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Cost Allocation for IROL Critical Generator CIP Costs

The ISO proposes a new tariff mechanism to allocate the costs of CIP equipment and procedures for IROL-critical generators to electric consumers through charges. This article discusses alternative cost allocation options and the need for transparency in billing.

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Cost Allocation for IROL Critical Generator CIP Costs

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  1. Cost Allocation for IROL Critical Generator CIP Costs Transmission Committee – March 27, 2019

  2. Background • The ISO plans to designate certain generators as Interconnection Reliability Operating Limits (IROL) “Critical” resources. • This designation may require these resources to add incremental CIP equipment and/or procedures. • The ISO says the cost of this incremental equipment and/or procedures cannot be competitively offered into the energy and capacity markets. • The ISO is proposing a new tariff mechanism that would allow “IROL-critical” generators to seek cost recovery for expenditures approved by FERC. • The ISO’s proposal would allocate these costs to electric consumers through charges born by Regional Network Load (i.e. transmission customers)

  3. Considerations for Cost Recovery • For most businesses, compliance with new regulations is a cost of doing business • Because only some generators are designated as IROL-critical and market-base cost recovery for these expenses, there may some justification for cost-based recovery. • Assuming that CIP costs for IROL critical generators are appropriately eligible for cost-based recovery, recovering these costs through transmission charges is inappropriate. • Transmission charges should primarily reflect the costs of building, operating, maintaining and ensuring the reliability of the transmission system. • Other rate mechanisms should be used to recover the costs of generation equipment or generator expenses.

  4. Alternative Cost Allocation Options • Cost allocation options exist other than Network Load. • Real-Time Load Obligation (RTLO), used for: • Winter fuel reliability programs and fuel security cost-of-service agreements (i.e. Mystic contracts) • Generator performance audit payments • Capacity Load Obligation • Primary mechanism for recovery of generator costs not covered by energy market (i.e. “missing money”) • Real-Time Non-Coincident Peak Load Obligations • Used for ISO Schedule 3 Reliability Administration Service (RAS) to provide other reliability and informational services. • Capacity Load Obligation or Real-Time Non-Coincident Peak Load Obligation are the most appropriate allocator for CIP costs for IROL critical generators • No matter the allocator, the ISO should create a separate billing item to facilitate transparency of these costs

  5. Costs Allocated to Regional Network Load NEW • Infrastructure • Post 1996 Infrastructure • Pre 1997 Infrastructure • Reliability • FCM PDFR Pro-ration Denied for Reliabiliity) • FCM RFR (Retained for Reliability) • High Voltage Control • System Restoration • Voltage Support • Administrative • ISO Dispatch & Control • NESCOE Budget • PTO Dispatch & Control

  6. Typical MA Eversource Residential Bill NEW

  7. Typical NH Eversource Residential Bill NEW

  8. Typical CT Eversource Residential Bill NEW

  9. ISO Self Funding Tariff – Schedule 3 NEW • Reliability Administration Service (Schedule 3) • The ISO provides Reliability Administration Service to administer the Reliability Markets, including the Forward Capacity Market, in accordance with Market Rule 1 and to provide other reliability and informational services. These services are of a type not directly related to the services provided under Schedules 1 and 2, and are expenses of operating the New England Control Area generally, rather than expenses attributable to serving a particular Customer.

  10. ISO Self Funding Tariff – Schedule 3 (cont) NEW • Examples of functions performed: • generation and demand dispatch associated with Reliability Markets; • Reliability Markets accounting; • billing preparation; • generation emissions analysis; • risk profile updates; • triennial review of resource adequacy; • studies and qualification of resources under FCM; • preparation of regional reports and load forecasts and profiles (Capacity, Energy, • Load and Transmission (“CELT”) Reports; reports to the Energy Information • Administration of the United States Department of Energy; reports to NERC; • Regional System Plan); • support of power supply, environmental, and market reliability planning activities; • market power monitoring, mitigation, and assessment for the Reliability Markets; and • formulation of additional market rules and proposals to modify existing rules.

  11. ISO Self Funding Tariff – Schedule 3 (cont) NEW • Schedule 3 allocates internal load activity based on Real-Time NCP [Non-Coincident Peak] Load Obligation. For Exports other than Coordinated External Transactions, Schedule 3 assesses a volumetric (per MWh) charge. Specifically, the ISO divides the Schedule 3 Revenue Requirement by the real-time load obligation forecasted for the upcoming year in the most recent CELT Report to yield the unitized rate per kW-month. The remaining revenue requirement for Schedule 3 (i.e., net of that allocated to Exports) is then divided by the total Real-Time NCP Load Obligation forecast to yield the unitized rate per kW-month.

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