EXHIBIT 10.1
RATE REDUCTION AGREEMENT
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Staff of the Arizona Corporation Commission (Staff) and Arizona Public
Service Company (APS or Company) agree:
1. APS will implement a first year average 3.25% base rate reduction of
$48.3 million, based on retail sales to and revenues from eligible
customers for the adjusted test year ended July 1, 1995. See 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 by means of the 0.299(cent)/kWh reduction as shown in
Attachment 1 by reducing energy charges for all current APS rate
schedules except those set forth in Attachment 2.
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. 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(cent)/kWh reduction in
the 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 the Plan, 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 and approval. The reduction for the current year
will automatically become effective for usage on or after July 1,
unless the Commission orders a hearing, which would automatically delay
its effective date 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 Agreement.
6. During the Moratorium Period, no party shall seek to change the rates
except as set forth specifically in this 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. Approval of a flexible contracting schedule, Rate E-36, that
permits APS to contract with individual customers on price, terms
and conditions of service. Contracts negotiated under this tariff
would be supplied under strict confidentiality to ACC Staff for
their approval within 30 days of submission. This schedule would
provide APS the ability to expeditiously and effectively price its
services to individual customers to retain and grow its load.
Schedule E-36, as shown on Attachment 4, shall also include the
following provisions:
* The negotiated rate must be commensurate with the costs to
the customer of that customer's alternative(s).
* APS must file each contract with Staff at least 30 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. APS must provide adequate
documentation on each element of the tariff (for example, the
customer's alternatives) before the 30 day review period
commences.
* The customer must 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 the demand side
management activities or audit/review.
* For contracts whose terms extend beyond the date when APS
will need to add capacity, marginal cost shall mean long run
marginal cost.
In addition, the last sentence under service billing on Schedule
E-36 shall be revised to read: "The revenue from the customer
shall exceed the marginal cost of serving that customer."
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. Revise the time-of-use (TOU) pricing periods and prices (both
residential and general service) once advanced meter
communications systems are in place.
ii. Establish a real-time pricing experiment or operational
program.
iii. Unbundle 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
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 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.
c. XXX-0, -0, xxx -0, xxxxxxxx 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
XXX-0, XXX-0, 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.
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 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 xxxxxx 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.
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. If APS
spends less than $7 million 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
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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 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 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 Agreement.
14. Each provision of this Agreement is in consideration and support of all
the other provisions. This Agreement shall not become effective until
the issuance of a final Commission Order approving this 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 Agreement according to its terms on or
before July 1, 1996, this Agreement shall be deemed automatically
withdrawn, the rate reduction provisions of this 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 Agreement, then the parties shall no longer be bound by the terms
of this Agreement and this 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 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 Agreement apply solely to and are
binding only in the context of the purposes and results of this
Agreement and none of the positions taken herein by 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 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 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 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 4th day of December 1995.
STAFF OF ARIZONA ARIZONA PUBLIC SERVICE
CORPORATION COMMISSION COMPANY
By: Xxxx Xxxxxxxx By: Xxxxxxx X. Post
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Title: Director, Utilities Division Title: Senior Vice President &
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Chief Operating Officer
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Attachment 1
Calculation of Base Rate Reduction
(Test Year Ended 6/30/95)
(1) Adjusted Base Revenues $ 1,485.1 Million
(2) 3.25% Base Rate Reduction [(1) x 3.25%] $ 48.3 Million
(3) Electric Sales Subject to Decrease 16,152 GWh
(4) Base Rate Decrease Factor [(2) / (3)] $ 0.00299 per kWh
(5) EEASE Roll-in Factor at $10 Million/year /a/ $ 0.00058 per kWh
(6) Net Base Rate Decrease Factor [(4) - (5)] $ 0.00241 per kWh
/a/ $10 million divided by the electric sales subject to EEASE (17,143.2 GWh).
ATTACHMENT 2
Attachment 2
Rates and Contracts Exempt
From General Rate Decreases
1. Rate E-67, Municipal Lighting Service -- City of Phoenix
2. Cyprus Copper Company Contract
3. El Paso Natural Gas (Leupp and Xxxxxxxx) Contract
4. Magma Copper Company Contract
5. Xxxxxx Dodge Contract
6. Stone Southwest Contract
7. Contracts under proposed Rate E-36
8. Future ACC approved contracts with pricing provisions that exempt them from
general rate decreases.
These rates and contracts are already discounted or have fixed rate provisions
and will not be subject to the general price decreases resulting from the
operation of the Plan unless so specified by contract.
ATTACHMENT 3
Attachment 3
Unit Cost Ratio and Unit Price Ratio Definitions
(The revenues and costs to be utilized in this calculation will be derived from
the actual audited financial statements of the Company)
Unit Cost Ratio (UCR): Annual cents-per-kilowatt-hour average cost of electric
services.
UCR = Annual total electric costs (1)
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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)
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Annual total Company kwh sales (2)
1. Excludes sales taxes (as in the case of the income statement), all ITC
amortization (as required by federal tax laws), annual Pinnacle West
charges net of costs for shareholder services, fuel expenses for
non-traditional and interchange sales (generally defined as opportunity
sales which are cost justified on an incremental basis), and
non-utility income or deductions and related income tax effects.
Includes fuel, operations and maintenance, depreciation and
amortization (including the accelerated amortization of regulatory
assets), property and other taxes, cost of capital (consisting of
long-term interest; debt discount, premium and expense; preferred stock
dividend requirements; and a return on equity of 11.25% applied to the
average annual equity balance), the gross profit margin on
non-traditional and interchange sales, DSM and renewable expenditures
(including net lost revenues and incentives), and income taxes on
Operating Income including adjustments to income taxes for the above
exclusions and inclusions.
2. Excludes kwh sales for non-traditional and interchange sales.
3. Includes miscellaneous revenues. Excludes sales taxes (as in the case
of the income statement) and non-traditional and interchange revenues.
ATTACHMENT 4
E-36
ELECTRIC RATES
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ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5223
Phoenix, Arizona Tariff or Schedule No. E-36
Filed by: Xxxx X. Xxxxxxxxx Original Filing
Title: Director, Business Financial Services Effective:
Original Effective Date:
FLEXIBLE CONTRACTING
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APPLICATION
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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 combined, 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, 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
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Only individual billing accounts 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
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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 filed with 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. APS must provide adequate documentation
on each element of the tariff (for example, the customer's alternatives) before
the thirty day review period commences. If no action is taken within 30 days of
the filing, the contract is deemed approved by the Commission. Nothing in this
tariff is intended to limit the Arizona Corporation Commission's power to order
recovery of costs determined to be attributable to the customer either prior to
or after termination of the contract.
ATTACHMENT 5
PROPOSED CHANGES TO SCHEDULE #1
2. ESTABLISHMENT OF SERVICE
2.2 Add to first sentence, "or to make a special read without a
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disconnect and calculate a xxxx for a partial month."
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2.2 Modify last sentence to read "Billing for the service charge
will be rendered as part of not later than the second
service xxxx."
2.3 GROUNDS FOR REFUSAL OF SERVICE
2.3.8 Change wording to "Service is requested by an Applicant and a
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prior customer living with the Applicant owes a delinquent
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xxxx."
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2.3.9 Change wording to "Applicant is acting as agent for a prior
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Customer who is deriving benefits of the electric service and
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who owes a delinquent xxxx."
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2.4 ESTABLISHMENT OF CREDIT OR SECURITY DEPOSIT
2.4.1.3 Delete Letter of Guarantee
2.6 SECURITY DEPOSITS
2.6.3 Add "effective on the first business day of each year."
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2.6.5.1 Change bankruptcy from within the last 6 months to within the
last 12 months.
2.6.6 Change to "...Customer's maximum monthly billing as estimated
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by the Company."
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4.2 BILLING AND COLLECTION
4.2.1 Change late charge from 12% to "18%."
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4.4 RETURNED CHECKS
4.4.1 Change $10 to "$15."
---
4.5 Change collection charge to "field charge", change amount from
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$9.50 to "$15.00" and add "or terminate the service." For
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other than termination, premise visit must be requested by
customer.
4.5.2 Change acceptable to "satisfactory to Company."
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5.3 COMPANY ACCESS TO CUSTOMER PREMISES
5.3 Add requirement of "unassisted" access in two sentences. All
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existing conditions shall be grandfathered, i.e., tariff shall
apply only to services established after effective date of
tariff.
5.3 Expand remedy for inaccessibility.
5.5 Add "a minimum standard is IEEE 519" and simplify language.
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6. METERING AND METERING EQUIPMENT
6.1.1 Add "Electric Service Requirements manual." All updates to
this manual shall be provided to Staff in a timely manner.
7. TERMINATION
7.1.5 Add "satisfactory and unassisted." All existing conditions
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shall be grandfathered, i.e., tariff shall apply only to
services established after effective date of tariff.
ATTACHMENT 6
ELECTRIC RATES
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ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5215
Phoenix, Arizona Tariff or Schedule No. E-52
Filed by: Xxxx X. Xxxxxxxxx Original Filing
Title: Director, Business Financial Services Effective Date:
Original Effective Date:
ELECTRIC SERVICE FOR PARTIAL REQUIREMENTS SERVICE
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OF LESS THAN 3,000 KW
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I. AVAILABILITY
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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
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Applicable to any non-residential customer requiring Partial Requirements
services, Supplemental Power, Standby Power or Maintenance Power 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.
III. TYPE OF SERVICE
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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 XXXX
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The monthly xxxx shall be the sum of the amounts computed under A., B.,
C., and D. below, including the applicable Adjustments:
A. Basic Service
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$ 106.79 per month Basic Service Charge, plus
$ 17.06 per month for each Generator Meter
B. Supplemental Service
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In accordance with the rate levels contained in General Service
Rate Schedule E-32 excluding the monthly Basic Service Charge.
C. Standby Service
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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.
2. Standby Energy Charge:
June - October $0.0213 per kWh on-peak
Billing Cycles $0.0154 per kWh off-peak (Summer)
November - May $0.0187 per kWh on-peak
Billing Cycles $0.0135 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
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$0.0187 per kWh on-peak
$0.0135 per kWh off-peak
E. Energy Rates
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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
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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
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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:
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.
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. 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 = 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
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.
ELECTRIC RATES
--------------
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5214
Phoenix, Arizona Tariff or Schedule No. E-55
Filed by: Xxxx X. Xxxxxxxxx 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 Power 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.
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 XXXX
------------
The monthly xxxx 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 and 2 below:
1. Monthly Reservation Charge of either a, b or c:
a. $ 4.13 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. $ 5.05 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. $ 6.98 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 of this rate schedule.
2. Standby Energy Charge:
June - October $0.0217 per kWh on-peak
Billing Cycles $0.0159 per kWh off-peak (Summer)
November - May $0.0193 per kWh on-peak
Billing Cycles $0.0139 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
-------------------
$0.0193 per kWh on-peak
$0.0139 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.
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. $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 19.43 per kW per month.)
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. 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 = 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
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.
ATTACHMENT 7
ELECTRIC RATES
--------------
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5216
Phoenix, Arizona Cancelling A.C.C. No. 5137
Filed by: Xxxx X. Xxxxxxxxx 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.
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.
METERING CONFIGURATION
----------------------
[GRAPHIC OMITTED]
[The omitted material is a diagram of a bidirectional meter which reads energy
flows from the Company into the customer for the customer's QF's load and also
reads the QF's generator's excess supply sold back to the Company.]
ELECTRIC RATES
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5217
Phoenix, Arizona Cancelling A.C.C. No. 5159
Filed by: Xxxx X. Xxxxxxxxx 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 xxxx for purchases and sales:
A. Net Xxxx 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 Xxxx 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)
(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.
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.
METERING CONFIGURATIONS & OPTIONS
FOR SOLAR/PHOTOVOLTAIC QF APPLICATIONS 10 KW OR LESS
(Parallel Mode of Operation)
[GRAPHIC OMITTED]
[The omitted material is a diagram of two meters which are set between the
Company and QF's generator and load. Meter 1 registers sales by the Company and
meter 2 represents sales to the Company.]
METERING OPTIONS
--------------------------------------------------------------------------------
Type of Meter Type of Meter
(Meter 1) (Meter 2)
---------- -----------
Qualifying Facilities Utilizing Solar/Photovoltaic
--------------------------------------------------
Technology 10 kW or less:
------------------------
If on an Energy Only (kWh) Type Rate* kWh(a) TOU(b)
If on a Time-of-Use Type Rate* TOU(c) TOU(d)
*Refers to the Customer's otherwise applicable standard retail rate for
firm purchases from the Company.
(a) A non-timed watthour meter that registers kWh's only.
(b) A Time-of-use (TOU) meter that registers kWh's only during peak and
off-peak periods as specified in the "Monthly Purchase Rate" section of
this rate schedule.
(c) As per applicable rate schedule.
NOTE: APS shall be responsible for providing all required meters for
the parallel mode of operation under the EPR-3 Metering
Configuration.
ELECTRIC RATES
--------------
ARIZONA PUBLIC SERVICE COMPANY A.C.C. No. 5188
Phoenix, Arizona Tariff or Schedule No. EPR-4
Filed by: Xxxx X. Xxxxxxxxx Original Filing
Title: Director, Business Financial Services Effective:
Original Effective Date:
PURCHASE RATES FOR QUALIFIED SMALL POWER PRODUCTION FACILITIES 10 KW OR LESS
----------------------------------------------------------------------------
UTILIZING RENEWABLE RESOURCE TECHNOLOGIES
-----------------------------------------
THAT RECEIVE PARTIAL REQUIREMENTS ELECTRIC SERVICE
--------------------------------------------------
AVAILABILITY
------------
In all territory served by Company.
APPLICATION
------------
To all small power production facilities with a nameplate rating of 10 kW or
less utilizing renewable resource technologies where the customer's generator(s)
and load are located at the same premise and meet qualifying status pursuant to
the Arizona Corporation Commission's Decision No. 52345 on cogeneration and
small power production facilities. Applicable only to qualifying facilities
(QF's) electing to configure their systems as to require only partial
requirements or interruptible service from the Company in order to meet their
electric requirements.
TYPE OF SERVICE
---------------
Electric sales to the Company must be single phase, 60 Hertz, at one standard
voltage as may be selected by customer (subject to availability at the
premises). The qualifying facility will have the option to sell energy to the
Company at a voltage level different than that for purchases from the Company;
however, the Customer will be responsible for all incremental costs incurred by
APS to accommodate such an arrangement.
PAYMENT FOR PURCHASES FROM AND SALES TO THE CUSTOMER
----------------------------------------------------
Power sales and special services supplied by the Company to the Customer in
order to meet its supplemental or interruptible electric requirements will be
priced at the applicable retail rate or rates.
The Company will pay the Customer for any energy purchased as calculated on the
standard purchase rate (see below).
MONTHLY PURCHASE RATE
---------------------
Rate for pricing of energy, net of that for the customer's own use, that is
delivered to the Company:
Cents per kWh
--------------------------------------------------
Non-Firm Power Firm Power
------------------------ -----------------------
On-Peak(1) Off-Peak(2) On-Peak(1) Off-Peak(2)
---------- ----------- ---------- -----------
Summer Billing Cycles 1.58 1.17 2.20 1.52
(June - October)
Winter Billing Cycles 1.25 1.08 1.74 1.38
(November - May)
(1) On-Peak Periods: 9 a.m. to 9 p.m., weekdays
(2) Off-Peak Periods: All other hours
These rates are based on the Company's estimated avoided energy costs and will
be updated annually to reflect changes in the Company's fuel costs.
CONTRACT PERIOD
---------------
As provided for in the Purchase Agreement.
DEFINITIONS
-----------
1. Partial Requirements Service - A QF's system configuration whereby the
------------------------------
output from its electric generator(s) first go to supply its own electric
requirements with any excess energy (over and above its own requirements
at the time) then being sold to the Company. The Company supplies the
Customer's supplemental electric requirements (those not met by the QF's
own-generation facilities). This also may be referred to as the "parallel
mode" of operation.
2. Special Service(s) - The electric service(s) specified in this section
-------------------
that will be provided by the Company in addition to or in lieu of normal
service(s).
* Interruptible Power - Electric energy or capacity supplied by the
--------------------
Company subject to interruption by the Company under specified
conditions and under agreed upon lead time requirements (Non-Firm
Power).
3. Non-Firm Power - Electric power which is supplied by the power producer at
--------------
the producer's option, where no firm guarantee is provided, and the power
can be interrupted by the power producer at any time.
4. Firm Power - Power available, upon demand, at all times (except for forced
----------
outages and scheduled maintenance) during the period covered by the
Purchase Agreement from the Customer's facilities with an expected or
demonstrated reliability which is greater than or equal to the average
reliability of the Company's firm power sources.
5. Time Periods - Mountain Standard Time shall be used in the application of
------------
this rate schedule. Because of potential differences of the timing
devices, there may be a variation of up to 15 minutes in timing for the
pricing periods.
TERMS AND CONDITIONS
--------------------
Subject to Company's Schedule No. 2, "Terms and Conditions for Energy Purchases
from Qualified Cogeneration or Small Power Production Facilities", or as it may
be amended or modified from time to time by any supplemental or special Terms
and Conditions pursuant to Customer's Purchase Agreement with the Company.
METERING CONFIGURATION
----------------------
[GRAPHIC OMITTED]
[The omitted material is a diagram of a bidirectional meter which reads energy
flows from the Company into the customer for the customer's QF's load and also
reads the QF's generator's excess supply sold back to the Company.]
Attachment 8
------------
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 xxxxxx 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 consumer and consumers in rural
areas.
s. Limitations on the ability of cooperatives to sell
electricity or transmission service to non-members.
t. Transaction costs of participation in competitive
markets.
u. Impacts of restructuring on employment and other
economic factors.
v. Utility tax structure and its impact on Arizona
customers and companies.
Outcomes
--------
1. The results of restructuring should reflect a deliberate
process which considers the economic, financial,
operational and system planning effects of such
restructuring.
2. Restructuring of the electric industry should result in
increased efficiency in electric markets, with
nondiscriminatory access to transmission and distribution
facilities and services.
3. All major customer groups should benefit from competition,
including residential customers.
4. Special needs programs, such as lifeline programs, should
be continued.
5. Transaction costs of participating in competitive markets
and consumer confusion should be minimized.
6. Fair dispute resolution process should be available.
7. The supply of electricity should be reliable over the long
term, of adequate quality for consumers, and safe.
8. The investment environment should be conducive to raising
capital necessary to provide long-term electric energy
services.
9. The electric industry should:
* actively seek to protect the natural environment;
* promote renewable generating resources to manage
uncertainty, control costs, and meet consumer needs
over the long run;
* encourage efficiency in the use of electric energy,
including cost effective demand side management; and
* maintain a long term planning perspective.
Expectations
------------
Staff and APS recognize that there is a diversity of opinion on many
matters. Staff and APS agree that the Commission should be requested to consider
all the procedural and outcome issues listed above in developing its policies on
restructuring. The Commission may use hearings and other mechanisms (such as
collaborative approaches) to achieve resolution of the issues. Staff and APS
agree that the market and political environments may evolve rapidly and that
timetables for introducing restructuring cannot be rigidly set a priori.
ATTACHMENT 9
------------
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.
