Conclusions of Law

1. Rate design and ratemaking policies should:

a) provide for fair cost allocation among customers;

b) allow the utility adequate cost recovery while minimizing costs to customers;

c) facilitate customer-side distributed generation deployment; and

d) send proper price signals to prospective purchasers of distributed generation.

2. Customers should be able to enter into a contract to specify the capacity for which it will provide physical assurance.

3. Customers should not pay standby charges designed to recover the fixed costs associated with distribution service for the amount of capacity it provides to the utility with physical assurance.

4. It is appropriate for distribution infrastructure costs to be recovered from backup customers.

5. Supplemental power should continue to be priced according to the customer's otherwise applicable tariff.

6. Standby rates should appropriately reflect the reduced cost of providing services such as backup and maintenance service compared to supplemental service.

7. In order to recognize the cost difference between supplemental power and backup power needs, we should require the utilities to reflect diversity in the standby reservation charges.

8. Backup service should be allocated a greater share of costs than maintenance service because it is an on-demand service and has distribution infrastructure requirements associated with it.

9. Diversity factors should be applied to charges that recover fixed costs.

10. The utilities should not be required to separately calculate diversity factors for the transmission and distribution level interconnected generation in this decision, but we should consider such proposals if supported by studies of diversity at various voltage levels.

11. We should reject PG&E's request to make a finding that its current diversity factor is inappropriate for distributed generation connected at distribution voltage.

12. The utilities should propose diversity factors assuming various levels of penetration of distributed generation.

13. We should adopt a diversity factor assuming a distributed generation deployment level that is higher than exists today.

14. Physical assurance should not be required for purposes of calculating diversity factors.

15. If costs associated with maintaining distribution and transmission facilities to serve diversified standby load are fixed, those costs are appropriately reflected in fixed reservation or demand charges.

16. To the extent that there are costs that do vary with usage, those costs should be reflected in a usage-based charge.

17. Standby customers with onsite generation who sign up for backup service should be charged a $/kW reservation charge for their reserved capacity.

18. The reservation charge should reflect the distribution infrastructure costs that do not vary with usage.

19. Backup standby rates should include a volumetric rate, based on actual usage, that collects variable distribution costs.

20. We should continue to recover public purpose costs from standby customers through a $/kWh usage charge.

21. Maintenance customers and others whose use of the distribution system is on an as-available basis, should be charged a volumetric rate, based on usage, that recovers variable distribution costs.

22. Standby charges should be based on embedded, not incremental, costs of service, consistent with the manner in which rates are calculated for other distribution services.

23. Standby rates should remove any charges not associated with providing distribution standby service.

24. The utilities should develop an electricity procurement rate option, which may be a real time price, that will be paid by standby customers when the utility procures electricity on their behalf.

25. If allowed under state law, standby customers should also have the option to procure electricity to serve their backup or maintenance supply from a third party.

26. To the extent that transmission charges recover fixed costs, they should be recovered through reservation charges.

27. Variable transmission charges should be recovered through variable rate components.

28. To the extent a customer with distributed generation offers physical assurance, no fixed transmission costs should be recovered from that customer.

29. We should not support the CA ISO's gross load metering policy.

30. The utilities should propose non-firm standby rate options that recover only variable costs of distribution service from customers who offer physical assurance.

31. The diversity factor included in the unbundled standby rates we adopt today should account for lowered costs of distribution capacity deferred due to increased distributed generation deployment.

32. The utilities should review and revisit, if applicable, the costs allocated to standby customers as they develop rates consistent with this order.

33. The utilities should propose ratemaking approaches to address any temporal inequities associated with their recommended cost allocation.

34. We are not precluded from recognizing the ability of the proposed ICE-T to promote state policy goals as expressed in AB 970.

35. Adoption of the ICE-T will complement existing programs for solar generation and will be consistent with incentive programs proposed to implement AB 970.

36. Interconnection fees for solar distributed generation up to 1 MW that does not export power to the grid should be waived.

37. Customer-generators must comply with the interconnection requirements spelled out in Rule 21 of each utility's tariff.

38. Utilities should inform us once they have reached a level of participation in net energy metering and ICE-T equal to 75% of the 0.1% aggregate demand limit.

INTERIM ORDER

Therefore, 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 file applications within 60 days of the effective date of this decision proposing standby rates that implement the policies set forth herein. Specifically, the utilities shall file applications that:

a) propose a Form Contract for Physical Assurance;

b) allow customers using onsite generation to pay no standby charges if they sign a contract providing the utility with physical assurance;

c) propose on-demand backup rates that recover fixed distribution costs through a $/kW reservation charge and variable distribution costs through a $/kWh usage charge;

d) propose scheduled maintenance rate options that recover only variable costs of distribution service from customers who offer physical assurance;

e) propose non-firm standby rate options that recover only variable costs of distribution service from customers who offer physical assurance;

f) propose an electricity procurement rate option, which may be a real time price, that will be paid by standby customers when the utility procures electricity on their behalf;

g) provide standby customers the option of procuring their own backup electricity supply, consistent with state law;

h) propose on-demand backup reservation charges that reflect the diversity of distributed generation customer loads and reliability of distributed generation facilities assuming a distributed generation penetration level higher than exists today;

i) price supplemental power at the otherwise applicable tariff rate;

j) allow customers to elect a reservation capacity. Use by the customer in excess of the elected capacity will result in upward adjustment of the reservation capacity for a term of one year;

k) establish standby rates using embedded costs consistent with the manner in which rates for other distribution services are calculated;

l) ensure that proposed standby rates do not include any costs associated with electricity procurement,

m) propose standby rates that allow customers to take service at transmission or distribution voltages;

n) propose standby rates that recover fixed transmission costs through reservation charges and variable transmission costs through usage based charges;

o) reflect in the proposed standby rates that solar generating units up to 1 MW that do not export power to the grid are not subject to standby rates; and

p) collect public purpose costs from standby customers on a $/kWh usage basis, consistent with haw it is collected from other distribution service customers.

q) Allocate costs to standby customers consistent with the policies adopted herein and propose ratemaking approaches to address any temporal inequities associated with the recommended cost allocation.

2. Within 15 days of the effective date of this order, PG&E, SDG&E, and SCE shall:

a) submit an advice letter to revise Rule 21 to reflect that interconnection fees for solar generating units up to 1 MW that do not export power to the grid will be waived. The Advice Letter will be effective on the date filed if Energy Division finds it in compliance with this order; and

b) Notify solar generating units up to 1 MW that do not export power to the grid that they will be served under the otherwise applicable tariffs for customers of their size and that any standby charges will no longer apply.

3. PG&E, SDG&E, and SCE shall file and serve a report in this docket and with the Director of the Energy Division once participation in the net energy

metering program and load exempt from standby charges under the ICE-T proposal reaches 0.075% of each utility's aggregate load.

This order is effective today.

Dated , at San Francisco, California.