BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Order Instituting Rulemaking into Distributed Generation.
	Rulemaking 99-10-025
(Filed October 21, 1999)	

ADMINISTRATIVE LAW JUDGE’S RULING
REGARDING SCOPE OF PHASE 2 TESTIMONY

Summary
In Rulemaking (R.) 99-10-025, the Commission directed the Energy Division to conduct a workshop to discuss the scope of Phase 2 rate design testimony.  Energy Division conducted the Rate Design Workshop (workshop) on March 29, 2000.  I have consulted with the Assigned Commissioner’s office on the scope for Phase 2 testimony.  This ruling notifies parties of the issues to be covered in the second phase of written testimony.  Phase 2 testimony should be served by May 26, 2000 as set forth in the January 20, 2000 Scoping Memo.
Background
In preparation for the workshop, Energy Division issued a workshop notice and a list of potential issues for Phase 2 written testimony.  The list was developed based on issues originally identified in Decision (D.) 99-10-065.  The list contained both general guidelines and specific questions on stranded costs, implementation costs, standby, bypass, and distribution wheeling rates, flexible pricing and Performance-Based Ratemaking (PBR) mechanisms, and the potential impact of distributed generation on public purpose program funding. 
Energy Division invited parties to comment on the issue list, and to identify additional issues for discussion, on or before March 20, 2000.  Capstone Turbine, Pacific Gas and Electric Company, Southern California Edison Company, Pacific Bell Telephone Company, and the Office of Ratepayer Advocates submitted comments to Energy Division.  Their comments and proposed additional questions were incorporated into the list for further discussion at the workshop. 
During the workshop, participants discussed two documents:  the revised list of issues distributed by the Energy Division, and a list of rate design issues deferred to the workshop by the Interconnection Standards Working Group.  All questions were reviewed, discussed, and revised at the workshop.
Scope of Phase 2 Rate Design Testimony
Rate design and ratemaking proposals submitted in testimony should follow the principles adopted in D.99-10-065.  Each proposal should: 
1.	provide for fair cost allocation among customers;

2.	allow the utility distribution companies (UDCs) adequate cost recovery while minimizing costs to consumers; 

3.	facilitate customer-side distributed generation deployment; and

4.	send proper price signals to prospective purchasers of distributed generation. 

Testimony should identify how current rate structures and those proposed in other Commission proceedings may prevent or hinder deployment of distributed generation, and how rate structures could be modified to facilitate distributed generation deployment.  Parties should discuss the interrelationship among rate design issues:  stranded costs, bypass, demand, customer and grid charges, standby rates, and PBR and flexible pricing mechanisms.
Workshop participants observed that overlapping testimony would be unavoidable between first phase policy issues and second phase rate design issues regarding distribution wheeling.  Parties should provide a consistent approach in discussing the rate implications of the policies presented in their Phase 1 testimony.  Parties should also describe how distribution wheeling rates should be structured in the event the Commission requires the UDCs to provide an unbundled distribution wheeling service. 
Some participants raised the issue of localized distribution rates in both the Distribution System Planning and Operations and Rate Design Workshops. This issue is an appropriate topic for Phase 2 testimony.  Although this issue has impacts beyond distributed generation, and is being considered in several concurrent Commission proceedings, testimony in this proceeding should relate specifically to distributed generation.  
A number of rate design issues related to interconnection costs were identified through the Interconnection Standards Workshop process facilitated by the California Energy Commission.  Issues include cost recovery and allocation, such as who should pay for costs to interconnect to the distribution system and for interconnection studies, or if costs incurred by the first distributed generation customers on a specific circuit or feeder should be shared by subsequent distributed generation customers connecting to the same facilities.
These issues, along with additional issues identified by the workshop participants, have been compiled into a list of questions (Attachment A) that parties should address in their rate design testimony.  All questions proposed were reviewed and discussed at the workshop.  The exact questions proposed may not be reflected in the attached list, however, I believe that the list encompasses each of the questions, and ensures that parties can address such topics in testimony.  Attachment A provides a framework for the issues the Commission will consider in Phase 2 of this proceeding.  Parties are encouraged to present detailed testimony examining the issues identified in this ruling, but are not required to address each question.

Therefore, IT IS RULED that:
1.	Phase 2 testimony will address the rate design issues identified in the body of this ruling and in Attachment A.
2.	Consistent with the Scoping Memo, parties shall serve Phase 2 written testimony by May 26, 2000.
Dated April 14, 2000, San Francisco, California.

			
		Michelle Cooke
Administrative Law Judge	

CERTIFICATE OF SERVICE

I certify that I have by mail this day served a true copy of the original attached Administrative Law Judge’s Ruling Regarding Scope of Phase 2 Testimony on all parties of record in this proceeding or their attorneys of record.
Dated April 14, 2000, at San Francisco, California.

	
Mae F. Dyson	

NOTICE

Parties should notify the Process Office, Public Utilities Commission, 505 Van Ness Avenue, Room 2000, San Francisco, CA  94102, of any change of address to insure that they continue to receive documents. You must indicate the proceeding number on the service list on which your name appears.

ATTACHMENT A
Phase 2 Testimony Rate Design Questions

Stranded Costs:
1.	To what extent is stranded cost recovery appropriate in a competitive market?  What kinds of stranded costs may occur with the deployment of distributed generation? Define stranded cost and identify likely components.
2.	Provide a methodology for calculating stranded costs associated with distributed generation deployment.
3.	How should the Commission assess whether stranded costs have occurred from deployment of distributed generation?
4.	Discuss the policy conditions and market factors, which will impact the determination if there are stranded costs (i.e. future resolution of ownership issues of distributed generation). What method can be used to identify stranded costs?  How would stranded costs, if any, be reflected in the CTC or rates?
5.	What rates will affect or are applicable to the development of the distributed generation market?  Discuss how the rate design of these rates (including standby and bypass charges), and stranded costs will mutually affect one another.
6.	Should benefits and revenues be considered as offsets to any stranded costs? If yes, how?
Implementation Costs:
7.	Should implementation costs incurred to broadly accommodate distributed generation deployment, if any, be considered in order to facilitate distributed generation competition?  For example, how should system improvements to accommodate distributed generation be charged when costs cannot be ascribed to a specific generator?  How should these costs be accounted for through rate or non-rate vehicles? 

Standby Charges and General Rate Design for the Distributed Generation Market:
8.	Are standby charges appropriate in a competitive distributed generation market? How should standby charges be structured?
9.	Should the standby charge reflect the incremental cost of providing service? If so, should performance data be developed on the reliability of installed distributed generation facilities? How could such data be collected and used?
10.	Should the standby charge be based on the full costs of serving the customer? If so, how can the costs associated with providing standby service be quantified?
11.	What costs should be included in the standby charge?
12.	Identify and discuss how the current standby rate structure may prevent or hinder the deployment of distributed generation.   Discussion should include how these rates can be modified to facilitate distributed generation deployment.
13.	Do current standby rates accurately reflect the T&D cost of providing standby service?
14.	Does the recovered cost of standby facilities accurately reflect the probability that backup service is required?
15.	Should there be consistency of the rate design of standby charges among the UDCs? How can consistent rate design be ensured?
16.	Discuss how standby rate design options will affect end-user choice and cost allocation. Examples of rate design options could include standby rates that reflect:
a.	Different levels of reliability, frequency of use, or differing voltage levels
b.	Firm standby or non-firm service
c.	Fixed connection charge
d.	Demand structure and ratchets
e.	TOD/TOU structures
f.	Elimination of potential redundancies between demand and standby charges.
g.	Geographical impacts on standby costs.
h.	Grid or customer charges

17.	Identify and discuss how the current structure of rates or charges applicable to distributed generation customers may prevent or hinder the deployment of distributed generation.   Discussion should include charges of any otherwise applicable tariff, including the customer charge, fixed connection charge, demand charge, or proposed grid charges.  Discussion should include how these rates can be modified to facilitate distributed generation deployment. Identify and discuss the same for any rates and charges proposed in concurrent proceedings.

Distribution Wheeling and Distribution-Only Rates:
18.	If the Commission determines that distribution wheeling is applicable to distributed generation, how should distribution wheeling rates be structured?  For example, how should transmission be charged to end user customers taking power by wheeling through primary and/or secondary distribution only?  How should primary distribution be charged to end user customers taking power by wheeling via secondary distribution only?
19.	How can services be identified for unbundling to develop distribution-only tariffs?

Exit Fees/Bypass Charges, Pricing Flexibility, and PBR Proposals to Minimize Cost-Shifting:
20.	Are proposed mechanisms such as exit fees/bypass charges, pricing flexibility, and PBR incentives to offset cost-shifting from potential bypass appropriate in a competitive electric market?  Is the need to consider bypass charge proposals, exit fee proposals, or the option to offer of flexible pricing contingent upon the Commission’s decision on stranded costs?
21.	Are there differences between exit fees and bypass charges? Define “exiting customer”.
22.	Compare the use of pricing flexibility, exit fees, bypass charges, and PBR incentive mechanisms to minimize cost shifting or potential stranded cost from bypass due to distributed generation.  

a)	Explain the impact of each mechanism in reducing potential loss of revenues due to distributed generation bypass.   
b)	Evaluate how each mechanism would affect allocation of the revenue shortfall or stranded cost among stakeholders or remaining ratepayers; how will the remaining load be charged?
c)	Discuss the structure and application of these proposals to prevent cost shifting from potential stranded cost from bypass to distributed generation.  Testimony should include discussion of price floors and risk allocation where applicable to these proposals.

PBR Incentives to Incorporate Distributed Generation Deployment:
23.	What objectives or outcomes should a PBR achieve in order to minimize potential stranded costs and cost shifting and facilitate distributed generation deployment? For example, certain parties have proposed that mechanisms be developed to separate UDC revenues from throughput. 
24.	How could a PBR mechanism be designed to achieve these objectives or outcomes? How should distributed generation be incorporated in a PBR mechanism? 
25.	Evaluate the consistency of the proposed objectives or outcomes in response to question 23 with general PBR policy and structure.
26.	Evaluate the use of a PBR incentive mechanism with regards to the alternative mechanisms proposed to minimize cost shifting from potential bypass, such as pricing flexibility and exit fees/bypass charges.  
27.	What issues need to be resolved before a distributed generation PBR mechanism can be designed?

Public Purpose Program Funding:
28.	If end-use customers install distributed generation, what is the impact to public purpose funding? How could rates be designed to ensure continued funding for public purpose programs?
Localized or De-Averaged Rates:
29.	Are localized or deaveraged rates appropriate in a competitive distributed generation market?  Discuss whether distribution service rates could be further disaggregated to provide for more localized or deaveraged rates for the distributed generation market.  For example, is it possible to use de-averaged credits or limited term localized rates to send more accurate pricing signals specifically to distributed generation customers without impacting existing rate design of other customers? Discuss whether and how 

distribution service rates could provide an incentive mechanism for distributed generation in areas of high marginal cost.   Identify other rate mechanisms that provide clear signals to end users of the full costs of supplying their electric needs.
Interconnection Costs:
30.	What happens if a utility overhead line is fully depreciated and upgrades/replacements are needed for distributed generation interconnection.  Does the distributed generation customer pay for the upgrade/replacement cost?
31.	Should distributed generation customers be required to pay for distribution system upgrades that would have otherwise occurred in the absence of a distributed generation interconnection?
32.	Who pays for the costs of the interconnection study and how are such costs incorporated in rates?
33.	Should subsequent distributed generation customers on a particular feeder line be responsible for costs applied to the first distributed generation customer on a line?  If so, what type of crediting mechanism should be put in place for the first customer?
34.	What type of ratemaking approach should be used to recover interconnection costs (i.e. fixed vs. demand charges, marginal cost vs. average cost, etc)?
35.	Because of the "lumpy" nature of some distribution system upgrades, should a distributed generation customer pay for the "excess capacity" created by an upgrade necessitated by distributed generation but used by future customers? Should  customers using distributed generation for some or all of their local load be treated similarly for cost allocation purposes to a customer without distributed generation?
36.	Should incremental charges assessed to distributed generation customers be adjusted during periods of utility-imposed curtailments?  For example, utility-imposed curtailments may affect the demand ratchet upon which the distributed generation customer’s demand charge is based.  How should any relevant adjustments be applied to distributed generation customers?