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Connecticut’s Output-Based Emissions Standards for DG, A Survey of Rates for Customers with On-Site Generation, and Verm

Connecticut’s Output-Based Emissions Standards for DG, A Survey of Rates for Customers with On-Site Generation, and Vermont’s New RPS Law. Frederick Weston 17 June 2005. Connecticut’s DG Emissions Rule.

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Connecticut’s Output-Based Emissions Standards for DG, A Survey of Rates for Customers with On-Site Generation, and Verm

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  1. Connecticut’s Output-Based Emissions Standards for DG,A Survey of Rates for Customers with On-Site Generation,and Vermont’s New RPS Law Frederick Weston 17 June 2005

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

  6. Emissions Standards:Existing Generators

  7. Emissions Standards:New Generators

  8. Other State Actions • Massachusetts: Draft rule with technology-differentiated 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 > 50 kW (unless subject to new source review) to the model rule’s 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 Feet:Some 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 don’t 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 83:Full Requirements [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 75:Partial Requirements

  17. NSTAR G-3 Rate

  18. NSTAR Stand-By Delivery Rate

  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 T&D 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: • Connecticut’s DG emissions rule in greater detail

  24. Connecticut’s 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 state’s 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 Rule’s Phase One Attainment emissions limits to existing non-emergency generators • The rule applies the Model Rule’s non-attainment, three-phase standards to new non-emergency generators

  31. Emissions Standards:Existing Generators

  32. Emissions Standards:New Generators

  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 Standards:Compliance • Performance testing • Existing generators: within 180 days of the rule’s 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 Reductions:Flared 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 Reductions:CHP • 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 Reductions:CHP (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-differentiated 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 > 50 kW (unless subject to new source review) to the model rule’s attainment standards.

  39. Appendix B • Synapse-RAP stand-by rates survey report in greater detail

  40. Rates for Customers with On-Site DG: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.

  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 we’ve 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 Feet:Some 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 customer’s non-coincident peak, maximum potential demand, or contract demand, but they are intended to cover the cost of the customer’s contribution to coincident peak on the shared facilities (the rates, in effect, reflect the relationship between the average customer’s 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 don’t 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 customer’s 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 customer’s 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

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