10. Comments on Proposed Decision

The proposed decision of ALJ Pulsifer in this matter was mailed to the parties in accordance with Section 311 of the Public Utilities Code and comments were allowed under Rule 14.3 of the Commission's Rules of Practice and Procedure. Comments were filed on March 1, 2010, and reply comments were filed on March 8, 2010. The proposed decision was also mailed to the service lists of R.08-01-025 and R.09-10-032 so that all affected LSEs could comment on the proposed decision. We have incorporated parties' comments, as appropriate, in finalizing this decision.

Findings of Fact

1. On October 11, 2009, SB 695 was signed into law as an urgency statute, adding Section 365.1 (b) to the Public Utilities Code.

2. Public Utilities Code Section 365.1(b) requires the Commission to allow individual retail nonresidential end-use customers to acquire electric service from other providers in each electrical corporation's distribution service territory, up to a maximum allowable total annual limit.

3. The amounts of DA load as set forth in Appendix 1 of this decision constitute the incremental amount of transactions that are allowed in conformance with implementation of Public Utilities Code Section 365.1(b).

4. The statute allows for a phase-in period for new DA of not less than three years and not more than five years, subject to Commission determination.

5. A four-year phase-in period with annual caps as set forth in Appendix 2 will reasonably accommodate the utilities' long-term procurement and resource planning needs, while providing for timely implementation of new DA load consistent with the provisions of SB 695.

6. Under current rules, former DA customers receiving bundled utility service must provide six-months' notice in order to leave bundled utility service. The six-month notice requirement applies for customers that switch back to DA. A DA customer who returns to bundled service must commit to stay for at least a three-year period.

7. Under current rules, any customer with a peak load that is greater than 50 kW is required to install an approved interval meter. Interval meters allow customers better access and control to their load consumption, and are a step toward a smarter, more efficient electric grid.

8. Rule 22 requires that service accounts with demands greater than 50 kW have interval meters prior to being placed on DA service.

9. SB 695 requires that other providers of electricity in California are to be subject to the same procurement-related requirements that apply to the IOUs, including resource adequacy requirements, renewable portfolio standards, and greenhouse gas emission reductions.

10. The interim measures set forth in Appendix 3 for the treatment of Local RA obligations during the enrollment period for new DA will provide a reasonable way to satisfy an LSE's RA obligations in connection with customer migration pursuant to SB 695, subject to any further disposition in R.09-10-032.

11. The enrollment procedures for new Direct Access Load as set forth in Appendix 2 of this decision provides for an orderly process that will be manageable by the utilities while providing for timely processing of new enrollments.

12. The Proposed Decision (PD) was served on parties in R.08-01-025 and R.09-10-032 so that all affected Load Serving Entities could comment on the PD.

Conclusions of Law

1. The Commission is required by the provisions of Public Utilities Code Section 365.1(b) to allow individual retail non-residential end-use customers to acquire electric service from other providers in each electrical corporation's distribution service territory, up to a maximum allowable total annual limit.

2. The authorizations for increased DA transactions, as set forth below in the ordering paragraphs of this decision, reasonably satisfy the requirements of Section 365.1(b) for increased limits in DA transactions.

3. The investor-owned utilities should proceed with implementation of the processing of new DA service requests in accordance with the revised limits adopted below.

4. A temporary one-time waiver of the current three-year minimum bundled service commitment for customers now on BPS customers should be granted covering the initial open enrollment period, starting on the effective date of this decision and extending through June 30, 2010.

5. Any commercial/industrial customers whose peak load is between 50 kW and 200 kW should have the choice of whether to install an interval meter.

6. The procedures for enrollment of new DA load pursuant to SB 695, as set forth in Appendix 2 of this decision, are reasonable and should be adopted.

7. The procedures for the treatment of Local Resource Adequacy Obligations pursuant to SB 695, as set forth in Appendix 3 of this decision are reasonable and should be adopted.

8. The next phase of this proceeding should expeditiously address the remaining issues to be resolved relating to the phase-in of additional limits on direct access transactions.

9. The provisions for new enrollments of DA customers under SB 695 should be based upon a first-come, first-served principle, without special set-asides for DA-eligible customers who have exercised the right to take DA previously.

10. In order to establish an orderly process for enrolling new DA customers pursuant to SB 695, a Notice of Intent (NOI) to subscribe to DA should be submitted by customers. The NOI should be subject to utility review and notification of space availability to the customer and the ESP in accordance with the procedures set forth in Appendix 2 of this decision.

11. SB 695 contains no language granting any preference or special rights to DA-eligible customers who have exercised the right to take DA previously, and there is no basis for the Commission to impose special preferential treatment for such DA-eligible customers in implementing SB 695.

12. For purposes of determining if the authorized cap has been reached in relation to the total requests for new DA service, a daily NOI batching process, as proposed by the Joint Parties, provides for a more streamlined implementation.

13. The right to acquire new DA pursuant to SB 695 excludes residential customers who are not already taking DA service o otherwise eligible per D.05-03-034.

ORDER

IT IS ORDERED that:

1. Revised limits are hereby adopted in the cap on direct access transactions within the service territories of each of California's three major investor-owned utilities, Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company, as set forth in Appendix 1 of this decision. The authorized increases in direct access transactions shall be incorporated into the utilities' tariffs pursuant to Ordering Paragraph 8. Adjustments to each utility's baseline amount of direct access load as set forth in Appendix 1 shall be based on the same method used by the utilities to calculate direct access load in their Direct Access Implementation Activities Reports submitted to the Commission on a monthly basis. The Energy Division is authorized to post each utility's monthly baseline amount of direct access load, as reported in their Direct Access Implementation Activities Reports, on the Commission's public website.

2. The increased limits on direct access transactions set forth in Appendix 1 hereof shall be phased in over a four-year period beginning on the effective date of April 11, 2010, in accordance with the enrollment procedures set forth in Appendix 2.

3. A one-time waiver of the current three-year minimum bundled service commitment for customers now on bundled portfolio service is hereby granted for any bundled portfolio service commitments in existence as of April 11, 2010, the direct access reopening effective date. This one-time waiver will effectively eliminate those bundled portfolio service commitments in existence on the Effective Date of the direct access reopening, even if those customers do not elect to take direct access service during the Open Enrollment Window, to allow these customers to elect Direct Access service at any time with the required 6-month advance notice, assuming there is room under the annual limits or overall cap. The three-year bundled portfolio service commitment period will continue to apply anytime a Direct Access customer returns to bundled portfolio service after the Effective Date of the direct access reopening.

4. The increased authorizations in the level of direct access transactions as set forth in Appendix 1 of this decision shall take effect beginning April 11, 2010, and continue for four calendar years, with annual limits as set forth in Appendix 2.

5. The procedures for enrollment of new direct access load pursuant to SB 695, as set forth in Appendix 2 of this decision, are hereby adopted. The IOUs shall file advice letters within 20 days of the issuance of this decision proposing modifications to their direct access tariffs in compliance with this decision. The advice filings shall be effective upon filing, and any modifications subsequently requested by the Energy Division based on its review of the advice filings shall not alter their effectiveness as of their filing dates. The advice letters shall include the form NOI to be used during the Open Enrollment Window authorized in this decision.

6. A temporary waiver is hereby granted of Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company's direct access interval meter installation requirement applicable to service accounts with demand between 50 kilowatts (kW) and 199 kW, pending the scheduled installation of an Advanced Metering Infrastructure Smart Meter by the utility, unless an interval meter is specifically required by the customer's electric service provider.

7. A methodology for local Resource Adequacy obligations, based on the Joint Proposal and set forth in Appendix 3, is hereby adopted. The methodology shall be in effect for 2010 only, unless otherwise specified by a future ruling. We delegate authority to the Energy Division to make minor refinements or clarifications to the adopted methodology in the course of implementation.

8. Investor-owned utilities subject to the provisions of this decision are directed to file advice letters to modify their tariff rules in compliance with this decision, due 20 days after the issuance of the decision, and effective upon filing.

9. This proceeding shall remain open to address the remaining implementation issues relating to the increased phase-in of direct access and other pending issues to be addressed in this rulemaking.

This order is effective today.

Dated March 11, 2010, in San Francisco, California

MICHAEL R. PEEVEY

President

DIAN M. GRUENEICH

JOHN A. BOHN

TIMOTHY ALAN SIMON

NANCY E. RYAN

Commissioners

Appendix 1

Authorized Increases in Caps on Direct Access Transactions

By Service Territory

Authorized Direct Access Cap Increase (in GWh)

Within Service Territories of the Electric Utilities

(End of Appendix 1)

APPENDIX 2

Adopted Enrollment Procedures for the Phase-In Period

1. As described more fully below, the phase-in period will begin on April 11, 2010 (the "Effective Date"), and continue for four calendar years, with the annual limits on direct access (DA) load increases over the phase-in period as described in step 2 below, up to the maximum DA cap for each investor-owned utility's ("IOU") service territory (the DA cap). Any kilowatt-hours (kWh) not used in one year will be rolled over to the subsequent years as part of the cumulative increasing annual limits.

2. The annual kWh limits are as follows:

¬ Y1 (2010): 35% of the current room available under the DA cap.

¬ Y2 (2011): An additional 35% of the current room available under the cap (or70% of the available room under the DA cap).

¬ Y3 (2012): An additional 20% of the current room available under the cap (or 90% of the available room under the DA cap).

¬ Y4 (2013): An additional 10% of the current room available under the cap (or 100% of the available room under the DA cap).

3. The same switching rules will apply to all customers eligible to switch to DA service under SB 695 ("DA-eligible customers").

4. To facilitate implementation as of the Effective Date, the IOU will notify all DA-eligible customers prior to the Effective Date of the terms and conditions for participation in the partial DA reopening under SB 695. Specifically, the IOU will use a bill insert or onsert¹⁸ to notify all DA-eligible customers as early as March 2010 to visit the IOU's website for details on the partial DA reopening. The website will be updated to ensure accurate information based on the Commission's final decision implementing the DA reopening.

5. To facilitate implementation as of the Effective Date, an Open Enrollment Window ("OEW") will be established as of the Effective Date, during which all DA-eligible customers will be allowed to submit a notice of intent ("NOI")¹⁹ to transfer to DA service.

6. The OEW will begin on the fifth business day after the Effective Date and end ninety (90) calendar days thereafter or on June 30, 2010, whichever comes first. The OEW will occur in Y1 of the phase-in period only.

7. Enrollment during the OEW:

a. A temporary, one-time waiver of the 6-month advance notice requirement for all DA-eligible customers will be granted so that all DA-eligible customers may begin to enroll in DA service as of the Effective Date if they wish to do so, pursuant to the process described herein.

b. A one-time waiver of the current Bundled Portfolio Service ("BPS") commitment periods (per Rule 25.1) will be granted so that all DA-eligible customers may begin to enroll in DA service as of the Effective Date if they wish to do so, pursuant to the process described herein.²⁰

c. All LSEs (those that currently serve load and those that do not) will file forecasts of new customers that they expect to gain from via the OEW and other periods for RA compliance years 2010 and 2011 according to the rule set forth by Energy Division for the RA process. Energy Division will issue an amended RA Guide and reporting template for 2010 compliance year as well as an RA Guide and reporting template for 2011 compliance year.

d. The IOU will begin accepting NOIs up to the Y1 limit as of 9:00 a.m. PST on the fifth business day after the Effective Date. The methods for submitting NOIs will be specified by each utility on its website, provided that all methods shall allow for a time and date stamping to determine precedence. The daily batch process for accepting NOIs during the OEW (described in 7.d below) will allow for up to a 10 percent (10%) threshold above the Y1 limit.

e. The IOU will process NOIs in daily (12:00 a.m. to 11:59 p.m.) batches. Each daily batch of NOIs will, within 20 days of its receipt, be accepted unless and until the Y1 limit is reached. A daily batch that causes the Y1 limit to be exceeded will nevertheless be accepted provided that such daily batch does not exceed the Y1 limit by more than 10%. Should a daily batch cause the Y1 limit to be exceeded by more than 10%, NOIs in that particular daily batch will be accepted on a first-come, first-served basis (based on the date/time stamp of the NOI) up to the Y1 limit plus a threshold of no more than 10%. All other NOIs in that particular daily batch will be rejected.4²¹

f. NOIs submitted during the OEW will be rejected only if the Y1 limit has been reached. Any NOI that is found to have a deficiency (e.g., incorrect service account number) will be accepted on the condition that it is corrected by the customer within two business days after the IOU notifies the customer of such deficiency. NOIs will be void in the event a Direct Access Service Request (DASR) is not timely submitted, as described in 7.h below, or in the event a deficiency in the NOI is not corrected by the customer within two business days.

g. For any NOI accepted during the OEW, the IOU will notify the customer of NOI acceptance within 20 days of NOI receipt, and will instruct the customer to notify its Electric Service Provider (ESP) that a DASR to switch customer's service account(s) to DA service must be submitted to the IOU within 60 calendar days of the date the IOU's notice of NOI acceptance is sent to the customer.

h. The customer will have 60 calendar days from the IOU's notice of NOI acceptance to cause its ESP to submit a DASR.²² DASRs will be processed using existing processes and timelines in accordance with Rule 22 (or equivalent rule),²³ and eligible service accounts will be switched to DA service on their next scheduled meter read date, or the date specified on the DASR, if different from the next meter read date, depending on when the IOU receives the DASR. Although Rule 22 (at Section E.18) allows the IOU, the customer and the ESP to mutually agree to a different service change date for the service changes requested in a DASR, the IOUs may be unable to accommodate special service change dates during the OEW. Nothing in this Appendix 2 is intended to rescind Section E.18 of Rule 22; however, it may not be operable during the OEW.

i. If a DASR is not received by the IOU for an accepted NOI by the end of the 60-day period, the customer's NOI will be void.

j. Any NOIs voided for failure to submit a DASR within the 60-day period will not be subject to a three-year minimum BPS commitment period as a result such failure. This exception will apply only to NOIs accepted during the OEW.

k. If the Y1 limit is reached during the OEW, the IOU will stop accepting NOIs, and will begin placing submitted NOIs on a wait-list on a first-come, first-served basis. The wait-list shall have a maximum capacity equal to 25% of the Y1 limit, and will be maintained until the last day of the OEW. Should any room under the Y1 limit become available during the OEW as a result of any voided NOIs, within one (1) business day of any room becoming available, the IOU will notify eligible customers on the wait-list by email of the acceptance of their NOIs. The IOU will continue to issue such email notices, on a 1-business day basis as room becomes available during the OEW, through the last day of the OEW. A customer coming off the OEW wait-list will have 60 days after the IOU's notice of the NOI acceptance to cause its ESP to submit a DASR to the IOU. If a DASR is not received by the IOU by the end of the 60-day period, the customer's NOI will be void, and the exception under Section 7.k for the three-year BPS commitment will apply. The wait-list will end on the last day of the OEW. Any NOIs on the wait-list that were not accepted during the OEW will be void, and customers will be notified that they can begin submitting 6-month advance NOIs as early as July 1, 2010 to switch to DA in 2011. No wait-list will be used after the OEW.

l. The OEW will close 90 calendar days after the Effective Date, or on June 30, 2010, whichever comes first. There will be no OEW in subsequent years of the phase-in period.

m. All LSEs that intend to serve load during 2011 will refile load forecasts for 2011 RA compliance year by May 26, 2010. This revised forecast shall account both for customer migration up to that date, but also to forecast expected customer migration during the second phase of DA access that commences in January of 2011. The updated load forecasts due by May 26, 2010 will be used by the Energy Division and CEC to develop Local RA obligations, inclusive of adjustments, as accurately as possible within the constraints of the 2011 RA filing cycle.

8. Enrollment after the OEW closes:

a. In 2010:

¬ Customers may submit 6-month advance NOIs starting July 1, 2010 to switch to DA in 2011 (Y2). The IOU will accept 6-month advance NOIs up to the Y2 limit. The daily batch process for accepting NOIs (described in 7.d above) will allow for up to a 10 percent (10%) threshold above the Y2 limit.

¬ A customer with an accepted NOI will be switched to DA starting in January 2011, provided the customer's 6-month advance notice period has been satisfied and a DASR has been timely received.

¬ DASRs will be processed using existing processes and timelines in accordance with Rules 22 and 22.1 (or equivalent rules), and eligible service accounts will be switched to DA service on their next scheduled meter read date, or the date specified on the DASR, if different from the next meter read date, depending on when the IOU receives the DASR. Customers who fail to meet the time limitations and DASR requirements set forth in Rules 22 and 22.1 will be subject to a three-year minimum BPS period as provided for in Rule 22.1 (or equivalent IOU rules).

¬ Once the Y2 limit is reached, the IOU will stop accepting 6-month advance notices.

¬ If room under the Y2 limit subsequently becomes available, the IOU will update its website to notify customers that it is accepting 6-month advance notices. The IOU will use the same daily batch process described above for accepting NOIs for any room under the Y2 limit.

b. In 2011:

¬ Customers may continue to submit 6-month advance notices after January 1, 2011 to switch to DA in 2011 or 2012, depending on whether there is room available under the Y2 limit. The IOU will accept 6-month advance notices up to the Y3 limit. The daily batch process for accepting NOIs (described in 7.d above) will allow for up to a 10 percent (10%) threshold above the Y3 limit.

¬ A customer with an accepted NOI will be switched to DA as soon as possible (depending on whether there is room under the Y2 limit), but in any event starting in January 2012, provided the customer's 6-month advance notice period has been satisfied and a DASR has been timely received. If there is no room available under the Y2 limit, customers who submit 6-month advance NOIs prior to July 2011 may need to remain on bundled service for up to twelve months before being able to switch to DA. In other words, they may have to wait for the Y3 allotment to open up in January 2012 before they can switch to DA. If room under the Y2 limit subsequently becomes available in 2011, some customers may be able to switch to DA prior to 2012, provided the 6-month advance notice period has been satisfied and a DASR has been timely received.

¬ DASRs will be processed using existing processes and timelines in accordance with Rules 22 and 22.1 (or equivalent rules), and eligible service accounts will be switched to DA service on their next scheduled meter read date, depending on when the IOU receives the DASR. A customer failing to meet the time limitations and DASR requirements set forth in Rules 22 and 22.1 will be subject to a three-year minimum BPS period as provided for in Rules 22 and 22.1 (or equivalent rules).²⁴

¬ Once the Y3 limit is reached, the IOU will stop accepting 6-month advance NOIs.

¬ If room under the Y3 limit subsequently becomes available, the IOU will update its website to notify customers that it is accepting 6-month advance NOIs. The IOU will use the same daily batch process described above for accepting NOIs for any room under the Y3 limit.

c. In 2012 and 2013:

¬ The IOU will use the same enrollment process as described above for 2011, using the applicable annual limits, except that a threshold for daily batch processing will not apply to the Y4 limit (because it represents the overall cap).

9. During the phase-in period, the IOU will indicate on its public website whether NOIs (during OEW) or 6-month advance NOIs are being accepted, and update this information regularly, as reasonably necessary, but in no event less frequently than monthly. This information should be sufficient to inform customers and ESPs whether there is room available under the annual limits during the phase-in or the overall cap after the phase-in. The IOU will provide notice on its public website when the level of annualized sales for customers electing DA service approaches a certain percentage of the annual limit or overall cap (e.g., 95%).

10. Changes in the 12-month usage of DA accounts will be reflected in order to determine the room available under the cap. No customer taking DA service while room was available under the cap will be removed from DA service as a result of growth in DA load.

(End of Appendix 2)

APPENDIX 3

Adopted Temporary Treatment
for Local Resource Adequacy Obligations During Direct Access Reopening

We hereby adopt the methodology set forth below in order to fairly allocate local RA costs among LSEs during RA compliance year 2010:

The first step in the methodology is to determine the size of the Local RA obligation associated with a migrating customer. The following calculation is suggested:

Calculate a "Local to Peak Ratio" (LPR) for each IOU service territory. This ratio would be determined by taking the total Local RA obligation in the service area in MW, as adopted by the CPUC decision that established Local RA obligations for 2010, and then subtracting the Local MW that were allocated among all LSEs for Demand Response (DR), Cost Allocation Mechanism (CAM) resources, and RMR Condition 1 (RMR-1) resources. That number is then divided by the total forecasted 2010 coincident peak load in MW of that same IOU service territory (Service Area CPD) that was developed by the California Energy Commission for purposes of establishing 2010 RA obligations. This LPR would be expressed as a percentage. The LPR will be calculated by the CPUC Energy Division and posted to the CPUC website for each service territory alongside the amended 2010 RA Guide and Templates in April of 2010²⁵.

When a customer seeks to migrate between LSEs after the date of DA reopening, a Customer Local (RA) Obligation (CLO) would be established for that customer, based on the customer's actual recorded Coincident Peak Demand (COPD) in MW at the time of the IOU service territory's 2009 coincident system peak, grossed up by the appropriate Distribution Loss Factor (DLF) for the service area and multiplied by the LPR for the service territory in which the customer is located. The resulting figure would be the Local RA obligation of that customer in MW, the CLO. The LSE losing the load and the LSE receiving the load would stipulate to this figure, which would require only the data establishing the customer's 2009 CPD at the time of the CAISO system peak.

In mathematical terms:

LPR = Total 2010 Service Area LCR in MW (less Local MW from DR, CAM, and RMR1 & 2)/ Forecasted Service Area 2010 CPD.

CLO = LPR x Customer 2009 CPD.

In order to simplify the process for this temporary and interim solution, the LSE gaining the additional load would have the option²⁶ to obtain an allocation of Local RA "credits" from the LSE losing the load, without the need for any actual commercial sale of physical capacity to occur between the two LSEs. Rather, the LSE gaining the load would make a payment to the LSE losing the load, equal to the customer's CLO times an administratively determined price in dollars per kilowatt-year (kW-yr) or kilowatt-month (kW-mo). This payment would be deemed to satisfy the acquiring LSE's Local RA obligation for the remainder of the 2010 compliance year. LSE RA filings from both the LSE that lost the customer and the LSE that gained the customer would need to clearly indicate and highlight the exchange of customer MW and RA capacity if any transferred or sold directly to the other LSE. These rules and implementation procedures will be described in an amended RA Guide and Template for 2010 compliance year, and LSEs will be notified in April of 2010 of the new procedures and rules.

No changes to the current RA compliance process would be required, except that both LSEs would report in their System RA monthly true-ups to Energy Division the amount of the Local RA obligation (the CLO) that was being transferred, and the acquiring LSE would also report the amount of the CLO being satisfied through the default transfer payment, as well as the amount of CLO that was being otherwise satisfied.²⁷ The capacity that is transferred via the default mechanism would still be obligated by the RA Must-Offer Obligation (MOO) throughout the period in which it was originally shown in the year ahead filing, and the SC for the capacity would be required to demonstrate that in each monthly supply plan. Additionally, in the event that Local RA capacity is not sold to another LSE but is now in excess of the Local RA obligations of the original LSE, the original LSE would still be required to list the capacity to on its RA filing and that capacity would still be subject to the RA MOO via requirement to submit supply plans. LSEs are still under the obligation to demonstrate all Local RA capacity that they have under contract via RA Filings. The current process for monthly true-ups to LSEs' System RA obligations would continue without change. All LSEs that expect to serve load during any month(s) are required to submit a monthly load forecast and System RA filing for each month that the LSE will serve load. Failure of an LSE to demonstrate that it has satisfied the CLO through a timely default transfer payment to the transferring LSE and/or through other means will result in a deficiency in the Local RA obligation of such LSE.

Consistent with proposals in the current RA proceeding (R.09-10-032), in order to reduce administrative complexity, local true-ups shall be completed twice during 2010: once for August and September, and a second time for October-December. For 2010 compliance year, the Local RA true-ups will be performed as follows: On May 31, LSEs (both LSEs that currently serve load and LSEs that assume load during the OEW) shall file their monthly load forecast adjustments for August compliance month pursuant to the current RA schedule. This filing for August will be used to establish adjusted Local RA obligations for LSEs for August and September, 2010. LSEs that do not currently serve load will be required to file with the CPUC and demonstrate RA capacity sufficient to meet their Local RA obligations gained from new customers. On August 2, LSEs will file load migration adjustments to establish Local RA obligations for the months of October, November, and December 2010.

The default transfer payment would provide an administrative price for the transfer of Local RA credits of $24 per kW-year. This amount is intended to reflect only the "premium" value of Local RA capacity over System RA capacity, since the LSEs acquiring new load would still be purchasing any increased amount of System RA capacity required to be shown in its monthly System RA filing under the current RA load migration rules. Rather than a flat $2.00 per kW-month, the monthly prices would be "shaped" to reflect the fact that RA capacity is most valuable during the peak summer months. This shaping would spread the $24 over the months of the year based on the same factors (shown below) that were used to allocate capacity payments under the CAISO's former Reliability Capacity Services Tariff program across the 12 months of the year. In mathematical terms, the transfer payment would be determined as follows:

CLO x $24/kW-yr x Shaping Factor for remaining months of 2010.

If, during the course of 2010, the new DA load subsequently switched to another LSE, the same process would be repeated again, and the new LSE would meet the CLO for the new DA load by either making a transfer payment to the prior LSE under the default mechanism or showing that it has obtained Local RA from another source.

This temporary and interim solution shall explicitly apply only for calendar year 2010, and shall continue or be replaced as a result of whatever solution (if any) is adopted in R.09-10- 032 for the 2011 RA compliance year. If the LSE that was gaining the load already held excess Local RA capacity or was able to obtain it from another source, the acquiring LSE shall not be required to use this temporary and interim option, but shall still be required to make a true-up filing, even if there is no change. To facilitate a smoother synchronization between the phased reopening of DA and the annual RA schedule, the next step in the DA phase-in schedule shall occur on January 1, 2011 rather than April 11, 2011. The use of the January date would allow LSEs' year-ahead Local RA showings for 2011 to reflect any load migration that is expected to occur at the start of the next step of the DA reopening phase-in.

In order to provide Energy Division and California Energy Commission with all necessary documentation for a transfer of local RA obligation, both the losing and gaining LSE shall provide the following information to the California Energy Commission and Energy Division at the time of the local true-ups: CLO for each customer gained and lost, documentation of customer transfer, default transfer payment amount (if a transfer payment has been made), identity (CAISO scheduling resource ID and MW amount) of any local RA capacity transferred, and any other information that may be required by Energy Division and California Energy Commission to implement this methodology. Energy Division shall publish a template to facilitate this documentation.

Monthly Shaping Factors

(End of Appendix 3)

¹⁸ A bill onsert is a message imprinted on the customer's bill, as distinguished from a bill insert, which is a separate insertion included in the bill's envelope. The bill onsert may be a more cost-effective way to provide customers notice of the partial DA reopening, because it can be included only on DA-eligible customers' bills, and does not increase the weight of the bills (and thereby should not increase bill mailing costs).

¹⁹ The parties will work together cooperatively in advance of the Open Enrollment Window to develop a uniform NOI in a timely fashion, which shall be filed as part of the IOUs' advice letters implementing changes to their direct access tariffs in compliance with this decision. Customers wishing to authorize their ESP or other third party to submit the NOI on their behalf may do so by providing the IOU with a signed "Authorization to Receive Customer Information or Act on a Customer's Behalf" (CISR) form, indicating that the ESP or other third party is authorized to "Request Rate Changes" for the customer.

²⁰ The one-time waiver will apply to all non-residential customers under current BPS commitments, even if they do not elect to take DA service during the OEW. After the end of the OEW, these customers may elect DA service at any time with the required 6-month advance notice, assuming there is room under the annual limits or overall cap. However, the 3-year BPS commitment period will continue to apply anytime a DA customer returns to BPS.

²¹ The threshold is only used for purposes of processing daily batches of NOIs. It is not intended as an increase in the annual limits.

²² In accordance with the IOUs' current procedures, rejected DASRs must be corrected and resubmitted by the ESP and be acceptable to the IOU no later than 20 days following the conclusion of the 60-day period. DASRs not corrected by the ESP within this time period will be cancelled by the IOU.

²³ The DA Rules for SDG&E are Rules 25 and 25.1. The IOUs' DA Rules generally require that DASRs received by the OIU on or before the 15th of the month will be switched over no later than the next month's scheduled meter reading date for that service account. Under SCE and SDG&E's current DASR process, DASRs that are received by SCE or SDG&E five (5) business days before the customer service account's next scheduled meter reading date will be switched over on its next scheduled meter reading date.

²⁴ With the exception that customers who submit 6-month advance NOIs prior to July 2011 may be required to remain on bundled service for longer than 6 months (but not more than 12 months) before switching to DA service, if there is no room under the Y2 limit. In other words, they may have to wait for the Y3 allotment to open up in January 2012 before they can switch to DA.

²⁵ RA compliance materials for 2008 through 2010 are posted to the CPUC website here: http://www.cpuc.ca.gov/PUC/energy/Procurement/RA/ra_guides_2008-09.htm

²⁶ If the LSE that was gaining the load (the acquiring LSE) can show that it already met some or all of its Local RA obligation with excess Local RA capacity or was able to obtain it from another source, the acquiring LSE would not be required to use this "default" option for some or all of its Local RA obligation. For purposes of these mid-year load migration adjustments only, LSEs gaining load may meet increased Local RA obligations in the PG&E service territory via procurement in either the Other PG&E Areas or in the Greater Bay Area, or any combination of the two. Similarly, the SCE service territory, procurement may be in either the LA Basin or in the Big Creek/Ventura area. Procurement adjustments in the SDG&E service territory must be in the San Diego Area.

²⁷ See fn. 1, above.