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1
Utility Rate Structures for Customers with
On-Site GenerationNECHPI Annual
ConferenceAlbany, New York

• Frederick Weston
• 6 April 2005

2
The Project

• Under a contract with the California Energy
  Commission (through the National Renewable Energy
  Laboratory), Synapse Energy Economics and RAP are
  surveying state policy on stand-by rates for
  customer-sited DG/CHP systems.
• The purpose is to identify the suite of
  innovative ratemaking policies that will best
  support the deployment of clean DG systems.

3
The Project

• Three parts
• Survey of a representative sample of states
• Arizona, California, Indiana, Massachusetts,
  Minnesota, New York, Oregon, Rhode Island, Texas,
  and Vermont
• Interviews with regulators, utility officials,
  consumers, manufacturers, developers, etc.
• Final report with policy recommendations
• First two parts are (largely) completed final
  report due in June.
• This presentation is a summary of what weve
  learned from the surveys and interviews

4
Some Stated Objectives of Pricing for Customers
with On-Site Generation

• To encourage (discourage) DG deployment
• Clean DG?
• To provide the services that DG customers want
  and need
• To give price signals that reflect the system
  costs and benefits of DG
• To cover the costs imposed on the system by such
  customers
• Charges should accurately reflect the temporal
  and geographic properties of cost causation
• To reflect the benefits bestowed on the system by
  such customers
• Reliability, diversity, avoided G, T, and D

5
From 30,000 FeetSome Recurring Themes

• DG reduces consumer demand for grid-supplied
  energy and can reduce demand for grid-supplied
  generation capacity, but the extent to which it
  will depends upon customer loads and the
  operational characteristics of the on-site
  generation
• DG can defer or avoid transmission and
  distribution investments, but again the extent to
  which it will depends upon customer loads, the
  characteristics of the on-site generation, and
  the characteristics of the distribution system
• On-site generation cannot avoid distribution
  investments that serve only the individual
  customer (can possibly affect sizing, however)
• The grid, and the reliability it provides, has
  value for which all customers must pay their fair
  share
• Reliable analyses of the costs and benefits of
  on-site generation have not been performed

6
General Features of Utility Rates for DG Customers

• Users with on-site generation are often referred
  to as partial requirements customers
• Typical services provided
• Stand-by
• Grid power during an unscheduled outage of the
  on-site generation
• Scheduled maintenance
• Grid power, without penalty or reservation
  charges, while the on-site generation is being
  serviced
• Supplemental (or baseline) Service
• Grid power in excess of that supplied by the
  on-site generation, often supplied at the
  applicable full-requirements tariff
• Economic replacement
• Low-cost (usually interruptible) grid power to
  displace on-site generation at times of utility
  surplus

7
Rate Components

• Stand-by and related rates are typically
  structured along conventional lines
• Customer charges
• Demand charges for capacity (per kW)
• Distribution, transmission, generation
• Bundled or un-
• Energy charges (per kWh)

8
Rate Components

• Distribution
• Fixed recurring customer charges for billing,
  metering, administration, etc. (daily or monthly)
• Demand charge components
• Charges for distribution facilities dedicated
  wholly to the customer (local or dedicated
  facilities)
• Some of which may be included in the fixed
  customer charges
• Assessed against either customer non-coincident
  peak demand, maximum potential demand, or
  negotiated contract demand
• Charges for the portion of shared distribution
  and transmission facilities attributed to the
  customer
• Because the rates are typically multiplied by a
  customers non-coincident peak, maximum potential
  demand, or contract demand, they reflect the
  average customers contribution to coincident
  peak on the shared facilities.

9
Rate Components

• Generation
• Demand charges
• Reservation fees, to cover the costs of
  generation capacity that will be needed to
  provide stand-by service, or
• Fees for contingency reserves, the amount of
  spinning and supplemental reserves that must be
  available to meet the load otherwise served by
  the on-site generator
• Energy
• Unscheduled, at market prices
• Scheduled, at tariffed or otherwise specified
  prices
• Risk and other cost adjustments (e.g., system
  usage fee)

10
Typical Tariff Features

• Customer size, as measured in MW
• Minimum amounts of contract demand
• Indiana (AEP) 500 kW, increments of 100 kW
• Exemptions if below a specified size
• Minnesota 60 kW
• Oregon 1 MW
• Texas for on-site renewables that dont export
  (considered energy efficiency)
• Note TX does not have stand-by service for
  partial requirements customers service is taken
  under regular tariffs
• New York 50 kW (contract demand) or if the DG
  serves no more than 15 of the on-site load
• Massachusetts (NSTAR) 250 kW and aggregations
  between 251 kW and 1 MW that serve no more than
  30 of the on-site load

11
Typical Tariff Features

• Technology
• Exemptions for renewables
• MA (NSTAR) Renewables as defined in other state
  policies, except fuel cells
• NY Designated technologies including CHP
• RI Eligible renewable energy resources up to
  an aggregate statewide cap of 3 MW
• Seasonal Cost Differences
• MA, NY, CA, AZ
• Time of Use
• Peak, off-peak AZ, CA, NY

12
Typical Tariff Features

• Billing Demand or Reservation Capacity
• Most tariffs tie a customers billing demand to
  usage coincident with system peak or peak periods
  of usage (e.g., Rhode Island, Texas, Minnesota,
  and Oregon).
• Contract demand, as agreed on by the customer and
  stand-by service provider not necessarily
  related to the size of the on-site generation
• Physical Assurance Customer guarantee that, if
  its generator trips, the customers demand for
  grid power will not exceed a specified level
  (often involves instantaneous load shedding)
• Billing demand will be used to calculate total
  charges for shared facilities and generation
  capacity

13
Arizona

• Tucson Electric Powers Partial Requirements
  Usage Percentage (PRUP)
• Determines whether a customer takes service under
  the standby tariff or the supplemental.
• Effectively caps the number of hours per billing
  period during which a customer can rely on
  back-up power.
• The PRUP is the ratio of Backup Energy Purchased
  to the product of Billing Demand for standby
  service and hours in the billing period. If the
  PRUP exceeds five percent in a period, the
  customers Energy Charge is converted to the
  Supplemental Service energy charge for all
  kilowatt-hours in excess of the five percent.
• Arizona Public Service
• Minimum number of stand-by hours/month
  allocation of hours determined by customer
  penalties for violations
• Must maintain a 75 capacity factor over rolling
  18 months
• Discounts for achieving higher CFs

14
California

• DG, 5 MW and less, that meets certain fuel and
  environmental criteria is exempt from stand-by
  charges
• Solar generation of up to 1 MW that does not
  export to the grid is exempt from any additional
  charges
• Other specified DG is exempt from exit fees or
  cost responsibility surcharges

15
Minnesota

• Customers are eligible for PUC-approved credits
  for
• Avoided distribution costs and avoided line
  losses
• If renewable DG, avoided purchases of green power
• Avoided purchases of SO2 allowances
• To receive the credits, customer must fund a
  utility study to determine whether the customers
  load and generation profiles justify them

16
New York

• Contract demand charges for local facilities
  costs
• Based on a customers potential maximum electric
  load, determined by the utility, and set yearly
• On-peak, daily as-used demand charge for shared
  facilities costs
• Assessed during daytime (e.g., from 8am to 10pm)
  and for the daily amount of standby service
  demand (kW) a customer uses.
• No differentiation between distribution prices
  for scheduled and unscheduled outages
• On the grounds that the costs of the wires do not
  differ according to the portion of the customers
  load served by DG or whether an outage is
  scheduled or not

17
Oregon (PGE)

• Full requirements rates for local and shared
  facilities
• Times the average of the two highest months in
  previous 12-month period
• Will reflect the impacts (in kW) of an outage of
  on-site generation if replaced by Unscheduled
  Energy
• Rates for Contingency Reserves
• DG subject to same requirement of other
  generators they must have or buy spinning and
  supplemental reserves which together equal to 7
  of their nameplate capacity
• Rates for the two contingency reserves are equal
  to 7 of the cost of reserve capacity (adjustable
  by agreed-on, instantaneous load reductions)
• 0.468 per kilowatt per month (2,808/yr for a
  500-kW reserved capacity)
• Multiplied by reserved capacity in excess of 1 MW
• Supplemental service at full requirements tariffs
• Scheduled maintenance
• Unscheduled Energy

18
Issues and Ideas

• What kinds of service do DG customers really want
  and need?
• What is the probability that stand-by service
  will be needed and how should the various rate
  elements be adjusted to reflect it?
• Sliding scale of performance-based stand-by
  charges? Based on capacity factor or number and
  duration of calls for stand-by?
• How do rates affect customer capital allocation
  decision?
• What is the proper differentiation between local
  and shared facilities? Does DG alter the
  allocation of shared facilities to DG customers?
  How easily and quickly are shared facilities
  redeployed?
• Tension between the fixed nature of the
  facilities in the short run and their
  demand-driven nature in the long-run

19
Issues and Ideas

• How do the load profiles of customers with DG
  differ from those without? Do they?
• What rate design policies flow from this? Should
  DG customers be treated differently from non-DG
  customers?
• If not, will DG customers be penalized by full
  requirements tariffs?
• What costs does on-site generation impose on the
  system?
• What benefits does on-site generation provide the
  system?
• Diversity of opinion on diversity benefits e.g.,
  CA acknowledges them, MN does not
• Cost of service reductions from avoided
  generation, transmission, and distribution costs
  e.g., MN recognizes
• Environmental, reduced losses, improved
  reliability e.g., in recognition of such, RI
  allows PUC to order rate discounts

20
Issues and Ideas

• Demand charges
• As-used Monthly, daily
• Ratchets
• Policy leadership assuring consistency among
  state agencies, utilities
• E.g., How can rates for DG customers be
  structured to promote environmental policy
  objectives?
• Distribution planning and the sizing of the wires
• Ability of planning methods to properly value DG
• Incentives for DG incentives for utilities
• Impacts on utility profitability regulatory fixes

21
Issues and Ideas

• Best efforts or Non-Firm Stand-by Service
• A customer would not be creating any requirement
  for the utility to invest in any generation or
  transmission plant or equipment to provide
  standby service. This could justify no demand
  charge at all.
• Low Demand, High Energy
• Demand charges based on a fraction of nameplate
  capacity, high energy charge
• Reflects low probability of DG outages coincident
  with peak
• Strong incentive to maintain and operate DG
• Similar to RI settlement where customers are not
  charged TD for back-up, only for supplemental
  (reflects diversity)

22
An Appeal

• Thoughts, comments, suggestions on the project
  are all warmly welcomed
• Lucy Johnston, Synapse Energy Economics
• ljohnston_at_synapse-energy.com
• Rick Weston
• rapweston_at_aol.com