BEFORE THE ARIZONA CORPORATION COMMISSION
CARL J. KUNASEK
CHAIRMAN
JIM IRVIN
COMMISSIONER
WILLIAM A. MUNDELL
COMMISSIONER
IN THE MATTER OF COMPETITION IN THE DOCKET NO. RE-00000C-94-0165
PROVISION OF ELECTRIC SERVICES
THROUGHOUT THE STATE OF ARIZONA. DECISION NO. 61969
OPINION AND ORDER
DATES OF PUBLIC COMMENT HEARINGS: June 14, 17, 21, and 23, 1999
PLACES OF HEARINGS: Phoenix and Tucson, Arizona
PRESIDING OFFICERS: Jane Rodda and Teena Wolfe
IN ATTENDANCE: Carl J. Kunasek, Chairman
Jim Irvin, Commissioner
William A. Mundell, Commissioner
APPEARANCES: Mr. Paul A. Bullis, Chief Counsel,
and Ms. Janet Wagner, Staff
Attorney, Legal Division, on behalf
of the Utilities Division of the
Arizona Corporation Commission.
BY THE COMMISSION:
On December 26, 1996, in Decision No. 59943, the Arizona Corporation
Commission ("Commission") adopted rules which provided the framework for the
introduction of retail electric competition in Arizona. These rules are codified
at A.A.C. R14-2-1601 et seq. ("Rules" or "Electric Competition Rules"). Under
the Rules adopted in December 1996, competition in the retail electric industry
was to be phased-in beginning in January 1999.
The Commission adopted certain modifications to the Electric Competition
Rules on an emergency basis on August 10, 1998, in Decision No. 61071 (the
"Emergency Rules"). On December 11, 1998, in Decision No. 61272, the Commission
adopted the Emergency Rules on a permanent basis. On January 11, 1999, the
Commission issued Decision No. 61311 which stayed
1 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
the effectiveness of the Rules and related Decisions, and ordered the Hearing
Division to begin consideration of further comment and actions in the Docket. On
April 23, 1999, the Commission issued Decision No. 61634, in which the
Commission adopted modifications to the Electric Competition Rules ("Revised
Rules").
The Revised Rules were published in the Arizona Administrative Register on
May 14, 1999. By Procedural Order dated April 21, 1999, public comment sessions
were scheduled in Phoenix on June 14, and 23, 1999, and in Tucson on June 17,
and 21, 1999. The April 21, 1999 Procedural Order also ordered interested
parties to file written comments to the Revised Rules no later than May 14,
1999, and to file responsive comments no later than June 4, 1999. After
consideration of the filed written comments and oral comments received in the
public comment hearings, the Hearing Division recommends the modification of the
Revised Rules as set forth in Appendix A ("Proposed Modifications").
The Proposed Modifications are not substantive. Adoption of the Proposed
Modifications will allow the Commission to more effectively implement the
restructuring of the retail electric market by providing stakeholders with
details of the structure and process of the introduction of competition into
Arizona's electric industry.
The Proposed Modifications include the following provisions:
The modifications to R14-2-203 and -209 are clarifications necessitated to
conform to the revisions to Article 16 and to clarify who pays charges for meter
rereads, respectively.
The modifications to R14-2-1601 provide definitions for "Aggregation" and
"Self-Aggregation", "Ancillary Services" and "Public Power Entity" which were
needed to clarify terms utilized in the Revised Rules. The definition of Utility
Distribution Company ("UDC") was amended to reinstate the word "constructs".
R14-2-1602 is not modified.
The modification of R14-2-1603 clarifies that distribution cooperatives
that provide Competitive Services within their distribution service territories
do not need to apply for a Certificate of Convenience and Necessity ("CC&N"),
and clarifies that applicants affiliated with an Affected
2 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
Utility must demonstrate that they have a Commission-approved Code of Conduct as
a requisite of certification.
The modifications to R14-2-1604 clarify that small users are eligible to
aggregate their loads and are eligible to participate in the competitive market
subject to the limitations of the phase-in period. The proposed modification
also provides that a waiting list of residential customers interested in
participating in the competitive market be made available to certificated
Electric Service Providers upon request.
The modification of R14-2-1605 clarifies that distribution cooperatives
providing services within their service territories do not require a CC&N.
The modifications to R14-2-1606 define the term "open market" and further
delineate the elements that must be unbundled in the Standard Offer Service
tariffs.
There are no proposed modifications to R14-2-1607(Recovery of Standard
Cost) or -1608 (System Benefits Charges).
The modification to R14-2-1609 clarifies that the UDC retains the
obligation to assure adequate transmission import and distribution capability to
meet the needs of all distribution customers within its service territory. The
proposed changes were based upon parties' comments that additional guidance
regarding a UDC's obligation concerning transmission import capability would be
beneficial. The modifications do not alter the obligation established in the
Revised Rules.
No change was proposed for R14-2-1610 concerning in-state reciprocity.
In R14-2-1611(C), the word "terms" is changed to "provisions" to avoid
confusion about the Commission's obligation concerning the confidentiality of
special contracts.
The modifications to R14-2-1612(C) add protections contained in A.R.S. ss.
40-202 regarding the authorization to switch electric providers. In addition,
Section 1612(I) was revised to clarify confusion about the timeframe for
terminating competitive service and returning a customer to Standard Offer
Service. Section 1612(K) was revised slightly to provide that each competitive
point of delivery shall be assigned a Universal Node Identifier and that the
Load-Serving Entity developing the load profile determines if a load is
predictable. Section 1612(N) was revised to provide the
3 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
minimum elements that should appear on every bill.
R14-2-1613 was modified to remove the word "and" from Section 1613(A) and
to correct the numbering of section 1613(B).
There is no proposed change to R14-2-1614.
The proposed modifications to R14-2-1615 replace the reference to "meters"
in Section 1615(B) with "Meter Services and Meter Reading Services" and replace
the reference to service territory at the time of these rules with "its
distribution service territory" in section 1615(C). Also, the reference in
Section 1615(C) to the generation cooperative is removed.
The modification to R14-2-1616 clarifies that this section, requiring a
Code of Conduct, applies to Affected Utilities, including cooperatives, that
plan to offer Competitive Services through an affiliate and also provides
minimum guidelines for the content of the required Codes of Conduct. Further,
the modification clarifies that the Code of Conduct is subject to Commission
approval after a hearing.
The modifications to R14-2-1617 add language to Sections 1617(A) and (B) to
clarify that Load-Serving Entities providing either generation service or
Standard Offer Service must prepare the consumer information label, and correct
a typo in Section 1617(D).
* * * * * * * * * *
Having considered the entire record herein and being fully advised in the
premises, the Commission finds, concludes, and orders that:
FINDINGS OF FACT
1. Decision No. 59943 enacted R14-2-1601 through -1616, the Retail Electric
Competition Rules.
2. Decision No. 61071 (August 10, 1998) adopted certain modifications to
the Retail Electric Competition Rules and conforming changes to R14-2-203,
R14-2-204 and R14-2-208 through R14-2-211 on an emergency basis.
3. Decision No. 61272 (December 11, 1998) adopted the Emergency Rules on a
permanent basis, including Staff's additional changes proposed on November 24,
1998.
4 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
4. Decision No. 61311 stayed the effectiveness of the Emergency Rules and
related Decisions, and ordered the Hearing Division to conduct further
proceedings in this Docket.
5. In Decision No. 61634 (April 23, 1999), the Commission adopted the
Revised Rules, which revised R14-2-201 through -207, -210 and -212 and
R14-2-1601 through -1617.
6. The Revised Rules and the Economic, Small Business and Consumer Impact
Statement were sent to the Secretary of State and published in the Arizona
Administrative Register on May 14, 1999.
7. Pursuant to Procedural Order dated April 21, 1999, public comment
sessions on the Revised Rules were held in Phoenix on June 14, and 23, 1999, and
in Tucson on June 17 and 21, 1999, and interested parties filed written comments
to the Revised Rules by May 14, 1999, and filed responsive comments by June 4,
1999.
8. After consideration of the filed written comments and oral comments
received in the public comment hearings, the Hearing Division recommended the
Proposed Modifications set forth in Appendix A, and incorporated herein by
reference. The Proposed Modifications amend R14-2-203 and -209, and R14-2-1601,
- -1603 through -1606, -1609, -1611 through -1613, and -1615 through -1617.
9. The Concise Explanatory Statement for the Proposed Modifications is set
forth in Appendix B, attached hereto and incorporated herein by reference.
10. We believe that in the interest of economic efficiency, transaction
processing methods used by market participants should be standardized and
coordinated statewide, and that Commission Staff, market participants, and the
Residential Utility Consumer Office should participate in a process to achieve
the goal of consistent statewide application of transaction processing methods
by the time that the Arizona market is open to full retail electric competition.
To achieve this goal, a Process Standardization Working Group, coordinated by
the Director, Utilities Division or Director's designee, should be formed; and
the Process Standardization Working Group should, as soon as practicable, submit
a Report to the Commission containing Standardized Operating Procedures to be
used by all market participants. The Report should also contain any additional
Staff
5 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
recommendations based on the Process Standardization Working Group's review of
transaction processing methods.
CONCLUSIONS OF LAW
1. The Commission has the authority for the Proposed Modifications pursuant
to Article XV of the Arizona Constitution and A.R.S. ss.ss. 40-202 , 40-203,
40-250, 40-321, 40-322, 40-331, 40-332, 40-336, 40-361, 40-365, 40-367 and
A.R.S. Title 40, generally.
2. Notice of rulemaking and of the hearing was given in the manner
prescribed by law.
3. The Proposed Modifications are not substantive in nature.
4. Adoption of the Proposed Modifications is in the public interest, and
should be approved.
5. The Concise Explanatory Statement set forth in Appendix B should be
adopted.
6. Formation of a Process Standardization Working Group and submission of a
Report as outlined in Findings of Fact No. 10 above will serve the public
interest.
ORDER
IT IS THEREFORE ORDERED that A.A.C. R14-2-201 et seq. and R14-2-1601 et
seq. as set forth in Appendix A and the Concise Explanatory Statement, as set
forth in Appendix B are hereby adopted.
IT IS FURTHER ORDERED that the Commission's Utilities Division shall submit
the adopted amended Rules A.A.C. R14-2-201 et seq. and R14-2-1601 et seq. to the
Office of the Secretary of State.
IT IS FURTHER ORDERED that within thirty days of the effective date of this
Order, a Process Standardization Working Group shall be formed, which shall
consist of Commission Staff, market participants, and the Residential Utility
Consumer Office; and shall be coordinated by the Director, Utilities Division or
the Director's designee.
IT IS FURTHER ORDERED that the Process Standardization Working Group shall
meet as necessary to review transaction processing methods used by market
participants, for the purpose of standardizing and coordinating those methods.
6 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
IT IS FURTHER ORDERED that on or before June 15, 2000, the Director,
Utilities Division, or the Director's designee, shall file with the Commission a
Process Standardization Working Group Report, which shall contain Standardized
Operating Procedures to be used by all market participants. The Report may also
contain additional Staff recommendations based on the Process Standardization
Working Group's review of transaction processing methods.
IT IS FURTHER ORDERED that this Decision shall become effective
immediately.
BY ORDER OF THE ARIZONA CORPORATION COMMISSION.
Carl J. Kunasek Jim Irvin William A. Mundell
- --------------------------------------------------------------------------------
CHAIRMAN COMMISSIONER COMMISSIONER
IN WITNESS WHEREOF, I, BRIAN C. McNEIL,
Executive Secretary of the Arizona
Corporation Commission, have hereunto set
my hand and caused the official seal of the
Commission to be affixed at the Capitol, in
the City of Phoenix, this 29th day of
September, 1999.
BRIAN C. McNEIL
-------------------------------------------
BRIAN C. McNEIL
EXECUTIVE SECRETARY
DISSENT _________________
JR:dap
7 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
SERVICE LIST FOR: ELECTRIC COMPETITION RULES
DOCKET NO. RE-00000C-94-0165
Copies mailed to the Service List of RE-00000C-94-0165
Paul A. Bullis, Chief Counsel
LEGAL DIVISION
1200 W. Washington Street
Phoenix, Arizona 85007
Utilities Division Director
ARIZONA CORPORATION COMMISSION
1200 W. Washington Street
Phoenix, Arizona 85007
8 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
APPENDIX A
TITLE 14. PUBLIC SERVICE CORPORATIONS; CORPORATIONS
AND ASSOCIATIONS; SECURITIES REGULATION
CHAPTER 2. CORPORATION COMMISSION - FIXED UTILITIES
ARTICLE 2. ELECTRIC UTILITIES
R14-2-201. Definitions - No Change
R14-2-202. Certificate of Convenience and Necessity for electric utilities;
filing requirements on certain new plants - No Change
R14-2-203. Establishment of service - Modified
R14-2-204. Minimum customer information requirements - No Change
R14-2-205. Master metering - No Change
R14-2-206. Service lines and establishments - No Change
R14-2-207. Line Extensions - No Change
R14-2-208. Provision of service - No Change
R14-2-209 Meter reading - Modified
R14-2-210. Billing and collection - No Change
R14-2-211 Termination of service - No Change
R14-2-212. Administrative and hearing requirements - No Change
R14-2-213 Conservation - No Change
ARTICLE 16. RETAIL ELECTRIC COMPETITION
R14-2-1601. Definitions - Modified
R14-2-1602. Commencement of Competition - No Change
R14-2-1603. Certificates of Convenience and Necessity - Modified
Competitive Phases - Modified
1 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
R14-2-1605. Competitive Services - Modified
R14-2-1606. Services Required To Be Made Available - Modified
R14-2-1607. Recovery of Stranded Cost of Affected Utilities - No Change
R14-2-1608. System Benefits Charges - No Change
R14-2-1609. Transmission and Distribution Access - Modified
R14-2-1610. In-state Reciprocity - No Change
R14-2-1611. Rates - Modified
R14-2-1612. Service Quality, Consumer Protection, Safety, and Billing
Requirements - modified
R14-2-1613. Reporting Requirements - Modified
R14-2-1614 Administrative Requirements - No Change
R14-2-1615 Separation of Monopoly and Competitive Services - Modified
R14-2-1616. Code of Conduct - Modified
R14-2-1617 Disclosure of Information - Modified
2 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
ARTICLE 2. ELECTRIC UTILITIES
R14-2-201. DEFINITIONS - No change
R14-2-202. CERTIFICATE OF CONVENIENCE AND NECESSITY FOR ELECTRIC UTILITIES;
FILING REQUIREMENTS ON CERTAIN NEW PLANTS - No change
R14-2-203. ESTABLISHMENT OF SERVICE
A. No change.
B. No change.
C. No change.
D. Service establishments, re-establishments or reconnection charge
1. Each utility may make a charge as approved by the Commission for the
establishment, reestablishment, or reconnection of utility services,
including transfers between Electric Service Providers.
2. Should service be established during a period other than regular
working hours at the customer's request, the customer may be required
to pay an after-hour charge for the service connection. Where the
utility scheduling will not permit service establishment on the same
day requested, the customer can elect to pay the after-hour charge for
establishment that day or his service will be established on the next
available normal working day.
3. For the purpose of this rule, the definition of service establishments
are where the customer's facilities are ready and acceptable to the
utility and the utility needs only to install a meter, read a meter,
or turn the service on.
4. Service establishments with an Electric Service Provider will be
scheduled for the next regular meter read date if the direct access
service request is provided 15 calendar days prior to that date and
appropriate metering equipment is in place. If a direct access service
request is made in less than 15 days prior to the next regular read
date, service will be established at the next regular meter read date
thereafter. The utility may offer after-hours or earlier service for a
fee.
3 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
This section shall not apply to the establishment of new service, but
is limited to a change of providers of existing electric service.
E. No change.
R14-2-204. MINIMUM CUSTOMER INFORMATION REQUIREMENTS - No change
R14-2-205. MASTER METERING - No change
R14-2-206. SERVICE LINES AND ESTABLISHMENTS - NO CHANGE
R14-2-207. LINE EXTENSIONS - NO CHANGE
R14-2-208. PROVISION OF SERVICE - NO CHANGE
R14-2-209 METER READING
A. No change.
B. No change.
C. Meter rereads
1. Each utility or Meter Reading Service Provider shall at the request of
a customer, or the customer's Electric Service Provider, Utility
Distribution Company (as defined in A.A.C. R14-2-1602) or billing
entity reread that customer's meter within 10 working days after such
a request.
2. Any reread may be charged to the customer, or the customer's Electric
Service Provider, Utility Distribution Company (as defined in A.A.C.
R14-2-1601) or billing entity making the request at a rate on file and
approved by the Commission, provided that the original reading was not
in error.
3. When a reading is found to be in error, the reread shall be at no
charge to the customer, or the customer's Electric Service Provider,
Utility Distribution Company (as defined in A.A.C. R14-2-1601) or
billing entity.
D. No change.
E. No change.
F. No change.
R14-2-210. BILLING AND COLLECTION - No change
4 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
R14-2-211 TERMINATION OF SERVICE - No change
R14-2-212. ADMINISTRATIVE AND HEARING REQUIREMENTS - No change
R14-2-213 CONSERVATION - No change
ARTICLE 16. RETAIL ELECTRIC COMPETITION
R14-2-1601. DEFINITIONS
In this Article, unless the context otherwise requires:
1. "Affected Utilities" means the following public service corporations
providing electric service: Tucson Electric Power Company, Arizona
Public Service Company, Citizens Utilities Company, Arizona Electric
Power Cooperative, Trico Electric Cooperative, Duncan Valley Electric
Cooperative, Graham County Electric Cooperative, Mohave Electric
Cooperative, Sulphur Springs Valley Electric Cooperative, Navopache
Electric Cooperative, Ajo Improvement Company, and Morenci Water and
Electric Company.
2. "Aggregator" means an Electric Service Provider that, as part of its
business, combines retail electric customers into a purchasing group.
3. "Aggregation means the combination and consolidation of loads of
multiple customers.
4. "Ancillary Services" means those services designated as ancillary
services in Federal Energy Regulatory Commission Order 888, including
the services necessary to support the transmission of electricity from
resource to load while maintaining reliable operation of the
transmission system in accordance with good utility practice.
5. "Bundled Service" means electric service provided as a package to the
consumer including all generation, transmission, distribution,
ancillary and other services necessary to deliver and measure useful
electric energy and power to consumers.
6. "Competition Transition Charge" (CTC) is a means of recovering
Stranded Costs.
7. "Competitive Services" means all aspects of retail electric service
except those services
5 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
specifically defined as "Noncompetitive Services" pursuant to
R14-2-1601(27) or noncompetitive services as defined by the Federal
Energy Regulatory Commission.
8. "Control Area Operator" is the operator of an electric system or
systems, bounded by interconnection metering and telemetry, capable of
controlling generation to maintain its interchange schedule with other
such systems and contributing to frequency regulation of the
interconnection.
9. "Consumer Education" is the provision of impartial information to
consumers about competition or Competitive and Noncompetitive Services
and is distinct from advertising and marketing.
10. "Current Transformer" (CT) is an electrical device used in conjunction
with an electric meter to provide a measurement of energy consumption
for metering purposes.
11. "Direct Access Service Request" (DASR) means a form that contains all
necessary billing and metering information to allow customers to
switch electric service providers. This form must be submitted to the
Utility Distribution Company by the customer's Electric Service
Provider.
12. "Delinquent Accounts" means customer accounts with outstanding past
due payment obligations that remain unpaid after the due date.
13. "Distribution Primary Voltage" is voltage as defined under the
Affected Utility's Federal Energy Regulatory Commission (FERC) Open
Access Transmission Tariff, except for Meter Service Providers, for
which Distribution Primary Voltage is voltage at or above 600 volts
(600V) through and including 25 kilovolts (25 kV).
14. "Distribution Service" means the delivery of electricity to a retail
consumer through wires, transformers, and other devices that are not
classified as transmission services subject to the jurisdiction of the
Federal Energy Regulatory Commission; Distribution Service excludes
Metering Service, Meter Reading Service, and billing and collection
services, as those terms are used herein.
15. "Electronic Data Interchange" (EDI) is the computer-to-computer
electronic exchange of business
6 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
documents using standard formats which are recognized both nationally
and internationally.
16. "Electric Service Provider" (ESP) means a company supplying,
marketing, or brokering at retail any Competitive Services pursuant to
a Certificate of Convenience and Necessity.
17. "Electric Service Provider Service Acquisition Agreement" or "Service
Acquisition Agreement" means a contract between an Electric Service
Provider and a Utility Distribution Company to deliver power to retail
end users or between an Electric Service Provider and a Scheduling
Coordinator to schedule transmission service.
18. "Generation" means the production of electric power or contract rights
to the receipt of wholesale electric power.
19. "Green Pricing" means a program offered by an Electric Service
Provider where customers elect to pay a rate premium for electricity
generated by renewable resources.
20. "Independent Scheduling Administrator" (ISA) is an entity, independent
of transmission owning organizations, intended to facilitate
nondiscriminatory retail direct access using the transmission system
in Arizona.
21. "Independent System Operator" (ISO) is an independent organization
whose objective is to provide nondiscriminatory and open transmission
access to the interconnected transmission grid under its jurisdiction,
in accordance with the Federal Energy Regulatory Commission principles
of independent system operation.
22. "Load Profiling" is a process of estimating a customer's hourly energy
consumption based on measurements of similar customers.
23. "Load-Serving Entity" means an Electric Service Provider, Affected
Utility or Utility Distribution Company, excluding a Meter Service
Provider, and Meter Reading Service Provider.
24. "Meter Reading Service" means all functions related to the collection
and storage of consumption data.
25. "Meter Reading Service Provider" (MRSP) means an entity providing
Meter Reading Service, as
7 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
that term is defined herein and that reads meters, performs
validation, editing, and estimation on raw meter data to create
billing-ready meter data; translates billing-ready data to an approved
format; posts this data to a server for retrieval by billing agents;
manages the server; exchanges data with market participants; and
stores meter data for problem resolution.
26. "Meter Service Provider" (MSP) means an entity providing Metering
Service, as that term is defined herein.
27. "Metering and Metering Service" means all functions related to
measuring electricity consumption.
28. "Must-Run Generating Units" are those local generating units that are
required to run to maintain distribution system reliability and to
meet load requirements in times of congestion on certain portions of
the interconnected transmission grid.
29. "Noncompetitive Services" means Distribution Service, Standard Offer
Service, transmission and any ancillary services deemed to be
non-competitive by the Federal Energy Regulatory Commission, Must-Run
Generating Units services, provision of customer demand and energy
data by an Affected Utility or Utility Distribution Company to
Electric Service Providers, and those aspects of Metering Service set
forth in R14-2-1612(K).
30. "OASIS" is Open Access Same-Time Information System, which is an
electronic bulletin board where transmission-related information is
posted for all interested parties to access via the Internet to enable
parties to engage in transmission transactions.
31. "Operating Reserve" means the generation capability above firm system
demand used to provide for regulation, load forecasting error,
equipment forced and scheduled outages, and local area protection to
provide system reliability.
32. "Potential Transformer" (PT) is an electrical device used to step down
primary voltages to 120V for metering purposes.
33. "Provider of Last Resort" means a provider of Standard Offer Service
to customers within the
8 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
provider's certificated area whose annual usage is 100,000 kWh or less
and who are not buying competitive services.
34. "Public Power Entity" incorporates by reference the definition set
forth in A.R.S. ss. 30-801.16.
35. "Retail Electric Customer" means the person or entity in whose name
service is rendered.
36. "Scheduling Coordinator" means an entity that provides schedules for
power transactions over transmission or distribution systems to the
party responsible for the operation and control of the transmission
grid, such as a Control Area Operator, Arizona Independent Scheduling
Administrator or Independent System Operator.
37. "Self-Aggregation" is the action of a retail electric customer or
group of customers who combine their own metered loads into a single
purchase block.
38. "Standard Offer Service" means Bundled Service offered by the Affected
Utility or Utility Distribution Company to all consumers in the
Affected Utility's or Utility Distribution Company's service territory
at regulated rates including metering, meter reading, billing and
collection services, demand side management services including but not
limited to time-of-use, and consumer information services. All
components of Standard Offer Service shall be deemed noncompetitive as
long as those components are provided in a bundled transaction
pursuant to R14-2-1606(A).
39. "Stranded Cost" includes:
a. The verifiable net difference between:
i. The net original cost of all the prudent jurisdictional
assets and obligations necessary to furnish electricity
(such as generating plants, purchased power contracts, fuel
contracts, and regulatory assets), acquired or entered into
prior to December 26, 1996, under traditional regulation of
Affected Utilities; and
ii. The market value of those assets and obligations directly
attributable to the introduction of competition under this
Article;
9 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
b. Reasonable costs necessarily incurred by an Affected Utility to
effectuate divestiture of its generation assets;
c. Reasonable employee severance and retraining costs necessitated
by electric competition, where not otherwise provided; and
d. Other transition and restructuring costs as approved by the
Commission as part of the Affected Utility's Stranded Cost
determination pursuant to R14-2-1607.
40. "System Benefits" means Commission-approved utility low income, demand
side management, Consumer Education, environmental, renewables,
long-term public benefit research and development and nuclear fuel
disposal and nuclear power plant decommissioning programs, and other
programs that may be approved by the Commission from time to time.
41. "Transmission Primary Voltage" is voltage above 25 kV as it relates to
metering transformers.
42. "Transmission Service" refers to the transmission of electricity to
retail electric customers or to electric distribution facilities and
that is so classified by the Federal Energy Regulatory Commission or,
to the extent permitted by law, so classified by the Arizona
Corporation Commission.
43. "Unbundled Service" means electric service elements provided and
priced separately, including, but not limited to, such service
elements as generation, transmission, distribution, Must Run
Generation, metering, meter reading, billing and collection and
ancillary services. Unbundled Service may be sold to consumers or to
other Electric Service Providers.
44. "Utility Distribution Company" (UDC) means the electric utility entity
regulated by the Commission that operates, constructs and maintains
the distribution system for the delivery of power to the end user
point of delivery on the distribution system.
45. "Utility Industry Group" (UIG) refers to a utility industry
association that establishes national standards for data formats.
46. "Universal Node Identifier" is a unique, permanent, identification
number assigned to each service
10 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
delivery point.
R14-2-1602. COMMENCEMENT OF COMPETITION - No change
R14-2-1603. CERTIFICATES OF CONVENIENCE AND NECESSITY
A. Any Electric Service Provider intending to supply Competitive Services
shall obtain a Certificate of Convenience and Necessity from the Commission
pursuant to this Article. An Affected Utility need not apply for a
Certificate of Convenience and Necessity to continue to provide electric
service in its service area during the transition period set forth in
R14-2-1604. A Utility Distribution Company providing Standard Offer
Service, or services authorized in R14-2-1615, after January 1, 2001, need
not apply for a Certificate of Convenience and Necessity. All other
Affected Utility affiliates created in compliance with R14-2-1615(A) shall
be required to apply for appropriate Certificates of Convenience and
Necessity.
B. Any company desiring such a Certificate of Convenience and Necessity shall
file with the Docket Control Center the required number of copies of an
application. In support of the request for a Certificate of Convenience and
Necessity, the following information must be provided:
1. A description of the electric services which the applicant intends to
offer;
2. The proper name and correct address of the applicant, and
a. The full name of the owner if a sole proprietorship,
b. The full name of each partner if a partnership,
c. A full list of officers and directors if a corporation, or
d. A full list of the members if a limited liability corporation;
3. A tariff for each service to be provided that states the maximum rate
and terms and conditions that will apply to the provision of the
service;
4. A description of the applicant's technical ability to obtain and
deliver electricity if appropriate and to provide any other proposed
services;
5. Documentation of the financial capability of the applicant to provide
the proposed services, including the most recent income statement and
balance sheet, the most recent projected income
11 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
statement, and other pertinent financial information. Audited
information shall be provided if available;
6. A description of the form of ownership (for example, partnership,
corporation);
7. {For an applicant which is an affiliate of an Affected Utility, a
statement of whether the Affected Utility has complied with the
requirements of R14-2-1616, including the Commission Decision
approving the Code of Conduct, where applicable; and} [An explanation
of how the applicant intends to comply with the requirements of
R14-2-1616, or a request for waiver or modification thereof with an
accompanying justification for any such requested waiver or
modification.]
8. Such other information as the Commission or the staff may request.
C. No change.
D. No change.
E. No change.
F. No change.
G. No change.
H. No change.
I. No change.
J. No change.
K. No change.
R14-2-1604. COMPETITIVE PHASES
A. At the date established pursuant to R14-2-1602(A), each Affected Utility
shall make available at least 20% of its 1995 system retail peak demand for
competitive generation supply on a first-come, first-served basis as
further described in this rule. First-come, first-served for the purpose of
this rule, shall be determined for non-residential customers by the date
and time of an Electric Service Provider's filing of a Direct Access
Service Request with the Affected Utility or Utility Distribution Company.
The effective date of the Direct Access Service Request must be within 60
days of the filing date of the Direct Access Service Request.
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Residential customer selection will be determined under approved
residential phase-in programs as specified in R14-2-1604.
1. All Affected Utility customers with single premise non-coincident peak
demand load of 1 MW or greater will be eligible for competitive
electric services upon the commencement of competition. Customers
meeting this requirement shall be eligible for competitive services
until at least 20% of the Affected Utility's 1995 system peak demand
is served by competition.
2. Any class of customer may aggregate into a minimum combined load of 1
MW or greater within an Affected Utility's service territory and be
eligible for competitive electric services. From the commencement of
competition pursuant to R14-2-1602 through December 31, 2000,
aggregation of new competitive customers will be allowed until such
time as at least 20% of the Affected Utility's 1995 peak demand is
served by competitors.
3. Affected Utilities shall notify customers eligible under this
subsection of the terms of the subsection no later than 60 days prior
to the start of competition within its service territory.
4. {Effective January 1, 2001, all Affected Utility customers
irrespective of size will be eligible for Aggregation and
Self-Aggregation. Aggregation and Self-Aggregation customers
purchasing their electricity and related services at any time after
the effective date of these rules must do so from a certificated
Electric Service Provider as provided for in these rules.}
B. As part of the minimum 20% of 1995 system peak demand set forth in
R14-2-1604(A), each Affected Utility shall reserve a residential phase-in
program that provides an increasing minimum percentage of residential
customers with access to competitive electric services according to the
following schedule:
1. January 1, 1999 1 1/4%
April 1, 1999 2 1/2%
July 1, 1999 3 3/4%
October 1, 1999 5%
January 1, 2000 6 1/4%
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April 1, 2000 7 1/2%
July 1, 2000 8 3/4%
October 1, 2000 10%
2. Access to the residential phase-in program will be on a first-come,
first-served basis. The Affected Utility shall create and maintain a
waiting list to manage the residential phase-in program, {which list
shall promptly be made available to any certificated Load-Serving
Electric Service Provider upon request.}
3. Residential customers participating in the residential phase-in
program shall be permitted to use load profiling to satisfy the
requirements for hourly consumption data; however, they may choose
other metering options offered by their Electric Service Provider
consistent with the Commission's rules on Metering.
4. If not already done, each Affected Utility shall file a residential
phase-in program proposal to the Commission for approval by Director,
Utilities Division by September 15, 1999. Interested parties will have
until September 30, 1999, to comment on any proposal. At a minimum,
the residential phase-in program proposal will include specifics
concerning the Affected Utility's proposed:
a. Process for customer notification of residential phase-in
program;
b. Selection and tracking mechanism for customers based on
first-come, first-served method;
c. Customer notification process and other education and information
services to be offered;
d. Load Profiling methodology and actual load profiles, if
available; and
e. Method for calculation of reserved load.
5. After the commencement of competition pursuant to R15-2-1602, each
Affected Utility shall file quarterly residential phase-in program
reports within 45 days of the end of each quarter. The 1st such report
shall be due within 45 days of the 1st quarter ending after the start
of the phase-in of
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competition for that Affected Utility. The final report due under this
rule shall be due within 45 days of the quarter ending December 31,
2002. As a minimum, these quarterly reports shall include:
a. The number of customers and the load currently enrolled in
residential phase-in program by Energy Service Provider;
b. The number of customers currently on the waiting list;
c. A description and examples of all customer education programs and
other information services including the goals of the education
program and a discussion of the effectiveness of the programs;
and
d. An overview of comments and survey results from participating
residential customers.
6. {Aggregation or Self-Aggregation of residential customers is allowed
subject to the limitations of the phase-in percentages in this rule.}
C. No change.
D. No change.
E. No change.
F. No Change
R14-2-1605. COMPETITIVE SERVICES
{Except as provided in R14-2-1615(C)}, Competitive Services shall require a
Certificate of Convenience and Necessity and a tariff as described in
R14-2-1603. A properly certificated Electric Service Provider may offer
Competitive Services under bilateral or multilateral contracts with retail
consumers.
R14-2-1606. SERVICES REQUIRED TO BE MADE AVAILABLE
A. No change.
B. After January 1, 2001, power purchased by an investor owned Utility
Distribution Company {for Standard Offer Service shall be acquired from the
competitive market through prudent, arm's-length transactions, and with at
least fifty percent through a competitive bid process.} [to provide
Standard Offer Service shall be]
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[acquired through the open market.]
C. Standard Offer Tariffs
1. By July 1, 1999, or pursuant to Commission Order, whichever occurs
first, each Affected Utility shall file proposed tariffs to provide
Standard Offer Service. Such rates shall not become effective until
approved by the Commission. Any rate increase proposed by an Affected
Utility or Utility Distribution Company for Standard Offer Service
must be fully justified through a rate case proceeding.
2. Standard Offer Service tariffs shall include the following elements,
{each of which shall be clearly unbundled and identified in the filed
tariffs:}
a. Competitive Services: [Electricity:]
(1) Generation, {which shall include all transaction costs and
line losses;}
(2) Competition Transition Charge, {which shall include recovery
of generation related regulatory assets;}
(3) {Generation-related billing and collection;} [Must-Run
Generating Units]
{(4) Transmission Services;}
{(5) Metering Services;
(6) Meter Reading Services; and
(7) Optional Ancillary Services, which shall include spinning
reserve service, supplemental reserve, regulation and
frequency response service, and energy imbalance service.}
b. {Non-Competitive Services}: [Delivery]
(1) {Distribution services};
(2) {Required Ancillary services, which shall include
scheduling, system control and dispatch service, and
reactive supply and voltage control from generation sources
service;} [Transmission services]
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(3) {Must-Run Generating Units};[Ancillary services]
{(4) System Benefit Charges; and}
{(5) Distribution-related billing and collection.}
[c. Other:
(1) Metering Service
(2) Meter Reading Service
(3) Billing and collection
d. System Benefits
The Competition Transition Charge shall be included in the
Standard Offer Service tariffs for the purpose of clearly showing
that portion of Standard Offer Service charges being collected to
pay Stranded Cost.]
3. Affected Utilities and Utility Distribution Companies may file
proposed revisions to such rates Any rate increase proposed by an
Affected Utility or Utility Distribution Company for Standard Offer
Service must be fully justified through a rate case proceeding, which
may be expedited at the discretion of the Utilities Division Director.
4. Such rates shall reflect the costs of providing the service.
5. Consumers receiving Standard Offer Service are eligible for potential
future rate reductions as authorized by the Commission.
6. After January 2, 2001, tariffs for Standard Offer Service shall not
include any special discounts or contracts with terms, or any tariff
which prevents the customer from accessing a competitive option, other
than time-of-use rates, interruptible rates or self-generation
deferral rates.
D. {By the effective date of these rules},[July 1, 1999] or pursuant to
Commission Order, whichever occurs first, each Affected Utility or Utility
Distribution Company shall file an Unbundled Service tariff which shall
include a Noncompetitive Services tariff. {The Unbundled Service tariff
shall calculate the items listed in R14-2-1602(C)(2)(b) on the same basis
as those items are calculated in the Standard Offer Service tariff.}
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E. No change.
F. No change.
G. No change.
H. No change.
I. No change.
R14-2-1607. RECOVERY OF STRANDED COST OF AFFECTED UTILITIES - No Change
R14-2-1608. SYSTEM BENEFITS CHARGES - No Change
R14-2-1609. TRANSMISSION AND DISTRIBUTION ACCESS
A. No change.
B. Utility Distribution Companies shall retain the obligation to assure that
adequate transmission import capability is available to meet the load
requirements of all distribution customers within their service areas.
{Utility Distribution Companies shall retain the obligation to assure that
adequate distribution system capacity is available to meet the load
requirements of all distribution customers within their service areas.}
C. No change.
D. No change.
E. The Affected Utilities that own or operate Arizona transmission facilities
shall file a proposed Arizona Independent Scheduling Administrator
implementation plan with the Commission within 30 days of the Commission's
adoption of final rules herein. The implementation plan shall address
Arizona Independent Scheduling Administrator governance, incorporation,
financing and staffing; the acquisition of physical facilities and staff by
the Arizona Independent Scheduling Administrator; the schedule for the
phased development of Arizona Independent Scheduling Administrator
functionality {and proposed transition to a regional ISO or Regional
Transmission Organization;} contingency plans to ensure that critical
functionality is in place no later than 3 months following adoption of
final rules herein by the Commission; and any other significant issues
related to the timely and successful implementation of the Arizona
Independent Scheduling Administrator.
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F. No change.
G. No change.
H. No change.
I. No change.
J. No change.
R14-2-1610. IN-STATE RECIPROCITY - No change.
R14-2-1611. RATES
A. No change.
B. No change.
C. Prior to January 1, 2001, competitively negotiated contracts governed by
this Article customized to individual customers which comply with approved
tariffs do not require further Commission approval. However, all such
contracts whose term is 1 year or more and for service of 1 MW or more must
be filed with the Director, Utilities Division as soon as practicable. If a
contract does not comply with the provisions of the Load Serving Entity's
approved tariffs, it shall not become effective without a Commission order.
The {provisions} [terms] of such contracts shall be kept confidential by
the Commission.
D. No change.
E. No change.
F. No change.
R14-2-1612. SERVICE QUALITY, CONSUMER PROTECTION, SAFETY, AND BILLING
REQUIREMENTS
A. No change.
B. No change.
C. No consumer shall be deemed to have changed providers of any service
authorized in this Article (including changes from the Affected Utility to
another provider) without written authorization by the consumer for service
from the new provider. If a consumer is switched to a different ("new")
provider without such written authorization, the new provider shall cause
service by the previous provider to be
19 DECISION NO. 61969
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resumed and the new provider shall bear all costs associated with switching
the consumer back to the previous provider. {A new provider who switches a
customer without written authorization shall also refund to the retail
electricity customer the entire amount of the customer's electricity
charges attributable to the electric generation service from the new
provider for 3 months, or the period of the unauthorized service, whichever
is more.} A Utility Distribution Company {may request the Commission's
Consumer Services Section} [has the right] to review or audit written
authorizations to assure a customer switch was properly authorized. A
written authorization that is obtained by deceit or deceptive practices
shall not be deemed a valid written authorization. Electric Service
Providers shall submit reports within 30 days of the end of each calendar
quarter to the Commission itemizing the direct complaints filed by
customers who have had their Electric Service Providers changed without
their authorization. Violations of the Commission's rules concerning
unauthorized changes of providers may result in penalties, or suspension or
revocation of the provider's certificate. {The following requirements and
restrictions shall apply to the written authorization form requesting
electric service from the new provider:
1. The authorization shall not contain any inducements;
2. The authorization shall be in legible print with clear and plain
language confirming the rates, terms, conditions and nature of the
service to be provided;
3. The authorization shall not state or suggest that the customer must
take action to retain the customer's current electricity supplier;
4. The authorization shall be in the same language as any promotional or
inducement materials provided to the retail electric customer; and
5. No box or container may be used to collect entries for sweepstakes or
a contest that, at the same time, is used to collect authorization by
a retail electric customer to change their electricity supplier or to
subscribe to other services.}
D. No change.
E. No change.
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F. No change.
G. No change.
H. No change.
I. Electric Service Providers shall give at least 5 days notice to their
customer [and to the appropriate Utility Distribution Company] of scheduled
return to Standard Offer Service.[but that return of that customer to the
Standard Offer Service would be at the next regular billing cycle if
appropriate metering equipment is in place, and the request is processed 15
calendar days prior to the next regular read date.] {Electric Service
Providers shall provide 15 calendar days notice prior to the next scheduled
meter read date to the appropriate Utility Distribution Company regarding
the intent to terminate a service agreement. Return of that customer to
Standard Offer Service will be at the next regular billing cycle if
appropriate metering equipment is in place and the request is provided 15
calendar days prior to the next regular meter read date.} Responsibility
for charges incurred between the notice and the next scheduled read date
shall rest with the Electric Service Provider.
J. No change.
K. Additional Provisions for Metering and Meter Reading Services
1. {When authorized by the consumer, an Electric Service Provider who
provides metering or meter reading services pertaining to a particular
consumer shall provide appropriate meter reading data via standardized
EDI formats to all applicable Electric Service Providers serving that
same consumer.}[An Electric Service Provider who provides metering or
meter reading services pertaining to a particular consumer shall
provide access using EDI formats to meter reading data to other
Electric Service Providers serving that same consumer when authorized
by the consumer.]
2. Any person or entity relying on metering information provided by an
[another] Electric Service Provider may request a meter test according
to the tariff on file and approved by the Commission. However, if the
meter is found to be in error by more than 3%, no meter testing fee
will be charged.
21 DECISION NO. 61969
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3. Each competitive {point of delivery} [customer] shall be assigned a
Universal Node Identifier [for each service delivery point] by the
Affected Utility or the Utility Distribution Company whose
distribution system serves the customer.
4. Unless the Commission grants a specific waiver, all competitive
metered and billing data shall be translated into consistent,
statewide Electronic Data Interchange (EDI) formats based on standards
approved by the Utility Industry Group (UIG) that {shall} [can] be
used by the Affected Utility or the Utility Distribution Company and
the Electric Service Provider.
5. Unless the Commission grants a specific waiver, an Electronic Data
Interchange Format shall be used for all data exchange transactions
from the Meter Reading Service Provider to the Electric Service
Provider, Utility Distribution Company, and Schedule Coordinator. This
data will be transferred via the Internet using a secure sockets layer
or other secure electronic media.
6. Minimum metering requirements for competitive customers over 20 kW, or
100,000 kWh annually, should consist of hourly consumption measurement
meters or meter systems. Predictable loads will be permitted to use
load profiles to satisfy the requirements for hourly consumption data.
{The Load-Serving Entity developing the load profile shall determine
if a load is predictable.} [The Affected Utility or Electric Service
Provider will make the determination if a load is predictable.]
7. Competitive customers with hourly loads of 20 kW (or 100,000 kWh
annually) or less, will be permitted to use Load Profiling to satisfy
the requirements for hourly consumption data, however, they may choose
other metering options offered by their Electric Service Provider
consistent with the Commission rules on Metering.
8. Metering equipment ownership will be limited to the Affected Utility,
Utility Distribution Company, and the Electric Service Provider or
their representative, or the customer, who must obtain the metering
equipment through the Affected Utility, Utility Distribution Company
or an Electric Service Provider.
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9. Maintenance and servicing of the metering equipment will be limited to
the Affected Utility, Utility Distribution Company and the Electric
Service Provider or their representative.
10. Distribution primary voltage Current Transformers and Potential
Transformers may be owned by the Affected Utility, Utility
Distribution Company or the Electric Service Provider or their
representative.
11. Transmission primary voltage Current Transformers and Potential
Transformers may be owned by the Affected Utility or Utility
Distribution Company only.
12. North American Electric Reliability Council recognized holidays will
be used in calculating "working days" for meter data timeliness
requirements.
13. By May 1, 1999, the Director, Utilities Division shall approve
operating procedures be used by the Utility Distribution Companies and
the Meter Service Providers for performing work on primary metered
customers.
14. By May 1, 1999, the Director, Utilities Division shall approve
operating procedures be used by the Meter Reading Service Provider for
validating, editing, and estimating metering data.
15. By May 1, 1999, the Director, Utilities Division shall approve
performance metering specifications and standards to be used by all
entities performing metering.
L. No change.
M. No change.
N. Billing Elements. After the commencement of competition within a service
territory pursuant to R14-2-1602, all customer bills, including bills for
Standard Offer Service customers within that service territory, will list,
at a minimum, the following billing cost elements:
1. {Competitive Services:}[Electricity Costs]
a. Generation, {which shall include generation-related billing and}
collection;
b. Competition Transition Charge, and
c. {Transmission and Ancillary Services;} [Fuel or purchased power
adjustor, if applicable]
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d. {Metering Services; and
e. Meter Reading Services.
2. Non-Competitive Services:} [Delivery costs]
a. Distribution services, {including distribution-related billing
and collection, required Ancillary Services and Must-Run
Generating Units; and
b. System Benefit Charges.} [Transmission services;]
3. {Regulatory assessments;} and [Other Costs
a. Metering Service,
b. Meter Reading Service,
c. Billing and collection, and
d. System Benefits charge.]
{4. Applicable taxes.}
O. No change.
R14-2-1613. REPORTING REQUIREMENTS
A. Reports covering the following items, as applicable, shall be submitted to
the Director, Utilities Division by Affected Utilities or Utility
Distribution Companies and all Electric Service Providers granted a
Certificate of Convenience and Necessity pursuant to this Article. These
reports shall include the following information pertaining to Competitive
Service offerings, Unbundled Services, and Standard Offer services in
Arizona:
1. Type of services offered;
2. kW and kWh sales to consumers, disaggregated by customer class (for
example, residential, commercial, industrial);
3. Revenues from sales by customer class (for example, residential,
commercial, industrial);
4. Number of retail customers disaggregated as follows: residential,
commercial under 40 kW, commercial 41 to 999 kW, commercial 1000 kW or
more, industrial less than 1000 kW, industrial
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1000 kW or more, agricultural (if not included in commercial), and
other;
5. Retail kWh sales and revenues disaggregated by term of the contract
(less than 1 year, 1 to 4 years, longer than 4 years), and by type of
service (for example, firm, interruptible, other);
6. Amount of [and] revenues from each type of Competitive Service, and,
if applicable, each type of Noncompetitive Service provided;
7. Value of all assets used to serve Arizona customers and accumulated
depreciation;
8. Tabulation of Arizona electric generation plants owned by the Electric
Service Provider broken down by generation technology, fuel type, and
generation capacity;
9. The number of customers aggregated and the amount of aggregated load;
10. Other data requested by staff or the Commission.
{B.}[A.] Reporting Schedule
1. For the period through December 31, 2003, semi-annual reports shall be
due on April 15 (covering the previous period of July through
December) and October 15 (covering the previous period of January
through June). The 1st such report shall cover the period January 1
through June 30, 1999.
2. For the period after December 31, 2003, annual reports shall be due on
April 15 (covering the previous period of January through December).
The 1st such report shall cover the period January 1 through December
31, 2004.
C. No change.
D. No change.
E. No change.
F. No change.
G. No change.
R14-2-1614. ADMINISTRATIVE REQUIREMENTS - No change
R14-2-1615. SEPARATION OF MONOPOLY AND COMPETITIVE SERVICES
25 DECISION NO. 61969
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A. No change.
B. Beginning January 1, 2001, an Affected Utility or Utility Distribution
Company shall not provide Competitive Services. as defined in R14-2-1601.
1. This Section does not preclude an Affected Utility or Utility
Distribution Company from billing its own customers for distribution
service, or from providing billing services to Electric Service
Providers in conjunction with its own billing, or from providing
{Meter Services and Meter Reading Services} [meters] for Load Profiled
residential customers. Nor does this Section preclude an Affected
Utility or Utility Distribution Company from providing billing and
collections, Metering and Meter Reading Service as part of the
Standard Offer Service tariff to Standard Offer Service customers.
2. This Section does not preclude an Affected Utility or Utility
Distribution Company from owning distribution and transmission primary
voltage Current Transformers and Potential Transformers.
C. An Electric Distribution Cooperative is not subject to the provisions of
R14-2-1615 unless it offers competitive electric services outside of {its
distribution service territory.} [the service territory it had as of the
effective date of these rules. A Generation Cooperative shall be subject to
the same limitations to which its member Distribution Cooperatives are
subject.]
R14-2-1616. CODE OF CONDUCT
A. No later than 90 days after adoption of these Rules, each Affected Utility
which plans to offer Noncompetitive Services and {which plans to offer}
Competitive Services through its competitive electric affiliate shall
propose a {Code} [code] of {Conduct} [conduct] to prevent anti-competitive
activities. {Each Affected Utility that is an electric cooperative, that
plans to offer Noncompetitive Services, and that is a member of any
electric cooperative that plans to offer Competitive Services shall also
submit a Code of Conduct to prevent anti-competitive activities. All} [The]
Codes of Conduct shall be subject to Commission approval {after a hearing.}
B. {The Code of Conduct shall address the following subjects:}
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{1. Appropriate procedures to prevent cross subsidization between the
Utility Distribution Company and any competitive affiliates, including
but not limited to the maintenance of separate books, records and
accounts;
2. Appropriate procedures to ensure that the Utility Distribution
Company's competitive affiliate does not have access to confidential
utility information that is not also available to other market
participants;
3. Appropriate guidelines to limit the joint employment of personnel by
both a Utility Distribution Company and its competitive affiliate;
4. Appropriate guidelines to govern the use of the Utility Distribution
Company's name or logo by the Utility Distribution Company's
competitive affiliate;
5. Appropriate procedures to ensure that the Utility Distribution Company
does not give its competitive affiliate any preferential treatment
such that other market participants are unfairly disadvantaged or
discriminated against;
6. Appropriate policies to eliminate joint advertising, joint marketing,
or joint sales by a Utility Distribution Company and its competitive
affiliate;
7. Appropriate procedures to govern transactions between a Utility
Distribution Company and its competitive affiliate; and
8. Appropriate policies to prevent the Utility Distribution Company and
its competitive affiliate from representing that customers will
receive better service as a result of the affiliation.
9. Complaints concerning violations of the Code of Conduct shall be
processed under the procedures established in R14-2-212.}
R14-2-1617. DISCLOSURE OF INFORMATION
A. Each Load-Serving Entity {providing either generation service or Standard
Offer Service shall} prepare a consumer information label that sets forth
the following information:
1. Price to be charged for generation services,
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2. Price variability information,
3. Customer service information,
4. Time period to which the reported information applies.
B. Each Load-Serving Entity {providing either generation service or Standard
Offer Service} shall provide, upon request, the following information (to
the extent reasonably known):
1. Composition of resource portfolio,
2. Fuel mix characteristics of the resource portfolio,
3. Emissions characteristics of the resource portfolio.
C. No change.
D. Each Load-Serving Entity shall include the information disclosure label in
a prominent position in all written marketing materialsspecifically
{targeted} [target] to Arizona. When a Load-Serving Entity advertises in
non-print media, or in written materials not specifically {targeted}
[target] to Arizona, the marketing materials shall indicate that the
Load-Serving Entity shall provide the consumer information label to the
public upon request.
E. No change.
F. No change.
G. No change.
H. No change.
I. No change.
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APPENDIX B
CONCISE EXPLANATORY STATEMENT
I. CHANGES IN THE TEXT OF THE PROPOSED RULES FROM THAT CONTAINED IN DECISION
NO. 61634 (PUBLISHED ON MAY 14, 1999, IN THE ARIZONA ADMINISTRATIVE
REGISTER).
The following sections have been modified as indicated in the text of the
rules set forth in Appendix A hereto, and incorporated herein by reference.
ARTICLE 2 ELECTRIC UTILITIES
R14-2-201 Definitions - No Change
R14-2-202 Certificate of Convenience and Necessity for electric utilities;
filing requirements on certain new plants - No Change
R14-2-203 Establishment of service - Modified
R14-2-204 Minimum customer information requirements - No Change
R14-2-205 Master metering - No Change
R14-2-206 Service lines and establishments - No Change
R14-2-207 Line Extensions - No Change
R14-2-208 Provision of service - No Change
R14-2-209 Meter reading - Modified
R14-2-210 Billing and collection - No Change
R14-2-211 Termination of service - No Change
R14-2-212 Administrative and hearing requirements - No Change
ARTICLE 16. RETAIL ELECTRIC COMPETITION
R14-2-1601 Definitions - Modified
R14-2-1602 Commencement of Competition - No Change
R14-2-1603 Certificates of Convenience and Necessity - Modified
R14-2-1604 Competitive Phases - Modified
R14-2-1605 Competitive Services - Modified
1 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
R14-2-1606 Services Required To Be Made Available - Modified
R14-2-1607 Recovery of Stranded Cost of Affected Utilities - No Change
R14-2-1608 System Benefits Charges - No Change
R14-2-1609 Transmission and Distribution Access - Modified
R14-2-1610 In-state Reciprocity - No Change
R14-2-1611 Rates - Modified
R14-2-1612 Service Quality, Consumer Protection, Safety, and Billing
Requirements - modified
R14-2-1613 Reporting Requirements - Modified
R14-2-1614 Administrative Requirements - No Change
R14-2-1615 Separation of Monopoly and Competitive Services - Modified
R14-2-1616 Code of Conduct - Modified
R14-2-1617 Disclosure of Information - Modified
II. EVALUATION OF THE ARGUMENTS FOR AND AGAINST THE PROPOSED AMENDMENTS TO THE
RULES.
R14-2-203 - ESTABLISHMENT OF SERVICE
203(B)
ISSUE: New West Energy ("NEW") recommended that a provision be added to
Section 203(B)(6) to clarify that deposits for residential and nonresidential
customers would be estimated using average monthly usage for Noncompetitive
Services. The Arizona Corporation Commission ("Commission") Staff ("Staff")
responded that the existing Section already contains the word "estimated" and
argued no change was required.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
ISSUE: Commonwealth Energy Corporation ("Commonwealth") stated that Section
203(B)(9) should be deleted because Utility Distribution Companies ("UDCs") may
attempt to dissuade customers from seeking competitive services by claiming
customer deposits may be raised if the
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DOCKET NO. RE-00000C-94-0165
customers are dissatisfied with the alternative provider and return to Standard
Offer Service. Staff responded that it is clear that the only reason a UDC can
increase a deposit is for the return to Standard Offer Service, which may be
more expensive than competitors' service. Staff argued that this provision
should motivate customers to choose another Electric Service Provider ("ESP")
and not return to Standard Offer Service.
ANALYSIS: This Section allows the deposit to be raised only in proportion
to the expected increase in monthly billing, and also requires a refund of the
deposit for non-delinquent customers when a customer switches to competitive
services. This Section is not anti-competitive and requires no change.
RESOLUTION: No change is necessary.
203(D)(1)
ISSUE: NWE recommended that the language "including transfers between
Electric Service Providers" in Section 203(D)(1) be deleted. Staff responded
that no change is necessary because the Rules already contemplate a charge for
transfers between ESPs.
ANALYSIS: This Section requires Commission approval of such charges. ESPs
may object if they believe the amount of such a charge is unreasonable.
RESOLUTION: No change is necessary.
203(D)(4)
ISSUE: The City of Tucson ("Tucson") advocated rewriting Section 203(D)(4)
regarding service establishments to clearly set time limits for actions by each
party and to avoid incentives to delay processing Direct Access Service Requests
("DASRs") or meter changes.
ANALYSIS: We agree that the language "if the direct access service request
is processed 15 calendar days prior to that date" does not provide a
sufficiently clear time limit, and does not avoid incentives to delay processing
DASRs. As explained in our analysis of Section 1612(I), whether appropriate
metering equipment is in place is an important concern in some circumstances,
and that language should remain unchanged.
RESOLUTION: Modify the first sentence of this Section as follows:
3 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
Service establishments with an Electric Service Provider will be scheduled
for the next regular meter read date if the direct access service request
is PROVIDED 15 calendar days prior to that date and appropriate metering
equipment is in place.
Such change merely clarifies the intent of this provision and is not
substantive.
R14-2-204 - MINIMUM CUSTOMER INFORMATION REQUIREMENTS
ISSUE: Arizona Consumers Council ("AZCC") objected to the language in this
Section on the grounds that an ESP might sign consumers up for new service
without being obligated to provide adequate information regarding the offered
services.
ANALYSIS: Our modification to Section 1612(C) addresses this concern by
requiring that the written authorization to switch providers confirm the rates,
terms, conditions and nature of the service to be provided. This Section
requires Load-Serving Entities to provide further information to residential
consumers who request it.
RESOLUTION: No change is required.
R14-2-205 - MASTER METERING
ISSUE: In late-filed comments, the Arizona Multihousing Association ("AMA")
advocated for the deletion of Section 205(B) which limits master metering for
newly constructed apartment complexes. The AMA asserted that the prohibition was
counterproductive to achieving the critical mass necessary to benefit from
aggregation. AMA also recommended that the issue of aggregation be clarified.
ANALYSIS: The AMA raised this issue for the first time very late in the
rule revision process and other parties have not had opportunity to respond. We
do not believe revision of this existing rule is warranted, especially without
input from other parties. We believe that at least some of AMA's concerns are
addressed by our clarifications to the process of aggregation in Section 1604.
RESOLUTION: No change is required.
R14-2-209 - METER READING
ISSUE: The AZCC raised a concern that under this Section a customer may be
charged for a meter re-read when the customer had nothing to do with the request
for a re-read.
4 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
ANALYSIS: Section 209(C)(1) provides that a customer, ESP, UDC, or billing
entity may request a re-read of a meter. Section 209(C)(2) provides that a
re-read may be charged to the customer, ESP, UDC or billing entity at the tariff
rate. It is implicit in this Section that the requesting party will be the party
to be charged. However, we will modify this Section to clarify that it is the
requesting party that may be charged for the re-read.
Such modification merely clarifies this provision and is not substantive.
RESOLUTION: Insert "MAKING THE REQUEST" after "or billing entity" in
Section 209(C)(2).
R14-2-210 - BILLING AND COLLECTION
210(A)
ISSUE: Tucson Electric Power Company ("TEP") recommended deleting Section
210(A)(5)(c) which prohibits estimated bills for direct access customers
requiring load data because the utility or billing entity has the ability to do
it and such bills can be estimated in accordance with Sections 209(A)(8) and
1612(K)(14). Staff responded that as a general rule, direct access customers'
bills should not be estimated, and argued against changing this provision.
ANALYSIS:. We concur with Staff.
RESOLUTION: No change is necessary.
ISSUE: NWE states that the terms "utility" and "customer" are not defined
in Section 210(A)(2). Staff noted that these terms are defined in Section 201.
ANALYSIS: The definitions in Section 201 are sufficient.
RESOLUTION: No change is necessary.
ISSUE: NWE states that the rules for estimated meter readings should be
developed by the working group and should not be included in Sections 210(A)(3)
through (6). Staff stated that this Section sets forth conditions which the
working groups have previously developed and therefore no change is warranted.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
210(C-I)
5 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
ISSUE: NWE states that Sections 210(C) through (I) should be stricken in
their entirety because it believes they do not apply to ESPs, and that to the
extent they apply to UDCs, they should be covered by the UDCs' tariffs. Staff
responded that these rules apply to UDCs and ESPs.
ANALYSIS: As the term "utility" is defined in Section 201, these Sections
apply to both UDCs and ESPs. It is preferable that the issues covered in these
Sections be prescribed by general rule rather than be provided in individual
tariffs.
RESOLUTION: No change is necessary.
R14-2-211 - TERMINATION OF SERVICE
ISSUE: Commonwealth recommended the deletion of the opening sentences in
Sections 211(B) and (C), which prohibit an ESP from ordering disconnection of
service for nonpayment. Staff responded that ESPs can terminate service to
customers for nonpayment through terminating their contract with customers.
ANALYSIS: This Section does not preclude an ESP from terminating a contract
for nonpayment. Commonwealth's concerns about its ability to terminate contracts
expediently are addressed by our revisions to Section 1612(I).
RESOLUTION: No change required.
R14-2-213 - CONSERVATION
ISSUE: TEP proposed deleting this Section because it is premature; the
issue will be addressed when revisiting the Resource Planning Rules; it should
apply to all utilities and ESPs; and it should be delayed until there is 100
percent statewide competition. Staff responded that this rule has been in effect
for several years and there is no justification for deleting it at this time.
ANALYSIS: We remain unconvinced that a change in this provision is
warranted.
RECOMMENDATION: No change is necessary.
R14-2-1601 - DEFINITIONS
1601(2) "AGGREGATOR"
ISSUE: The Land and Water Fund of the Rockies and the Grand Canyon Trust
(collectively, the "LAW Fund") and the AZCC expressed concern that the Rules do
not sufficiently encourage
6 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
aggregation of smaller users. Commonwealth concurred. The Arizona Transmission
Dependent Utility Group ("ATDUG") suggested deleting the term "Aggregator" and
adding a new definition of "Aggregation." Staff responded that the definition of
"Aggregator" was placed in the Rules, as originally drafted, to address
businesses that choose to provide "aggregation" as an electric service to
customers. Staff noted that apparently, that definition has created confusion,
causing some to believe that in order for a group of customers to combine or
"aggregate" their load, they would have to become an ESP. Staff stated that was
not the intent of the Rule as originally drafted. Staff noted that in addition,
there have been questions raised about whether residential customers are able to
aggregate their load, either through self-aggregation or through the services of
an Aggregator. Staff believed that clarification of this issue would be helpful.
Staff therefore proposed new language to clarify that only entities which
perform aggregation services as part of their business are required to obtain
ESP certification; to provide new definitions of "Aggregation" and
"Self-Aggregation"; to clarify that residential customers may also aggregate or
self-aggregate their loads, subject to the phase-in percentage limitations; and
to clarify that eligible residential and non-residential customers may be
aggregated together. Staff proposed the following new definition of
"Aggregator":
"2. `AGGREGATOR' MEANS AN ELECTRIC SERVICE PROVIDER THAT, AS PART OF ITS
BUSINESS, COMBINES RETAIL ELECTRIC CUSTOMERS INTO A PURCHASING GROUP."
Staff also suggested a new definition of "Aggregation" similar to that suggested
by ATDUG:
"3. `AGGREGATION' MEANS THE COMBINATION AND CONSOLIDATION OF LOADS OF
MULTIPLE CUSTOMERS."
Staff proposed that a revised version of the definition of "Self-Aggregation" be
included in the Rules:
"SELF-AGGREGATION IS THE ACTION OF A RETAIL ELECTRIC CUSTOMER OR GROUP OF
CUSTOMERS WHO COMBINE THEIR OWN METERED LOADS INTO A SINGLE PURCHASE
BLOCK."
In addition, Staff proposed additional clarifying modifications to Sections
1604(A)(2) and (4) and 1604(B)(6) concerning aggregation and self-aggregation,
which are discussed in our analysis of those Sections.
ANALYSIS: Staff's recommended modifications to this Section are not
substantive, but provide clarity and should be adopted.
7 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
RESOLUTION: Modify Section 1601 in accordance with Staff's recommendations
and renumber accordingly.
1601(3) "ANCILLARY SERVICES"
ISSUE: Staff noted that although the Proposed Rules contain several
references to the term "Ancillary Services," they do not include a definition
for that term, and suggested that the following definition be added to the
Rules:
"ANCILLARY SERVICES" MEANS THOSE SERVICES DESIGNATED AS ANCILLARY SERVICES
IN FEDERAL ENERGY REGULATORY COMMISSION ORDER 888, INCLUDING THE SERVICES
NECESSARY TO SUPPORT THE TRANSMISSION OF ELECTRICITY FROM RESOURCE TO LOAD
WHILE MAINTAINING RELIABLE OPERATION OF THE TRANSMISSION SYSTEM IN
ACCORDANCE WITH GOOD UTILITY PRACTICE.
ANALYSIS: The proposed definition provides clarity and is not a substantive
change to the Rules.
RESOLUTION: Add the definition as proposed and renumber accordingly.
1601(5) - COMPETITIVE SERVICES
ISSUE: Arizona Public Service Company ("APS") argued that the Commission
should not define "Competitive Services" simply by negative reference to another
definition because it is vague. APS proposed that the definition of "Competitive
Services" should be replaced with the following:
5. "Competitive Services" means RETAIL ELECTRIC GENERATION, METER SERVICE
(OTHER THAN THOSE ASPECTS OF METER SERVICE DESCRIBED IN R14-2-1612(K)),
METER READING SERVICE, AND BILLING AND COLLECTION FOR SUCH SERVICES (OTHER
THAN JOINT OR CONSOLIDATED BILLING PROVIDED PURSUANT TO A TARIFF). IT DOES
NOT INCLUDE STANDARD OFFER SERVICE OR ANY OTHER ELECTRIC SERVICE DEFINED BY
THIS ARTICLE AS NONCOMPETITIVE. [all aspects of retail electric service
except those services specifically defined as "Noncompetitive Services"
pursuant to R14-2-1601(27) or noncompetitive services as defined by the
Federal Energy Regulatory Commission.]
Arizona Electric Power Cooperative, Inc., Duncan Valley Electric
Cooperative, Inc. and Graham County Electric Cooperative, Inc. ("AEPCO, Duncan
and Graham") supported APS' modification of the definition. Commonwealth and
Arizonans for Electric Choice and Competition ("AECC") opposed APS' proposal. In
its responsive comments, Staff noted that Competitive and Noncompetitive
Services as defined by the Rules are mutually exclusive, and argued that APS
appears to be attempting to create a third category of services: Competitive
Services that may be provided by Affected Utilities or Utility Distribution
Companies. Staff believed that the existing
8 DECISION NO. 61969
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DOCKET NO. RE-00000C-94-0165
definition is sufficiently clear, and maintains the proper distinction between
services that may be provided by Affected Utilities or UDCs, and those services
that may not.
ANALYSIS: APS' proposal could narrow the competitive environment by
excluding other energy-related services. The distinction between Competitive and
Noncompetitive Services is sufficiently clear without modification.
RESOLUTION: No change is required.
1601(4) "COMPETITION TRANSITION CHARGE"
ISSUE: Navopache Electric Cooperative, Inc. ("Navopache") and Mohave
Electric Cooperative, Inc. ("Mohave") commented that the definition of
Competition Transition Charge ("CTC") should include costs incurred by the
Affected Utilities in implementing these Rules. Navopache and Mohave argued that
these costs would not be incurred but for customers electing to switch to
competitive providers, and therefore customers who switch should bear the
associated costs, rather than the customers who remain on Standard Offer
Service.
Staff stated that because many of Navopache's and Mohave's concerns are
already addressed by the proposed modification to the definition of Stranded
Cost to include "other transition and restructuring costs," it is unnecessary to
make the modification Navopache and Mohave recommend.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is required.
1601(13) (NEWLY PROPOSED) "ECONOMIC DEVELOPMENT TARIFFS"
ISSUE: Staff proposed to add a new definition for "Economic Development
Tariffs" as "those discounted tariffs used to attract new business expansions in
Arizona" to comport with its recommendation to add language to Section
1606(C)(6), referring to "economic development tariffs that clearly mitigate
Stranded Costs."
ANALYSIS: As explained in our discussion under Section 1606(C) below, due
to insufficient evidence in the record to support the implementation of the
proposed "Economic Development Tariff", we will not revise Section 1606(C) as
proposed by Staff at this time. Therefore, this proposed definition is not
needed.
RESOLUTION: No change is required.
9 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
1601(15) "ELECTRIC SERVICE PROVIDER SERVICE ACQUISITION AGREEMENT"
ISSUE: NWE recommends that the Electric Service Provider Service
Acquisition Agreement be a standardized, Commission-approved agreement between
an Affected Utility and an ESP because NWE believes that the rule as written
creates an uncertain process that may deter potential ESPs from competing in
Arizona. NWE also argues that a standardized, Commission-approved agreement is
the most efficient mechanism for controlling the technical and financial
viability of competitors. Commonwealth supported the approach of a Commission
pre-approved agreement for all service areas.
Staff stated it agreed with the Commission's conclusion in Decision No.
61634 on this issue, that the certification process is not overly burdensome or
anti-competitive.
ANALYSIS: We believe that the certification process as currently structured
is not such an uncertain or burdensome process as to deter potential ESPs from
competing in Arizona, and that the current process provides adequate oversight
of ESPs' technical and financial viability.
RESOLUTION: No change is required.
1601(27) "NONCOMPETITIVE SERVICES"
ISSUE: Navopache and Mohave argued that it is necessary for customer-owned
distribution cooperatives to maintain the relationships and communications links
with their members/owners for membership, voting and other purposes. To achieve
that goal, Navopache and Mohave recommended that the definition of
Noncompetitive Services be modified to state that metering, meter ownership,
meter reading, billing, collections and information services are deemed to be
Noncompetitive Services in the service territories of the distribution
cooperatives.
Staff responded that the provisions of Section 1615(B)(1) allow
distribution cooperatives to maintain sufficient links with their
members/owners.
ANALYSIS: We agree with Staff that Section 1615(B)(1) explicitly allows an
Affected Utility or UDC to bill its own customers for distribution service and
to provide billing services to ESPs in conjunction with its own billing, and
also allows an Affected Utility or UDC to provide billing and collections,
Metering and Meter Reading Service as part of its Standard Offer Service tariff
to Standard Offer Service customers.
10 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
RESOLUTION: No change is required.
ISSUE: ATDUG suggested that the definition of Noncompetitive Services
should be amended to add "Aggregation Service."
ANALYSIS: Although the actual delivery of electricity sold to aggregated
customers will be a Noncompetitive Service, there is no reason to differentiate
the generation services provided to aggregated customers from generation
services provided to non-aggregated customers. Both aggregated and
non-aggregated competitive generation services should remain classified as
Competitive Services.
RESOLUTION: No change is required.
ISSUE: Commonwealth asserted that ESPs should not have to pay the utility
for customer data when the customer requests its release. Commonwealth
recommended that the definition of Noncompetitive Services should be amended by
deleting "provision of customer demand and energy data by an Affected Utility or
Utility Distribution Company to an Electric Service Provider" so that the
utility cannot impose a charge on these services. Alternatively, Commonwealth
argued that the Rules should provide that the data will be provided to the
customer (or its authorized representative) at no charge.
ANALYSIS: Because customers who switch providers will be the
"cost-causers," it is appropriate that they should bear the administrative costs
associated with switching providers. We share Commonwealth's concern, however,
that such charges may be prohibitively high and discourage new market entrants.
As this will be a tariffed item, the Commission will oversee the reasonableness
of such a charge. If an ESP finds the tariffed charge unreasonable, the ESP is
free to protest the tariff.
RESOLUTION: No change is required.
1601(28) (FORMER) "NET METERING OR NET BILLING"
ISSUE: Tucson recommended not deleting the definition of Net Metering or
Net Billing from the Rules, as the potential for customer-sited generation using
any sort of generation is still possible, even if not mandated. Tucson
recommended striking the word "solar electric" from the definition.
11 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
ANALYSIS: The terms "Net Metering or Net Billing" are not referenced in the
Rules and consequently, their inclusion in the definitions is not necessary and
could be confusing.
RESOLUTION: No change is required.
1601 (34) (NEWLY PROPOSED) "PUBLIC POWER ENTITY"
ISSUE: Staff noted that although the Rules have added the term "Public
Power Entity" they do not include a definition for that term. Staff recommend
that the definition parallel that set forth by the legislature in A.R.S. ss.
30-801.16. Trico Electric Cooperative ("Trico") and Commonwealth concurred.
ANALYSIS: This definition is needed because prior revisions of Section 1610
introduced this term, however, the change is not substantive.
RESOLUTION: Add the following definition to Section 1601 and renumber
accordingly: "`PUBLIC POWER ENTITY' INCORPORATES BY REFERENCE THE DEFINITION SET
FORTH IN A.R.S. SS. 30-801.16."
1601(35) "STRANDED COST"
ISSUE: TEP argued that the Proposed Rules' replacement of the word "value"
with "net original cost" is not appropriate because the new term may be
inconsistent with assets held under lease arrangements and with various
regulatory assets. AECC disagreed with TEP. Staff responded that it concurs with
the change made in Decision No. 61634 to replace "value" with "net original
cost," and that this language will not preclude TEP from seeking what it
believes to be an appropriate level of recovery for its Stranded Costs.
Trico recommended adding "and distribution assets" after "regulatory
assets" in Section 1601(35)(a)(i), because distribution electric public service
corporations are also entitled to recover their Stranded Costs. ATDUG and
Commonwealth responded to Trico's recommendation by questioning how distribution
assets could be considered "stranded" since they remain with the regulated
entity. Staff responded that due to the difficulty in calculating distribution
cooperatives' Stranded Costs prior to competition, it is more appropriate to
deal with those costs in rate cases for distribution electric public service
corporations. Staff therefore recommends that the definition of Stranded Costs
not be changed.
12 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
ANALYSIS: We concur with Staff that the term "net original cost" will not
preclude TEP from recovering appropriate Stranded Costs. We also concur that the
recovery of costs related to distribution assets are appropriately handled in a
rate case.
RESOLUTION: No change is necessary.
1601(36) "SYSTEM BENEFITS"
ISSUE: NWE states that the definition of "System Benefits" is "vague and
fails to specify who will determine what specific costs qualify as System
Benefits." Staff responded that it believes that testimony on System Benefit
charges will be taken in the Stranded Cost and Unbundled Tariff hearings that
will commence in August 1999, and that based on that testimony, the Commission
will determine the specific costs to be included in the System Benefits Charges
in the Decisions rendered in those proceedings. Staff therefore believes that no
change to this definition is necessary.
TEP recommended that non-nuclear plant decommissioning costs be included in
the System Benefits charge because generating plants other than nuclear will
also have decommissioning costs in the future. AEPCO, Duncan and Graham
supported and Commonwealth opposed TEP's suggestion. Staff asserted that
non-nuclear decommissioning costs should not be included in System Benefits, for
two reasons. First, nuclear decommissioning costs are already being collected in
rates, in part because nuclear utilities are required by the Nuclear Regulatory
Commission to begin accumulating funds for decommissioning while the nuclear
plants are operating. This is not the case with non-nuclear facilities. Staff
pointed out that in addition, nuclear decommissioning costs are of such a great
magnitude that it is reasonable to attempt to spread them over the operating
life of the plant, but that it is unlikely that the costs to decommission
non-nuclear plants will be as large.
ANALYSIS: We concur with Staff's reasoning.
RESOLUTION: No change is necessary.
1601(40) "UTILITY DISTRIBUTION COMPANY"
ISSUE: The Arizona State Association of Electrical Workers ("ASAEW") urged
the Commission to insert the word "constructs" as part of the definition of a
Utility Distribution Company so that the definition would include an entity that
"operates, CONSTRUCTS and maintains the distribution system . . . ." TEP also
argued for the inclusion of the word "constructs" in the definition
13 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
because it will be the responsibility of the UDC to construct the transmission
and distribution systems to ensure consistent, safe and reliable service. Staff
agrees that "construction" is an integral part of the provision of electrical
distribution service, and recommends adoption of TEP and ASAEW's recommendation.
ANALYSIS: We concur with ASAEW, TEP and Staff. This is not a substantive
change.
RESOLUTION: Add the word "constructs" after "operates" in the definition of
"Utility Distribution Company."
R14-2-1602 "COMMENCEMENT OF COMPETITION"
ISSUE: AEPCO proposed that statewide competition commence at the same time,
subject to the phase-in schedule in Section 1604. Commonwealth made a proposal
that full competition commence immediately upon the conclusion of the scheduled
Stranded Cost/Unbundling proceeding. Staff believes that both proposals would
delay the commencement of competition until all the Stranded Cost/Unbundling
proceedings are concluded, rather than bringing the benefits of competition to
the citizens of Arizona as quickly as possible at the conclusion of each
Affected Utility's proceedings, and that further, phasing in competition under
Section 1604 establishes a workable timetable to implement competition to
various customer classes. APS argued that at this date, the Commission should
not make additional adjustments to start dates or phase-in schedules.
ANALYSIS: We believe that the current timetable for bringing competition to
the state is an expeditious and achievable means of implementing competition.
RESOLUTION: No change is required.
R14-2-1603 "CERTIFICATES OF CONVENIENCE AND NECESSITY"
1603(A)
ISSUE: AEPCO, Duncan and Graham proposed modifying the third sentence of
Section 1603(A) as follows:
A Utility Distribution Company providing Standard Offer Service OR SERVICES
AUTHORIZED IN R14-2-1615 after January 1, 2001 need not apply for a
Certificate of Convenience and Necessity.
14 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
Staff agreed with AEPCO that this change is needed to remedy the conflict
between Sections 1603 and 1605 which might result if one were to conclude that a
distribution cooperative needs to acquire a new Certificate of Convenience and
Necessity ("CC&N") to provide competitive services pursuant to Section 1615.
ANALYSIS: We concur that this clarification is needed. The change is not
substantive.
RESOLUTION: Amend Section 1603(A) as recommended by AEPCO, Duncan, and
Graham.
1603(B)
ISSUE: Arizona Community Action Association ("ACAA") proposes to insert new
language in R14-2-1603(B)(1). The new language would require the CC&N applicant
to provide information as follows:
1. A description of the electric services which the applicant intends to
offer; including a plan to enroll and serve at least 15% of the total
residential consumers eligible on October 1, 2000;
Staff responded that although it understands that ACAA's goal in making this
proposal is to encourage an equitable and robust market, this proposal directly
conflicts with efforts to develop a competitive market that will attract the
maximum number of potential provider applicants. Staff further commented that if
implemented, this proposal might in fact discourage some competitors from
entering the Arizona market, and therefore would not serve the public interest.
ANALYSIS: We agree with Staff that requiring competitive ESPs to provide
services to the residential market as a prerequisite to being allowed entry to
the industrial and commercial markets may impede, rather than encourage the
development of a truly competitive market and therefore would not serve the
public interest.
RESOLUTION: No change is necessary.
1603(B)(3-6)
ISSUE: NWE recommended that Section 1603(B)(3), which requires the CC&N
applicant to file a tariff for each service to be provided, be modified in the
following manner:
3. A tariff for each service to be provided that states the [maximum rate
and] terms and conditions that will apply to the provision of the service.
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NWE believes this change would be appropriate because Section 1611(A) deems
market rates just and reasonable, and market forces may cause an ESP's rate to
temporarily surpass its filed maximum rate. NWE requested that if maximum rates
must be filed with the Commission, the Commission should clarify that those
maximum rates are deemed approved when the Commission grants a CC&N. NWE claims
that items (4), (5), (6), and (8) relating to CC&N application information
concerning the applicant's technical ability, financial capability, description
of form of ownership, and requiring any other information the Commission or
Staff may request are vague and should be deleted. Staff stated that Section
1603(B)(3)'s requirement that maximum rates be filed should remain intact
because it is necessary for the Commission to have this information in order to
fulfill its constitutional responsibility to evaluate the service rates of
public service utilities. Staff also stated that the information required in
items (4), (5), (6), and (8) are consistent with requirements for CC&Ns for
other services regulated by the Commission, that CC&N and certification
authority is required not only by Commission rules but by HB2663, and that the
specifics of what the Commission means by technical capability, financial
capability, and other information is obvious in the CC&N application form.
ANALYSIS: We concur with Staff. It is in the public interest to have
maximum rates and the other information included in the CC&N application as
required by Section 1603(B)(3-6) and (8) for the Commission to evaluate in the
course of considering the CC&N application. Approval of a CC&N application that
includes maximum rates in the tariff required by Section 1603(B)(3) constitutes
approval of those maximum rates, unless the Order approving the application
conditions approval upon the filing of different maximum rates.
RESOLUTION: No change is required.
1603(B)(7)
ISSUE: NWE suggested the following change:
7. An explanation of how AN APPLICANT WHICH IS AN AFFILIATE OF AN AFFECTED
UTILITY [the applicant] intends to comply with the requirements of
R14-2-1616, or a request for waiver or modification thereof with an
accompanying justification for any such requested waiver or modification.
16 DECISION NO. 61969
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DOCKET NO. RE-00000C-94-0165
Staff agrees with NWE that Section 1603(B)(7) should be modified to reflect the
fact that Section 1616 by its terms applies only to Affected Utilities planning
to provide Competitive Services through a competitive electric affiliate, and
that the applicant which is an affiliate of an Affected Utility should be
required to provide a statement of whether the Affected Utility has complied
with the requirements of Section 1616. Staff therefore recommended replacing
Section 1603(B)(7) in its entirety with the following:
7. FOR AN APPLICANT WHICH IS AN AFFILIATE OF AN AFFECTED UTILITY, A
STATEMENT OF WHETHER THE AFFECTED UTILITY HAS COMPLIED WITH THE
REQUIREMENTS OF R14-2-1616, INCLUDING THE COMMISSION DECISION NUMBER
APPROVING THE CODE OF CONDUCT, WHERE APPLICABLE.
ANALYSIS: We concur with Staff. It is in the public interest for entities
that are required to have an approved Code of Conduct to be required to
demonstrate compliance with this requirement as part of the certification
process. This modification is not substantive.
RESOLUTION: Modify Section 1603(B)(7) as recommended by Staff.
1603(E)
ISSUE: NWE proposed to delete the entire Section concerning the requirement
of the CC&N applicant to provide notice of its application to each of the
respective Affected Utilities, Utility Distribution Companies or an electric
utility not subject to the jurisdiction of the Commission in whose service
territories it wishes to offer service. NWE claims that this provision protects
the Affected Utilities' market share and invites unfair business practices.
Staff responded that proper notice is required for any CC&N application.
ANALYSIS: This formal notice requirement is not unduly burdensome to new
CC&N applicants, who, in order to serve their customers, must establish a
working relationship with the UDCs. It is in the public interest to insure that
the CC&N applicant provides proper notice.
RESOLUTION: No change is necessary.
1603(F)
ISSUE: NWE proposes to delete this Section which states that the Commission
may issue a CC&N for a specific period of time. NWE feels this provision would
add a further obstacle to market entry by some ESPs and would deter some
entrants from competing in Arizona. NWE feels that the
17 DECISION NO. 61969
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necessary security provisions can be efficiently achieved through an ESP Service
Agreement in lieu of this provision. Staff responded that this Section is
necessary to provide the Commission with needed flexibility in certificating
ESPs who have little or no experience, and that an ESP certificated under this
provision may apply for an extension of the effectiveness the CC&N.
ANALYSIS: Instead of creating an obstacle to market entry by ESPs with
little or no experience, this provision allows the Commission to provisionally
certificate such companies, and thus is pro-competitive.
RESOLUTION: No change is necessary.
1603(G)(2), (4), AND (5)
ISSUE: NWE proposes to delete Sections 1603(G)(2), (4), and (5). According
to NWE, Section 1603(G)(2) should be deleted because the technical and financial
capabilities of an ESP can be controlled through the ESP Service Agreement with
the UDC, and that Section 1603(G)(4) should not be a precondition to
certification, as explained in NWE's comment to Section 1603(I). NWE also opined
that Section 1603(G)(5) is not necessary. Staff stated that it would not be in
the public interest to issue competitive retail electric CC&Ns without
explicitly addressing the public interest and consumer protection issues
contained in these Sections.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is required.
1603(G)(7)
ISSUE: ACAA proposed to insert a new Section 1603(G)(7) to provide an
additional condition for the Commission to deny certification to any CC&N
applicant as follows:
7. FAILS TO PROVIDE A PLAN TO ENROLL AND SERVE RESIDENTIAL CONSUMERS
PURSUANT TO R14-2-1603(B)(1).
ACAA makes this recommendation in conjunction with its proposed new language for
Section 1603(B)(1) that would require a CC&N applicant to provide a plan to
enroll and serve at least 15% of the total residential consumers eligible for
competitive services on October 1, 2000. Staff stated that although ACAA
suggested this Section to help make the residential market an equitable and
robust
18 DECISION NO. 61969
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market, this proposal is too restrictive and may keep potential service
providers from viewing Arizona's retail market as being entirely open to
providers offering competitive service to those customers they wish to initially
target.
ANALYSIS: We agree with Staff. Adopting the provision ACAA suggests could
discourage potential competitive ESP applicants who might find the associated
costs prohibitive. Instead of leading to a more robust market, this would
actually lessen the chances of developing a truly competitive market. Adoption
of this recommendation would therefore not ultimately serve the public interest.
RESOLUTION: No change is necessary.
1603(I)(4)
ISSUE: NWE recommends the following change to this Section:
4. The Electric Service Provider shall maintain on file with the Commission
all current tariffs;[and any service standards that the Commission shall
require;]
NWE argues that the term "service standards" is not defined in the rules and the
requirement in this Section does not provide adequate notice of the requirements
for remaining certificated in Arizona. Staff stated that it is in the public
interest for the Commission to require ESPs to file any service standards the
Commission deems necessary to serve its customers.
ANALYSIS: We concur with Staff
RESOLUTION: No change is required.
1603(I)(6)
ISSUE: NWE recommended deletion of Section 1603(I)(6), which conditions a
CC&N on the ESP obtaining all necessary permits and licenses including relevant
tax licenses. NWE believes that the Commission has no authority to police
state-law permit and license requirements. Staff believes the item should remain
in the rule because it is in the public interest.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
1603(I)(9)
19 DECISION NO. 61969
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DOCKET NO. RE-00000C-94-0165
ISSUE: ACAA proposed to insert a new Section 1603(I)(9) that contains the
following additional condition for an ESP to obtain a CC&N:
9. THE ELECTRIC SERVICE PROVIDER SHALL COMPLY WITH THE PROVISIONS OF
R14-2-1603(B)(1) ON OR BEFORE SEPTEMBER 1, 1999.
Staff disagreed with the propriety of this proposal because it is too
restrictive and may keep potential service providers from viewing Arizona's
retail market as being entirely open to providers offering competitive service
to those customers they are targeting to serve, which could result in fewer
competitors seeking to provide service in Arizona.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
ISSUE: Navopache and Mohave recommended the addition of a new Section
1603(I)(9) as follows:
9. AN ELECTRIC SERVICE PROVIDER CERTIFICATED PURSUANT TO THIS ARTICLE SHALL
BE SUBJECT TO THE JURISDICTION OF THE ARIZONA CORPORATION COMMISSION.
Staff responded that because the Rules are specific in regard to which entities
are governed by the competitive retail electric rules, and HB2663 describes the
CC&N jurisdictional authority of the Commission for public power entities, this
change is not necessary.
ANALYSIS: We concur with Staff that this proposed amendment is unnecessary
as it is addressed throughout the Rules and by HB2663.
RESOLUTION: No change is necessary.
1603(K)
ISSUE: NWE recommended deletion of Section 1603(K), which allows the
Commission to require in appropriate circumstances, as a precondition to
certification, the procurement of a performance bond sufficient to cover any
advances or deposits the applicant may collect from its customers, or order that
such advances or deposits be held in escrow or trust. NWE objected to this
provision because the amount of the performance bond or escrow can only be based
on estimations before the ESP commences to do business in the state. Staff
responded that a bond requirement is just one option the ESP has to address
customer protection in the certification process, and that this
20 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
provision is needed to provide the Commission flexibility in having the CC&N
applicant address customer protection concerns prior to being certificated.
ANALYSIS: We agree with Staff that Section 1603(K) provides the Commission
with a means of protecting consumers. The Commission has flexibility to adjust
the amount of the performance bond, escrow or trust after the ESP commences
doing business. While it is true that the amount of the performance bond, escrow
or trust must initially be based on estimates, the amount required, or indeed
whether the bond, escrow or trust is required at all, is an issue that the CC&N
applicant is free to address in the proceedings on the application.
RESOLUTION: No change is necessary.
R14-2-1604 "COMPETITIVE PHASES"
1604(A)
ISSUE: Commonwealth and Tucson requested that the phase-in of load be
eliminated, and that a "flash cut" be substituted. Commonwealth stated that it
wants to serve commercial loads of all sizes, but cannot because this Section
does not include smaller customers with loads less than 1 MW or who cannot
aggregate 40 kW loads into 1 MW during the phase-in to competition. Tucson
stated that it desires to have its entire load served competitively, but that it
cannot because the phase-in rule precludes facilities less than 40 kW, which
includes many City premises, from obtaining Competitive Services. Tucson further
stated that the original reason for the phase-in, to limit the exposure of
Affected Utilities to the technical problems that could result from a large
number of customers suddenly switching to competitive generation providers, is
no longer valid because based on the experience in California, few customers are
likely to initially participate in the competitive market. APS, AEPCO, Duncan
and Graham opposed a flashcut. Staff agreed that a flash-cut would eliminate
many of the inequities and other problems associated with a phase-in, but noted
that the current phase-in is much shorter than the one in the 1996 version of
the rules.
NWE commented that the rule is unclear in regard to aggregation of loads
and the definition of "customer," and recommended that the rule clarify that, if
a single site is over 1MW, all lesser sites for the same entity also become
eligible for competitive generation. NWE also noted that this Section does not
allow any further aggregation once 20 percent of an Affected Utility's 1995
system
21 DECISION NO. 61969
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peak demand is reached, although more 1 MW customers could be allowed, and that
this provision favors large ESPs that can provide incentives for aggregation at
the earliest possible date while penalizing customers who might not be prepared
to aggregate in the early phases of competition. Staff conceded that this
Section currently does not require Affected Utilities to allow small commercial
customers to participate in the competitive market during the phase-in, but
pointed out that all classes of customers will be eligible by January 1, 2001.
Staff stated that this Section makes clear that the eligibility of a customer's
load is to be determined at a single premise, and that smaller loads at other
premises for the same entity are not eligible. Staff agreed with NWE that this
Section as currently written appears to favor 1 MW customers over aggregated 40
kWh customers, but that the intent of this Section was to give both groups of
customers equal opportunity to participate. Staff recommended that in order to
clarify that 1MW customers should not be favored over aggregated 40 kW
customers, the sentence stating that additional aggregated customers must wait
until 2001 to obtain competitive service should be deleted.
TEP asserted that only customers with a 1 MW minimum demand should be
eligible for direct access under Section 1604(A)(1) and (2), and that utilizing
a single non-coincident peak has the consequence of expanding direct access
eligibility beyond 20 percent of TEP's 1995 system retail peak demand, thereby
excluding some customers with loads in excess of 1MW. TEP also suggested that
Section 1604 (A)(2) be modified to read that the 40 kWh criterion shall be met
if the customer's usage exceeds 16,500 kWh in any six months, instead of in any
month, in the event peak load data are not available. TEP believes that this
would better characterize a customer whose load usage is more consistently at
least 40 MW or 16,500 kWh. Staff responded to TEP's recommendations by stating
that minimum demands should not be used to determine eligibility, which could
exclude a customer because of one particular month having a lower demand than
usual. Staff also disagreed with TEP's proposal to change one month to six
months to determine eligibility of 40 kW customers because Staff believes there
should be no increased restrictions on the eligibility of medium-size commercial
customers.
In its responsive comments, TEP disagreed with Tucson regarding a flashcut
and regarding the 40kW minimum requirement for aggregation.
22 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
ANALYSIS: We concur with Staff that TEP's proposal to change one month to
six months to determine eligibility of 40 kW customers should not be adopted.
We do not agree with Tucson that the phase-in should be eliminated based on
California's experience that a only a limited number of customers are likely to
initially participate in the competitive market. The current phase-in schedule
is not unreasonable and will allow the Affected Utilities to continue their
current course of preparation for the commencement of full competition.
We agree with Staff that deleting the last sentence of Section 1604(A)(2)
would clarify that 1MW customers should not be favored over aggregated 40 kW
customers. This deletion is not substantive.
RESOLUTION: Delete the last sentence of Section 1604(A)(2). No other change
is required.
1604(A)(2) AND (4) AND 1604(B)(6)
ISSUE: In response to comments filed by ATDUG on June 23, 1999, and to the
numerous oral comments made at the public comment hearing on June 23, 1999,
Staff proposed that these Sections be clarified regarding the ability of
customers to aggregate or self-aggregate their loads, subject to the phase-in
percentage limitations; and to clarify that eligible residential and
non-residential customers may be aggregated together. Staff recommended
modifying the first sentence of Section 1604(A)(2) as follows:
"During 1999 and 2000, an Affected Utility's customers with single premise
non-coincident peak load demands of 40 kW or greater aggregated by an
Electric Service Provider WITH OTHER SUCH CUSTOMERS OR ELIGIBLE RESIDENTIAL
CUSTOMERS into a combined load of 1 MW or greater within the Affected
Utility's service territory will be eligible for competitive electric
services."
Staff also recommended reinserting the following after "competitive electric
services":
"SELF-AGGREGATION IS ALSO ALLOWED PURSUANT TO THE MINIMUM AND COMBINED LOAD
DEMANDS SET FORTH IN THIS RULE.";
and adding the following sentence after the foregoing:
"CUSTOMERS CHOOSING SELF-AGGREGATION MUST PURCHASE THEIR ELECTRICITY AND
RELATED SERVICES FROM A CERTIFICATED ELECTRIC SERVICE PROVIDER AS PROVIDED
FOR IN THESE RULES."
Staff recommended adding a new Section 1604(A)(4) as follows:
23 DECISION NO. 61969
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"EFFECTIVE JANUARY 1, 2001, ALL AFFECTED UTILITY CUSTOMERS IRRESPECTIVE OF
SIZE WILL BE ELIGIBLE FOR AGGREGATION AND SELF-AGGREGATION. THOSE CUSTOMERS
MUST PURCHASE THEIR ELECTRICITY AND RELATED SERVICES FROM A CERTIFICATED
ELECTRIC SERVICE PROVIDER AS PROVIDED FOR IN THESE RULES."
Staff also recommended a new Section 1604(B)(6) as follows:
"AGGREGATION OR SELF-AGGREGATION OF RESIDENTIAL CUSTOMERS IS ALLOWED
SUBJECT TO THE LIMITATIONS OF THE PHASE-IN PERCENTAGES IN THIS RULE.
CUSTOMERS CHOOSING SELF-AGGREGATION MUST PURCHASE THEIR ELECTRICITY AND
RELATED SERVICES FROM A CERTIFICATED ELECTRIC SERVICE PROVIDER AS PROVIDED
FOR IN THESE RULES."
Staff believed that the above changes would help clarify the original
intent of the Rules to require certification of businesses that choose to
provide Aggregation services, while also allowing customers to combine load
("Self-Aggregation") in a manner that will facilitate obtaining favorable
competitive bids from ESP. Staff stated that the practice of Self-Aggregation
could cut costs to competitors by having the customers themselves perform the
functions of combining loads and developing purchase blocks.
ATDUG replied that some of Staff's proposed language additions to Section
1604 "are written as to regulate the conduct of customers" and make it "appear
that the Commission is trying to prevent retail electric customers from buying
power through aggregation or self-aggregation from Salt River Project and other
legitimate electricity suppliers that are not regulated by the Commission."
ATDUG suggested that the Sections in question be rewritten so as to require ESPs
to sell electricity to aggregated customers, instead of requiring that
aggregated customers must purchase their electricity from certificated ESPs.
ANALYSIS: We agree with Staff's recommended changes. However, as written,
proposed Section 1604(A) and Section 1604(B)(6) are redundant, as both state the
requirement that customers choosing Self-Aggregation must purchase electricity
from a certificated provider. Consequently, we will adopt Staff's
recommendation, with the exception of the second sentence in newly proposed
Section 1604(B)(6). We do not agree that these changes will have the effect that
ATDUG suggests, because in order to ensure system reliability and consumer
protection, all ESPs providing competitive retail electric services in the
service territories of the Affected Utilities must be certificated by the
24 DECISION NO. 61969
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Commission. Further, we do not believe that requiring ESPs to provide designated
services to designated customers would encourage competition.
The changes merely clarify the original intent of the Rules and are not
substantive.
RESOLUTION: Modify Sections 1604(A)(2) and (4), and Section 1604(B)(6) as
recommended by Staff, with the exception of the second sentence of Staff's
proposed Section 1604(B)(6) which is redundant.
1604(B)
ISSUE: NWE suggested that the proposed limitations on residential
participation will make the residential market unattractive to potential ESPs,
but NWE did not make a specific recommendation other than that the Section
should be "entirely revised." ACAA proposed that the minimum percentages for
participation of residential customers be increased. Commonwealth believes that
it should not have to obtain a customer list from its competing utility in order
to market its services, and that the waiting list of interested residential
customers should be distributed to all ESPs. Staff responded that the percentage
increases ACAA proposed are probably too small to have a major impact on
participation of residential customers. Staff stated that any lists of
interested customers should be readily available to ESPs if the customers have
given permission for their names and other information to be released, and
stated that this Section does not preclude availability of such lists.
ANALYSIS: We concur with Staff. This Section should be clarified with
respect to the release of customer lists to ESPs. Such modification is not
substantive.
RESOLUTION: Add the following to Section 1604(B)(2) after "manage the
residential phase-in program":
", WHICH LIST SHALL PROMPTLY BE MADE AVAILABLE TO ANY CERTIFICATED
LOAD-SERVING ESP UPON REQUEST"
1604(C)
ISSUE: APS recommended that the words "such as" replace "including" when
referring to rate reductions in this Section in order to clarify that this
Section does not require a rate reduction. NWE commented that a mandatory rate
reduction would be anti-competitive unless applied to all customers and that
information about a rate reduction must be made available before competition
begins.
25 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
ANALYSIS: This Section as written does not require a rate reduction.
RESOLUTION: No change is necessary.
R14-2-1605 "COMPETITIVE SERVICES"
ISSUE: Section 1605 requires a CC&N for all competitive services. AEPCO,
Duncan, Graham, Trico, Navopache, and Mohave (collectively, "Cooperatives")
argue that this requirement conflicts with Section 1615(C), which allows
distribution cooperatives to provide Competitive Services within their
distribution service territories after January 1, 2001. The Cooperatives believe
that it was not the intent of Section 1615(C) to require them to obtain a CC&N
in order to provide competitive services within their distribution service
territories. Staff agreed with these comments, and recommended the following
addition to Section 1605:
"EXCEPT AS PROVIDED IN R14-2-1615(C), Competitive Services shall require a
Certificate of Convenience and Necessity and a tariff as described in
R14-2-1603."
ANALYSIS: We concur with the Cooperatives and Staff that this Section
should be modified to clarify that the Cooperatives do not have to apply for a
CC&N to provide Competitive Services within their distribution service
territories. Such modification adds clarity and is not substantive.
RESOLUTION: Revise Section 1605(C) as recommended by Staff.
R14-2-1606 - SERVICES REQUIRED TO BE MADE AVAILABLE
1606(A)
ISSUE: APS proposed that a sentence be added to state that a UDC, at its
option, may provide Standard Offer Service to customers whose annual usage is
more than 100,000 kWh. Navopache and Mohave proposed additional language to
state that the UDC shall offer Standard Offer Service to the larger customers if
the tariff covers the cost of providing the service and that the UDC could seek
Commission approval for additional rate schedules to provide such service.
Commonwealth suggested that ESPs be allowed to bid on services furnished to
Standard Offer customers. Staff stated that the Rules already allow UDCs to
provide Standard Offer Service to customers with usage greater than 100,000 kWh,
but UDCs will not be Providers of Last Resort for those customers, and that
26 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
because the Commission has determined that Standard Offer Service is a
Noncompetitive Service, ESPs cannot bid on Standard Offer Service.
ANALYSIS: UDCs may offer Standard Offer Service to any customer, but as
Staff pointed out, are not required to offer Standard Offer Service to customers
whose annual usage exceeds 100,000 kWh. Competitive bidding on Provider of Last
Resort services is not currently contemplated in the Rules, but the Commission
may consider implementing such a process in the future when the competitive
generation market has developed.
RESOLUTION: No change is necessary at this time.
1606(B)
ISSUE: Commonwealth proposed that power for Standard Offer Service be
acquired through a competitive bid process instead of through the "open market."
In addition, Commonwealth proposed that cooperatives not be excluded from the
requirement of this Section. Tucson feels that the meaning of "open market" is
not clear and proposed that power for Standard Offer Service be acquired
"through a competitive procurement with prudent management of market risks,
including management of price fluctuations." TEP proposed that a purchased power
adjustment mechanism should be allowed as a means for UDCs to recover costs of
procuring power for Standard Offer Service. Staff agreed with Commonwealth and
Tucson that power for Standard Office Service should be acquired through
competitive bidding, and agreed with Tucson's proposed language. Staff opposed
the use of a purchased power adjustment mechanism because it would reduce the
incentive for the utility to obtain reliable power sources at reasonable rates.
Staff recommended that the following sentence be added to Section 1606(B):
"STANDARD OFFER SERVICE POWER SHALL BE ACQUIRED THROUGH A COMPETITIVE
PROCUREMENT WITH PRUDENT MANAGEMENT OF MARKET RISKS, INCLUDING MANAGEMENT
OF PRICE FLUCTUATIONS.
Staff further recommended that if the Commission does not adopt a competitive
bid process, then the term "open market" should be defined in the Rules.
ANALYSIS: There appears to be some confusion concerning the meaning of the
term "open market." We do not wish to impose the constraints on energy
procurement that would be associated
27 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
with a competitive bid process. Consequently, we will modify Section 1606(B) to
clarify the term "open market". Our clarification is not substantive.
RESOLUTION: Revise Section 1606(B) by replacing "open market" with "an
open, fair and arms-length transaction with prudent management of market risks,
including management of price fluctuations."
1606(C)
ISSUE: Navopache and Mohave proposed adding language to Section 1606(C)(2)
which would provide an exception to the requirement that Standard Offer Service
be unbundled when wholesale power supplies are obtained on a bundled basis.
Trico made a similar comment. APS recommended that the prohibition of "contracts
with term" in Section 1606(C)(6) be deleted or at least limited to customers
whose annual usage is 100,000 kWh or less because the prohibition restricts
customer options and imposes burdens on the UDC when large customers leave from
or return to Standard Offer Service. Commonwealth suggested that UDCs be
prohibited from offering any discount, special contract, or unique tariff to any
particular customer, as these services would in effect constitute Competitive
Services. Commonwealth also opposed Trico's proposal because it would prevent
potential customers and competitors from easily calculating Commonwealth's
proposed "Generation Shopping Credit."
APS also recommended that an Affected Utility be allowed to submit for
Commission approval a plan for unbundling Standard Offer Service that varies
from the requirements of this Section. Commonwealth vigorously opposed APS'
suggestion that the utility develop its own unbundling and billing plan because
a unified billing format should be available to all customers. Commonwealth
proposed addition of the new definition "Generation Shopping Credit" to Section
1601 and a new provision 1606(C)(3) to require that the "Generation Shopping
Credit" appear on the bills of those customers who opt for competitive
generation as follows:
"SIMULTANEOUSLY WITH THE START DATE FOR THE IMPLEMENTATION OF RETAIL
CHOICE, EACH AFFECTED UTILITY SHALL PROVIDE A GENERATION SHOPPING CREDIT ON
THE BILL OF EACH RETAIL CUSTOMER OF AN AFFECTED UTILITY THAT CHOOSES TO
PURCHASE ITS ELECTRIC GENERATION SERVICE FROM AN ENTITY OTHER THAN THE
AFFECTED UTILITY THAT PROVIDES ITS DISTRIBUTION SERVICE. THE GENERATION
SHOPPING CREDIT SHALL BE BASED ON THE AFFECTED UTILITY'S FULL COST TO
28 DECISION NO. 61969
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PROVIDE RETAIL ELECTRIC GENERATION SERVICE TO EACH CUSTOMER CLASS,
INCLUDING BUT NOT LIMITED TO THE COST OF ENERGY, CAPACITY, ANCILLARY
SERVICES, MUST-RUN GENERATING UNITS, ALL RELEVANT TAXES, RESERVES,
TRANSMISSION SERVICE (OR THE APPLICABLE INDEPENDENT SYSTEM ADMINISTRATOR OR
INDEPENDENT SYSTEMS OPERATOR), MARKETING, ADMINISTRATION AND GENERAL COSTS,
AND THE APPLICABLE RATE OF RETURN ON THE ENERGY, CAPACITY, ANCILLARY
SERVICES, RESERVES, MUST-RUN GENERATING UNITS, MARKETING, ADMINISTRATIVE
AND GENERAL COSTS. THE COMMISSION SHALL DETERMINE THE APPROPRIATE LEVEL OF
GENERATION SHOPPING CREDITS FOR EACH AFFECTED UTILITY."
Commonwealth proposed the following definition be added to Section 1601:
"`GENERATION SHOPPING CREDIT' MEANS THE BILL CREDIT THAT WILL BE AFFORDED
TO EACH CUSTOMER OF AN AFFECTED UTILITY THAT CHOOSES TO PURCHASE ITS
ELECTRIC GENERATION SERVICE FROM AN ENTITY OTHER THAN THE AFFECTED UTILITY
THAT PROVIDES ITS DISTRIBUTION SERVICE."
Commonwealth also proposed that 1606(C)(2)(a)(1) and 1612(N)(1)(a) be amended to
read: "Generation Shopping Credit", and that Must-Run Generating Units should be
deleted from 1606(C)(2)(a)(3) as that cost component should be part of the
Generation Shopping Credit.
Staff argued that when possible, unbundled elements need to be standard
across companies so that comparisons can be made, and that APS' suggested
changes to Section 1606(C)(2) are unnecessary because an Affected Utility can
file for Commission approval of a waiver, if necessary. Staff stated that the
intent of Section 1606(C)(6) is to prohibit tariffs for Standard Offer Service
that prevent customers from accessing a competitive option, and believes that
the prohibition against "contracts with term" is consistent with that intent.
Staff stated that this Section should be made consistent with Section 1612(N),
which identifies billing elements. Staff also stated that ancillary services
should be identified as either variable costs or fixed costs. Staff therefore
recommended that Section 1606(C)(2) be amended as follows:
"a. Electricity:
(1). Generation INCLUDING ANCILLARY SERVICES (VARIABLE COSTS)
(2) Competition Transition Charge
(3) Must-Run Generating Units
b. Delivery:
(1) Distribution services
(2) Transmission services
(3) Ancillary Services (FIXED COSTS)
c. Other:
(1) Metering Service
(2) Meter Reading Service
29 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
(3) Billing and collection
d. System Benefits"
Staff also recommended that the date in Section 1606(C)(6) be made
consistent with dates appearing elsewhere in the Rules.
In its responsive comments, Commonwealth stated that it is unclear what
Staff means by "variable" ancillary services which are part of generation costs
and "fixed" ancillary services, which are included in delivery costs.
Commonwealth contended that all ancillary services relating to generation, both
variable and fixed, should be included in the computation of the "Generation
Shopping Credit." Commonwealth argued that under its proposal, the distinction
between a fixed and variable ancillary service would not be a pathway for cost
shifting from generation to delivery charges. Commonwealth recommended that all
ancillary services be included in both the Standard Offer Service tariff
provision (Section 1606(C)(2)) and the Billing provision (Section 1612(N)),
under "Generation Shopping Credit." APS argued that because FERC classifies all
ancillary services as transmission related costs, they should be included in the
"delivery" category of unbundled bills. APS contended that to modify Section
1606(C) as Staff proposed would be confusing and an unnecessary complication.
In its responsive written comments, NWE proposed the following changes to
Section 1606(C)(2):
1. Standard offer tariffs shall include the following elements, {each of
which shall be clearly unbundled and identified in the filed tariffs:}
a. [Electricity] {Competitive Services}
(1) Generation, {which shall include all transaction costs and
line losses}
(2) Competition Transition Charge, {which shall include recovery
of generation related regulatory assets}
(3) [Must Run Generating Units] {Generation-related billing and
collection}
(4) {Transmission Services}
(5) {Metering services}
30 DECISION NO. 61969
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DOCKET NO. RE-00000C-94-0165
(6) {Meter reading service
(7) Optional Ancillary Services, which shall include spinning
reserve service, supplemental reserve service, regulation
and frequency response service, and energy imbalance service
b. [Delivery] Non-Competitive Services
(1) Distribution services}
(2) [Transmission services]
(2) {Required} Ancillary services, {which shall include
scheduling, system control and dispatch service, and
reactive supply and voltage control from generation sources
service
(3) Use of generating units for must-run purposes
(4) System Benefit Charges
(5) Distribution-related billing and collection}
c. [Other
(2) Meter Reading Service
(3) Billing and Collection
The Competition Transition Charge shall be include in the
Standard Offer Service tariffs for the purpose of clearly
showing the portion of Standard Offer Service charges being
collected to pay Stranded Cost.] {Each of these unbundled
elements of the standard offer price shall be clearly
identified on each customer bill.}
{Each of these unbundled elements of the standard offer price shall be
clearly identified on each customer bill.}
ANALYSIS: Standard Offer Service tariffs must be unbundled in a manner that
permits a meaningful comparison for consumers but not be cost prohibitive.
Section 1606(C)(4) provides that unbundled Standard Offer Service tariffs be
cost-based. If an entity is not able to comply with the unbundling provisions,
it may seek a waiver after notice and a hearing.
For the most part, NWE' s proposal concerning unbundled Standard Offer
Service appears reasonable and appropriately categorizes the various elements.
NWE's proposed unbundled tariff elements present the existing categories in a
logical manner and recognize that Ancillary Services may be either generation-
or transmission-related. The Rule provides that the Commission must
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approve all Standard Offer Service tariffs, and it is through the approval
process that the Affected Utility must demonstrate that costs are appropriately
allocated. The process of unbundling tariff elements with Commission oversight
and after public hearing, should alleviate Commonwealth's concerns that costs
may be unfairly shifted from generation to transmission.
We believe, however, that the last sentence in NWE's proposal requiring
that each of the unbundled elements shall be identified on the customer bill is
more appropriately addressed in Section 1613(K) regarding billing elements.
While we agree that customer bills for Standard Offer Service must reflect all
of the unbundled elements, we do not believe that the bill format must exactly
parallel the detail of the tariff because of the potential confusion for
consumers. As long as all bill formats are identical for all providers, and
billing elements reflect the same underlying costs to permit comparisons, bills
should be as simple as possible to read while providing the consumer with
adequate information to make informed choices.
Our modification provides additional guidance and detail into how tariffs
should be unbundled, but it does not substantively alter the original provision
that requires unbundled tariffs.
RESOLUTION: Replace "After January 2, 2001" with "Beginning January 1,
2001". Modify 1606(C)(2) as follows:
2. Standard Offer Service tariffs shall include the following elements,
EACH OF WHICH SHALL BE CLEARLY UNBUNDLED AND IDENTIFIED IN THE FILED
TARIFFS:
a. COMPETITIVE SERVICES: [Electricity]
(1) Generation, WHICH SHALL INCLUDE ALL TRANSACTION COSTS AND
LINE LOSSES;
(2) Competition Transition Charge, WHICH SHALL INCLUDE RECOVERY
OF GENERATION RELATED REGULATORY ASSETS;
(3) GENERATION-RELATED BILLING AND COLLECTION; [Must-Run
Generating Units]
(4) TRANSMISSION SERVICES;
(5) METERING SERVICES;
(6) METER READING SERVICES; AND
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(7) OPTIONAL ANCILLARY SERVICES, WHICH SHAL INCLUDE SPINNING
RESERVE SERVICE, SUPPLEMENTAL RESERVE, REGULATION AND
FREQUENCY RESPONSE SERVICE, AND ENERGY IMBALANCE SERVICE.
b. NON-COMPETITIVE SERVICES: [Delivery]
(1) DISTRIBUTION SERVICES;
(2) REQUIRED ANCILLARY SERVICES, WHICH SHALL INCLUDE SCHEDULING,
SYSTEM CONTROL AND DISPATCH SERVICE, AND REACTIVE SUPPLY AND
VOLTAGE CONTROL FROM GENERATION SOURCES SERVICE;
[Transmission services]
(3) MUST-RUN GENERATING UNITS; [Ancillary services]
(4) SYSTEM BENEFIT CHARGES; AND
(5) DISTRIBUTION-RELATED BILLING AND COLLECTION.
[c. Other:
(1) Metering Service
(2) Meter Reading Service
(3) Billing and collection
d. System Benefits
The Competition Transition Charge shall be included in the
Standard Offer Service tariffs for the purpose of clearly
showing that portion of Standard Offer Service charges being
collected to pay Stranded Cost.]
ISSUE: Staff recommended that Section 1606(C)(6) be modified to allow
"economic development tariffs that clearly mitigate stranded costs" to be
included in Standard Offer Service. AECC urged the Commission to broaden the
definition of Economic Development Tariff to provide discounted tariffs to
businesses for whom a discounted tariff would provide an economic benefit that
would be in the public interest and ensure continued availability of jobs for
Arizona citizens. At the public comment sessions, consumer and low-income groups
expressed reservations about whether the implementation of such "Economic
Development Tariffs" would be equitable. Commonwealth believes Staff's proposal
merges the "wires" business with the "generation" business and retains the
33 DECISION NO. 61969
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DOCKET NO. RE-00000C-94-0165
monopoly configuration of a utility. Commonwealth opposes utility generation
discounts or any other special deals that drive up the distribution charges for
all customers.
ANALYSIS: At the present time there is insufficient evidence in the record
to adopt the proposed "Economic Development Tariff" over the concerns and
reservations expressed by representatives of captive Standard Offer Service
ratepayers. It appears that if this tariff were allowed, it would be Standard
Offer Service ratepayers who would be subsidizing this economic development
program. We are therefore reluctant to implement such a program without the
guidance of a cost-benefit analysis, and none was presented in the record to
support this proposal. Furthermore, the benefits this proposal seeks to accord
should come as a natural consequence of a competition, with competitive rates
becoming available to businesses. Indeed, approval of such a tariff for UDCs
could thwart the growth of competition in the generation market and thereby
actually have an anticompetitive result. Absent the showing of any evidence to
the contrary, we find that the proposed "Economic Development Tariff" is neither
necessary nor beneficial at this time and consequently, we decline to revise
Section 1606(C) as proposed by Staff.
RESOLUTION: No change is necessary.
1606(D)
ISSUE: Trico recommended that the Unbundled Service tariff not include a
Noncompetitive Service tariff, but that instead, two separate tariffs should be
filed. Staff responded that the Unbundled Service tariff should reflect all
components of services available, and that it will be less confusing to all
parties if Noncompetitive Services are included in the Unbundled Service tariff
rather than filing two separate tariffs.
In its responsive comments NWE recommended adding the following
modification to Section 1606(D):
D. [By July 1, 1999,] BY THE EFFECTIVE DATE OF THESE RULES, or
pursuant to Commission Order, whichever occurs first, each
Affected Utility or Utility Distribution Company shall file an
Unbundled Service tariff which shall include a Noncompetitive
Services tariff. THE UNBUNDLED SERVICE TARIFF SHALL CALCULATE THE
ITEMS LISTED IN 1606(C)(2)(B) ON THE SAME BASIS AS THOSE ITEMS
ARE CALCULATED IN THE STANDARD OFFER TARIFF.
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ANALYSIS: NWE's recommended modifications add clarity and should be
adopted. The proposed modification is not substantive.
RESOLUTION: Modify Section 1606(D) as recommended by NWE.
1606(G)
ISSUE: Commonwealth proposed that oral authorization, subject to third
party verification, be allowed for the release of customer data. NWE commented
that the customer should be able to give the data to whomever the customer
wants, but did not suggest a change to the Section. Staff believes it is
important that customer information not be released without written consent from
the customer, because written authorization minimizes the possibility of third
parties receiving customer information without customer consent. The AZCC, in
public comments, opposed oral third-party verification, stating that it hasn't
been of benefit to residential consumers of telephone service.
ANALYSIS: Because customer data belongs to the customer, we agree with NWE
that the customer should be able to give the data to whomever the customer
wants. For the reasons given by Staff, however, it is important that customer
information not be released without the customer's written authorization. The
required written authorization to switch providers as required by Section
1612(C) can also specify the customer's consent for the release of the
customer's demand and energy data. For the reasons explained below under Section
1612(C), we are not convinced at this time that permitting oral authorization
for the release of customer data with third party verification should be
allowed.
RESOLUTION: No change is necessary at this time.
1606(H)
ISSUE: Section 1606(H)(2) provides that rates for Competitive Services and
for Noncompetitive Services shall reflect the costs of providing the services.
Trico suggested amending Section 1606(H)(2) to clarify that cost has nothing to
do with competitive rates. Trico also suggested amending Section 1606(H)(3) to
clarify that flexible rates are limited to Competitive Services. Trico further
stated that Sections 1606(H)(2) and (H)(3) discriminate between UDCs and ESPs.
Staff asserted that it is unreasonably restrictive to limit flexible pricing to
Competitive Services. Staff noted that adjuster mechanisms, which are commonly
used in monopoly regulation, are a form of
35 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
flexible pricing, with the maximum rates subject to Commission approval. Staff
stated that because Section 1606(H) by its terms applies to both Competitive and
Noncompetitive Services, there is no discrimination.
ANALYSIS: We concur with Staff. Competitive tariffs are required to state a
maximum rate, and the minimum rate cannot be below marginal cost. Accordingly,
competitive rates are clearly related to cost. Section 1606(H)(3) allows
downwardly flexible pricing if the tariff is approved by the Commission. This
approval process provides a forum in which Trico may address any particular
concerns.
RESOLUTION: No change is necessary.
R14-2-1607 - RECOVERY OF STRANDED COST OF AFFECTED UTILITIES
1607(A)
ISSUE: TEP urged the Commission to delete the reference to "expanding
wholesale or retail markets or offering a wider scope of permitted regulated
utility services for profit, among others" as a mechanism for mitigating
Stranded Cost. TEP believes that most, if not all, new products and services
will develop in the unregulated, competitive market, and because the profits
therefrom will be unregulated, the Commission will not require those profits to
be used to offset Affected Utilities' Stranded Cost. APS contends that the
definition of "Competitive Services" in Section 1601 "all but eliminates the
possibility of an Affected Utility offering such additional services" as are
referred to in this Section. Staff concurs with the resolution of this issue in
Decision No. 61634 when TEP's argument was not adopted, and believes that TEP's
concern was adequately addressed in our earlier revision to this provision.
ANALYSIS: This provision requires the Affected Utilities to take every
reasonable, cost-effective measure to mitigate or offset Stranded Cost. It does
not, however, mandate any particular method for doing so. We agree with APS that
the definition of "Competitive Services" precludes the Affected Utilities from
offering those competitive services that their competitive affiliates may offer
for profit. We also agree with TEP that unsubsidized profits from the activities
of competitive affiliates of Affected Utilities will not be required to offset
Affected Utilities' Stranded Cost.
36 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
However, we do not believe that the inclusion in this Section of various options
for mitigating Stranded Cost disadvantages the UDCs.
RESOLUTION: No change is required.
1607(B)
ISSUE: Trico asked the Commission to insert the word "all" before
"unmitigated Stranded Costs" to clarify that Affected Utilities are entitled to
recover all of their unmitigated Stranded Costs.
ANALYSIS: This issue was raised and rejected in earlier revisions of the
Rules. We stand by our earlier decision to reject this argument. We believe that
the inclusion of the word "all" may infer that Affected Utilities are entitled
to recover all Stranded Costs in all circumstances.
RESOLUTION: No change is required.
1607(C)
ISSUE: Trico recommended that, after competition has been implemented,
Affected Utilities be required to file on an annual basis the amount of the
actual unmitigated distribution Stranded Cost incurred. Staff responded that
although distribution electric public service corporations may experience
distribution Stranded Cost from competition, due to the difficulty in
calculating such Stranded Cost prior to competition, it would be more
appropriate to deal with those costs in rate cases for distribution electric
public service corporations.
ANALYSIS: We concur with Staff that there is no need for distribution
electric public service corporations to make a distribution-related Stranded
Cost filing with the Commission outside the confines of a rate case.
RESOLUTION: No change is required.
1607(F-G)
ISSUE: TEP urged the Commission to remove the exclusion of self-generated
power from the calculation of recovery of Stranded Cost from a customer. TEP
believes that this Section as written will increase uneconomic self-generation
while increasing cost burdens on customers who purchase their power in the
competitive marketplace. Staff disagreed with TEP that this Section will create
significant problems, noting that although self-generation has been an option
for customers even prior
37 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
to competition, significant problems of cost-shifting have not developed. TEP
also requested adding the following language to the end of Section 1607(G):
"SUBJECT TO COMMISSION APPROVAL, NEITHER SECTION F OR G OF THIS RULE
SHALL PRECLUDE AN AFFECTED UTILITY FROM IMPLEMENTING STAND-BY TARIFFS
THAT RECOVER APPROPRIATE STRANDED COSTS OR FROM PROVIDING OTHER
OPPORTUNITIES TO RECOVER SUCH RESULTANT STRANDED COSTS."
TEP argued this language is necessary to allow an Affected Utility, with
Commission approval, to implement stand-by tariffs or other mechanisms to
recover Stranded Costs in the event there are Stranded Cost recovery shortfalls
resulting from conditions completely outside the control of the Affected
Utility. Staff opposed TEP's proposal, characterizing it as transforming an
opportunity to recover Stranded Costs into a guarantee of recovery. In public
comments, TEP explained that it wishes for customers who self-generate, but will
be taking back-up service from TEP, to come under a maintenance and backup
tariff, which would include some Stranded Cost recovery. In the event
self-generation raises a UDC's distribution costs, such increase is
appropriately addressed in the context of a rate case.
ANALYSIS: We concur with Staff that TEP's recommended language is not
necessary. Sections 1607(F) and (G) do not preclude an Affected Utility from
filing tariffs that apply to maintenance and backup customers who may
self-generate but will remain connected to the system in order to receive backup
power. It is reasonable for such customers to pay a CTC based on the amount of
generation purchased from any Load-Serving Entity.
RESOLUTION: No change is required.
R14-2-1609 - TRANSMISSION AND DISTRIBUTION ACCESS
ISSUE: NWE suggested numerous language changes throughout this Section to
emphasize that an Independent System Operator ("ISO") will be "regional" in form
and that the Arizona Independent Scheduling Administrator ("AISA") is an
"interim" organization. Staff responded that because Section 1609(F) adequately
describes the support of an ISO being regional and the intent to transition from
the AISA to an ISO, NWE's suggested addition of the descriptive terms "regional"
and "interim" in the numerous locations throughout this Section would be
redundant.
ANALYSIS: NWE's concerns are adequately addressed by Section 1609(F).
38 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
RESOLUTION: No change is necessary.
1609(B)
ISSUE: Navopache, Mohave, Trico, and APS contended that UDCs should not be
required to ensure that adequate transmission import capability is available to
meet the load requirements of all distribution customers within their service
areas. Trico contended that such a requirement should apply only to customers
receiving Standard Offer Service from the UDC. Navopache and Mohave contended
that the Section as written places an obligation with the UDC but fails to
address cost and revenue responsibility. AEPCO, Duncan and Graham supported the
modification or deletion of Section 1609(B). Navopache, Mohave and APS question
Commission jurisdictional authority to regulate a FERC jurisdictional
transmission issue. As a solution, Navopache and Mohave suggested replacing the
words "transmission import" with "distribution." APS suggested deletion of this
Section altogether because it "arguably extends to extra-high voltage ("EHV")
and other FERC-regulated transmission systems as well." APS further contended
that a rule requiring UDCs to ensure adequate EHV transmission import capability
could eliminate or mask market forces that rightly drive plant-siting decisions
by new market entrants or merchant generators.
ATDUG suggested that additional clarity would result from the substitution
of the words "transmission and distribution import, export, and local
operation", for the words "transmission import" noting this would require a UDC
to construct facilities to accommodate load growth. ATDUG noted that facilities
subject to FERC jurisdiction would have regulations in place to determine
available transfer capability ("ATC") and assigned costs for increased system
transfer requirements, but that this Section is silent as to how these issues
will be faced for facilities subject to Commission jurisdiction. ATDUG contended
that additional safeguards are required to guarantee that ATC calculations are
not used as a shield against competition.
Staff responded that the advent of electric retail competition does not
remove, eliminate or diminish the obligation of UDCs to ensure reliable delivery
of distribution service to all retail customers and that this obligation does
not extend exclusively to only Standard Offer Service customers, because the UDC
is the Provider of Last Resort for competitive retail consumers as well. Staff
stated that because the ability of a UDC to meet this obligation depends upon
the adequacy of
39 DECISION NO. 61969
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its distribution system, local generation and its interconnections with the bulk
transmission system, this Section's reference to transmission import capability
is proper.
Staff also pointed out that because the cost of distribution system
improvements is recovered via the UDC's distribution delivery charge, ensuring
that such system adequacies are achieved does not imply that the UDC must absorb
the full cost for required system improvements, and that transmission providers
recover transmission system improvement costs via a transmission delivery
charge. Staff stated that although such charges may be regulated by different
jurisdictional authorities, adequate system delivery obligation remains a
composite responsibility of the UDC and its interconnected transmission
providers.
For those reasons, Staff did not agree with suggestions to delete this
Section or eliminate use of the words "transmission import" therein. Staff did
note, however, that the current rule fails to speak to the obligation of the UDC
to provide an adequate distribution system as well as transmission capabilities,
and recommended that this Section be amended to read as follows:
"Utility Distribution Companies shall retain the obligation to assure
that adequate transmission import capability AND DISTRIBUTION SYSTEM
CAPACITY is available to meet the load requirements of all
distribution customers within their services areas."
ANALYSIS: We concur with Staff that the advent of electric retail
competition does not remove, eliminate or diminish the obligation of UDCs to
ensure reliable distribution service to all retail customers, and not
exclusively to Standard Offer Service customers. Because the ability of a UDC to
meet this obligation depends upon the adequacy of its distribution system, local
generation, and interconnections with the bulk transmission system, this
Section's reference to transmission import capability does not exceed the
Commission's jurisdiction. As in the past, the cost of distribution system
improvements are recoverable via the UDC's distribution delivery charge, and
transmission providers can recover transmission system improvement costs via
transmission delivery charges.
We will adopt Staff's recommended modification. We will not delete this
Section as requested by APS, or eliminate the use of the words "transmission
import" as suggested by Navopache and Mohave, because the Commission has the
authority and the obligation to mandate
40 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
that all distribution ratepayers in UDC service territories have access to
generation provided by the certificated ESP of their choice. However, we agree
that distribution issues are closely tied to transmission issues, and that
ideally market forces, and not UDC decisions, should drive plant-siting
decisions by new market entrants or merchant generators. We will therefore
modify this Section to indicate that eventually, the obligation to assure
adequate transmission import capabilities should rest with the ISO, or in the
event the ISO does not become operational, by default with the AISA. Our
modifications do not substantively modify this Section.
RESOLUTION: Modify this Section as follows:
"UNTIL SUCH TIME THAT THE TRANSMISSION PLANNING PROCESS MANDATED BY
R14-2-1609(D)(5) IS FULLY IMPLEMENTED, OR UNTIL SUCH TIME THAT A
FERC-APPROVED AND OPERATIONAL INDEPENDENT SYSTEM OPERATOR ASSUMES THE
OBLIGATIONS OF THE AISA AS IS CONTEMPLATED BY R14-2-1609(F), Utility
Distribution Companies shall retain the obligation to assure that
adequate transmission import capability is available to meet the load
requirements of all distribution customers within their services
areas. UTILITY DISTRIBUTION COMPANIES SHALL RETAIN THE OBLIGATION TO
ASSURE THAT ADEQUATE DISTRIBUTION SYSTEM CAPACITY is available to meet
the load requirements of all distribution customers within their
services areas."
1609(D)
ISSUE: TEP proposed that transmission-owning Affected Utilities'
participation in AISA formation be made optional instead of mandatory, and that
the resulting optional-participation AISA should be given the latitude to
determine whether the functional characteristics of the AISA contemplated by
this Section are "appropriate." To this end, TEP suggested that, because the
AISA should determine what functions it must carry out as circumstances change
over time, the word "shall" should be replaced with the word "may" throughout
this Section. NWE proposed revised language that would limit the AISA role to
that of a monitor or auditor without developing and operating an overarching
statewide Open Access Same-Time Information System ("OASIS"). APS stated that
the AISA should be limited to verifying rather than calculating the Available
Transmission Capacity ("ATC") for Arizona transmission facilities. Staff
responded that the functional characteristics outlined for the AISA in this
Section describe what is required to assure non-
41 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
discriminatory retail access in a robust and efficient electricity market, and
that reducing or changing such functional characteristics could jeopardize the
effective achievement of a fair and non-discriminatory retail market. Staff
further stated that by filing with FERC, the AISA will become a regulated entity
that cannot indiscriminately change its functionality.
Staff explained that two stages of development are envisioned for AISA: an
initial implementation and an ultimate implementation, and that the ultimate
implementation includes an overarching statewide OASIS that will provide AISA
with the technical ability to take an active role in the calculation and
allocation of the ATC for the Arizona transmission system. Staff explained that
this Section by necessity defines a fully developed AISA providing the necessary
functional requirements in the absence of an ISO, and that the pace of ISO
implementation will dictate to what extent the AISA becomes fully developed
before handing over its responsibilities and functions to the regional ISO as
contemplated by Section 1609(F). Staff therefore believes that the language
changes suggested by TEP and NWE are not appropriate.
ANALYSIS: It is essential that the Rules assure, in the event of any delay
in the implementation of the planned regional ISO, the fair and
non-discriminatory transmission access that is essential to the development of a
robust and efficient electricity market. We agree with Staff's characterization
of the two stages of implementation of the AISA, and that this Section should
remain in place as written. The role of the AISA should not be limited at this
time in reliance on the planned regional ISO, which has as yet has not been
officially formed and is awaiting FERC approval.
RESOLUTION: No change is necessary.
1609(D)(5)
ISSUE: APS and TEP contend that the transmission planning function required
of AISA by this Section is unnecessary, duplicates the efforts of the Southwest
Regional Transmission Association ("SWRTA") and the Western States Coordinating
Council ("WSCC"), and should be deleted. Staff stated that Affected Utilities
historically assumed the responsibility to plan transmission expansion
requirements, and that although SWRTA and WSCC do study the interconnected EHV
transmission system's capability to perform reliably under various forecast
operating conditions, the transmission system analysis functions currently
performed by SWRTA and
42 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
WSCC do not consider transmission alternatives to solve local transmission
problems. Staff further stated that it should not be assumed that the
transmission planning function accompanying a regional ISO will address the
transmission interface with local UDC distribution systems. Staff agreed with
APS' and TEP's assessment that because Section 1609(B) places that obligation
with the UDC and its transmission providers, AISA implementation of a
transmission planning process as required by Section 1609(D)(5) would be
redundant and unnecessary. Staff therefore recommended that this Section be
deleted.
ANALYSIS: Due to our modification of Section 1609(B), this Section is not
redundant, but is essential to assure that the transmission interface with local
UDC distribution systems is addressed. Otherwise, we concur with Staff.
RESOLUTION: No change is necessary.
1609(E)
ISSUE: APS contended that because APS has already filed a proposed AISA
implementation plan on behalf of itself, AEPCO, TEP, and Citizens, Section
1609(E) is moot and should be deleted. NWE recommended inclusion of language in
Section 1609(E) to require a proposed schedule for the phased development of a
regional ISO. Staff agreed that a proposed schedule for the staged development
of the AISA and its transition to a regional ISO is needed, and that the AISA
implementation plan should be updated and re-filed with the Commission following
final adoption of these rules, and recommended the following language changes to
Section 1609(E):
"... the schedule for the phased development of Arizona Independent
Scheduling Administrator functionality AND PROPOSED TRANSITION TO A
REGIONAL ISO; ..."
ANALYSIS: We concur with Staff's recommendation. This modification is not
substantive.
RESOLUTION: Make the changes to Section 1609(E) as suggested by Staff to
require a proposed regional ISO transition schedule in the AISA implementation
plan.
1609(F)
ISSUE: Tucson expressed doubts as to the necessity of a regional ISO, which
Tucson states may be more expensive than originally anticipated, and therefore
recommended deletion of Section 1609(F).
43 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
ANALYSIS: Section 1609(F) directs the Affected Utilities to make good-faith
efforts to develop a regional ISO. The FERC has provided guidelines for ISO
formation to ensure nondiscriminatory access to the transmission grid. Section
1609(C) expresses the Commission's support for a regional ISO. We do not believe
that this provision as written overly burdens the Affected Utilities, nor does
it mandate the creation of an ISO if it is not economically feasible to do so.
RESOLUTION: No change is required.
1609(G)
ISSUE: APS wanted assurances that the Commission "will" authorize Affected
Utilities to recover costs for establishing and operating the AISA or regional
ISO if FERC fails to do so within 90 days of application with FERC. Staff
recognized that the cost of organizing and implementing AISA and Desert STAR has
been partially assumed by Arizona's Affected Utilities, and that their timely
recovery of such costs is a reasonable expectation. Staff stated, however, that
this Section already accommodates such a cost recovery and therefore did not
support wording changes in Section 1609(G).
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
1609(I)
ISSUE: NWE recommended removal of language requiring AISA development of
protocols for pricing and availability of Must-Run Generating Units, their
presentation to the Commission for review and approval prior to filing with
FERC, provision of such services by UDCs, and recovery of such fixed-costs via a
regulated charge that is part of the distribution service charge. APS opposed
NWE's proposal. Staff recommended that this Section should be left intact, as
the AISA is developing such protocols and is proceeding to comply with this
Section as it is written.
ANALYSIS: NWE's comments do not provide the basis upon which its proposed
changes are premised, and do not suggest an alternative method of developing
protocols for the availability of services from Must-Run Generating Units.
Generation from Must-Run Generating Units is essential
44 DECISION NO. 61969
DOCKET NO. RE-00000C-94-0165
to maintain system reliability, and should therefore remain a Noncompetitive
Service. Must-Run Generating Units should operate on a regulated cost-of-service
basis.
RESOLUTION: No change is necessary.
1609(J)
ISSUE: APS suggested deletion of this Section on the basis that the AISA
will not address settlement protocols. Staff responded that the AISA is in fact
addressing protocols for settlement of Ancillary Services, Must-Run Generation,
Energy Imbalance, and After-the-Fact Checkout in order to shape and manage
Scheduling Coordinators' expectations of the settlement process, and that this
Section should remain as written.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
FORMER R14-2-1609 - SOLAR PORTFOLIO STANDARD
ISSUE: Photovoltaics International, LLC encouraged the Commission to retain
the Solar Portfolio Standard and further stated that in selecting a location for
its next solar manufacturing plant, it would look for a state with "appropriate
encouragements for adoption of solar electricity generation." Similarly, the
ACAA, Golden Genesis Company, and Robert Annan recommended the reinstatement or
retention of the Solar Portfolio Standard (R14-2-1609). Tucson also recommended
that the Solar Portfolio Standard be retained, but indicated that it "... may be
desirable to modify the standard to make it more practical, but complete
elimination of the solar requirements is poor public policy." Tucson expressed
support of the Environmental Portfolio Standard as outlined in Commissioner
Kunasek's April 8, 1999, letter "as a substitute for the Solar Portfolio
Standard." Tucson suggested that the Environmental Portfolio Standard "be
formulated to follow the intent of the Solar Portfolio Standard." The LAW Fund
also recommended reinstatement of the Solar Portfolio Standard. However, the LAW
Fund applauded the opening of a new docket on an Environmental Portfolio
Standard (E-00000A-99-0205), and stated that it will participate in the new
docket. The Arizona Solar Energy Industries Association ("ARISEIA") stated that
the Solar Portfolio Standard "should have been retained in the Rules." ARISEIA
further stated, however that it
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supports the new Environmental Portfolio Standard docket, which will "provide
significant economic development opportunities, cleaner air and a brighter
future for Arizona."
Staff provided the following comments: "Staff has been supportive of the
Solar Portfolio Standard since its inception in 1996. However, since the Amended
Rules approved in Decision No. 61634 on April 23, 1999, did not include the
Solar Portfolio Standard, it is problematic to attempt to reintroduce the
standard at this point in the rule amendment process. To do so would be a
"substantive" change in the rules, in Staff's opinion, necessitating a
re-commencement of the rule amendment process that might delay the start of
competition. Staff believes that delaying the entire rules package would be
neither prudent nor wise.
"Staff does, however, agree with Tucson, the LAW Fund and ARISEIA that the
new docket for the Environmental Portfolio Standard, as suggested by
Commissioner Kunasek's April 8, 1999, letter is an excellent vehicle to
incorporate solar and other clean technologies into the new competitive market.
In fact, Staff believes that the Environmental Portfolio Standard process, if
promptly handled, and followed by a supplemental rulemaking process, could add
Environmental Portfolio Standard rules that could be in effect by January 1,
2000."
Staff recommended no change to the rules at this time, but a continuation
of the Environmental Portfolio Standard proceedings in the new docket.
ANALYSIS: We believe that the Environmental Portfolio Standard docket
constitutes the proper forum for consideration of the costs and benefits of
renewable energy requirements, and that the start of competition should not be
delayed pending such consideration.
RESOLUTION: No change is required.
R14-2-1611 - RATES
1611(B)
ISSUE: NWE opposed the language in Section 1611(B) regarding the filing of
maximum rates, stating that the market will set the price of electric services
and that in certain cases, the maximums may need to be exceeded. NWE also
pointed out that this provision does not establish any time limitations for the
Commission to approve such rates. Staff responded that the filing of maximum
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rates is an established rate/regulatory practice in Arizona, and that the
Commission has approved maximum rates in conjunction with its approval of ESP
applications.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
1611(C)
ISSUE: NWE stated that Section 1611(C) is an unnecessary remnant of the
regulatory regime that Arizona is now abandoning, and that it should be stricken
in its entirety, but that if retained, strict time limitations for such review
should be required, and submitted contracts should be presumed valid unless
disapproved under clear criteria within the established time period. Staff
stated that this Section requires a Commission Order for contract approval only
if the contract terms deviate from a Load Serving Entity's approved tariffs.
Tucson stated that this Section should be deleted because it is unclear why
competitively negotiated contracts should be treated differently before January
1, 2001, than after that date. Trico recommended that because the word "terms"
is ambiguous, the word "terms" should be replaced by the word "provisions" in
the last sentence of Section 1611(C). Commonwealth joined in the concerns of
Tucson and Trico. Staff agreed that the word "terms" may be misconstrued to mean
the length of the contract and recommended adoption of Trico's proposed
modification.
ANALYSIS: This Section places a reasonable requirement on Load-Serving
Entities in order to allow the Commission's Utilities Division to monitor the
referenced contracts during the phase-in of competition. After January 1, 2001
all customers will have access to contracts with competitive suppliers, and this
monitoring will no longer be necessary for contracts that comply with the
provisions of approved tariffs. It is reasonable that a Commission Order be
required for approval of contracts that deviate from approved tariffs, because
to approve such contracts without Commission Order would render Commission
approval of tariffs meaningless. We concur with Staff regarding the substitution
of the word "provisions" for the word "terms."
RESOLUTION: Replace the word "terms" with the word "provisions" in the last
sentence of this Section. No other change is necessary.
1611(D)
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ISSUE: Tucson recommended deletion of the first sentence of this Section.
Staff responded that this Section affirms the fact that the referenced contracts
no longer need to be filed with the Director, Utilities Division on or after
January 1, 2001, and recommended no change.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
R14-2-1612 - SERVICE QUALITY, CONSUMER PROTECTION, SAFETY, AND BILLING
REQUIREMENTS
1612(A-B)
ISSUE: Trico recommended that words "each paragraph" be replaced by the
words "the applicable provisions" in the last sentence of Section 1612(A)
because in this Section as well as Section 1612(B), there are numerous
provisions of Sections 201 through 212 that are not applicable to ESPs. Staff
responded that ESPs are subject to all of the provisions of Sections 201 through
212, and therefore no change to Sections 1612(A) or (B) is necessary.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
1612(C)
ISSUE: Commonwealth proposed that oral authorization, subject to third
party verification, be allowed for the switching of service providers in lieu of
the requirement of a written authorization, and that this Section be modified
accordingly. Commonwealth argued that allowing third party oral verification
would reduce costs for ESPs. Staff responded that a customer's service provider
should not be changed without written consent from the customer, because written
authorization minimizes the possibility of being switched to other service
providers without customer consent, and that there is no reason that this
requirement would result in a delay of the transaction. In their oral comments,
ACAA informed the Commission that it and other consumer groups have been
communicating with Commonwealth regarding this issue, but that the consumer
groups cannot yet endorse Commonwealth's proposal. At the public comment
session, Staff stated that written confirmation is
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the best way to avoid any potential unauthorized switching of providers, or
"slamming" problems that may occur, and recommended no change.
ANALYSIS: Arizona's electricity consumers must be protected from the
practice of "slamming" that is unfortunately an ongoing problem in the
deregulated long-distance telecommunications industry. In that industry, the
third-party oral verification process is known not to be completely effective in
preventing slamming. We do not believe that requiring written authorization
rather than third-party oral verification will necessarily result in higher
market entry costs for competitive ESPs. On the contrary, the requirement of
written customer authorization will provide protection for ESPs as well as for
consumers, because it will result in fewer erroneous switches, which are costly
for ESPs. In keeping with the intent of A.R.S. ss. 40-202(C)(4), we will not
modify this Section as Commonwealth requests.
RESOLUTION: No change is necessary.
ISSUE: A.R.S. ss. 40-202(C)(4) confirms the Commission's authority to adopt
consumer protection requirements related to switching service providers. Several
of the requirements appearing in A.R.S. ss. 40-202(C)(4) are embodied in Section
1612(C), but some are not.
ANALYSIS: For consistency, clarity and certainty, Section 1612(C) should
include the specific requirements and prohibitions relating to written
authorizations to switch service providers that appear in A.R.S. ss.
40-202(C)(4). Such additions to the Rules are not substantive.
RESOLUTION: Modify Section 1612(C) by adding the following after "switching
the consumer back to the previous provider.":
"A NEW PROVIDER WHO SWITCHES A CUSTOMER WITHOUT WRITTEN AUTHORIZATION
SHALL ALSO REFUND TO THE RETAIL ELECTRICITY CUSTOMER THE ENTIRE AMOUNT
OF THE CUSTOMER'S ELECTRICITY CHARGES ATTRIBUTABLE TO ELECTRIC
GENERATION SERVICE FROM THE NEW PROVIDER FOR THREE MONTHS, OR THE
PERIOD OF THE UNAUTHORIZED SERVICE, WHICHEVER IS LESS."
Add the following after "the provider's certificate.":
"THE FOLLOWING REQUIREMENTS AND RESTRICTIONS SHALL APPLY TO THE
WRITTEN AUTHORIZATION FORM REQUESTING ELECTRIC SERVICE FROM THE NEW
PROVIDER:
1. THE AUTHORIZATION SHALL NOT CONTAIN ANY INDUCEMENTS;
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2. THE AUTHORIZATION SHALL BE IN LEGIBLE PRINT WITH CLEAR AND PLAIN
LANGUAGE CONFIRMING THE RATES, TERMS, CONDITIONS AND NATURE OF
THE SERVICE TO BE PROVIDED;
3. THE AUTHORIZATION SHALL NOT STATE OR SUGGEST THAT THE CUSTOMER
MUST TAKE ACTION TO RETAIN THE CUSTOMER'S CURRENT ELECTRICITY
SUPPLIER;
4. THE AUTHORIZATION SHALL BE IN THE SAME LANGUAGE AS ANY
PROMOTIONAL OR INDUCEMENT MATERIALS PROVIDED TO THE RETAIL
ELECTRIC CUSTOMER; AND
5. NO BOX OR CONTAINER MAY BE USED TO COLLECT ENTRIES FOR
SWEEPSTAKES OR A CONTEST THAT, AT THE SAME TIME, IS USED TO
COLLECT AUTHORIZATION BY A RETAIL ELECTRIC CUSTOMER TO CHANGE
THEIR ELECTRICITY SUPPLIER OR TO SUBSCRIBE TO OTHER SERVICES.
ISSUE: Commonwealth objected to the language in Section 1612(C) that
authorizes UDCs to audit ESPs written authorizations to switch providers in
order to assure that a customer switch was properly authorized.
ANALYSIS: We agree that this provision could unnecessarily delay the
switching process. The penalties for unauthorized switching should be adequate
to deter intentional unauthorized switching, which should preclude any need to
audit written authorizations. However, the Commission's Consumer Services
Division has the regulatory authority to conduct such audits, and if a UDC
believes such an audit is necessary, the UDC should request that the Commission
conduct an audit. A UDC, especially one with a competitive ESP affiliate, should
not have the authority to conduct such audits itself.
RESOLUTION: Replace "HAS THE RIGHT" with "may request that the Commission's
Consumer Services Division". Such modification does not substantively affect any
entity's right to an audit.
1612(E)
ISSUE: NWE recommended that this Section be redrafted to clarify that
compliance with applicable reliability standards is the responsibility of the
scheduling coordinator, the ISO or the ISA, and that notification of scheduled
outages is the responsibility of the UDC and should not apply to ESPs. Staff
responded that ESPs should remain subject to the same applicable reliability
standards as UDCs and recommended no change.
ANALYSIS: We concur with Staff.
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RESOLUTION: No change is necessary.
1612(G-H)
ISSUE: NWE stated that the provisions found in Sections 1612(G) and (H)
should apply only to UDCs. Staff responded that ESPs should remain subject to
the same service quality provisions as the UDCs, and recommended no change.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
1612(I)
ISSUE: Tucson requested that Section 1612(I) be modified to clarify the
time frames and conditions that a customer that is being served by an ESP may
return to Standard Offer Service. Staff stated that it will be necessary for
both the ESP and UDC to coordinate a customer returning to Standard Offer
Service through the Termination of Service Agreement Direct Access Service
Request (DASR) process, because once properly notified by the ESP, the UDC has
the responsibility to ensure that the proper metering equipment is in place to
serve a customer who is returning to Standard Offer Service. Staff stated that
the time frames and the conditions that are included in Section 1612(I) are
therefore necessary and reasonable. Further, APS responded that Tucson's
suggestion fails to recognize the timing and coordination that may be necessary
to return some customers to Standard Offer if it is necessary to replace meter
equipment.
ANALYSIS: We concur with Tucson that the timeframes in this Section are
ambiguous concerning the timing for providing notice to return a customer to
Standard Offer Service. We agree with Staff and APS, however, that in certain
situations, whether appropriate metering equipment is in place can affect the
transfer of service. Provided that the appropriate metering equipment is in
place, we believe 15 days notice is adequate for a UDC to return a customer to
Standard Offer Service. Consequently, we adopt Tucson's proposed modification,
with the exception of Tucson's proposed deletion of the reference concerning the
placement of appropriate metering equipment.
RESOLUTION: Revise Section 1612(I) as follows:
Electric Service Providers shall give at least 5 days notice to their
customer [and to the appropriate Utility Distribution Company] of
scheduled return to Standard Offer Service [but that return of that
customer to Standard Offer Service would be at the next regular
billing cycle, if appropriate metering equipment is in place and the
request is processed 15 calendar days prior to the next scheduled
meter read date]. ELECTRIC SERVICE PROVIDERS SHALL PROVIDE 15 CALENDAR
DAYS NOTICE PRIOR TO THE NEXT SCHEDULED METER READING DATE TO THE
APPROPRIATE UTILITY DISTRIBUTION COMPANY REGARDING THE INTENT TO
TERMINATE A SERVICE AGREEMENT. RETURN OF THAT CUSTOMER TO STANDARD
OFFER SERVICE
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WILL BE AT THE NEXT REGULAR BILLING CYCLE IF APPROPRIATE METERING
EQUIPMENT IS IN PLACE AND THE REQUEST IS PROVIDED 15 CALENDAR DAYS
PRIOR TO THE NEXT REGULAR READ DATE. Responsibility for charges
incurred between the notice and the next scheduled read date shall
rest with the Electric Service Provider.
1612(K)(1)
ISSUE: Navopache and Mohave proposed adding a sentence to Section
1612(K)(1) to allow UDCs to recover costs associated with collecting and
distributing metering data when UDCs provide metering data to an ESP or
customer, and proposed adding the words "Utility Distribution Companies shall
make available to the Customer or Electric Service Provider all metering
information and may charge a fee for that service. The charge or fee shall
reflect the cost of providing such information." Staff pointed out that UDCs may
request that the Commission approve this type of charge as a tariff item, and
recommended no change to this Section.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
1612(K)(2)
ISSUE: NWE contended that the Commission should not approve tariffs for
meter testing, and that rather than establishing a set percentage of error, this
Section should refer to a Commission-approved standard. NWE also suggested
replacing "another" with "an".
ANALYSIS: This Section contains the Commission-approved standard of + 3
percent as provided by Section 209(F). Tariffs for meter testing should be filed
for approval by the Commission. NWE's suggestion that "another" be replaced by
"an" provides clarity and should be adopted.
RESOLUTION: Replace "another" with "AN [another]". No other change is
required.
1612(K)(3)
ISSUE: Staff stated that at the June 2, 1999 Metering Committee meeting it
was proposed that the word "customer" be removed after the word "competitive"
and be replaced with "point of delivery," and deletion of the words "for each
service delivery point." Staff stated that the Metering
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Committee had previously determined that each point of delivery be assigned a
Universal Node Identifier ("UNI"), and that because a customer could have more
than one point of delivery, a UNI must be assigned to each point of delivery.
Staff recommended that this Section be modified using the wording developed by
the Metering Committee.
ANALYSIS: We concur with Staff. This modification is not substantive.
RESOLUTION: Modify this Section as follows:
3. Each competitive [customer] POINT OF DELIVERY shall be assigned a
Universal Node Identifier [ for each service delivery point] by the Affected
Utility or the Utility Distribution Company whose distribution system serves the
customer.
1612(K)(4)
ISSUE: NWE contended that the Utility Industry Group ("UIG") should be
required to complete its standards at least 60 days before competition begins,
and therefore proposed deleting the words "standards approved by the Utility
Industry Group (UIG) that can be used by the Affected Utility or the Utility
Distribution Company and the Electric Service Provider." and replacing them with
"UIG standards in effect at least 60 days before the onset of competition." NWE
alternatively proposed that in the penultimate line of this Section, "can"
should be changed to "shall." Staff responded that because the use of EDI
formats approved by UIG has been discussed by the Metering Committee, and all
formats that are being used were already in effect earlier this year, NWE's
first proposed change is unnecessary.
ANALYSIS: We concur with Staff's reasoning regarding the first proposed
change, and agree with NWE regarding its alternative proposal. This modification
is not substantive.
RESOLUTION: Change "can" to "shall" in the penultimate line of this
Section. No other change is necessary.
1612(K)(6)
ISSUE: TEP proposed deleting the words "Predictable loads will be permitted
to use load profiles to satisfy the requirement of hourly consumption data. The
Affected Utility or Electric Service Provider will make the determination if a
load is predictable." APS did not oppose allowing some "predictable load" to use
load profiling in lieu of hourly consumption data, but believed that
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this Section is unclear as to who may waive the requirements for hourly
consumption data. APS recommended changing the last sentence of Section
1612(K)(6) to provide that the "entity developing the load profile shall
determine if a load is predictable." Staff responded that ESPs and UDCs are
responsible for developing the load profiles for their respective customers and
if they do not estimate the load profile correctly, the AISA will require them
to pay scheduling penalties. Staff believed that APS' proposed language
appropriately clarifies where this responsibility resides, and recommended that
APS' wording be used.
Commonwealth disagreed with Staff's and APS' proposed modification as an
additional barrier to entry and supported keeping the original language.
Commonwealth argued that any ESP should be able to make its independent
determination of whether or not a customer has a load it desires to serve. TEP
did not agree with the modifications proposed by Staff, Tucson and APS on the
basis that they do not address the concerns TEP raised. TEP argued that loads
are determined by an Affected Utility's unmetered tariffs, so only the Affected
Utility is in a position to determine whether load is predictable. TEP
maintained that there are many reasons why load profiling fails to adequately
address issues such as economic efficiency, system reliability, proper
allocation of costs to customers and proper allocation of costs to third-party
suppliers. TEP strongly contended that until these issues are resolved, there is
no justification to avoid the use of interval metering in favor of load
profiling.
ATDUG believed that some types of loads such as irrigation and other water
pumping loads are inherently predictable and suggested the following sentence be
added: "The Commission will identify categories of loads that are deemed
predictable."
ANALYSIS: TEP states there are unresolved issues that argue against the use
of load profiling in lieu of interval metering. However, TEP did not provide the
rationale why these issues should prevent the use of profiling for predictable
loads. We concur with Tucson, Staff and APS that it is reasonable to allow
predictable loads to use load profiling in lieu of hourly consumption data. We
agree with Staff that because the entity determining whether a load is
predictable or not will bear the responsibility of paying any scheduling
penalties stemming from inaccurate predictions, that
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APS' proposed language should be adopted. We do not believe that ATDUG's
suggestion that the Commission should identify categories of loads to be deemed
predictable is necessary at this time.
RESOLUTION: Delete the last sentence of Section 1612(K)(6) and replace with
"THE LOAD-SERVING ENTITY DEVELOPING THE LOAD PROFILING SHALL DETERMINE IF A LOAD
IS PREDICTABLE." Such modification is not substantive.
1612(K)(6) AND (7)
ISSUE: Commonwealth proposed that instead of the current 20 kW and 100,000
kWh limit for hourly interval meters, that a limit of 50 kW and 250,000 kWh be
imposed for the use of hourly interval meters. Tucson proposed that the 20 kW
demand threshold be re-evaluated. Staff responded that 20kW was the appropriate
cut-off for requiring hourly interval meters because customers over 20 kW do not
have easily predictable load profiles and use of load profiling for such
customers can result in higher scheduling errors and cause the Load-Serving
Entities to pay scheduling penalties which would be passed on to both the
Standard Offer Service and competitive consumers. APS asserted that Commonwealth
has not provided a compelling argument why the threshold of 20kW, developed by
the working group, is not appropriate. Staff argued that the lower limit reduces
scheduling errors and results in lower costs to the Standard Offer Service and
competitive customers.
ANALYSIS: Section 1612(K)(6) provides a means for loads over 20 kW
determined to be predictable by Load-Serving Entities developing load profiles
to use those load profiles in lieu of interval meters. We concur that the 20 kW
threshold, that was developed by the working group, should remain unchanged.
RESOLUTION: No change is necessary.
1612(M)
ISSUE: NWE recommended that Section 1612(M) be stricken in its entirety
because the Electric Power Competition Act (HB 2663) requires substantial
statewide consumer outreach and education, and further informational programs by
ESPs is unnecessary. Staff responded that the Commission has a duty to ensure
that all customers throughout the state are well informed regarding electric
competition and recommended that this provision remain.
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ANALYSIS: This provision provides the Commission with the ability to ensure
that consumers receive information about competition.
RESOLUTION: No change is necessary.
1612(N)
ISSUE: Trico, Navopache and Mohave recommend that the language in Section
1612(N) be modified to clarify that UDCs are not required to segregate Wholesale
Power Contract bills which combine generation and transmission services. Staff
responded that the Commission recognizes that distribution cooperatives may not
have the ability to segregate Wholesale Power Contract bills which bundle
generation and transmission services. Staff believed the proper remedy would be
for the affected distribution cooperatives to seek a waiver from this Rule.
ANALYSIS: We believe that the proper way to address the distribution
cooperatives' concerns is through the waiver process rather than the revision of
this Rule.
RESOLUTION: No change is necessary.
ISSUE: NWE states that if an ESP is mandated by Section 1612(N) to provide
the listed information on their billing statements, then Affected Utilities and
UDCs should be mandated to provide such information that is in their control to
the ESP in order to permit the ESP to meet its requirements. Staff responded
that the billing entity will be responsible for providing this information on
customer bills, and that the billing entity for direct access customers will be
responsible for coordinating with UDCs, ESPs, and Meter Reader Service Providers
to provide this information. Staff therefore recommended no change to this
Section.
ANALYSIS: We concur with Staff. This information exchange should be covered
in the Electric Service Provider Service Acquisition Agreement between the ESP
and the UDC.
RESOLUTION: No change is necessary.
ISSUE: Most commentators who addressed the issue of bill elements opined
that they should be consistent with the unbundled tariff elements established in
Section 1606(C)(2).
ANALYSIS: Bills should provide information to customers in a manner that is
easily understood and that permits customers to compare the price of the various
services. We believe that the format established in our revised Section
1606(C)(2) concerning unbundled tariffs provides a
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good framework for delineating bill elements. We agree with the Residential
Utility Consumer Office's comments to a past version of these Rules that
consumers likely are not interested in and may be confused by too much detail on
the bill. Consequently, we believe that certain elements that are broken down
for tariff purposes are better combined when presented on the bill.
Our modifications to this Section, while providing additional direction to
the affected entities and clarity for consumers, are not substantive changes
from the original provision.
RESOLUTION: Revise Section 1612(N) as follows:
1. COMPETITIVE SERVICES:[Electricity Costs]
a. Generation, WHICH SHALL INCLUDE GENERATION-RELATED BILLING AND
COLLECTION;
b. Competition Transition Charge, and
c. TRANSMISSION AND ANCILLARY SERVICES; [Fuel or purchased power
adjustor, if applicable]
d. METERING SERVICES; AND
e. METER READING SERVICES.
2. NON-COMPETITIVE SERVICES:[Delivery costs]
a. Distribution services, INCLUDING DISTRIBUTION-RELATED BILLING AND
COLLECTION, REQUIRED ANCILLARY SERVICES AND MUST-RUN GENERATING
UNITS; AND
b. SYSTEM BENEFIT CHARGES. [Transmission services;]
3. REGULATORY ASSESSMENTS; AND [Other Costs:
a. Metering Service,
b. Meter Reading Service,
c. Billing and collection, and
d. System Benefits charge.]
4. APPLICABLE TAXES.
R14-2-1613 - REPORTING REQUIREMENTS
ISSUE: NWE recommended that this entire Section be deleted because NWE
believed that the reporting requirements are regulatory in nature with no
pro-competitive justification, and that the
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requirements will harm consumers by raising costs, as ESPs will be forced to
hire employees whose sole purpose is to fulfill these reporting requirements.
TEP questioned the need for the amount of information this Section requires,
arguing that the amount of information will be difficult to compile and will
increase the costs that, ultimately, customers will be required to pay.
Staff responded that the reporting requirements are necessary for the
Commission to monitor and determine that the bond and insurance coverage amounts
are adequate to protect consumers, including customer deposits and advances.
Staff contended that the reports required by this Section will also furnish the
Commission with valuable information in assessing the competitiveness of the
electricity market in Arizona.
ANALYSIS: We agree with Staff that the information required by this Section
is very valuable to the Commission, especially in the early stages of
competition, and that the information is also needed to ensure continued
consumer protection via bonds and insurance.
RESOLUTION: No change is necessary.
R14-2-1614 - ADMINISTRATIVE REQUIREMENTS
1614(A-C)
ISSUE: NWE repeated its suggestion that there should be no requirement to
file maximum rates, and therefore proposed deletion of these Sections 1614 (A),
(B), and (C). Staff responded that ESPs are public service corporations, for
whom the Commission is lawfully authorized to establish just and reasonable
rates. Staff contended that the filing of maximum rates, subject to discount,
and the filing of contracts are the means by which the Commission has decided to
exercise its jurisdiction.
EVALUATION: We concur with Staff.
RESOLUTION: No change is necessary.
1614(E)
ISSUE: ACAA suggested additional language which would further define
specifics surrounding the Consumer Education Program. ACAA would have this
Section specifically reference adoption of a funding plan, specify that the
adopted Consumer Education Program is to be a model, and require Affected
Utilities to conform to the adopted plan. Staff responded that this
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Section as currently written will accommodate the concerns addressed by ACAA,
and recommended no change.
ANALYSIS: We believe that ACAA's concerns will be addressed when the
Commission adopts the Consumer Education Program required by this Section.
RESOLUTION: No change is necessary.
R14-2-1615 - SEPARATION OF MONOPOLY AND COMPETITIVE SERVICES
1615(A)
ISSUE: Section 1615(A) requires all competitive generation and Competitive
Services to be separated from an Affected Utility prior to January 1, 2001. Such
separation shall either be to an unaffiliated party or to a separate corporate
affiliate or affiliates. Commonwealth asserted that all generation assets,
except for Must Run Generating Units, should be sold at market value to third
parties. Commonwealth also suggested that an Affected Utility's competitive
affiliate should be precluded from acquiring generation assets unless it is the
highest bidder at auction. Commonwealth believes that, without the requirement
of a sale at market value, the UDCs will be able to manipulate values and shift
costs from Competitive Services to Noncompetitive Services.
Staff responded that Commonwealth's proposal to require generation assets
to be divested through a market auction is in direct conflict with Decision No.
61677, the Commission's Stranded Cost order, which treats divestiture as an
option, not a requirement. Staff pointed out that pursuant to Section 1615(A),
the asset transfer shall be at a value determined by the Commission to be fair
and reasonable, and that accordingly, the asset transfer will not occur outside
of Commission oversight. Staff further stated that Commonwealth's concerns
regarding cost shifting between UDCs and their affiliates may be addressed
through the Code of Conduct required by Section 1616 and through subsequent UDC
rate cases governing Noncompetitive Services.
Commonwealth asserted that Section 1615(A) should be clarified by deleting
the word "competitive", thereby requiring all generation assets except for
Must-Run Generating Units to be separated from Affected Utilities prior to
January 1, 2001. Staff responded that the definition of "Noncompetitive
Services" clearly excludes generation services, except for Must-Run Generating
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Units, and that it is therefore clear that competitive generation includes all
generation except for Must-Run Generating Units. Staff recommended against
adoption of Commonwealth's suggested modifications to this Section.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is necessary.
ISSUE: Section 1615(A) requires Affected Utilities to transfer their
generation assets by January 1, 2001. TEP suggested changing this date to
January 1, 2003 to accommodate lease and bond restrictions that may interfere
with TEP's ability to comply with the 2001 deadline. Staff responded that the
Rules already provide an avenue in which a public service corporation may
request a waiver to the rules, and that while TEP's individual circumstances may
justify a case-specific waiver from the proposed deadline, these circumstances
do not justify an amendment to the Rules.
ANALYSIS: We believe that TEP's concerns are best addressed through a
waiver rather than a redrafting of this rule.
RESOLUTION: No change is necessary.
ISSUE: Section 1615(A) allows Affected Utilities to transfer competitive
generation assets to affiliates. TEP suggested adding the word "subsidiary"
because it believes that transfer to a subsidiary may under some circumstances
be less costly than transfer to an affiliate. Staff responded that in Decision
No. 61669, the Commission clearly indicated its intent to require transfer to an
affiliate, instead of a subsidiary, and that TEP's suggestion conflicts with the
Commission's clearly established intent. Staff therefore recommended no change.
ATDUG expressed grave concerns about the effectiveness of "separation" if the
transfer of generation assets is allowed to affiliates.
ANALYSIS: We agree that the requirement that competitive generation assets
and Competitive Services be separated to an unaffiliated party or to a separate
corporate affiliate or affiliates, will provide greater protection against
cross-subsidization than would separation to a subsidiary.
RESOLUTION: No change is necessary.
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ISSUE: APS argued that the separation from the UDC of metering, meter
reading, billing, and collection required by Section 1615 is not necessary,
appropriate, or to the benefit of consumers or the competitive market. APS
proposed amending Section 1615 to allow UDCs to offer non-generation related
Competitive Services without divesting such functions to affiliates. AECC
opposed APS' proposal. Staff responded that Affected Utilities, such as APS,
currently have substantial market power by virtue of their status as incumbent
monopolists, and that the prospective competitive market will benefit by the
creation of a level playing field for new market entrants so that competitors
will have an incentive to enter the market. Staff therefore recommended no
change to this Section.
ANALYSIS: We concur that separation of monopoly and competitive services by
the incumbent Affected Utilities must take place in order to foster development
of a competitive market in Arizona.
RESOLUTION: No change is necessary.
1615(B)
ISSUE: Section 1615(B)(1) recognizes that UDCs may provide meters for Load
Profiled customers. APS proposed clarifying this Section by substituting the
phrase "Meter Services and Meter Reading Services" for the word "meters." Staff
supported APS' proposal as it uses defined terms in place of an undefined term.
ANALYSIS: We concur with Staff. This modification eliminates ambiguity and
is not substantive.
RESOLUTION: Delete "meters" and replace with "Meter Services and Meter
Reading Services".
1615(C)
ISSUE: Section 1615(C) allows distribution cooperatives to provide
competitive electric services in areas in which they currently provide service.
AEPCO, Duncan, Graham, and Trico suggested amending this Section to allow the
distribution cooperatives to provide competitive services in any areas in which
they will be providing Noncompetitive Services now or in the future. Staff
responded that Section 1615(C) was intended to allow distribution cooperatives
to provide
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competitive services within areas in which they are providing distribution
services, and that because distribution service territories change, it would be
sensible to draft the rule in a manner that recognizes this. Staff therefore
recommended deleting the phrase "the service territory it had as of the
effective date of these rules" and replace it with "its distribution service
territory."
ANALYSIS: We agree with this nonsubstantive modification.
RESOLUTION: Replace "the service territory it had as of the effective date
of these rules" with "ITS DISTRIBUTION SERVICE TERRITORY."[the service territory
it had as of the effective date of these rules.]
ISSUE: Section 1615(C) states that a generation cooperative shall be
subject to the same limitations to which its member cooperatives are subject.
AEPCO argues that a generation cooperative, such as AEPCO, does not have a
geographic service territory and does not have distribution customers. AEPCO
further argued that, because it is not a distribution cooperative, it is not
eligible for the exemption contained in this Section, and is therefore subject
to all the requirements contained in Sections 1615(A) and (B). AEPCO therefore
recommended deleting the last sentence of Section 1615(C). Staff agreed with
AEPCO.
ANALYSIS: The intent of this provision was to preclude a generation
cooperative or its competitive affiliate from providing power in the competitive
market before the territories of its member distribution cooperatives were open
to competition. The reference here is misplaced and we agree it should be
removed. The timing for AEPCO's competitive affiliate to begin providing
Competitive Services will be addressed by Commission order in AEPCO's Stranded
Cost/Unbundled tariff proceeding.
RESOLUTION: Delete the last sentence of Section 1615(C). This change is not
substantive.
R14-2-1616 - CODE OF CONDUCT
ISSUE: Commonwealth, Tucson, AECC and Enron Corp. ("Enron") opposed the
Commission's elimination of the Affiliate Transaction rules (formerly
R14-2-1617). AECC joined in and fully supported the separately filed comments of
Enron and submits that the Electric Competition Rules must contain Affiliate
Transaction rules to provide consumers appropriate safeguards in the competitive
marketplace. Enron claimed that the Affiliate Transaction rules should be
designed to prevent Affected Utilities from abusing or unfairly exerting market
power due to their inherent and
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historical monopoly positions in Arizona. Enron argued that at a minimum, the
above concerns would be reduced if Affected Utilities and their marketing
affiliates are required to operate as separate corporate entities, keeping
separate books and records. Enron indicated that market power concerns have been
heightened recently because of the Commission's approach to Stranded Cost which
does not require Affected Utilities to divest generation assets, thereby leaving
Affected Utilities with tremendous competitive advantage and market power. Enron
identified the potential absence of uniformity among the Affected Utilities'
Codes of Conduct as a problem resulting in the ESPs having to guess which types
of activities are allowed for each individual Affected Utility and its
affiliates. Commonwealth recommended that the Code of Conduct should preclude
any Affected Utility from offering competitive services through an affiliate
until a Code of Conduct has been approved by the Commission, after notice,
comment, and hearing. Tucson urged the Commission to promulgate Affiliate
Transaction rules with sufficient detail to assure the public that there is
adequate Commission oversight of these relationships. Commonwealth stated that
the Code of Conduct should not displace Affiliate Transaction rules or
guidelines. Commonwealth suggested that, if the Affiliate Transactions rule is
not reinserted back into the rules, an alternative seven pages of guidelines for
Affected Utilities and their competitive affiliates should be incorporated
within the Codes of Conduct of each Affected Utility.
TEP disagreed with the comments of AECC, Tucson and Commonwealth regarding
the re-adoption of the Affiliate Transaction rules, preferring the flexibility
of a Code of Conduct. TEP argued that contrary to Enron's assertion, the
requirements that Affected Utilities transfer their generation assets to a
separate affiliate and that Standard Offer Service generation be procured in the
open market, will make it impossible for the Affected Utility to favor its
generation affiliates to the detriment of other ESPs. Trico and AEPCO, Duncan
and Graham believed that each entity that would be subject to the Affiliate
Transaction rules is unique and the parties advocating their reinstatement have
not provided adequate reasons why an individually tailored Code of Conduct
subject to Commission review and approval is not a satisfactory solution. ATDUG
believed that Affected Utilities should not draft their own Code of Conduct
without, at a minimum, a guideline or standard.
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Staff responded that a Code of Conduct for Affected Utilities and their
affiliates is necessary in order to ensure the development of a robust
competitive market. Staff believed that, while it is not essential for all
Affected Utilities to have identical Codes of Conduct, it is desirable for each
Code of Conduct to address certain significant issues. Staff stated that in the
absence of some minimal degree of uniformity, parties will be uncertain as to
the rules governing the Arizona market, and enforcement of these issues will be
difficult. Staff therefore supported amending Section 1616 to require each
Affected Utility to address certain minimum standards in its Code of Conduct.
Staff recommended making the following changes to Section 1616:
No later than 90 days after adoption of these Rules, each Affected Utility
which plans to offer Noncompetitive Services and WHICH PLANS TO OFFER
Competitive Services through its competitive electric affiliate shall
propose a Code of Conduct to prevent anti-competitive activities. EACH
AFFECTED UTILITY THAT IS AN ELECTRIC COOPERATIVE, THAT PLANS TO OFFER
NONCOMPETITIVE SERVICES, AND THAT IS A MEMBER OF ANY ELECTRIC COOPERATIVE
THAT PLANS TO OFFER COMPETITIVE SERVICES SHALL ALSO SUBMIT A CODE OF
CONDUCT TO PREVENT ANTI-COMPETITIVE ACTIVITIES. ALL [The] Codes of Conduct
shall be subject to Commission approval.
THE CODE OF CONDUCT SHALL ADDRESS THE FOLLOWING SUBJECTS:
1. APPROPRIATE PROCEDURES TO PREVENT CROSS SUBSIDIZATION BETWEEN THE
UTILITY DISTRIBUTION COMPANY AND ANY COMPETITIVE AFFILIATES;
2. APPROPRIATE PROCEDURES TO ENSURE THAT THE UTILITY DISTRIBUTION
COMPANY'S COMPETITIVE AFFILIATE DOES NOT HAVE ACCESS TO CONFIDENTIAL
UTILITY INFORMATION THAT IS NOT ALSO AVAILABLE TO OTHER MARKET
PARTICIPANTS;
3. APPROPRIATE GUIDELINES TO LIMIT THE JOINT EMPLOYMENT OF PERSONNEL BY
BOTH A UTILITY DISTRIBUTION COMPANY AND ITS COMPETITIVE AFFILIATE;
4. APPROPRIATE GUIDELINES TO GOVERN THE USE OF THE UTILITY DISTRIBUTION
COMPANY'S NAME OR LOGO BY THE UTILITY DISTRIBUTION COMPANY'S
COMPETITIVE AFFILIATE;
5. APPROPRIATE PROCEDURES TO ENSURE THAT THE UTILITY DISTRIBUTION COMPANY
DOES NOT GIVE ITS COMPETITIVE AFFILIATE ANY UNREASONABLY PREFERENTIAL
TREATMENT SUCH THAT OTHER MARKET PARTICIPANTS ARE UNFAIRLY
DISADVANTAGED;
6. APPROPRIATE POLICIES TO ELIMINATE JOINT ADVERTISING, JOINT MARKETING,
OR JOINT SALES BY A UTILITY DISTRIBUTION COMPANY AND ITS COMPETITIVE
AFFILIATE;
7. APPROPRIATE PROCEDURES TO GOVERN TRANSACTIONS BETWEEN A UTILITY
DISTRIBUTION COMPANY AND ITS COMPETITIVE AFFILIATE; AND
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8. APPROPRIATE POLICIES TO PREVENT THE UTILITY DISTRIBUTION COMPANY AND
ITS COMPETITIVE AFFILIATE FROM REPRESENTING THAT CUSTOMERS WILL
RECEIVE BETTER SERVICE AS A RESULT OF THE AFFILIATION.
ANALYSIS: Nearly all parties providing comments on this issue suggest that
the entire Affiliate Transactions rule (formerly R14-2-1617) be reinserted back
into the proposed rules. Others suggested rewriting the current Code of Conduct,
R14-2-1616, to include specific appropriate Affiliate Transactions rules. We
believe that to promote competition it is critical to have a statewide standard
for the Codes of Conduct. We believe that Staff's recommended guideline for Code
of Conduct content is reasonable and will promote competition within the state
while at the same time providing flexibility for individual Affected Utilities.
RESOLUTION: Modify Section 1616 as recommended by Staff, adding
clarification that approval shall occur after a notice and a hearing. Staff's
recommended modification provides additional detail as to what is expected in a
Code of Conduct, but does not substantively change the affect of this section.
R14-2-1617 - DISCLOSURE OF INFORMATION
ISSUE: NWE and TEP proposed that this entire Section be deleted. APS
proposed that only Load-Serving ESPs, and not UDCs, should be required to
disclose information to consumers. Trico proposed that a new Section be added
stating that the UDC would not be required to furnish the same information as
provided by a Load-Serving Entity. AEPCO, Duncan and Graham believed that
mandating a "guess" about the characteristics of the resource portfolio will not
improve the value of data provided to the customer.
ACAA proposed that information about the resource mix be readily available
to residential consumers without any acquisition barriers. Tucson expressed
concern that this Section requires information about the resource portfolio to
be provided only upon request and stated that experience in other states has
shown that consumers "prefer a more environmentally sound mix of resources than
traditional suppliers have in their portfolios." Tucson believes that since the
information would have to be developed in case someone requested it, the only
rationale for not providing it automatically would be to hide the resource mix.
The LAW Fund pointed out that by not requiring disclosure about resources,
Arizona consumers will be not be informed about their choices and will be at a
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disadvantage in comparison to those in other western states. Commonwealth
asserts that it has found that many customers desire the option to purchase
generation from environmentally-compatible sources. Commonwealth supported the
disclosure requirements and urged that it be reinstated in the Rules. APS
believed that market forces would operate to provide consumers with information
concerning resource mix, and that mandatory disclosure adds unnecessary costs
Staff stated that consumers are entitled to receive information so that
they can make informed choices, and that research conducted in other states
indicates that consumers want information on generation resources. Staff argued
that all ESPs providing generation service and UDCs providing Standard Offer
Service should be required to disclose generation resource information as part
of the consumer information label, and not only upon request. Staff recommended
restoring Sections 1617(A)(4),(5) and (6), and deleting Section 1617(B). Staff
also recommended inserting "PROVIDING EITHER GENERATION SERVICE OR STANDARD
OFFER SERVICE" after "Load-Serving Entity" in Section 1617(A).
ANALYSIS: We agree with those entities who advocate for the disclosure of a
Load-Serving Entities' resource portfolio characteristics. However, we are also
concerned about the costs to Load-Serving Entities and question the need to
include this information, which may or may not be available, in all marketing
materials. There are going to be a significant number of customers who are
interested in this information. Because Load-Serving Entities will have to
prepare the information concerning the resource portfolio in anticipation of
customer requests, we do not believe that they will be able to hide the
information, and further, market forces will work to disseminate this
information.
RESOLUTION: Except to add Staff's clarifying language, we do not believe
that further modification is necessary. Insert "PROVIDING EITHER GENERATION
SERVICE OR STANDARD OFFER SERVICE" after Load-Serving Entity in Section 1617(A).
This modification is not substantive.
1617(G)
ISSUE: Commonwealth proposed that the word "written" be deleted from
Section 1617(G)(2) because it believes third-party orally verified customer
authorizations should suffice. Staff reiterated its belief that a customer's
service provider should not be changed without written consent from the
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customer because written authorization minimizes the possibility of being
switched to other service providers without customer consent, and therefore
recommended no change to this Section.
ANALYSIS: We concur with Staff.
RESOLUTION: No change is required.