Combined Heat and Power Partnership
California Standby Rates
|Date Last Updated||5/16/2013|
|Policy Type||State Utility Rate Policy|
|Policy Administrator/Contact Office||California Public Utilities Commission (CPUC)|
|Policy Initiation Date||5/22/2001|
|Policy Summary||An exemption from standby rates for CHP systems was established in Senate Bill 1-28 (SBX 1-28) and expired on June 1, 2011. Since then, standby rates are now addressed in each utility's general rate case. While the standby rate design of each utility will differ, the utilities are instructed to enact rates that account for the actual costs and benefits of distributed energy resources. The CPUC also specified that in establishing standby rates, a utility should ensure that customers with similar load profiles within a customer class will be subject to the same utility rates, regardless of their use of distributed energy resources. Specifically the CPUC orders 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 fixed standby charges if they sign a contract providing the utility with physical assurance.
c) Propose on-demand backup rates that recover facilities-related distribution costs through a $/kW reservation charge and variable distribution costs, including peak demand-related costs, through a $/kWh usage charge.
d) Propose scheduled maintenance rate options that recover only variable costs of distribution service, excluding peak demand-related costs, from customers who offer physical assurance.
e) Ensure that proposed standby rates separately identify any charges associated with electricity procurement.
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) Report on the extent of distribution level diversity and propose a diversity factor, if appropriate.
h) Price supplemental power at the otherwise applicable tariff rate.
i) Allow customers to elect a reservation capacity. Use by the customer in excess of the elected capacity will result in an immediate upward adjustment of the reservation capacity for a term of one year.
j) Establish standby rates using embedded costs consistent with the manner in which rates for other distribution services are calculated.
k) Propose standby rates that allow customers to take service at transmission or distribution voltages.
l) Propose standby rates that recover fixed transmission costs through reservation charges and variable transmission costs through usage based charges.
m) 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.
n) Collect public purpose costs from standby customers on a $/kWh usage basis, consistent with how it is collected from other distribution service customers.
o) 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.
The applications may also propose non-firm standby rate options that recover only variable costs of distribution service, excluding peak demand-related costs, from customers who offer physical assurance.
|CHP Eligibility Requirements||Does Not Specify|
|Eligible Project Size (MW)||Does Not Specify|
|Minimum Efficiency Required/|
Other Performance Requirements
|Does Not Specify|