expected
or demonstrated reliability which is greater than or equal to the
average reliability of the Company's firm power sources.
5. Time Periods - Mountain Standard Time shall be used in the application
of this rate schedule. Because of potential differences of the timing
devices, there may be a variation of up to 15 minutes in timing for the
pricing periods.
TERMS AND CONDITIONS
- --------------------
Subject to Company's Schedule No. 2, "Terms and Conditions for Energy Purchases
from Qualified Cogeneration or Small Power Production Facilities", or as it may
be amended or modified from time to time by any supplemental or special Terms
and Conditions pursuant to Customer's Purchase Agreement with the Company.
METERING CONFIGURATION
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[GRAPHIC OMITTED]
(The omitted material is a diagram of a bidirectional meter which reads energy
flows from the Company into the customer for the customer's QF's load and also
reads the QF's generator's excess supply sold back to the Company.)
<PAGE>
Attachment 8
<PAGE>
Attachment 8
Points of Agreement
RESTRUCTURING ELEMENT
Staff has commenced an investigation into electric industry
restructuring in Docket No. U-0000-94-165. A Working Group and Task Forces were
established to obtain information on possible options, implementation of those
options, and some of the advantages and disadvantages of those options. A
progress report was issued on October 5, 1995 (Report of the Working Group on
Retail Electric Competition). APS has actively participated in all the Working
Group efforts.
These points of agreement pertain to procedures and outcomes in Docket
No. U-0000-94-165 regarding electric industry restructuring. The parties
recognize that the Commission may also consider other procedural issues and
outcomes.
These points of agreement do not commit either APS or the Staff to
assert any particular position on the issues identified in Paragraph 5 of
Procedural Matters, below, nor do they commit the Commission to resolve any
issue in any particular manner or in any particular time frame or sequence. In
addition, these points of agreement do not preclude APS, the Staff, or any other
participant in Docket No. U-0000-94-165 from raising other issues not identified
in this document.
Procedural Matters
- ------------------
1. The Commission's process for developing an information base
and for considering electric industry restructuring shall
continue to be a public process open to all interested
parties.
2. In addition to hearings and litigation, a collaborative effort
among some interested parties seeking common ground may help
resolve some restructuring issues; APS and Staff agree to
participate in and support collaborative efforts in good
faith.
3. APS and Staff agree to foster resolution of issues in the
restructuring Docket and in related activities.
4. Staff and APS agree that they shall urge the Commission to
consider the following issues as the Commission develops its
policies regarding restructuring, recognizing that other
issues may also be raised:
a. The legal nature of electric public service
corporations' service rights and responsibilities.
b. Electric public service corporations' obligations to
serve in a restructured environment.
c. Compensation for restructuring, taking into account,
among other matters: the estimated magnitude of
stranded investment; the magnitude of offsetting
increases in the market value of assets such as
transmission or distribution assets; mitigation of
stranded investment; allocation of stranded
investment among utilities, consumers in competitive
markets, and consumers in noncompetitive markets;
collection mechanisms; the period over which stranded
investment is collected; and the impacts of
alternative compensation approaches on public service
corporations, lenders, shareholders, and consumers
over the long run.
d. Clarification of federal-state jurisdictional
uncertainties and possible activities in other
forums, including the Legislature and FERC, to help
resolve those uncertainties.
e. Commission jurisdiction over market entrants
(including independent power producers, utilities,
and others) and uniformity of regulation of market
entrants.
f. Maintenance of generation, transmission, and
distribution system reliability, including mechanisms
and responsibility for services related to
reliability.
g. Concerns of public power entities over which the
Commission does not have jurisdiction regarding
restructuring.
h. Access by Arizona electric public service
corporations to consumers located in other service
territories and the terms for access by others to the
customers of Arizona public service corporations.
i. Whether some or all consumers should be able to
access generation in a competitive marketplace, and,
if applicable, the pace of introducing competition,
including phasing in of competition.
j. Market structure, including whether and how to
require or induce utility divestiture into
generation, transmission, distribution, or other
companies.
k. Generation structure, including the proper roles of
bilateral contracting and pooling of generation.
l. Encouragement of energy efficiency through demand
side management and other techniques, including
competitively neutral allocation of the costs of
demand side management programs not borne by
participants.
m. Encouragement of renewable energy resources through
various techniques, such as renewables portfolio
requirements, in a manner which does not put some
suppliers of electricity to Arizona consumers in a
relatively less competitive situation than other
suppliers.
n. Encouragement of environmental protection in a manner
which does not put some suppliers of electricity to
Arizona consumers in a relatively less competitive
situation than other suppliers.
o. Coordination of restructuring with the public
interest in integrated resource planning.
p. The proper form of regulation for noncompetitive
markets in generation and distribution.
q. The effect of the market power of existing public
service corporations on the development of
competitive generation markets, and ways to reduce
any impediments to competition.
r. The affordability of electric service, especially for
low income consumers and consumers in rural areas.
s. Limitations on the ability of cooperatives to sell
electricity or transmission service to non-members.
t. Transaction costs of participation in competitive
markets.
u. Impacts of restructuring on employment and other
economic factors.
v. Utility tax structure and its impact on Arizona
customers and companies.
Outcomes
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1. The results of restructuring should reflect a deliberate
process which considers the economic, financial, operational
and system planning effects of such restructuring.
2. Restructuring of the electric industry should result in
increased efficiency in electric markets, with
nondiscriminatory access to transmission and distribution
facilities and services.
3. All major customer groups should benefit from competition,
including residential customers.
4. Special needs programs, such as lifeline programs, should be
continued.
5. Transaction costs of participating in competitive markets and
consumer confusion should be minimized.
6. Fair dispute resolution process should be available.
7. The supply of electricity should be reliable over the long
term, of adequate quality for consumers, and safe.
8. The investment environment should be conducive to raising
capital necessary to provide long-term electric energy
services.
9. The electric industry should:
* actively seek to protect the natural environment;
* promote renewable generating resources to manage
uncertainty, control costs, and meet consumer needs
over the long run;
* encourage efficiency in the use of electric energy,
including cost effective demand side management; and
* maintain a long term planning perspective.
Expectations
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Staff and APS recognize that there is a diversity of opinion on many
matters. Staff and APS agree that the Commission should be requested to consider
all the procedural and outcome issues listed above in developing its policies on
restructuring. The Commission may use hearings and other mechanisms (such as
collaborative approaches) to achieve resolution of the issues. Staff and APS
agree that the market and political environments may evolve rapidly and that
timetables for introducing restructuring cannot be rigidly set a priori.
<PAGE>
ATTACHMENT 9
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<PAGE>
ATTACHMENT 9
APS POSITION ON ISSUES RAISED BY INDUSTRY RESTRUCTURING
-------------------------------------------------------
The Points of Agreement to the restructuring element of the Plan, which
are set forth in Attachment 8 to this Agreement, deal with the electric utility
industry in Arizona. APS believes cooperative legislative and regulatory actions
at both the state and federal levels will be necessary to permit broader access
to the generation market by retail customers of regulated public service
corporations in Arizona. The steps proposed herein are presented by the Company
as a balanced, comprehensive package, each part of which is dependent on the
others. APS will not be committed to support any particular part in the event
one or more other parts are dropped or materially changed in the legislative or
regulatory processes. It is the Company's firm position that these issues must
be addressed and resolved prior to allowing open access in the retail markets of
Arizona public service corporations.
As APS has pointed out during the Commission's Docket on Competition In
The Electric Utility Industry, a number of legislative, regulatory and market
issues must be satisfactorily addressed for Arizona to benefit from the
increased economic efficiency that competition potentially can produce. By its
concurrence to the Points of Agreement in Attachment 8, Staff has likewise
agreed to the importance of such issues. In addition, APS believes that the
record should be clear as to its present position on industry restructuring. For
consistency sake, the Company has divided its comments using the categorization
of issues from Attachment 8. However, APS has retained its own descriptive
titles when referring to specific issues.
PROCEDURAL AND SUBSTANTIVE MATTERS
Process for Considering Restructuring Issues
As indicated by its concurrence in Attachment 8, APS agrees that
industry restructuring should be debated and resolved in an open
process after consideration of all points of view. The Commission's
Docket No. U-0000-94-165 provides an appropriate forum for this
process, although as noted above, both the Arizona Legislature and the
U.S. Congress (in addition to FERC) will be important players in any
comprehensive industry restructuring.
Exclusive Service Rights
In Arizona, electric public service corporations are granted
statutorily established Certificates of Convenience and Necessity by
the Commission. Under the State's concept of "regulated monopoly,"
these certificates confer an exclusive and perpetual right to serve all
customers within a delineated territory as long as the utility provides
or is ready and willing to provide reasonable service at
Commission-regulated prices, sometimes referred to as the regulatory
compact. This territorial right has been characterized by the Arizona
Supreme Court as a "vested property right" protected by the Arizona
Constitution that cannot be condemned or otherwise "taken" without
payment of adequate compensation. If the issue of compensation is
adequately addressed, APS will support legislation that allows the
Commission to open, on a "phased" basis, heretofore exclusive electric
service territories in Arizona to competition from all regulated
electric public service corporations.
Obligation To Serve
In return for exclusive territorial rights, public service corporations
are generally required to serve all customers requesting service
(whether profitable or not) in accordance with rules and regulations
established by the Commission. This obligation to serve is an essential
part of the regulatory compact and has required Arizona's electric
utilities to anticipate customer growth, demand and usage and prudently
invest in generation, transmission, distribution, and other utility
assets. Unlike an enterprise in a fully competitive market, Arizona's
electric public service corporations cannot decide unilaterally which
markets they wish to serve, set the terms for providing such service,
or determine whether or not to expend the capital funds necessary to
meet future demands.
As customers gain access to other generation suppliers, this will
require a symmetrical change in the obligation of incumbent suppliers
so that the incumbent utility is not unfairly burdened with
"provider-of-last-resort" status. A clear breach of the regulatory
compact will occur if the obligation to serve (and associated cost
burdens) remains on a particular utility, while its competitors are
free to pick who, how, and when they wish to serve. Accordingly, APS
will support appropriate modifications to service obligations of
Arizona public service corporations that recognize increasing customer
options (at least with respect to generation) while still preserving
the availability of reliable and affordable service.
Compensation Issues
Arizona public service corporations have rightful constitutional and
equitable claims for compensation relative to recovery of stranded
investment, compensable property rights and wheeling charges;
specifically, compensation is due for:
(a) investments in assets prudently made, or commitments
prudently incurred, by an Arizona public service
corporation for the benefit of the customers in its
service territory which becomes "stranded", i.e.,
non-recoverable, because of changes in the regulatory
compact;
(b) investments "stranded" because of accounting or other
regulatory changes occurring in the transition from a
regulated monopoly environment to a competitive
market;
(c) the loss of constitutionally protected property
rights in an exclusive service territory conferred by
the Commission pursuant to statute, both when the
exclusiveness of such service rights is phased out as
to a particular customer class and when the loss
occurs as to a particular customer;
(d) wheeling services by an incumbent public service
corporation for dedicating a portion of its "wires"
capacity and ancillary services to accommodate a
competitor's access to one or more retail customers
within the incumbent's service territory, which
compensation should reflect appropriate charges fully
compensating the incumbent public service corporation
for such service, regardless of whether such charges
are regulated by FERC or the Commission.
In the economic proposal of the Plan, APS will take an
important step towards mitigating its "stranded" investment by
accelerating the amortization of "regulatory assets" over an eight (8)
year transition period. The "7(cent) Result" which represents the
Company's goal to reduce its per kWh cost by a combination of
aggressive cost containment and the development of new marketing
opportunities, is another example of how APS hopes to mitigate the
compensable damages it will experience upon the implementation of
retail competition.
Federal-State Jurisdictional Uncertainties
Electric power commerce across the state and region is impeded by the
jurisdictional uncertainty over the conflicting scope of federal versus
state regulation in the utility industry. Therefore, at the federal
level, APS, in cooperation with the industry and others, will seek
congressional legislation that clarifies the right of states to
authorize retail access and related terms and conditions of service and
to effectively regulate such transactions when necessary. The Company
will also seek clarification, through legislation or by FERC actions,
that will clear the jurisdictional haze between the reach of federal
control over transmission in interstate commerce and a state's critical
ability to regulate and set retail rates.
Competitive Balance
Efficient competition will occur when all players, including
out-of-state suppliers entering the Arizona market, are subject to the
same rights and responsibilities, free from market-distorting special
privileges, regulations or unequal burdens. APS will propose that any
market entrant allowed into a previously exclusive territory of a
regulated electric public service corporation pursuant to the
legislation previously discussed regarding "Exclusive Service Rights"
must itself be, or become, a public service corporation subject to
appropriate Commission regulatory oversight and related obligations,
including plant and line siting requirements (which should be
administered directly by the Commission) and shared responsibility for
maintaining service reliability. Such entrants could include
out-of-state utilities, power marketers, independent power producers
and other competitors.
Public Power Entities
The Arizona Constitution expressly excludes municipal corporations from
the category of entities (public service corporations) which it
subjects to regulation by the Commission. Due among other things to the
uncertainties that any amendment of the Constitution would entail, the
Company proposes to exclude municipal, tribal or other government-owned
utilities from this restructuring proposal. Where such utilities have
lawfully-conferred rights to serve all customers within a delineated
territory, those rights would remain intact (i.e., would not be subject
to being "phased" out as proposed above with respect to public service
corporations); conversely, such utilities, by virtue of their not being
public service corporations subject to Commission regulatory oversight
and related obligations, would not be allowed competitive access to
public service corporation territories in Arizona. However, it appears
to APS that changes in law and relationships at the federal level, such
as entitlements to preferential power from federal facilities or
federal income tax advantages, could lead to a common interest in
eliminating or reducing differences among utilities at the state level,
thereby occasioning future reexamination of the difference proposed in
this paragraph.
Reciprocal Trade Opportunities
Efficient competition and the public interest require that public
service corporations be allowed the reciprocal opportunity to trade in
each other's markets. The willingness of APS to open its service
territory to competitors is contingent upon APS obtaining meaningful
reciprocity from such competitors and their regulators. The Company's
desire to remove barriers to entry into other state and regional
markets can only be achieved through Commission and State support and
involvement. The Company will urge federal legislation that will
explicitly recognize the ability of states to condition the entry of
out-of-state power suppliers into Arizona upon on reciprocal
opportunities for Arizona public service corporations in other states.
Finally, APS will support amendments to federal laws, such as the
Public Utility Holding Company Act, to remove artificial and
unnecessary restraints on utilities that desire to compete in regional
and national markets.
Integrated Resource Planning
APS continues to support efficiency in electric usage, environmental
protection and the Commission's Integrated Resource Planning ("IRP")
process. Although the IRP is solidly grounded in traditional regulatory
principles, many of APS' potential competitors are exempt from the IRP
process. APS will ask the Commission to revise, consistent with the
changes proposed herein, the current IRP process to recognize the
emergence of competition and the need to maintain generation
reliability in a system with proliferating suppliers. APS will continue
to support cost-effective DSM and renewables as long as competitively
neutral funding mechanisms are established.
Market Structure
The Company is, of course, aware of proposals in other jurisdictions
for mandatory pooling of generation and for separation of generation
and "wires" through mandatory divestiture.
APS believes mandatory pooling is another form of regulation, one which
presumably would be beyond the bounds of Commission jurisdiction and
which could well be more pervasive and onerous than current regulation
and ultimately contrary to the interests of customers. APS believes
that bilateral contracting (which could be tri-or-more lateral when
aggregators and marketers are considered) will afford effective
competition, particularly if and when facilitated by the emergence of
an exchange mechanism such as the NY Mercantile Exchange.
Mandatory divestiture in the Company's judgment contravenes two
important principles, one of an engineering nature and the other
economic. System reliability depends on both generation and wires--some
entity will have to control both to assure an effective operating
system. The economic perspective is that there seems to be a natural
tendency toward vertical integration in analogous situations: United
Kingdom electric companies; telecommunications (where APS interprets
the recent AT&T announcement of separation of its manufacturing and
service functions as a move toward re-integration of local and
long-distance services and facilities). Such a tendency is not
necessarily anti-competitive; in the case of telecommunications, the
opposite is probably true. Additionally, mandatory divestiture could
require a complete restructuring of contract rights under the Company's
mortgage indenture and other financing instruments; furthermore, such
divestiture would be extremely expensive to implement, and could result
in significant economic dislocation among customers, bondholders and
shareholders, with no proven customer benefit. The policy goal should
be an efficiently functioning generation market, free from
concentration of market power and from abuse of a monopoly asset (such
as transmission). APS does not believe this goal is served by mandatory
pooling (which may actually trend in the other direction), or that
mandatory divestiture is the appropriate answer to the monopoly asset
issue in view of the necessity for system reliability.
The market power issue is difficult to address without knowing the size
of the market, but that should come into view by 2000. By then there
will have been considerable experience with wholesale wheeling by way
of FERC standard setting and adversarial proceedings. APS considers it
unlikely that any Arizona-based electric utility will have excessive
dominion over the relevant market as defined in 2000, or that the
Commission will then need to do anything more about any wire monopoly
in the field than what FERC will have by then already done in the
wholesale field.
Phased Direct Retail Access
Assuming that the economic proposal of the Plan is approved, and that the
foregoing issues have by then been resolved, APS would request the Commission
to authorize access by retail customers of public service corporations to the
broad generation market starting in the year 2000. For its system, APS would
propose that initial access would apply to retail transmission customers
receiving power at 69 kv or above. If this proves successful, it would be
expanded approximately two years later by allowing access for all customers
whose loads are greater than 3 mW and, by 2004, access for customers with
demand in excess of 1 mW. Access for all remaining customers would be proposed
at the appropriate time. APS would expect that other Arizona public service
corporations would propose comparable retail access provisions that provide
meaningful competitive opportunities. Such retail access would not necessarily
"deregulate" utility service or eliminate the Commission's ultimate
responsibility to public service corporations and their customers; it would,
however, require modifications of the manner in which that oversight role is
performed.
OUTCOMES
APS would like to emphasize the first three (3) of the "Outcomes"
listed in Attachment 8.
It is critical that electric industry restructuring should be a careful
and deliberative process that fully considers the economic, financial,
operational, and system planning aspects of restructuring. This can be
accomplished by addressing and resolving issues before rather than after or
during the restructuring.
The goal of any industry restructuring should be increased efficiency,
and hence lower costs. Restructuring "benefits" based on preditory pricing, cost
shifting, or shareholder losses are illusory. APS' proposals to address the
compensation issues and create competitive balance are intended to further an
outcome based on increased efficiency.
Third, all major customer groups should be permitted to benefit from
this increased efficiency. APS' proposals to maintain competitive balance,
create reciprocal trade opportunities, and preserve the Commission's ability to
effectively establish retail rates will help to make this preferred outcome more
achievable.
APS proposes that the Commission specifically address and resolve these
and other related issues through a series of hearings during 1996 (as
contemplated by the Commission Staff in its Competition Docket) which will seek
to develop appropriate legislative and regulatory solutions to these barriers.
These hearings would be held independent from the Commission's consideration of
the Agreement described above. APS believes that Commission action, in
consultation with interested parties, can produce a set of regulatory and
legislative reforms that can be presented to the Arizona Legislature and to the
U.S. Congress in 1997. However, APS recognizes that the foregoing issues are
difficult ones, legally and politically, and that their resolution will require
time, particularly at the federal level.
<PAGE>
ATTACHMENT 10
<PAGE>
ATTACHMENT 10
ELECTRIC RATES
--------------
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5194
Phoenix, Arizona Tariff or Schedule No. E-20
Filed by: Gary J. Volkenant Original Filing
Title: Director, Business Financial Services Effective Date:
Original Effective Date:
GENERAL SERVICE
---------------
TIME OF USE FOR
---------------
RELIGIOUS HOUSES OF WORSHIP
---------------------------
AVAILABILITY
- ------------
In all territory served by Company at all points where facilities of
adequate capacity and the required phase and suitable voltage are adjacent to
the premises served.
APPLICATION
- -----------
Applicable to non-taxable religious houses of worship, that apply for
and are eligible for such service, whose main purpose is worship and who have an
established and continuing membership, but will be limited to the meter that
serves the building in which the sanctuary or principal place of worship is
located.
The religious houses of worship may be requested to provide the Company
a copy of the letter of determination of non-taxable status as a religious
organization from the Internal Revenue Service. In addition, the religious
houses of worship agrees to provide the Company a copy within 30 days if the
letter is changed by the Internal Revenue Service.
Service must be supplied at one point of delivery and measured through
one meter unless otherwise specified by individual customer contract.
Not applicable to breakdown, standby, supplementary, residential or
resale service, nor to service for which Rate Schedule E-34 is applicable.
Rate selection is subject to Sections numbered 3.3 of Schedule No. 1 of
the Company's "Terms and Conditions", except that this rate schedule would
become effective from the next meter reading after written notice to Company and
after Company has installed the required timed kilowatt meter. 1/
TYPE OF SERVICE
- ---------------
Single or three phase, 60 Hertz, at one standard voltage as may be
selected by customer subject to the availability at the customer's premise.
Three phase service is furnished under Company's standard rules covering line
extensions. Transformation equipment is included in cost of extension. Three
phase service is not furnished for motors of an individual rated capacity of
less than 7-1/2 HP, except for existing facilities or where total aggregate HP
of all connected three phase motors exceed 12 HP. Three phase service is
required for motors of an individual rated capacity of more than 7-1/2 HP.
MONTHLY BILL
- ------------
The monthly bill shall be the greater of the amount computed under A.
or B. below, including the applicable Adjustments.
A. RATE
----
June-October $27.00 Basic Service Charge, plus
Billing Cycles 2.19 per kW* Demand Charge On-Peak
(Summer) 0.1319 per kWh On-Peak
0.0637 per kWh Off-Peak
November-May $27.00 Basic Service Charge
Billing Cycles 1.98 per kW* Demand Charge On-Peak
(Winter) 0.1160 per kWh On-Peak
0.0571 per kWh Off-Peak
* In the event the Off-Peak kW is greater than twice the
highest On-Peak kW established during the current month,
the difference between such Off-Peak kW and twice the
On-Peak kW shall be billed at 50% of the current month's
On-Peak kW charge, in addition to the Demand Charge as
stated above.
(1) The type of meter required is not generally used for general service
purposes and therefore their availability is limited. Consequently, the
Company cannot guarantee installation within any specific time.
(CONTINUED ON REVERSE SIDE)
<PAGE>
DETERMINATION OF KW DEMAND
--------------------------
The average kW demands supplied during the 15-minute periods of
maximum use during the On-Peak and Off-Peak periods of the month,
as determined from the reading of the Company's meter.
TIME PERIODS
------------
On-Peak Period: 11 a.m. - 9 p.m., Monday through Friday
Off-Peak Period: All Other Hours
Mountain Standard Time shall be used in the application of this
rate schedule. In addition, to prevent radical changes in the
system loads the beginning and ending hours for individual
customers may be varied by up to one hour (total hours in each time
period to remain unchanged) and because of potential differences of
the timing devices, there may be a variation of up to 15 minutes in
timing for the pricing periods.
B. MINIMUM
-----------
$20.00 plus $1.83 for each kW in excess of five of either the
highest kW established during either the On- or Off-Peak period
during the 12 months ending with the current month or the minimum
kW specified in the agreement for service, whichever is the
greater.
ADJUSTMENTS
-----------
Subject to the applicable proportionate part of any taxes or
governmental impositions which are or may in the future be assessed
on the basis of gross revenues of the Company and/or the price or
revenue from the electric energy or service sold and/or the volume
of energy generated or purchased for sale and/or sold hereunder.
CONTRACT PERIOD
- ---------------
One (1) year, or longer, at Company's option.
TERMS AND CONDITIONS AND CONTRACT PROVISIONS
- --------------------------------------------
Subject to Company's Terms and Conditions for the sale of electric
service, and/or special Terms and Conditions at Company's option as provided for
in any contract or agreement for service with any customer subject hereto.
<PAGE>
Attachment 11
<PAGE>
Attachment 11
ELECTRIC RATES
--------------
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5095
Phoenix, Arizona Cancelling A.C.C No.
Filed by: Gary J. Volkenant Tariff or Schedule No. E-3
Title: Director, Business Financial Services Revision No. 3
Original Effective Date: April 1, 1988 Effective:
RESIDENTIAL ENERGY SUPPORT PROGRAM
----------------------------------
AVAILABILITY
- ------------
In all territory served by Company at all points where facilities of
adequate capacity and the required phase and suitable voltage are adjacent to
the premises served.
APPLICATION
- -----------
To electric service billed under Residential Rate Schedules where the
customer has qualified for this rate as specified in the Company's plan for
administration. All provisions of the applicable Residential rate schedule will
apply except as modified herein.
MONTHLY BILL
- ------------
The monthly bill shall be in accordance with above specified schedules
except:
The Total Bill (before Taxes
For Bills with and Regulatory Assessment)
Usage of Will be Discounted by:
------------- ----------------------
0 - 400 kWh 30%
401 - 800 kWh 20%
801 - 1200 kWh 10%
1200 kWh and above $10.00
<PAGE>
Attachment 12
<PAGE>
Attachment 12
ELECTRIC RATES
--------------
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5189
Phoenix, Arizona Tariff or Schedule No. E-4
Filed by: Gary J. Volkenant Revision No. 1
Title: Director, Business Financial Services Effective:
Original Effective Date: September 1, 1995
MEDICAL CARE EQUIPMENT PROGRAM
------------------------------
AVAILABILITY
- ------------
In all territory served by Company at all points where facilities of
adequate capacity and the required phase and suitable voltage are adjacent to
the premises served.
APPLICATION
- -----------
To electric service billed under Residential Rate Schedules where the
customer has qualified for this rate as specified in the Company's plan for
administration. All provisions of the applicable Residential rate schedule will
apply except as modified herein.
MONTHLY BILL
- ------------
The monthly bill shall be in accordance with above specified schedules
except:
The Total Bill (before Taxes
For Bills with and Regulatory Assessment)
Usage of Will be Discounted by:
-------------- ---------------------
0 - 800 kWh 30%
801 - 1400 kWh 20%
1401 - 2000 kWh 10%
2000 kWh and above $20.00
Exhibit 15.1
May 10, 1996
Arizona Public Service Company
Post Office Box 53999
Phoenix, Arizona 85072-3999
We have made a review, in accordance with standards established by the American
Institute of Certified Public Accountants, of the unaudited interim financial
information of Arizona Public Service Company for the periods ended March 31,
1996 and 1995, as indicated in our report dated May 2, 1996; because we did not
perform an audit, we expressed no opinion on that information.
We are aware that our report referred to above, which is included in your
Quarterly Report on Form 10-Q for the quarter ended March 31, 1996, is
incorporated by reference in Registration Statement Nos. 33-51085, 33-57822,
33-61228, 33-55473, and 33-64455 on Form S-3.
We are also aware that the aforementioned report, pursuant to Rule 436(c) under
the Securities Act of 1933, is not considered a part of the Registration
Statement prepared or certified by an accountant or a report prepared or
certified by an accountant within the meaning of Sections 7 and 11 of the Act.
DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Phoenix, Arizona
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
PUBLIC UTILITY COMPANIES AND PUBLIC UTILITY
HOLDING COMPANIES (THOUSANDS OF DOLLARS)
FISCAL YEAR ENDED DECEMBER 31, 1996 FOR PERIOD
JANUARY 1, 1996 THROUGH MARCH 31, 1996 THREE
MONTHS ENDED
</LEGEND>
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<PERIOD-END> MAR-31-1996
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<TOTAL-NET-UTILITY-PLANT> 4639626
<OTHER-PROPERTY-AND-INVEST> 104355
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<TOTAL-DEFERRED-CHARGES> 1351001
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 6385425
<COMMON> 178162
<CAPITAL-SURPLUS-PAID-IN> 1039515
<RETAINED-EARNINGS> 402472
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72000
174089
<LONG-TERM-DEBT-NET> 1961679
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0
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<TOT-CAPITALIZATION-AND-LIAB> 6385425
<GROSS-OPERATING-REVENUE> 345261
<INCOME-TAX-EXPENSE> 31359
<OTHER-OPERATING-EXPENSES> 236380
<TOTAL-OPERATING-EXPENSES> 267739
<OPERATING-INCOME-LOSS> 77522
<OTHER-INCOME-NET> 7034
<INCOME-BEFORE-INTEREST-EXPEN> 84556
<TOTAL-INTEREST-EXPENSE> 38950
<NET-INCOME> 45606
4477
<EARNINGS-AVAILABLE-FOR-COMM> 41129
<COMMON-STOCK-DIVIDENDS> 42500
<TOTAL-INTEREST-ON-BONDS> 36253
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