VIII. Assignment of Proceeding
Michael R. Peevey is the Assigned Commissioner and Kim Malcolm is the assigned ALJ in this proceeding.
1. Allocating implementation costs to ratepayers that are related to the development of the CCA program's infrastructure would be fair, relatively simple to administer and avoid the barriers to entry that might occur if a handful of individual CCAs were required to assume those costs.
2. Transaction costs and implementation costs that are attributable to individual CCAs should be charged to those CCAs in tariffs according to the costs of time and materials.
3. The utilities' incremental costing methodologies for CCA transaction costs are reasonable to the extent the utilities do not recover transaction costs twice.
4. Utilities are currently recovering the costs of certain transaction services to CCAs. Permitting the utilities to charge CCAs for those services prior to a general rate case would permit the utilities to recover related costs twice, to the extent the utilities do not incur incremental costs for those services.
5. Tracking revenues from CCA transaction services in an account for "other revenues" would not eliminate the prospect of double recovery because such an account does not provide for refunds for past paid costs; such accounts are considered in general rate cases for forecasted costs and revenues.
6. Approving balancing accounts for implementation costs is reasonable prior to a general rate case to assure the utilities recover reasonable implementation costs.
7. Approving permanent balancing account treatment for implementation and transaction costs would undermine utility incentives for cost containment and is contrary to the Commission's regulatory treatment of customer and operational costs generally. Forward-looking charges will provide certainty for CCAs, provide the utilities a reasonable opportunity to recover their costs, and permit the utilities to take advantage of cost savings and associated opportunities for making a reasonable return on serving CCA customers.
8. The utilities did not propose final charges for CCA services in this phase of the proceeding.
9. Delaying the effectiveness of CCA tariffs until after the close of Phase 2 in this proceeding would unreasonably delay the implementation of the CCA program.
10. Direct access tariffs provide a reasonable proxy for interim CCA tariffs until the Commission has approved final CCA tariffs.
11. The utilities are likely to incur incremental billing costs when they serve CCAs.
12. If CCA fees for processing utility bills are not unbundled, CCAs may be liable for costs related to utility customer services, rather than those incurred for CCA customers.
13. The utilities did not demonstrate that CCA customers will make significantly more calls to the utility than they made as utility bundled customers. The extent to which the utilities must respond to additional calls would be established by directing CCA customers to a separate "800" number for questions about CCA services.
14. Developing the infrastructure for opt-out procedures is an implementation cost attributable to the CCA program generally. The costs of issuing opt-out notices and processing related customer requests is a cost that is attributable to individual CCAs.
15. Re-entry fees are those that reflect the administrative cost of transferring a CCA customer back to the utility as a bundled service customer.
16. The utilities' "Detailed Processes" outlines provide information about how they propose to implement various operations and services for CCAs. These outlines form a reasonable foundation for resolving Phase 1 issues except as provided herein.
17. The Commission has adopted a CRS for certain types of customers in other proceedings.
18. DWR's methodology for developing the CRS reasonably reflects the energy liabilities that should be charged to CCAs, and would appropriately exclude avoidable costs, reflect DWR and utility bond or contract refunds or credits, and apply to new as well as existing customers. No party opposes DWR's methodology for estimating related costs.
19. "Vintaging" as defined by the parties would track the costs that are attributable to an individual CCA's customers depending on the timing of the CCA initiating operations, and reflects the changing liabilities of the utilities and DWR. As envisioned, it may also create substantial regulatory burdens for the parties and the Commission.
20. AB 117 provides that the CRS should include all costs that the utilities reasonably incurred on behalf of ratepayers, which may include costs incurred after the passage of AB 117 but should not include any costs that were "avoidable" or those that are not attributable to the CCA's customers.
21. Unbundling the components of the CRS may provide customers and CCAs with valuable information about the costs of their services.
22. Permitting CCAs to take delivery of power related to CRS liabilities may reduce California consumers' energy bills and promote the interests of the state and its economy. Whether and how power from some utility or DWR energy purchase contracts may be allocated to CCAs is unclear on the basis of the existing record.
23. An "open season," as SDG&E describes it, would help the utilities and CCAs plan for CCA operations in a way that may permit more efficient and effective resource planning.
24. The demand forecasts relied upon by DWR for purchasing power during the energy crisis assumed the installation of distributed generation in California.
25. The exemption from the CRS for baseline usage required by Water Code Section 80110 creates a revenue shortfall that must be recovered from the CCAs or their customers.
26. SCE's proposal to allocate the revenue shortfall from the baseline subsidy to all customers' distribution rates is administratively simple and avoids the customer confusion of an additional nonbypassable surcharge. However, this issue is more appropriately resolved in a ratemaking proceeding such as a general rate case or rate design window.
27. SCE's demand forecasts provided to DWR, and upon which DWR relied in purchasing long-term power, assumed load reductions at Norton Air Force Base in anticipation of the base's closing.
28. The utilities would overcollect or undercollect CCA CRS costs if they were not permitted to true-up in some fashion the difference between the forecasted CCA CRS rate and the actual CCA CRS liabilities, which can only be precisely specified after the fact. Similarly, a cost cap may permit a circumstance whereby the utilities might not be able to recover all CCA CRS costs, as mandated by AB 117.
29. Requiring utility bundled customers to assume liability for the CCA CRS forecast being equal to or more than actual CCA CRS liabilities would represent cost-shifting between utility bundled customers and CCA customers.
30. The Commission has always intended to set cost recovery for CCA services and the CCA CRS in Phase 1 of this proceeding.
31. Delaying the implementation of CCA costs until after the resolution of Phase 2 of this proceeding could delay implementation of the CCA program until almost three years after passage of AB 117.
32. The record in this proceeding does not permit the Commission to approve final rates and cost recovery amounts for CCA services that would be the subject of tariffs.
33. The utilities' tariffs that govern services to direct access customers address services and operations that are substantially similar to those needed by CCAs. They are reasonable proxies for the costs the utilities would incur in serving CCAs while the Commission reviews proposals for final CCA rates and tariffs.
34. DWR's model suggests that minor changes in market conditions could cause substantial variations in the CRS. For that reason, developing more precise specifications for the DWR model may not necessarily significantly improve the reliability of the CRS.
35. The record in this proceeding provides enough information about likely CCA CRS liabilities to set an interim CCA CRS in the amount of $.020/kWh, subject to true-up.
36. Permanent balancing accounts may undermine incentives for economizing.
37. Utility forecasts of the costs of CCA program implementation and transactions in general rate cases would promote certainty and cost management.
38. CCAs would "investigate or pursue" CCA programs prior to offering service and a CCA would need relevant customer and load data in order to conduct a meaningful investigation of CCA programs.
39. A CCA cannot notify customers of its intent to offer electrical service if it does not have access to relevant customer information.
40. In the CCA's effort to satisfy customer notice requirements, tax rolls are not a reasonable substitute for customer information held by utilities partly because property owners would not necessarily be a utility customer of record.
41. Nondisclosure agreements would provide reasonable protections against the disclosure by a CCA of a utility's customer information.
42. CCAs may need specific customer information in order to market energy services and tailor those services to individual customers or groups of customers.
43. CCAs need load data in order to develop cost-effective and reliable energy procurement strategies.
44. Customers would benefit from notification that contact information and usage data may be shared with the CCA and may not be disclosed to others.
45. A CCA phase-in or pilot program may facilitate the transfer of energy services from the utility to the CCA but may be costly.
46. Applying CCA-specific load profiles to ISO charges could increase liabilities to other customers.
47. Although developing CCA-specific load profiles may be costly, there may be simple ways to estimate them.
48. Boundary metering would help CCAs develop area load profiles.
49. Requiring a CCA to participate in an open season immediately would unreasonably delay initiation of service by CCAs because the Commission will not adopt guidelines for open seasons until Phase II of this proceeding.
1. AB 117 provides the Commission discretion to determine which implementation costs should be allocated to individual CCAs and which of those costs should be allocated to ratepayers generally.
2. AB 117 defines transaction costs as those relating to metering, billing, and other customer services that are attributable to a single CCA.
3. Each utility should be permitted to establish balancing accounts for implementation costs incurred prior to the implementation of its next general rate case. Those balancing accounts should be eliminated once the Commission has authorized a related revenue requirement in that general rate case.
4. The utilities should be ordered to charge CCAs for transaction costs in tariffs that include charges based on incremental costs. The utilities should not be permitted to establish balancing accounts for CCA transaction costs that are recoverable in tariffs.
5. The utilities should not be permitted to "true-up" transaction costs included in tariffs but should be permitted to forecast those costs in general rate cases.
6. The utilities should be ordered to apply direct access tariffs for CCA transactions until the Commission has approved final CCA tariffs in this proceeding.
7. The utilities should be ordered to propose final tariffs for recovery of transactions costs from ratepayers within 60 days of the effective date of this order for consideration in Phase 2 of this proceeding.
8. CCA tariffs should unbundle elements of the billing and call center services tariffs so that CCAs are not charged for billing processes and customers services that are unrelated to CCA services and CCA customer billings.
9. AB 117 requires CCAs to pay for "opt-out" notifications mailed by the utilities to customers. The utilities should charge for these services in the CCA tariffs.
10. The costs of developing the initial "opt-out" procedures and infrastructure should be assumed by all ratepayers as an implementation cost.
11. The utilities should be authorized to charge customers a re-entry fee after those customers have transferred from the CCA to the utility as a bundled customer. That fee should reflect the administrative cost of transferring back to the utility.
12. The utilities should establish a CRS, consistent with this order and DWR's model, to allow the utilities to recover costs of power purchase commitments that become stranded as a result of the CCA initiating service. Such costs include DWR bond and power purchase contracts, utility power purchase commitments and balances in power purchase accounts but should not include costs that may have been avoidable or are not otherwise attributable to the CCA's customers. The CRS as described herein should be net of any existing "nonbypassable" surcharges for past liabilities that are included on all customer bills.
13. The utilities should be ordered to provide information about the components of the CRS and to provide a tariffed service to CCAs that would unbundle the components of the CRS on customer bills.
14. The Commission should consider in Phase II whether there may be opportunities for the utilities to allocate power to CCAs from DWR where a CCA requests.
15. Utilities should not be required to assume the risks of CCA forecasting errors or non-performance, and should propose tariff fees that reflect the cost of forecasting errors or non-performance attributable to the CCA.
16. Whether the utilities should be required to act as provider of last resort where CCA power supplies are inadequate is a matter for resolution in R.04-04-003.
17. AB 117 requires that retail end-use customers of CCAs to pay for the CRS.
18. The utilities should charge CCA customers directly for the CRS.
19. The utilities should propose ways to allocate the revenue shortfall from the baseline subsidy in appropriate ratemaking proceedings.
20. In the event customers of Norton Air Force Base are served energy by a CCA, SCE should exempt Norton Air Force Base from the CRS in amounts equal to the reductions it included in its forecasts to DWR and upon which DWR relied for long-term power purchases.
21. AB 117 does not permit cost-shifting of CCA CRS liabilities between utility bundled customers and CCA customers.
22. When read in conjunction with other provisions of AB 117, the requirement in Section 366.2(c)(7) that the Commission "inform" the CCA of its CRS liabilities is not a requirement that the CRS be capped or that utilities or utility bundled customers assume the risk for undercollections of CRS cost liabilities.
23. The utilities should establish balancing accounts for CRS costs and revenues and reconcile actual costs and revenues in the proceedings addressing the CRS for direct access customers, unless the Commission directs review of these costs and revenues in a different proceeding.
24. The utilities should not be required to assume the risk for CRS forecasts where CRS liabilities were reasonably incurred.
25. In the interim, the utilities should be ordered to apply the rates and cost recovery provisions of direct access tariffs to CCAs that begin operations prior to the Commission's approval of final CCA tariffs.
26. The utilities should file tariffs that implement an interim CRS of $.020/kWh, subject to true-up in 18 months or when the final CRS forecast is 30% higher or lower than this amount. This CRS would not include costs already recovered by way of nonbypassable surcharges on existing utility bills for such liabilities as historic utility power liabilities or bond costs.
27. The utilities should be permitted to establish balancing accounts to track the costs of developing the infrastructure needed to implement the CCA program, and should allocate those costs to all ratepayers, as set forth herein. These balancing accounts should be eliminated following each utility's subsequent general rate case.
28. The utilities should be required to provide forecasts of CCA implementation costs in their general rate cases for recovery from all ratepayers.
29. The utilities should develop tariffs for transactions services to CCAs that include charges based on the incremental costs of each service but the utilities should not charge CCAs for services for which the utilities already recover costs in their revenue requirements, consistent with this order. The utilities should modify their CCA tariffs in general rate cases, consistent with the regulatory convention for adjustments to revenue requirements for other customers. In their general rate cases, the utilities may propose charges to CCA for transactions services that are currently included in utility revenue requirements and in such cases should propose offsetting reductions to other rates.
30. Section 366.2(c)(9) requires the utilities to provide all relevant information required by CCAs to "investigate, pursue or implement" meaningful programs. This requirement does not permit the utilities to deny CCAs access to relevant customer or load information.
31. Section 366.2(c)(13)(A) requires CCAs to provide customer notice of their intent to provide service, a requirement a CCA cannot satisfy without relevant customer information. Read in conjunction with Section 366.2(c)(9), this requirement presumes that the CCA will have access to certain customer information held by the utility.
32. Section 366.2(c)(9) requires the provision of detailed billing and load data to CCAs that are investigating, pursuing or implementing CCA programs.
33. The utilities should require CCAs to sign nondisclosure agreements when they share confidential information about customers or electricity load and should require a county or city's chief administrative officer to attest that it is "investigating" or "pursuing" status as a CCA as a precondition to receiving confidential customer information.
34. Notices to prospective CCA customers should inform customers that the utility may share customer information with the CCA and that the information may not be used for any purpose other than to facilitate the provision of energy services to the customer by the CCA.
35. Utility tariffs should provide that the CCA must indemnify utilities from liability for the disclosure of confidential customer information in cases where the utility has take all reasonable precautions to prevent that disclosure.
36. AB 117 does not prohibit a phase-in or pilot program by the CCA.
37. Utility tariffs should offer a phase-in of a CCA program at cost.
38. The Commission will not determine which customers CCA should serve.
39. Utility tariffs should offer to develop an estimation of a CCA's load profile at cost, consistent with the proposal by SDG&E to adjust the system average load profile by use and climate.
40. Section 366.2(c)(18) requires the utilities to offer boundary metering. Utility tariffs should include an option for boundary metering to be provided at cost.
41. CCAs may initiate service prior to the Commission's adoption of open season guidelines.
IT IS ORDERED that:
1. Pacific Gas and Electric Company (PG&E), San Diego Gas & Electric Company (SDG&E), and Southern California Edison Company (SCE) shall create balancing accounts for implementation costs incurred prior to cost recovery changes authorized in their respective general rate cases. The utilities shall not enter costs into those accounts after those changes to the revenue requirement in the general rate cases becomes effective.
2. PG&E, SDG&E, and SCE shall, within 60 days of the effective date of this decision, file tariffs that are substantively identical to those in effect for direct access customers and which shall apply in the interim to Community Choice Aggregators (CCAs) prior to the Commission's approval of final CCA tariffs.
3. PG&E, SDG&E, and SCE shall, no later than 60 days after the effective date of this order, serve tariffs on all parties to this proceeding regarding costs and terms of services for CCAs. Cost recovery proposed in those tariffs shall be based on incremental costs but the tariffs shall not include charges for services for which the utilities already receive remuneration in existing revenue requirements, consistent with this order. These draft tariffs will be considered in Phase 2 of this proceeding.
4. PG&E, SDG&E, and SCE shall, in their respective general rate cases, propose (1) a revenue requirement for CCA implementation costs and (2) changes to CCA tariffs for transactions including metering, billing, customer services and other services, which shall be authorized in the general rate case and remain in effect until a subsequent general rate case order, consistent with this order.
5. PG&E, SDG&E, and SCE's proposed tariffs shall include (1) unbundled elements for billing and call center services tariffs in ways that assure CCAs are not charged for billing processes or customer services that are unrelated to CCA services and CCA customer billings; (2) an optional service to produce and mail opt-out notices to customers at cost; (3) a re-entry fee for customers who transfer from the CCA to the utility and which reflects the administrative cost of transferring the customer; (4) an interim cost recovery surcharge (CRS) set at $.020/kilowatt hour (kWh) and applying the terms and conditions set forth in this order, and which is subject to modification within the subsequent 18 months only if and when the CRS forecast is at least 30% lower than or higher than $.020/kWh; (5) an option to unbundle components of the CRS on customer bills, at cost; (6) provisions that would protect the utilities from assuming the risk of CCA forecasting errors or nonperformance at cost; (7) a service to provide back-up energy supplies and balancing services at cost; (8) a provision to charge CCA customers directly for CRS liabilities; (10) the establishment of a balancing account for CRS costs and revenues that shall be subject to reconciliation in Commission proceedings reviewing the Department of Water Resources (DWR) revenue requirement or other proceeding, as the Commission may direct; (12) the offer to provide access to all relevant customer information, billing information, usage and load information, consistent with this order and which shall be provided to the CCA at cost except that those information services already approved in D.03-07-034 shall be provided at no cost to the CCA; (13) a requirement that all confidential utility information shall be provided subject to nondisclosure agreement and a requirement that the chief administrative officer of a city or county attest that the city or county is investigating or pursuing status as a CCA as a precondition of receiving confidential customer information; (14) a requirement that customer notifications about prospective CCA operations inform the customer that customer information may be provided to the CCA subject to nondisclosure for any purpose other than those related to facilitating the CCA's services; (15) a provision for CCAs to indemnify the utilities from liabilities associated with the CCA's disclosure of confidential customer information where the utility has taken all reasonable steps to prevent such disclosure; (16) an option to phase-in a CCA's program at the incremental cost of that option; and (17) an option to have the utility install meters at CCA boundaries, at cost.
6. In the event that the residents and businesses of Norton Air Force Base are served by a CCA for their energy requirements, SCE's proposed tariffs shall provide an exclusion from the CRS for Norton Air Force Base in amounts equal to the reduction it included in its forecasts to DWR and upon which DWR relied for long-term power purchases, consistent with this order.
7. PG&E, SCE, and SDG&E shall for Phase II of this proceeding develop a forecast for the CRS in their respective territories, consistent with this order, and serve a notice of availability of the forecast and work papers on all parties to this proceeding. Each cost component of the CRS shall be calculated and identified separately. Elements of the work papers that are confidential shall be provided subject to a standard nondisclosure agreement.
8. This proceeding remains open for the Commission's consideration in Phase 2 of final cost allocation and terms of services to CCAs and related issues as set forth herein.
9. In all respects, utility tariffs and practices shall permit CCAs to initiate service immediately following the filing of tariffs described in Ordering Paragraph 2.
10. This order is effective today.
Dated December 16, 2004, at San Francisco, California.
MICHAEL R. PEEVEY
President
CARL W. WOOD
LORETTA M. LYNCH
GEOFFREY F. BROWN
SUSAN P. KENNEDY
Commissioners
APPENDIX A
LIST OF APPEARANCES
************ APPEARANCES ************ |
Scott Blaising |
Matthew Gorman |
Dian M. Grueneich |
Randall W. Keen |
Gene Ferris |
Craig M. Buchsbaum |
Daniel W. Meek |
Richard Esteves |
Mike Florio |
Jennifer Tachera |
Diana L. Lee |
Andrew Ulmer |
|
|
(END OF APPENDIX A) | |
APPENDIX B
ASSEMBLY BILL 117
AB 117
Public Utilities Code
366.2. (a) (1) Customers shall be entitled to aggregate their
electric loads as members of their local community with community
choice aggregators.
(2) Customers may aggregate their loads through a public process
with community choice aggregators, if each customer is given an
opportunity to opt out of their community's aggregation program.
(3) If a customer opts out of a community choice aggregator's
program, or has no community choice program available, that customer
shall have the right to continue to be served by the existing
electrical corporation or its successor in interest.
(b) If a public agency seeks to serve as a community choice
aggregator, it shall offer the opportunity to purchase electricity to
all residential customers within its jurisdiction.
(c) (1) Notwithstanding Section 366, a community choice aggregator
is hereby authorized to aggregate the electrical load of interested
electricity consumers within its boundaries to reduce transaction
costs to consumers, provide consumer protections, and leverage the
negotiation of contracts. However, the community choice aggregator
may not aggregate electrical load if that load is served by a local
publicly owned electric utility, as defined in subdivision (d) of
Section 9604. A community choice aggregator may group retail
electricity customers to solicit bids, broker, and contract for
electricity and energy services for those customers. The community
choice aggregator may enter into agreements for services to
facilitate the sale and purchase of electricity and other related
services. Those service agreements may be entered into by a single
city or county, a city and county, or by a group of cities, cities
and counties, or counties.
(2) Under community choice aggregation, customer participation may
not require a positive written declaration, but all customers shall
be informed of their right to opt out of the community choice
aggregation program. If no negative declaration is made by a
customer, that customer shall be served through the community choice
aggregation program.
(3) A community choice aggregator establishing electrical load
aggregation pursuant to this section shall develop an implementation
plan detailing the process and consequences of aggregation. The
implementation plan, and any subsequent changes to it, shall be
considered and adopted at a duly noticed public hearing. The
implementation plan shall contain all of the following:
(A) An organizational structure of the program, its operations,
and its funding.
(B) Ratesetting and other costs to participants.
(C) Provisions for disclosure and due process in setting rates and
allocating costs among participants.
(D) The methods for entering and terminating agreements with other
entities.
(E) The rights and responsibilities of program participants,
including, but not limited to, consumer protection procedures, credit
issues, and shutoff procedures.
(F) Termination of the program.
(G) A description of the third parties that will be supplying
electricity under the program, including, but not limited to,
information about financial, technical, and operational capabilities.
(4) A community choice aggregator establishing electrical load
aggregation shall prepare a statement of intent with the
implementation plan. Any community choice load aggregation
established pursuant to this section shall provide for the following:
(A) Universal access.
(B) Reliability.
(C) Equitable treatment of all classes of customers.
(D) Any requirements established by state law or by the commission
concerning aggregated service.
(5) In order to determine the cost-recovery mechanism to be
imposed on the community choice aggregator pursuant to subdivisions
(d), (e), and (f) that shall be paid by the customers of the
community choice aggregator to prevent shifting of costs, the
community choice aggregator shall file the implementation plan with
the commission, and any other information requested by the commission
that the commission determines is necessary to develop the
cost-recovery mechanism in subdivisions (d), (e), and (f).
(6) The commission shall notify any electrical corporation serving
the customers proposed for aggregation that an implementation plan
initiating community choice aggregation has been filed, within 10
days of the filing.
(7) Within 90 days after the community choice aggregator
establishing load aggregation files its implementation plan, the
commission shall certify that it has received the implementation
plan, including any additional information necessary to determine a
cost-recovery mechanism. After certification of receipt of the
implementation plan and any additional information requested, the
commission shall then provide the community choice aggregator with
its findings regarding any cost recovery that must be paid by
customers of the community choice aggregator to prevent a shifting of
costs as provided for in subdivisions (d), (e), and (f).
(8) No entity proposing community choice aggregation shall act to
furnish electricity to electricity consumers within its boundaries
until the commission determines the cost-recovery that must be paid
by the customers of that proposed community choice aggregation
program, as provided for in subdivisions (d), (e), and (f). The
commission shall designate the earliest possible effective date for
implementation of a community choice aggregation program, taking into
consideration the impact on any annual procurement plan of the
electrical corporation that has been approved by the commission.
(9) All electrical corporations shall cooperate fully with any
community choice aggregators that investigate, pursue, or implement
community choice aggregation programs. Cooperation shall include
providing the entities with appropriate billing and electrical load
data, including, but not limited to, data detailing electricity needs
and patterns of usage, as determined by the commission, and in
accordance with procedures established by the commission. Electrical
corporations shall continue to provide all metering, billing,
collection, and customer service to retail customers that participate
in community choice aggregation programs. Bills sent by the
electrical corporation to retail customers shall identify the
community choice aggregator as providing the electrical energy
component of the bill. The commission shall determine the terms and
conditions under which the electrical corporation provides services
to community choice aggregators and retail customers.
(10) (A) A city, county, or city and county that elects to
implement a community choice aggregation program within its
jurisdiction pursuant to this chapter shall do so by ordinance.
(B) Two or more cities, counties, or cities and counties may
participate as a group in a community choice aggregation pursuant to
this chapter, through a joint powers agency established pursuant to
Chapter 5 (commencing with Section 6500) of Division 7 of Title 1 of
the Government Code, if each entity adopts an ordinance pursuant to
subparagraph (A).
(11) Following adoption of aggregation through the ordinance
described in paragraph (10), the program shall allow any retail
customer to opt out and to continue to be served as a bundled service
customer by the existing electrical corporation, or its successor in
interest. Delivery services shall be provided at the same rates,
terms, and conditions, as approved by the commission, for community
choice aggregation customers and customers that have entered into a
direct transaction where applicable, as determined by the commission.
Once enrolled in the aggregated entity, any ratepayer that chooses
to opt out within 60 days or two billing cycles of the date of
enrollment may do so without penalty and shall be entitled to receive
default service pursuant to paragraph (3) of subdivision (a).
Customers that return to the electrical corporation for procurement
services shall be subject to the same terms and conditions as are
applicable to other returning direct access customers from the same
class, as determined by the commission, as authorized by the
commission pursuant to this code or any other provision of law. Any
reentry fees to be imposed after the opt-out period specified in this
paragraph, shall be approved by the commission and shall reflect the
cost of reentry. The commission shall exclude any amounts
previously determined and paid pursuant to subdivisions (d), (e), and
(f) from the cost of reentry.
(12) Nothing in this section shall be construed as authorizing any
city or any community choice retail load aggregator to restrict the
ability of retail electricity customers to obtain or receive service
from any authorized electric service provider in a manner consistent
with law.
(13) (A) The community choice aggregator shall fully inform
participating customers at least twice within two calendar months, or
60 days, in advance of the date of commencing automatic enrollment.
Notifications may occur concurrently with billing cycles. Following
enrollment, the aggregated entity shall fully inform participating
customers for not less than two consecutive billing cycles.
Notification may include, but is not limited to, direct mailings to
customers, or inserts in water, sewer, or other utility bills. Any
notification shall inform customers of both of the following:
(i) That they are to be automatically enrolled and that the
customer has the right to opt out of the community choice aggregator
without penalty.
(ii) The terms and conditions of the services offered.
(B) The community choice aggregator may request the commission to
approve and order the electrical corporation to provide the
notification required in subparagraph (A). If the commission orders
the electrical corporation to send one or more of the notifications
required pursuant to subparagraph (A) in the electrical corporation's
normally scheduled monthly billing process, the electrical
corporation shall be entitled to recover from the community choice
aggregator all reasonable incremental costs it incurs related to the
notification or notifications. The electrical corporation shall
fully cooperate with the community choice aggregator in determining
the feasibility and costs associated with using the electrical
corporation's normally scheduled monthly billing process to provide
one or more of the notifications required pursuant to subparagraph
(A).
(C) Each notification shall also include a mechanism by which a
ratepayer may opt out of community choice aggregated service. The
opt out may take the form of a self-addressed return postcard
indicating the customer's election to remain with, or return to,
electrical energy service provided by the electrical corporation, or
another straightforward means by which the customer may elect to
derive electrical energy service through the electrical corporation
providing service in the area.
(14) The community choice aggregator shall register with the
commission, which may require additional information to ensure
compliance with basic consumer protection rules and other procedural
matters.
(15) Once the community choice aggregator's contract is signed,
the community choice aggregator shall notify the applicable
electrical corporation that community choice service will commence
within 30 days.
(16) Once notified of a community choice aggregator program, the
electrical corporation shall transfer all applicable accounts to the
new supplier within a 30-day period from the date of the close of
their normally scheduled monthly metering and billing process.
(17) An electrical corporation shall recover from the community
choice aggregator any costs reasonably attributable to the community
choice aggregator, as determined by the commission, of implementing
this section, including, but not limited to, all business and
information system changes, except for transaction-based costs as
described in this paragraph. Any costs not reasonably attributable
to a community choice aggregator shall be recovered from ratepayers,
as determined by the commission. All reasonable transaction-based
costs of notices, billing, metering, collections, and customer
communications or other services provided to an aggregator or its
customers shall be recovered from the aggregator or its customers on
terms and at rates to be approved by the commission.
(18) At the request and expense of any community choice
aggregator, electrical corporations shall install, maintain and
calibrate metering devices at mutually agreeable locations within or
adjacent to the community aggregator's political boundaries. The
electrical corporation shall read the metering devices and provide
the data collected to the community aggregator at the aggregator's
expense. To the extent that the community aggregator requests a
metering location that would require alteration or modification of a
circuit, the electrical corporation shall only be required to alter
or modify a circuit if such alteration or modification does not
compromise the safety, reliability or operational flexibility of the
electrical corporation's facilities. All costs incurred to modify
circuits pursuant to this paragraph, shall be born by the community
aggregator.
(d) (1) It is the intent of the Legislature that each retail
end-use customer that has purchased power from an electrical
corporation on or after February 1, 2001, should bear a fair share of
the Department of Water Resources' electricity purchase costs, as
well as electricity purchase contract obligations incurred as of the
effective date of the act adding this section, that are recoverable
from electrical corporation customers in commission-approved rates.
It is further the intent of the Legislature to prevent any shifting
of recoverable costs between customers.
(2) The Legislature finds and declares that this subdivision is
consistent with the requirements of Division 27 (commencing with
Section 80000) of the Water Code and Section 360.5, and is therefore
declaratory of existing law.
(e) A retail end-use customer that purchases electricity from a
community choice aggregator pursuant to this section shall pay both
of the following:
(1) A charge equivalent to the charges that would otherwise be
imposed on the customer by the commission to recover bond related
costs pursuant to any agreement between the commission and the
Department of Water Resources pursuant to Section 80110 of the Water
Code, which charge shall be payable until any obligations of the
Department of Water Resources pursuant to Division 27 (commencing
with Section 80000) of the Water Code are fully paid or otherwise
discharged.
(2) Any additional costs of the Department of Water Resources,
equal to the customer's proportionate share of the Department of
Water Resources' estimated net unavoidable electricity purchase
contract costs as determined by the commission, for the period
commencing with the customer's purchases of electricity from the
community choice aggregator, through the expiration of all then
existing electricity purchase contracts entered into by the
Department of Water Resources.
(f) A retail end-use customer purchasing electricity from a
community choice aggregator pursuant to this section shall reimburse
the electrical corporation that previously served the customer for
all of the following:
(1) The electrical corporation's unrecovered past undercollections
for electricity purchases, including any financing costs,
attributable to that customer, that the commission lawfully
determines may be recovered in rates.
(2) Any additional costs of the electrical corporation recoverable
in commission-approved rates, equal to the share of the electrical
corporation's estimated net unavoidable electricity purchase contract
costs attributable to the customer, as determined by the commission,
for the period commencing with the customer's purchases of
electricity from the community choice aggregator, through the
expiration of all then existing electricity purchase contracts
entered into by the electrical corporation.
(g) (1) Any charges imposed pursuant to subdivision (e) shall be
the property of the Department of Water Resources. Any charges
imposed pursuant to subdivision (f) shall be the property of the
electrical corporation. The commission shall establish mechanisms,
including agreements with, or orders with respect to, electrical
corporations necessary to ensure that charges payable pursuant to
this section shall be promptly remitted to the party entitled to
payment.
(2) Charges imposed pursuant to subdivisions (d), (e), and (f)
shall be nonbypassable.
(h) Notwithstanding Section 80110 of the Water Code, the
commission shall authorize community choice aggregation only if the
commission imposes a cost-recovery mechanism pursuant to subdivisions
(d), (e), (f), and (g). Except as provided by this subdivision,
this section shall not alter the suspension by the commission of
direct purchases of electricity from alternate providers other than
by community choice aggregators, pursuant to Section 80110 of the
Water Code.
(i) (1) The commission shall not authorize community choice
aggregation until it implements a cost-recovery mechanism, consistent
with subdivisions (d), (e), and (f), that is applicable to customers
that elected to purchase electricity from an alternate provider
between February 1, 2001, and January 1, 2003.
(2) The commission shall not authorize community choice
aggregation until it submits a report certifying compliance with
paragraph (1) to the Senate Energy, Utilities and Communications
Committee, or its successor, and the Assembly Committee on Utilities
and Commerce, or its successor.
(3) The commission shall not authorize community choice
aggregation until it has adopted rules for implementing community
choice aggregation.
(j) The commission shall prepare and submit to the Legislature, on
or before January 1, 2006, a report regarding the number of
community choices aggregations, the number of customers served by
community choice aggregations, third party suppliers to community
choice aggregations, compliance with this section, and the overall
effectiveness of community choice aggregation programs.
(END OF APPENDIX B)
