Transcript Facilitating DR Development: Barriers, Interconnection

Facilitating DR Development:
Barriers, Interconnection,
Rates, and Ratemaking
June 16, 2003
Harrisburg, PA
The Regulatory Assistance Project
50 State Street, Suite 3
Montpelier, Vermont USA 05602
Tel: 802.223.8199
Fax: 802.223.8172
177 Water St.
Gardiner, Maine USA 04345
Tel: 207.582.1135
Fax: 207.582.1176
Website:
http://www.raponline.org
Institutional and Regulatory
Barriers
 Permitting and Siting Processes
– Multiple agency approvals may be needed
– Potentially complex and time-consuming
 Rates and Ratemaking issues
– Stand-by rates, exit fees, deferral rates
– What is reasonable? How to structure?
– Potential financial impacts on utilities
 Grid Interconnection Process
– Safety, power quality, distribution system capacity constraints vs
utility discouragement of DG
Institutional and Regulatory
Barriers
Market
– Day ahead, multi-settlement demand bidding
For all of these issues:
– Lack of technology information and generally
accepted standards
– Large variation in requirements from state-tostate, utility-to-utility, and project to project
– Often a lengthy, complex, and expensive
process
Ratemaking
Revenue erosion
– Methods for addressing potential negative
financial impacts on utilities
• Lost-revenue adjustments
• Performance-based rate-making
– Revenue caps PBR
– Removing the throughput disincentive: why
not?
Lost Profits Problem
Consider whether regulation may
unintentionally cause utilities to be hostile
to demand-side (baseload energy efficiency)
and distributed resources and, if so, what
regulatory fixes are available.
Cost-of-Service Regulation
 Regulation and utility profits do not work as
one might expect
 Once a rate case ends prices are all that matter
 Profits = revenue - costs
 Rev = price * volume
 In the short-run, costs are mostly unrelated to
volume; instead they vary more directly with
number of customers
 If demand-side investment causes volume to
decrease, utility profits drop
Lost Profits Math:
Vertically Integrated Utility
 Utility with $284 million rate base
 ROE at 11% = $15.6 million
 Power costs $.04/kWh, retail rates average $.08;
sales at 1.776 TWh
– At the margin, each saved kWh cuts $.04 from profits
– If sales drop 5%, profits drop $3.5 M
 Demand reductions equal to 5% of sales will cut
profits by 23%
Lost Profits Math:
Wires-Only Company
 Utility now has only a $114 million rate base
 ROE at 11% = $6.2 million
 Distribution rate of $0.04/kWh; throughput of
1.776 TWh
– If DR is located in low-cost areas, each saved kWh cuts
$.04 from profits
– If sales drop 5%: profits drop $3.5 M
 5% reduction in sales will cut profits by 57%
Performance-Based
Regulation
All regulation is incentive regulation
– Trick is to understand the incentives
PBR structural options
– Revenue caps, price caps, hybrids, rate freezes
• Scope, duration
PBR
Formula for revenue caps PBR
– % change in Revenue = It – Xt + Zt
Formula for price caps PBR
– % change in Price = It – Xt + Zt
Common elements
– It = Inflation in year t
– X = Productivity improvement in year t
– Z = Exogenous changes in year t
PBR
Per Customer Revenue Cap
 A cap is placed on distribution company revenues
 Cap is computed at beginning of first year as
average revenue requirement per customer (RPC)
 Allowed revenues at end of year computed as RPC
times number of customers.
 RPC adjusted in following years for inflation,
productivity, and other factors
 Rates set as usual: per kW and per kWh
 Utility and customers both have incentive to be
efficient
PBR
 Revenue caps v. price caps
– Cost-cutting incentives are the same
– Revenue caps make more sense if costs don’t vary with volume
• Per-customer revenue cap more accurately matches utility short-run
revenue need with short-run costs
– Retail prices still set on unit basis (per kWh, kW)!
– Price caps make more sense if costs vary with volume
– Primary difference is the incentive for DSM and demand response
• Firms under revenue caps want very efficient customers
• Revenue caps deals with lost sales disincentives without radical price
reforms
– Logic also applies to transmission companies
• On a total revenue basis, with performance measures for congestion
management. Can’t be done on a per-customer basis.
Rate Issues
Rate design – how does it encourage or
discourage distributed resources?
– Standard offer and delivery rates
• Time-differentiated rates: TOU, seasonal, etc.
– Stand-by or back-up service and exit fees
– De-averaged distribution credits
Rates
 Retail prices: do they send proper economic
signals? Do they reveal the value of DR?
 Stand-by rates:
– How are they calculated? As they set so as to
discourage on-site generation?
– What is the probability that the self-generating
customer will demand grid power at high-cost times?
 Generation displacement rates: energy at low rates
to deter threat of self-generation
 Exit fees: to recover distribution costs “stranded”
by departing or self-generating customers
Distribution Costs
Distribution costs vary greatly from place to
place and time to time
– Marginal costs range from 0 to 20 cents per
kWh
High cost areas can be urban or rural
Typically, around 5% of a distribution
system is "high cost" at any time
Distribution Pricing
Geographically de-averaging prices is
probably not the answer
Prices would range from 0 to 20 cents per
kWh
Neighbors could see widely different prices
Equity and customer acceptance issues
would be large
Distribution Credits
 Offering distribution credits can send economic
price signals with much less risk
– Calculated with reference to the avoided cost of new
distribution investment in high-cost areas
 Credits can focus on customer and vendor actions
 Credits can be limited to “qualifying DR”
– Defined by type, performance, emissions, output,
duration, etc.
 Can use standard payments and/or bidding
Interconnection
Most DG projects need access to the grid
– For back-up/standby operation
– To supply some portion of power consumption
– To sell excess power
Interconnection raises real and complex
issues of grid security and worker safety but
can also be a means of utility
discouragement of DG.
Developer Concerns
Interconnection is left to the utility, which
may see DG as a direct competitor.
Utility is free to set complex and expensive
study and equipment requirements.
– Usually handled on a case-by-case basis (except
for net metering)
There is little accountability or recourse for
delays or unfavorable outcomes.
Utility Concerns
DG could disrupt or destabilize the grid
either in normal operation or malfunction.
DG could create a safety risk to workers.
Utilities have historically controlled these
issues and have their own procedures,
which they consider to be best practice.
Widespread DG is new for many utilities.
Interconnection Issues
Technical and equipment standards.
Degree of standardization.
Organization of utility review.
Level of review and treatment for large vs
small systems.
Net Metering
A demonstrated and workable solution for
small systems.
“Standardized” rules for small systems
behind the meter.
– “Small” ranges from 3 to 100 kW
– Technology requirements are limited
Still wide variation from state-to-state.
For Larger Systems
Often considered with requirements for
large merchant plants but issues may be
very different:
– Cost
– Technology
– Where is the size cut-off?
Different technical and procedural
approaches required for different
applications
Standardized
Interconnection Procedures
Define the procedures, responsibilities, and
limitations for various parties
Being developed at different levels
– National: FERC, NARUC/NRRI
– State: California, Texas, New York,
Massachusetts
Too many standards?
Topics of Standardized
Interconnection Procedures
Standard Application
Expeditious Review
– Screening criteria (size, drawings, devices)
Standard Agreement
– Technical requirements
Utility Actions
Testing
Dispute Resolution
Technical Standards
Provide specific technical/equipment
requirements for interconnection.
Primary focus is IEEE stakeholder process
to define standards.
IEEE 1547 nearly complete.