Connecticut

1
Connecticuts Output-Based Emissions Standards
for DG,A Survey of Rates for Customers with
On-Site Generation,and Vermonts New RPS Law

• Frederick Weston
• 17 June 2005

2
Connecticuts DGEmissions Rule

• Section 22a-174-42 of the Regulations of
  Connecticut State Agencies (RCSA) went into
  effect January 1, 2005
• Mirrors the RAP Model Rule in the three key
  provisions
• Emissions standards
• Manufacturer certification
• Credits for CHP

3
Mechanism and Applicability

• Permit-by-Rule Compliance with the Connecticut
  rule provides a standardized exemption from the
  duty to obtain an individual permit pursuant to
  RCSA Section 22a-174-3a for the owners and
  operators of distributed generators.
• The rule is an optional compliance mechanism
  traditional new source review is available for
  owners and operators who do not choose to operate
  under the rule.
• The rule applies to existing (installed prior to
  1/1/05), new (installed after 1/1/05), or
  modified non-emergency generators with the
  following characteristics
• A nameplate capacity of less than 15 MW
• A potential to emit 15 tons/yr of any air
  pollutant (as defined in RCSA 22a-174-1)
• Not a new major stationary source and
• Not operated more than a number of hours as
  determined by a specified formula.

4
What Emissions Are Regulated and How?

• For NOx, PM, CO, CO2
• Output-based standards pounds per MWh
• For SO2
• Ultra-low sulfur fuel requirements
• For liquid fuels, following EPA on-road
  requirements
• For gaseous fossil fuels other than natural gas,
  no more than 10 grains of sulfur per 100 dry
  standard cubic feet
• Credits for flared fuels and CHP
• Also, on approval of the DEP, for on-site
  renewables and end-use efficiency
• Dual-fuel generators standards apply to
  gas-fired operations liquid-fuel ops limited to
  30 days/year

5
Emissions Standards

• The Connecticut rule applies the Model Rules
  Phase One Attainment emissions limits to existing
  non-emergency generators
• The rule applies the Model Rules non-attainment,
  three-phase standards to new non-emergency
  generators
• Compliance Manufacturer certification or
  performance testing

6
Emissions StandardsExisting Generators
Oxides of Nitrogen (lbs/MWh) Particulate Matter (lbs/MWh) Carbon Monoxide (lbs/MWh) Carbon Dioxide (lbs/MWh)
4.0 0.7 10 1900
7
Emissions StandardsNew Generators
Date of First Operation Oxides of Nitrogen (lbs/MWh) Particulate Matter (lbs/MWh) Carbon Monoxide (lbs/MWh) Carbon Dioxide (lbs/MWh)
On or after January 1, 2005 0.6 0.7 10 1900
On or after May 1, 2008 0.3 0.07 2 1900
On or after May 1, 2012 0.15 0.03 1 1650
8
Other State Actions

• Massachusetts Draft rule with technology-differen
  tiated standards, no CHP credit.
• New York Draft rule with RACT approach but
  output-based. CHP credit uncertain. New and
  existing units.
• Delaware Draft rule based on the model currently
  under consideration.
• New Jersey Draft rule recently released for
  comment.
• Rhode Island Has begun a pre-rulemaking
  stakeholder process, using Model Rule as the
  basis for discussions.
• Maine Rule adopted 1 August 2004, subjecting
  non-mobile generators gt 50 kW (unless subject to
  new source review) to the model rules attainment
  standards.

9
Some Stated Objectives of Pricing for Customers
with On-Site Generation

• 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
• To encourage (discourage) DG deployment
• Clean DG?

10
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 should pay their
  fair share
• Reliable analyses of the costs and benefits of
  on-site generation have not been performed

11
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

12
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
• Charges for the portion of shared distribution
  and transmission facilities attributed to the
  customer
• 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)

13
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

14
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

15
PGE Schedule 83Full Requirements
Schedule 83, Standard Offer Service, Large Non-Residential Schedule 83, Standard Offer Service, Large Non-Residential Schedule 83, Standard Offer Service, Large Non-Residential Schedule 83, Standard Offer Service, Large Non-Residential
Delivery Voltage Delivery Voltage Delivery Voltage
Secondary Primary Subtransmission
Basic Monthly Charge
Single-Phase Service 20.00
Three-Phase Service 25.00 150.00 500.00

Transmission Related Services
Per kW of monthly Demand 0.78 0.78 0.78

Distribution Charges
The sum of the following, per month
Per kW of Facility Capacity 2.27 1.65 0.32
Per kW of monthly Demand
First 30 kW 0.56 1.89 1.05
Over 30 kW 1.89 1.89 1.05

Energy Charge
Cost of Service Option, per kWh
1,000 kW Facility Capacity 0.04239 0.04083
gt 1,000 kW Facility Capacity
On-Peak Period 0.04507 0.04326 0.04254
Off-Peak Period 0.03743 0.03593 0.03534

System Usage Charge
Per kWh 0.00485 0.00354 0.00257

1 Costs for contingency reserves are bundled in
the energy charges. PGE also offers a variety of
market-based energy options not described here.
16
PGE Schedule 75Partial Requirements
Schedule 75, Partial Requirements Service Schedule 75, Partial Requirements Service Schedule 75, Partial Requirements Service Schedule 75, Partial Requirements Service
Delivery Voltage Delivery Voltage Delivery Voltage
Secondary Primary Subtransmission
Basic Monthly Charge
Single-Phase Service 20.00
Three-Phase Service 25.00 150.00 500.00

Transmission Related Services
Per kW of monthly Demand 0.78 0.78 0.78

Distribution Charges
The sum of the following, per month
Per kW of Facility Capacity 2.27 1.65 0.32
Per kW of monthly Demand
First 30 kW 0.56 1.90 1.06
Over 30 kW 1.90 1.90 1.06

Generation Contingency Reserves
Spinning Reserves
Per kW of Reserved Capacity gt 1,000 kW 0.234 0.234 0.234
Supplemental Reserves
Per kW of Reserved Capacity gt 1,000 kW 0.234 0.234 0.234

System Usage Charge
Per kWh 0.00485 0.00354 0.00257

Energy Charge
Baseline Energy Per Schedule 83 Per Schedule 83 Per Schedule 83
Scheduled Maintenance, max 744 hrs/ calendar year Daily or Monthly Fixed, per Schedule 83 Daily or Monthly Fixed, per Schedule 83 Daily or Monthly Fixed, per Schedule 83
Unscheduled Dow Jones Mid-Columbia Hourly Firm Electricity Price Index, plus wheeling charges and a 0.003/kWh recovery charge, and adjusted for losses Dow Jones Mid-Columbia Hourly Firm Electricity Price Index, plus wheeling charges and a 0.003/kWh recovery charge, and adjusted for losses Dow Jones Mid-Columbia Hourly Firm Electricity Price Index, plus wheeling charges and a 0.003/kWh recovery charge, and adjusted for losses
17
NSTAR G-3 Rate
NSTAR Rate G-3 NSTAR Rate G-3 NSTAR Rate G-3
Customer Charge, per month 237.07 237.07

October May June September
Distribution Charge, per kW/month 5.58 11.66
Transition, per kW/month 2.46 7.70
Transition, per kWh
Peak hours usage 0.01954 0.03119
Off-peak hours usage 0.00704 0.01044
Transmission, per kW/month 2.37 2.37
Supplier Services (Optional)
Default or Standard Offer As in effect per tariff As in effect per tariff
18
NSTAR Stand-By Delivery Rate
NSTAR Rate SB-3 NSTAR Rate SB-3 NSTAR Rate SB-3
Customer Charge, per month As per applicable rate schedule As per applicable rate schedule

Monthly Distribution Charge, per kW October May June September
Contract Demand lt 1,000 kW 3.58 6.65
Contract Demand gt 1,000 kW 5.02 9.33

Transmission No charge No charge
Transition No charge No charge
19
Comparison

• Annual costs for stand-by service, customer and
  distribution charges only, for a customer with a
  contract demand of 1,000 kW, at primary voltage
• PGE 53,760.00
• NSTAR 80,324.84
• Caveat This implies no judgment as to the cost
  bases of the rates or the cost characteristics of
  the two utilities.

20
Issues and Ideas

• Demand charges
• As-used Monthly, daily
• Ratchets
• 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
• Policy leadership assuring consistency among
  state agencies, utilities
• What technical issues are consistent across
  systems?
• When does a policy overlay make sense (beyond
  technical and economic issues)?
• Cost-shifting (revenue responsibility) vs. future
  cost avoidance
• How can rates for DG customers be structured to
  promote environmental policy objectives? Should
  they be?

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
Renewables underVermont S.52

• RPS beginning 7/1/13, equal to all incremental
  sales growth between 11/05 and 1/1/12, not to
  exceed 10 of 2005 sales
• Satisfied through contracts, RECs, or payments to
  a renewables fund or for end-use efficiency
• Sustainably Priced Energy Enterprise Program
  (SPEED) in lieu of RPS
• Supports long-term utility contracting for
  renewables (qualifying resources) and CHP
  (non-qualifying) between 2006 and 2012. If
  output from qualifying resources meets or exceeds
  the RPS requirement, then the RPS will not go
  into effect
• Passed House and Senate this month. Governor
  expected to sign.

23
Appendix A

• Connecticuts DG emissions rule in greater detail

24
Connecticuts Rule

• Section 22a-174-42 of the Regulations of
  Connecticut State Agencies (RCSA) went into
  effect January 1, 2005
• Mirrors the RAP Model Rule in the three key
  provisions
• Emissions standards
• Manufacturer certification
• Credits for CHP

25
RAP Model Rule for DG Emissions

• Developed by a public/private stakeholder group
  over a two-year period
• Funded by DOE/NREL
• Available at www.raponline.org
• Model Regulations for the Output of Specified Air
  Emissions from Smaller-Scale Electric Generation
  Resources, 31 October 2002 Review Draft

26
Optional Compliance Mechanism

• Permit-by-Rule Compliance with the Connecticut
  rule provides a standardized exemption from the
  duty to obtain an individual permit pursuant to
  RCSA Section 22a-174-3a for the owners and
  operators of distributed generators.
• RCSA 22a-174-3a contains the states new source
  review permit program.
• Actual emissions are limited to less than 15
  tons/yr of any individual air pollutant (the new
  source review permitting threshold).
• The rule is an optional compliance mechanism
  traditional new source review is available for
  owners and operators who do not choose to operate
  under the rule.

27
Applicability

• The rule applies to existing (installed prior to
  1/1/05), new (installed after 1/1/05), or
  modified non-emergency generators with the
  following characteristics
• A nameplate capacity of less than 15 MW
• A potential to emit 15 tons/yr of any air
  pollutant (as defined in RCSA 22a-174-1)
• Not a new major stationary source and
• Not operated more than a number of hours as
  determined by a specified formula.
• Intent of the formula is to limit emissions of
  generators eligible for the permit-by-rule to
  under 15 tons per year of any air pollutant. If
  a generator cannot meet the requirements of the
  rule (e.g., the limits or the operating-hour
  limitation), the operator would seek an
  individual permit under new source review.

28
Exemptions

• The rule does not apply to
• Generators or engines subject to 40 CFR 52.21,
  89, 90, 91, or 92
• Generators powered by fuel cells, wind, or solar
  energy.
• Emergency generators, which are regulated under
  RCSA 22a-174-22(a) (defines emergency).
• In Connecticut, an emergency generator is not
  considered a distributed generator and therefore
  cannot operate under the rule.

29
What Emissions Are Regulated and How?

• For NOx, PM, CO, CO2
• Output-based standards pounds per MWh
• For SO2
• Ultra-low sulfur fuel requirements
• For liquid fuels, following EPA on-road
  requirements
• For gaseous fossil fuels other than natural gas,
  no more than 10 grains of sulfur per 100 dry
  standard cubic feet
• Credits for flared fuels and CHP
• Also, on approval of the DEP, for on-site
  renewables and end-use efficiency
• Dual-fuel generators standards apply to
  gas-fired operations liquid-fuel ops limited to
  30 days/year

30
Emissions Standards

• The Connecticut rule applies the Model Rules
  Phase One Attainment emissions limits to existing
  non-emergency generators
• The rule applies the Model Rules non-attainment,
  three-phase standards to new non-emergency
  generators

31
Emissions StandardsExisting Generators
Oxides of Nitrogen (lbs/MWh) Particulate Matter (lbs/MWh) Carbon Monoxide (lbs/MWh) Carbon Dioxide (lbs/MWh)
4.0 0.7 10 1900
32
Emissions StandardsNew Generators
Date of First Operation Oxides of Nitrogen (lbs/MWh) Particulate Matter (lbs/MWh) Carbon Monoxide (lbs/MWh) Carbon Dioxide (lbs/MWh)
On or after January 1, 2005 0.6 0.7 10 1900
On or after May 1, 2008 0.3 0.07 2 1900
On or after May 1, 2012 0.15 0.03 1 1650
33
Emissions Standards Compliance

• Options Certification or performance testing
• Certification
• Demonstrated certification by CARB
• Certification by manufacturer testing
• Generator will meet standards for the lesser of
  15,000 hours or three years of operation in
  effect, a warranty
• Testing methods applicable EPA Reference
  Methods, CARB methods, or equivalent
• Liquid fuel reciprocating engines ISO Method
  8178

34
Emissions StandardsCompliance

• Performance testing
• Existing generators within 180 days of the
  rules effective date
• New or modified generators within 180 days of
  installation or modification (if modification
  increases emissions output)
• Testing methods applicable EPA Reference
  Methods, CARB methods, or equivalent
• Liquid fuel reciprocating engines ISO Method
  8178
• If unable to comply, operation must cease
  immediately
• The DEP may conduct field audits at its discretion

35
Credit forConcurrent Emissions
ReductionsFlared Fuels

• If a generator uses fuel that would otherwise be
  flared, the owner or operator may deduct the
  emissions that were or would have been produced
  through the fuel flaring from the actual
  emissions of the generator on a per-pollutant
  basis, for the purposes of calculating compliance
  with the requirements of this rule.
• Credit may be based on either the actual
  emissions offset (if able to be documented) or on
  default values specified in the rule.

36
Credit forConcurrent Emissions ReductionsCHP

• The owner or operator of a CHP system may receive
  a compliance credit against its actual emissions
  on a per-pollutant basis, as follows
• The power-to-heat ratio must be between 4.0 and
  0.15, and
• The design system efficiency must be at least 55
  percent.

37
Credit forConcurrent Emissions ReductionsCHP
(continued)

• CHP Credit, mathematically
• Credit lbs/MWhemissions
• (thermal system lbs/MMBtu)/(thermal system
  efficiency) 3.412/(power-to-heat ratio)
• Note Offset boiler emissions are capped at (a),
  for new installations, the standards for new
  gas-fired boilers as set out in 40 CFR 60,
  Subparts Da, Db, and Dc, or (b), for existing
  boilers, maximums specified in the rule. This
  latter provision strikes a balance between
  rewarding owners for removing an older, dirtier
  boiler and perpetuating those old boiler
  emissions with a CHP system that is dirtier than
  it needs to be. The efficiency of the displaced
  system is (a) a default of 80, (b) its actual
  design efficiency, or (c), in the case of
  retrofits, its historic efficiency, if it can be
  documented.

38
Other State Actions

• Massachusetts Draft rule with technology-differen
  tiated standards, no CHP credit.
• New York Draft rule with RACT approach but
  output-based. CHP credit uncertain. New and
  existing units.
• Delaware Draft rule based on the model currently
  under consideration.
• New Jersey Draft rule recently released for
  comment.
• Rhode Island Has begun a pre-rulemaking
  stakeholder process, using Model Rule as the
  basis for discussions.
• Maine Rule adopted 1 August 2004, subjecting
  non-mobile generators gt 50 kW (unless subject to
  new source review) to the model rules attainment
  standards.

39
Appendix B

• Synapse-RAP stand-by rates survey report in
  greater detail

40
Rates for Customers with On-Site DGThe 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.

41
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, and of
  issues for recommendations

42
Some Stated Objectives of Pricing for Customers
with On-Site Generation

• 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
• To encourage (discourage) DG deployment
• Clean DG?

43
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

44
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

45
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)

46
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
• The rates are typically multiplied by a
  customers non-coincident peak, maximum potential
  demand, or contract demand, but they are intended
  to cover the cost of the customers contribution
  to coincident peak on the shared facilities (the
  rates, in effect, reflect the relationship
  between the average customers coincident and
  non-coincident demand).

47
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)

48
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

49
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

50
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

51
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

52
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

53
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

54
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

55
PGE Schedule 83Full Requirements
Schedule 83, Standard Offer Service, Large Non-Residential Schedule 83, Standard Offer Service, Large Non-Residential Schedule 83, Standard Offer Service, Large Non-Residential Schedule 83, Standard Offer Service, Large Non-Residential
Delivery Voltage Delivery Voltage Delivery Voltage
Secondary Primary Subtransmission
Basic Monthly Charge
Single-Phase Service 20.00
Three-Phase Service 25.00 150.00 500.00

Transmission Related Services
Per kW of monthly Demand 0.78 0.78 0.78

Distribution Charges
The sum of the following, per month
Per kW of Facility Capacity 2.27 1.65 0.32
Per kW of monthly Demand
First 30 kW 0.56 1.89 1.05
Over 30 kW 1.89 1.89 1.05

Energy Charge
Cost of Service Option, per kWh
1,000 kW Facility Capacity 0.04239 0.04083
gt 1,000 kW Facility Capacity
On-Peak Period 0.04507 0.04326 0.04254
Off-Peak Period 0.03743 0.03593 0.03534

System Usage Charge
Per kWh 0.00485 0.00354 0.00257

1 Costs for contingency reserves are bundled in
the energy charges. PGE also offers a variety of
market-based energy options not described here.
56
PGE Schedule 75Partial Requirements
Schedule 75, Partial Requirements Service Schedule 75, Partial Requirements Service Schedule 75, Partial Requirements Service Schedule 75, Partial Requirements Service
Delivery Voltage Delivery Voltage Delivery Voltage
Secondary Primary Subtransmission
Basic Monthly Charge
Single-Phase Service 20.00
Three-Phase Service 25.00 150.00 500.00

Transmission Related Services
Per KW of monthly Demand 0.78 0.78 0.78

Distribution Charges
The sum of the following, per month
Per kW of Facility Capacity 2.27 1.65 0.32
Per kW of monthly Demand
First 30 kW 0.56 1.90 1.06
Over 30 kW 1.90 1.90 1.06

Generation Contingency Reserves
Spinning Reserves
Per kW of Reserved Capacity gt 1,000 kW 0.234 0.234 0.234
Supplemental Reserves
Per kW of Reserved Capacity gt 1,000 kW 0.234 0.234 0.234

System Usage Charge
Per kWh 0.00485 0.00354 0.00257

Energy Charge
Baseline Energy Per Schedule 83 Per Schedule 83 Per Schedule 83
Scheduled Maintenance, max 744 hrs/ calendar year Daily or Monthly Fixed, per Schedule 83 Daily or Monthly Fixed, per Schedule 83 Daily or Monthly Fixed, per Schedule 83
Unscheduled Dow Jones Mid-Columbia Hourly Firm Electricity Price Index, plus wheeling charges and a 0.003/kWh recovery charge, and adjusted for losses Dow Jones Mid-Columbia Hourly Firm Electricity Price Index, plus wheeling charges and a 0.003/kWh recovery charge, and adjusted for losses Dow Jones Mid-Columbia Hourly Firm Electricity Price Index, plus wheeling charges and a 0.003/kWh recovery charge, and adjusted for losses
57
NSTAR G-3 Rate
NSTAR Rate G-3 NSTAR Rate G-3 NSTAR Rate G-3
Customer Charge, per month 237.07 237.07

October May June September
Distribution Charge, per kW/month 5.58 11.66
Transition, per kW/month 2.46 7.70
Transition, per kWh
Peak hours usage 0.01954 0.03119
Off-peak hours usage 0.00704 0.01044
Transmission, per kW/month 2.37 2.37
Supplier Services (Optional)
Default or Standard Offer As in effect per tariff As in effect per tariff
58
NSTAR Stand-By Delivery Rate
NSTAR Rate SB-3 NSTAR Rate SB-3 NSTAR Rate SB-3
Customer Charge, per month As per applicable rate schedule As per applicable rate schedule

Monthly Distribution Charge, per kW October May June September
Contract Demand lt 1,000 kW 3.58 6.65
Contract Demand gt 1,000 kW 5.02 9.33

Transmission No charge No charge
Transition No charge No charge
59
Comparison

• Annual costs for stand-by service, customer and
  distribution charges only, for a customer with a
  contract demand of 1,000 kW, at primary voltage
• PGE 53,760.00
• NSTAR 80,324.84
• Caveat This implies no judgment as to the cost
  basis of the rates or the cost characteristics of
  the two utilities.

60
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
  decisions?
• 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

61
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 than non-DG
  customers?
• If not, will DG customers be penalized by full
  requirements tariffs?
• What costs does on-site generation impose on the
  system?
• Distinctions between T, D, and G
• What benefits does on-site generation provide the
  system?
• Diversity of opinion on diversity benefits
• 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

62
Issues and Ideas

• Demand charges
• As-used Monthly, daily
• Ratchets
• 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
• Policy leadership assuring consistency among
  state agencies, utilities
• What technical issues are consistent across
  systems?
• When does a policy overlay make sense (beyond
  technical and economic issues)?
• Cost-shifting vs. future cost avoidance
• How can rates for DG customers be structured to
  promote environmental policy objectives? Should
  they be?

63
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)