9. Comments on Proposed Decision

The proposed decision of the ALJ 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 September 12, 2011, and reply comments were filed on September 19, 2011 by multiple parties. We have reviewed the comments and incorporated appropriate corrections and revisions in finalizing this decision.

1. The existing Commission-adopted methodology used to calculate the Indifference Amount has become outdated in view of industry and regulatory changes over time.

2. Pursuant to Pub. Util. Code § 365.1(b), individual retail nonresidential
end-use customers may acquire electric service from other providers in each electrical corporation's distribution service territory, up to a maximum allowable total annual limits established in D.10-03-022.

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

4. 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 RA requirements, renewable portfolio standards, and greenhouse gas emission reductions.

5. The current indifference methodology only recognizes the IOUs' cost of renewable resources in the calculation of the Total Portfolio Cost, but does not account for the market value of renewable resources in the MPB.

6. An adjustment to the MPB to account for the market value of renewable resources will result in a more accurate measure of indifference costs.

7. An accurate market-based measure for use in a renewable resource adder calls for data sources that represent transactions among all load serving entities in California, not just those of the IOUs.

8. Relying solely upon IOU transactions as the data source to construct a renewables adder is deficient to the extent it fails to account for transactions of other categories of California load serving entities.

9. All of the parties proposals for adjusting the MPB to account for renewable resources have deficiencies that make the proposals unsuitable as a basis for calculating the indifference amount.

10. The utilities' renewable resources constitute 68% of total California load subject to RPS requirements; the remaining 32% of such resources come from other load serving entities.

11. The data on renewable resource transactions from SNL Publications is not a reliable source for purposes of calculating a renewable adder to determine indifference costs.

12. The data reported by the United States Department of Energy survey of reported renewable energy contract premiums in the Western United States compiled by the National Renewable Energy Laboratory offers a proxy value that can be used in conjunction with California utility data to produce a weighted RPS adder.

13. The MPB incorporates a capacity adder value to reflect the cost of resource adequacy based on the annualized cost of a combined cycle combustion turbine, but the current methodology does not provide for updating the value over time.

14. SCE's proposal to update the capacity adder using the California Energy Commission's estimates of the going forward costs of a combustion turbine, which is updated biannually, and the Net Qualifying Capacity of all generation resources (utility owned and power purchases) in the utility portfolio, is a practical approach to update the RA capacity value in the MPB.

15. The currently pending CEC proposed "Capacity Procurement Mechanism" price before the Federal Energy Regulatory Commission is not suitable as MPB capacity adder value, particularly because the CPM price is above current RA capacity market values. The FERC has raised questions about the CPM price and has made it subject to refund pending further study.

16. The total portfolio calculation currently includes certain CAISO load-based costs which the IOUs avoid when load departs for DA service. Exclusion of the load-based CAISO costs including load-based congestion costs, that vary based on the amount of load will produce a more accurate indifference amount calculation.

17. Under the current method for calculating the indifference amount, the total portfolio reflects the profile of the underlying IOU generation resources or contracts; however, the MPB calculation essentially is weighted based on the number of peak and off-peak hours in a year.

18. The current MPB is based on an implicit assumption that the IOU supply portfolio serves a flatter load profile than it actually does, thus creating an artificially low market value and artificially high indifference amount.

19. Parties identified two alternative approaches by which to revise the MPB to reflect more accurately the shaped profile of portfolio resources, weighted either by using the IOU generation profile or the IOU bundled load profile.

20. The IOU generation profile would more closely track actual portfolio costs, but the IOU load profile follows the shape of how load varies from hour to hour.

21. By using the utility's bundled load profile for the weighting factors, the shaped energy price for "brown" power would be the same for all PCIA vintages and for the CTC portfolio.

22. The IOUs historical bundled load profile by rate groups is publicly available and adequately reflects the shape of the IOU generation portfolios.

23. Bundled customer indifference is determined with reference to total portfolio costs, not isolated costs related to just the ERRA costs.

24. Short-term power purchases for terms of less than one year, do not belong in the calculation of total portfolio costs.

25. PG&E's proposal would violate the bundled customer indifference by recognizing only the cost to bundled customers from using more above-market CTC resources, while not recognizing the offsetting benefit accruing to bundled customers from also using more below-market utility resources.

26. An 18-month minimum stay requirement for bundled service strikes a reasonable balance, mitigating the risk of stranded RA and other potential stranded costs, while acknowledging that the capped DA market supports some lowering of the minimum stay requirement from its current length of three years.

27. The re-entry fees which are covered under the provisions of § 394.25(e) should cover administrative costs resulting from the involuntary return of DA customers to bundled service, and also incremental procurement costs for involuntarily returned residential and small commercial customers that are necessary to avoid imposing costs on bundled customers. For purposes of re-entry fees and ESP financial security requirements, it is reasonable to treat small commercial DA customers affiliated with a large commercial or industrial DA customers in the same manner as their large customer affiliate.

28. A security bond, letter of credit, or secured cash deposits are alternative means that can meet the ESP financial security obligations of § 394.25(e). The use of self insurance or showing of an ESP's investment-grade bond ratings are inadequate alternatives that fail to provide the requisite financial security required by § 394.25(e).

29. The fees that are currently in effect by utility tariff to cover administrative costs for the voluntary return of a CCA customer offer a reasonable proxy to use for purposes of securing a bond and calculating re-entry fees for administrative costs applicable to involuntarily returned DA customers.

30. A 60-day safe harbor period followed by a six-month period offers a reasonable time frame for calculating the duration of re-entry fees for involuntary returned residential and small commercial DA customers, in terms of keeping the bond costs manageable while protecting bundled customers against cost shifting.

31. The determination of re-entry fees is required under § 394.25(e) for purposes of securing an ESP bond and calculating actual costs of re-entry once an involuntary return occurs.

32. PG&E and SCE have failed to demonstrate that their proposed financial security bond methodology is necessary to prevent shifting costs to utility bundled customers.

33. Placing involuntarily returned large commercial and industrial DA customers on the TBS rate during the safe harbor period and for a period of six months thereafter avoids the need to include procurement costs as a reentry fee and associated financial security requirements under § 394.25(e). The only "re-entry fee" necessary to meet § 394.25(e) requirements are administrative costs associated with the switching the customer from the ESP to the IOU procurement service and incremental procurement costs for residential and small commercial customers.

34. Any actual incremental costs incurred in connection with serving an involuntarily returned DA customer that are not covered by the ESP bond or the TBS rate shall be the obligation of the involuntarily returned customers, as necessary to prevent cost shifting to bundled service customers.

35. Under the financial security bond methodology proposed by PG&E and SCE, the financial security bond amount would be recalculated every 6 months upon the filing of an Advice Letter.

36. DA customers, particularly industrial and commercial customers, seek fixed price DA contracts to minimize risks of uncertainty as to energy costs.

37. The financial security methodology proposed by PG&E and SCE lacks a definitive calculation for implied volatility.

38. Because PG&E and SCE have only presented illustrative bond calculations, and omitted key inputs relating to implied volatility, there is uncertainty concerning how large an ESP's resulting bond obligation could be, as well as the resulting costs which could tend to make DA service less cost effective.

39. Substantial uncertainty regarding the financial security costs required to provide DA service could have an adverse effect on the viability of the DA market.

40. Requiring the ESP bond to be recalculated twice a year would result in uncertainty regarding the costs of providing the bonds.

41. One of the purposes of SB 695 is to expand the availability of Direct Access.

42. The TBS rate is designed to cover the incremental procurement-related costs associated with a DA customer's voluntary return to bundled utility service from an ESP.

43. The TBS rate is also suitable to cover incremental procurement-related costs associated with large commercial and industrial DA customers involuntary return to bundled service from an ESP.

44. Eliminating existing safe harbor provisions would significantly impede a customer's ability to return to DA service once it is involuntarily returned to IOU bundled procurement service.

45. Through a combination of the TBS rate and the safe harbor provisions in existing tariff rules, a customer who is returned by an ESP will be positioned to find a new ESP to supply its energy and to go back to DA service within a limited period of time.

46. The updated TBS rate, incorporating the effects of this decision, will include all procurement related costs, including the commodity cost of power, the incremental cost of RPS compliance, any incremental capacity/RA costs, and CAISO costs.

47. As sophisticated businesses with experience in obtaining goods and services via contracts, large commercial and industrial DA customers (and small commercial customers affiliated therewith) should have the ability to negotiate contractual provisions with an ESP to protect themselves in event of a breach, recognizing the potential to pay TBS rates if they return to the IOU.

48. Because residential and small commercial customers subscribing to direct access may not possess the same business sophistication as large commercial and industrial customers in terms of protecting themselves in the event of a breach by their ESP, additional measures are appropriate to protect residential and small commercial customers from the risk of higher procurement costs resulting from an involuntary return to bundled service. Small commercial customers affiliated with a large commercial or industrial customer, however, should be treated the same as their large customer affiliate for purposes of ESP bonds and applicable bundled service rates for an involuntary return.

49. Including the risk of higher procurement costs as part of the ESP bond requirement to cover the risk of higher procurement costs resulting from an involuntary return of small commercial and residential customers will provide appropriate protection to such customers.

50. Placing involuntarily returned residential and small commercial customers on the BPS rate will protect them against the risk of higher procurement costs, and will transfer that risk of higher procurement costs to the ESP .

51. Because the ESP bond calculation proposed by SCE and PG&E anticipated covering energy procurement risks for all involuntarily returned DA customers, the degree of complexity in the bond formulas and assumptions underlying those calculations may not be necessary for a bond that covers a much more modest procurement risk limited only to small commercial and residential DA.

52. There has been no mass involuntary return of customers since the energy crisis.

53. The CCA settlement adopting a bonding requirement has not been approved by the Commission.

54. A very small percentage of DA load currently serves residential customers. Residential and small commercial customers are not similarly situated to large commercial and industrial customers.

55. The SCE and PG&E proposed calculation of a financial security requirement to cover potential re-entry fees as set forth in their respective testimony does not provide an appropriate methodology for use in determining an ESP bond amount to cover the involuntiary return of large commercial and industrial DA customers under § 394.25(e).

56. The SCE/PG&E methodology to calculate ESP bond amounts relies on non-existent or unreliable data, an unduly extended time period and an unjustified and excessive confidence factor. The proposed bond methodology would use implied volatility data from a
third-party broker if that data is available. Information is available to parties to access market prices. However, limited information is available to parties to access implied volatilities. Access to the limited implied volatility information requires a fee-based subscription. Such data is available for SP 15 based on a proprietary model, from one broker only, and has not been shown to be reliable or verifiable as an indicator of future market price.

57. PG&E has not performed a study of volatilities comparing NP 15 and SP 15. Thus, we have no basis for concluding that SP 15 volatilities would serve as a reasonable proxy for NP 15 volatilities or whether SP 15 volatilities could be adjusted to become a reliable proxy for use in calculating a provision for incremental procurement costs to be included in an ESP bond.

58. PG&E has not performed a study comparing historic volatilities and their relationship to implied volatilities. Thus, there exists no basis for concluding that historic NP 15 volatilities are reasonable proxy for NP 15 implied volatilities or whether historic NP 15 volatilities could be adjusted to become a reliable proxy.

59. The calculation of re-entry fees set forth in the testimony of PG&E and SCE does not provide a reasonable methodology for determining actual re-entry fees due to an involuntary DA return.

60. An ESP with investment grade credit should be able to obtain a bond or insurance policy on the commercial market at an annual cost of about 1% of the face value of the bond/policy amount.

61. The procedures for the filing of advice letters to implement the provisions of the ESP bond requirements set forth in the Ordering Paragraphs below are reasonable.

62. The implementation of true-up procedures in accordance with the ALJ ruling dated April 14, 2011, as amended by the ALJ ruling dated April 22, 2011, provides a reasonable means of incorporating the revisions in methodologies adopted in this proceeding into the PCIA rates for 2011, taking into account the effects of those revisions for periods of time prior to the effective date of this decision.

1. In administering the DA program, any adopted rules are subject to the provisions of Pub. Util. Code § 366.1(d) that all retail customers bear their fair share of purchase power obligations with no shifting of recoverable costs between customers.

2. Consistent with the increased allowances for DA transactions authorized pursuant to SB 695, any revised rules adopted for administering the DA program should also seek to preserve the benefits of customer choice.

3. The total portfolio methodology used to determine bundled ratepayer indifference should be calculated in a manner that subtracts the total portfolio from a market price benchmark that includes recognition of the market value of RPS and RA resources applicable to all load-serving entities. The total portfolio cost methodology should exclude short term power purchases for terms of under one year.

4. Since the existing proposals do not offer a suitable basis to determine a market-based adder for RPS resources, the Commission needs to determine a suitable proxy based upon available information.

5. SCE's proposal for updating the resource adequacy capacity adder using the CEC's most recent estimates of the going forward costs of a combustion turbine and the Net Qualifying Capacity of all generation resources (utility owned and power purchases) in the utility portfolio should be adopted.

6. Section 394.25(e) gives the Commission discretion to determine re-entry fees deemed necessary to avoid imposing costs on other customers of electrical corporations.

7. Section 394.25(e) requires ESPs to post financial security to cover any re-entry fees deemed necessary by this Commission to avoid imposing costs on other customers of electrical corporations.

8. It is reasonable to determine the financial impact of any proposed financial security bond methodology based on actual sample calculations in considering its merits.

9. The financial security bond methodology proposed by PG&E and SCE could pose a material adverse impact on the continued viability of DA.

10. Commission has previously recognized the benefits of the continuation of DA and has sought to avoid measures making DA uneconomic.

11. Involuntarily returning large commercial and industrial DA customers (and small commercial DA customers affiliated therewith) should be placed on the TBS rate in order to avoid shifting costs from DA customers to utility bundled customers. DA customers should be permitted to reserve their space under the DA cap in order to find a new ESP and return to DA service during the 60-day safe harbor period without having to compete for the oversubscribed demand for additional DA capacity under the SB 695 caps.

12. The Commission has the discretion to deem that the TBS rate is not a
re-entry fee as defined by § 394.25(e).

13. Holding involuntarily returned large commercial and industrial DA customers responsible for payment of the TBS rate reduces the size of a re-entry fee and associated ESP financial security requirements for procurement costs under § 394.25(e).

14. All load-related CAISO costs including load-based congestion costs, should be excluded from the calculation of the total portfolio and market price benchmark in order to produce a more accurate measure of indifference.

15. The determination of the MPB should be revised to more accurately reflect the bundled load shape based upon time-of-use variations.

16. Under Pub. Util. Code § 394.25(e), the ESP is responsible for procuring a bond or related evidence of insurance as delineated in this decision to cover all re-entry fees imposed due to the ESP's customers that are involuntarily returned to bundled service. The ESP shall not be obligated for any re-entry fees, however, if a DA customer returns to the IOU due to default in payment to the ESP or other contractual obligations, or because the DA customer's contract with the ESP has expired.

17. For purposes of assessing re-entry fees, an involuntary return of a DA customer to bundled service may occur due to any of the following:

a. The Commission revokes the ESP registration;

b. The ESP Agreement with the utility becomes terminated; and

c. The ESP or its authorized CAISO SC has defaulted on its obligations, such that the ESP no longer has an authorized SC.

18. If an ESP becomes insolvent and is unable to discharge its obligations to pay re-entry fees, the returning DA customers must bear responsibility for the payment of the re-entry fees.

19. The purpose of § 394.25(e) is to protect against costs of re-entry fees being shifted on to other customers in the event of an involuntary return of DA customers to IOU service.

20. The requirements of § 394.25(e) must be satisfied through posting of a bond, letters of credit, cash security deposits, equivalent evidence of insurance or parental guarantee from an investment grade rated institutions or corporate parent, as applicable, as delineated in this decision sufficient to cover re-entry fees as defined in this order.

21. The re-entry fees as required under § 394.25(e) resulting from an en masse involuntary return of an ESP's customers to bundled utility service must include all costs incurred by the IOU as a result of the DA customers' involuntary return necessary to avoid cost shifting to bundled customers.

22. If involuntarily returned DA customers are charged for incremental procurement costs through a TBS rate, such charges imposed on involuntarily returned customers are not a legal obligation of the ESP pursuant to § 394.25(e).

23. Because incremental procurement costs resulting from serving involuntarily returned DA customers must not be shifted to bundled customers, if those associated incremental costs are not included in re-entry fees pursuant to § 394.25(e), the costs should be recovered through a TBS rate.

24. Section 394.25(e) provides broad discretion for the Commission to interpret the scope of reentry fees as covering a different range of costs for small commercial and residential in contrast to large commercial and industrial DA customers, recognizing the different characteristics of each customer group.

25. In order to implement a requirement to incorporate the risk for incremental procurement costs in the ESP bond amount for involuntarily returned small commercial and residential customers, the Commission has the discretion to define reentry fees as including those procurement costs only in reference to such customers.

26. A subsequent decision should determine how incremental ESP bond amounts limited to procurement costs for involuntarily returned small commercial and residential DA customers should be measured and implemented.

27. Because the ESP bond proposal sponsored by PG&E and SCE is not offered as a settlement in this proceeding, the proposal must be evaluated on its substantive merits rather than based upon the Commission's settlement rules. Nothing in this decision should be construed as a prejudgment regarding the merits of re-entry fees or bond obligations that may be deemed applicable to CCAs which are under consideration in R.03-10-003 in the context of the record in that proceeding and policy considerations relevant to CCAs.

28. The ESP bond proposal of PG&E and SCE fails to offer a reasonable means of complying with the requirements of § 394.25(e) for determination of an ESP bond obligation for involuntarily returned DA customers.

29. The calculation of the ESP bond amount for estimated re-entry fees for involuntarily retuned DA customers as proposed by SCE/PG&E should not be adopted.

30. The calculation of actual re-entry fees under § 394.25(e) to be paid at the time of an involuntary DA customer return as proposed by SCE/PG&E should not be adopted.

31. The procedures for implementation of the revised methodologies for calculating the PCIA and TBS rates as adopted in this proceeding should be implemented by tier 2 advice letter filings. The PCIA rate adjustments shall be in accordance with the directives set forth in the ALJ Ruling issued in this proceeding on April 14, 2011, as amended by ruling dated April 22, 2011. The Commission affirms both of the ALJ Rulings pursuant to the provisions of Pub. Util. Code § 310.

32. Unless otherwise expressly approved in the ordering paragraphs below, any proposals for revisions in the methodologies for calculating the indifference amount, CTC or TBS rate should be deemed denied.

ORDER

IT IS ORDERED that:

1. The calculation of the Power Charge Indifference Amount and the Competition Transition Charge applicable to Community Choice Aggregation, and other non-exempt Direct Access, and Departing Load customers must be modified to incorporate revisions in the calculation of the total portfolio and market price benchmark as directed in the following ordering paragraphs.

2. The Market Price Benchmark used to calculate the Power Charge Indifference Amount, and Competition Transition Charge must be revised to incorporate an adder to reflect the market value of renewable portfolio standard resources.

3. All pre-2004 procurement resources must be included in the Total Portfolio cost calculation for purposes of comparing it with the Market Price Benchmark used in the calculation of the Power Charge Indifference amount and Competition Transition Charge.

4. Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company must each file a Tier 2 advice letter with the Energy Division within 30 calendar days following the issuance of this decision, identifying the relevant data necessary to revise the Power Charge Indifference Amount, Competition Transition Charge, and Temporary Bundled Service tariffs, in accordance with this decision. The information shall include:

a. most recent 12 months figures derived from US Department of Energy survey of Western US renewable energy premiums in calculating a weighted proxy for the Market Price Benchmark compiled by the National Renewable Energy Laboratory; and

b. all RPS-compliant resources that are used to serve IOU customers during the current year (i.e., most recent 12 months) and those projected to serve customers during the next year, including both contracts and IOU-owned resources, including the projected costs together with the net qualifying capacity of energy produced by each of these resources (providing relevant costs in dollars and volumes in MWh and qualifying capacity in kW). Confidential data submitted to the Energy Division will be protected from public disclosure.

5. The Energy Division will prepare a resolution to adopt the Renewable Portfolio Standard adder to be used to determine a Market Price Benchmark proxy value based on consideration of a 32% weighting of the DOE data in relation to a 68% weighting of the investor-owned utility cost data as relevant in the Commission's adoption of an appropriate adder to reflect renewable resources in the calculation of the Power Charge Indifference Amount and Competition Transition Charge. The applicable percentage weightings are subject to relevant updated data in subsequent years. The Energy Division will calculate the average cost of power from the IOU resources by summing up all the costs from all three IOUs, subtracting the product of the NQCs of those resources times the IOU's current RA capacity adder used in the Market Price benchmark, and dividing by the sum of all the MWHs from all three IOUs.

6. All California Independent System Operator (CAISO) charges that vary based on the amount of load including congestion charges, shall be excluded from the total portfolio cost and Market Price Benchmark for purposes of calculating the Power Charge Indifference Amount and Competition Transition Charge. The list of load-related CAISO charges identified in the testimony of the Joint Direct Access parties (Exhibit 100, Exhibit A) is adopted for use in identifying the applicable load-related charges to be excluded. As the CAISO charges change over time, the IOUs shall file tier 2 advice letters to update the excluded charges.

7. The Market Price Benchmark (MPB) calculation must be weighted to reflect variations in load shape on a time-of-use basis based upon the most recent investor-owned utility (IOU) bundled load profile data that is publicly available.

8. The capacity adder in the MPB shall be updated using the Net Qualifying Capacity of the utility electric supply portfolio and the most recent California Energy Commission estimate of the going forward costs of a combustion turbine.

9. The calculation of the temporary bundled service (TBS) rate shall be conformed to be consistent with the relevant changes in the methodology for calculating the total portfolio and Market Price Benchmark (MPB) as adopted in this decision. Specifically, the adopted MPB changes for Renewable Portfolio Standard resources shall be reflected in the TBS rate. Load-related California Independent System Operator charges, however, shall continue to be included in the TBS rate so that all relevant short-term charges are paid by Direct Access customers.

10. The minimum stay commitment for Direct Access customers electing to return to investor-owned utility procurement service shall be reduced from three years to 18 months.

11. The six-month advance notice requirement shall continue in effect for Direct Access (DA) customers to return to investor-owned utility (IOU) service or for bundled customers departing IOU service to be served by an electric service provider.

12. The proposal for bundled customers to be charged to pay Direct Access customers for negative indifference amounts is denied.

13. The proposal is denied to set the Power Charge Indifference Amount to zero in those instances where the indifference amount is less than the ongoing Competition Transition Charge.

14. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company must each file a Tier 2 Advice Letter within 30 days of this order to amend their tariffs to incorporate the ESP financial security provisions and re-entry fee provisions to cover administrative costs applicable to the involuntary return of DA customers, as adopted in this decision.

15. A subsequent phase of this proceeding shall address the determination of ESP financial security and re-entry fee provisions applicable to the involuntary return of small commercial and residential DA customers, including the methodology to calculate a provision for incremental procurement costs relating to such customers' involuntary return. A related issue to be resolved is to precisely define the distinction between small versus large DA customers for purposes of applying the relevant ESP financial security and re-entry fee provisions consistent with the intent of this decision.

16. The advice letter required by Ordering Paragraph 14 shall set forth the calculation of the financial security amount applicable for each ESP operating in the utility's service territory. Any confidential data relating to an ESP utilized in the calculations shall be redacted. An unredacted version of the advice letter shall be submitted to the Energy Division under confidential seal. Concurrently with submitting the advice letter to the Energy Division, the utility shall serve by electronic means on each applicable ESP a copy of the advice letter, with the relevant supporting data and calculations of each respective ESP's financial security amount provided confidentially only to that specific ESP in complete and unredacted form.

17. If an ESP believes that its financial security amount has been calculated inaccurately or in conflict with the adopted processes, the ESP may file comments with the Energy Division, and served on the relevant IOU, indicating any appropriate corrections with relevant supporting explanation and detail within 20 days of the advice letter filing.

18. Upon Commission approval of the relevant ESP financial security amounts, the Energy Division shall notify each ESP of the final amount due on an aggregate statewide basis. Each ESP shall post the designated financial security amount with the Commission within 30 days. The applicable ESP financial security amount shall be subsequently updated annually, with an updated calculation to be submitted to the Energy Division by April 10 of each year, and with the updated amount posted by June 30 of each year.

19. Upon Commission approval of the above-referenced advice letters to implement the procedures for the posting of financial security in accordance with this decision, each electric service provider offering Direct Access service within California shall be responsible for posting a bond and/or other equivalent proof of insurance (e.g., letter of credit, cash deposit, third party guarantee) that covers re-entry fees pursuant to § 394.25(e).

20. The electric service provider re-entry fee must incorporate as a proxy for administrative costs, the administrative fees that are included in the respective retail utility tariff for returning Community Choice Aggregator customers.

21. The financial security bond methodology to include procurement costs for large commercial and industrial customers proposed by Pacific Gas and Electric Company and Southern California Edison Company is not adopted.

22. All large commercial and industrial involuntarily returned DA customers returning to IOU service shall be placed on the TBS tariff rate.

23. The electric service provider re-entry fee applicable to the involuntary return of small commercial and residential direct access customers must include a provision for incremental IOU procurement costs necessary to serve such customers.

24. Upon the involuntary return of small commercial and residential direct access customers, those customers shall be placed on the bundled procurement service tariff rate. In all other respects, such customers shall be subject to the same rights and obligations of other direct access customers with respect to the safe harbor, advance notices, and minimum stay provisions.

25. The determination of the appropriate methodology to determine the applicable electric service provider bond provision to cover the risk of incremental procurement costs for the involuntary return of small commercial and residential direct access customers shall be addressed in a subsequent decision.

26. Involuntarily DA returned customers are authorized to utilize the 60-day safe harbor on the same basis as DA customers that return voluntarily.

27. Sufficient space shall be reserved under the SB 695 cap to enable involuntarily returned customers to resume DA service with a new electric service provider (ESP), as follows. If the involuntarily returned customer finds a new ESP and submits a DASR within the 60-day safe harbor period, the customer may reclaim the reserved space under the cap to resume DA service after executing a DASR. If the returned customer fails to find a new ESP and to execute a DASR during the 60-day safe harbor period, the customer will continue to pay the applicable bundled procurement rate for the six months following the end of the 60-day safe harbor period (i.e., the TBS rate for large commercial and industrial DA customers and the BPS rate for small commercial and residential DA customers. After that, the customer will be placed on the BPS rate and must remain on BPS service for the adopted minimum stay period of 18-months.

28. The TBS rate tariff for each IOU shall be revised by tier 1 advice letter to incorporate the provisions of this decision, including those relating to the incremental cost of RPS compliance, and incremental capacity/RA costs, and CAISO costs. The advice letter filing shall be deemed accepted unless protested during the 30-day review period.

29. The amount of an electric service provider's bond must be calculated annually, by April 10 of each year. Bonds shall be posted by June 30 of each year.

30. For an electric service provider that begins service in Month M+2 (where M denotes the month when the investor-owned utility will calculate the bond amount,), the bond calculation must be performed using Month M-1 data, and the bond shall be for the period from the start date through the next annual calculation.

31. The gross ESP bond amount to cover incremental administrative costs, and the actual re-entry fees applicable upon involuntary return of Direct Access customers must be determined in accordance with this decision.

32. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company must submit the initial ESP bond calculation methodology to the Commission's Energy Division in a Tier 2 advice letter filing, calculated in a manner consistent with this decision.

33. After the Commission approves the initial bond calculation methodology by resolution, all subsequent updates in the bond calculations shall be submitted as a Tier 1 advice letter. Any formulas shall be supported with Excel spreadsheets provided to the Energy Division. The filing shall be deemed accepted unless protested by an ESP or the Energy Division suspends the advice letter during the 30-day review period.

34. The electric service provider (ESP) is responsible for covering all applicable re-entry fees for its customers that are involuntarily returned. Only if, or to the extent, that the ESP is unable to cover all of the applicable re-entry fees, any unreimbursed fees from the ESP's must be covered by the returned Direct Access customers.

35. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company must each calculate actual re-entry fees due within 60 days of the earlier of the start of the involuntary return, or the receipt of the electric service provider's written notice of involuntary return, using the method described below.

36. Re-entry fees must constitute a binding estimate of the incremental administrative costs to switch the involuntarily returned Direct Access customers to bundled service.

37. The re-entry fees must be demanded from the electric service provider only after the involuntary return is initiated.

38. The changes in Power Charge Indifference Amount methodologies adopted in this decision shall be implemented in accordance with the procedure set forth in the Administrative Law Judge (ALJ) April 14, 2011 Ruling, as amended by the April 22, 2011 Ruling. In accordance with Public Utilities Code Section 310, the directives of the April 14, 2011 ALJ ruling, as amended by the April 22, 2011 ruling, are hereby affirmed by the Commission

39. To implement of the revised Power Charge Indifference Amount (PCIA) determined pursuant to this proceeding, Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company each must promptly adjust its 2011 PCIA rate prospectively to be consistent with the revised PCIA methodology. Each of the advice letter filings shall also calculate the difference between their existing temporary bundled service (TBS) rate and the revised TBS rate calculated in accordance with the directives in this proceeding.

40. Southern California Edison Company and San Diego Gas & Electric Company must calculate the difference attributable to the revised Power Charge Indifference Amount (PCIA) compared with the PCIA previously adopted in their 2011 Energy Resource Recovery Account (ERRA) proceedings. This resulting billing adjustment amounts shall be refunded to each of the utility's customers who were direct access, community choice aggregation or non-exempt departing load customers during the period from the effective date of the PCIA rate change adopted in their respective ERRA proceedings for 2011 through the effective date of the revised PCIA implemented pursuant to the revisions adopted in this proceeding. Future changes to the PCIA shall be incorporated as an adjustment to the prospective 2011 PC1A rates in the Tier 2 Advice Letter filing based upon the revised PCIA methodology adopted in this proceeding.

41. Once Pacific Gas and Electric Company (PG&E) implements the revised Power Charge Indifference Amount (PCIA) consistent with the methodologies adopted in this proceeding, PG&E shall promptly revise its previously adopted 2011 PCIA rate to incorporate this deferred difference. This resulting difference shall be remitted in the form of a refund to each of the utility's customers who were direct access, community choice aggregation or non-exempt departing load customers during the period from April 14, 2011, through the effective date of the revised PCIA implemented pursuant to the revisions adopted in this proceeding. Future changes to the PCIA shall be incorporated as an adjustment to the prospective 2011 PCIA rates based upon the revised PCIA methodology adopted in this proceeding.

42. Rulemaking 07-05-025 remains open for further proceedings to resolve outstanding issues necessary to determine ESP financial security requirements and related re-entry fee provisions to cover incremental procurement costs for involuntarily returned small commercial and residential DA customers in accordance with the principles and directives adopted in this decision.

This order is effective today.

Dated December 1, 2011, at San Francisco, California.

I abstain.

Previous PageTop Of PageGo To First Page