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1
Facilitating DR DevelopmentBarriers,
Interconnection,Rates, and Ratemaking

• June 16, 2003
• Harrisburg, PA

2
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

3
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-to-state, utility-to-utility, and project
  to project
• Often a lengthy, complex, and expensive process

4
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?

5
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.

6
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

7
Lost Profits MathVertically 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

8
Lost Profits MathWires-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

9
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

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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

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PBRPer 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

12
PBR

• Revenue caps v. price caps
• Cost-cutting incentives are the same
• Revenue caps make more sense if costs dont 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. Cant be
  done on a per-customer basis.

13
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

14
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

15
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

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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

17
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

18
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.

19
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.

20
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.

21
Interconnection Issues

• Technical and equipment standards.
• Degree of standardization.
• Organization of utility review.
• Level of review and treatment for large vs small
  systems.

22
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.

23
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

24
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?

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Topics of Standardized Interconnection Procedures

• Standard Application
• Expeditious Review
• Screening criteria (size, drawings, devices)
• Standard Agreement
• Technical requirements
• Utility Actions
• Testing
• Dispute Resolution

26
Technical Standards

• Provide specific technical/equipment requirements
  for interconnection.
• Primary focus is IEEE stakeholder process to
  define standards.
• IEEE 1547 nearly complete.