Cost Recovery for IROL-Critical Generators in ISO-NE

1. march 27, 2019 | WESTBOROUGH, MA Jonathan Lowell (413) 540-4658 | jlowell@iso-ne.com Interconnection Reliability Operating Limit Critical Infrastructure Protection Cost Recovery

2. Generators designated by the ISO as “critical” to the determination of Interconnection Reliability Operating Limits (IROL) must meet higher North American Electric Reliability Corporation (NERC) Critical Infrastructure Protection (CIP) standards than “non-critical” generators • These costs cannot be competitively offered into the energy and capacity markets • ISO is proposing a new tariff mechanism that would allow “IROL-critical” generators and similarly-situated transmission facilities to seek cost recovery for expenditures approved by FERC • Today’s discussion • Quick, high-level review of background and problem definition • Discussion of questions and open issues from February meeting • Illustration of compensation and cost allocation timing • Discussion of potential alternatives to the ISO’s “cost-of-service” proposed design • Note that a FERC technical conference on March 28, 2019 may be addressing related topics, and could cause ISO to pause the stakeholder process to reassess the proposal

3. IROL cip Background Short review of important points from February 2019 Transmission Committee meeting

4. BackgroundNERC CIP Standards Abbreviated From 2/28/19 TC Meeting • NERC • Develops CIP standards defining measures users, owners, and operators of the Bulk Electric System (BES) must implement to protect against cyber and other threats • NERC Standard CIP-002-5.1a Attachment 1 determines a facility’s impact level • All generators that are part of the BES will be categorized as at least “Low Impact” • Facilities that meet Criterion 2.6 (critical to the derivation of IROLs) are classified as “Medium Impact” • For convenience in this presentation, facilities that meet Criterion2.6 are referred to as “IROL-critical”

5. BackgroundHow does the ISO determine that a specific facility is “IROL-critical”? New 3/27/19 • Methodology • The studies used to determine IROLs criticality are performed when major changes occur in the system (new generation, transmission or facility retirements) • Those studies note which facilities play a significant role in determining the IROL value • Types of equipment for which the ISO must have accurate info on status and parameter settings • Network model elements (transmission line impedances, transformer impedances and tap info, breaker status) • Facility modeling info (stability models for generators, exciters / AVRs, turbine governors, power system stabilizers, relays, etc.) • Fault clearing info from protection relays • What happens if ISO does not have accurate values for this information?

6. BackgroundHow does the ISO determine that a specific facility is “IROL-critical”? (cont.) New 3/27/19 • Factors that determine if a specific facility is "IROL-critical" • The factors include if the element is part of an IROL, if its loss is a critical contingency for the IROL or if facility can significantly impact the value of the IROL • How often is "IROL-critical" status reviewed? • At least annually - the studies which review this status are performed only when there is a significant change in the system, like major new transmission, new generation or a large facility retirement • How frequently in the past have facilities been added or dropped from the list? • Not all that often – a facility would normally comes off with new construction, which does not occur often; facilities may go on the list either when first coming on-line or when a significant change in the system occurs • IROLs in New England versus other ISOs • ISO NE has about as many IROLs as all other ISOs / RTOs together

7. BackgroundWho benefits from having “IROL-critical” generators secure their cyber systems? From 2/28/19 TC Meeting • IROLs are System Operating Limits that, if violated, could lead to instability, uncontrolled separation, or cascading outages that adversely impact the reliability of the BES • The limits are often designed to protect neighboring regions from disturbances that originate in a connected region and allow the ISO to maximize the use of the transmission grid, consistent with reliable operation • The facilities designated by ISO-NE as “IROL-critical”: • Protect other control areas from unanticipated events that might occur inside New England, and • Maximize internal transmission capability, which benefits all internal transmission customers

8. BackgroundWhat steps must be implemented by a facility to comply with the “medium risk” standard and how much does that cost? Abbreviated From 2/28/19 TC Meeting • Good question! • The requirements to be met by “Medium Impact” facilities are not clearly stated and require interpretation • Additional steps are required, beyond the steps required by all BES generators to meet Low Impact requirements • The ISO has no authority to interpret or enforce the NERC CIP requirements • The ISO is not positioned to determine the appropriate measures an “IROL-critical” generator should implement, or the reasonable cost of those measures • Compliance is not optional, and is periodically audited by NERC/NPCC

9. Iso-ne’s IROL-cip compensation proposal New OATT Schedule 17

10. Problem StatementHow can an “IROL-critical” facility obtain compensation for NERC mandated incremental CIP compliance costs? Abbreviated From 2/28/19 TC Meeting • The facility has no control or influence over the designation • Nor does the facility have control over factors that change over time, such as transmission topology, that may result in designation (or un-designation) as "IROL-critical" • Compliance is not optional • Most competing BES facilities must only meet “Low Impact” requirements • Prior FERC orders have confirmed that market participants should have a viable path to cost recovery for mandated costs • For example, see FERC Order 672, paragraph 259: “Pursuant to section 1241 of EPAct, the Commission will allow recovery of all costs prudently incurred to comply with the Reliability Standards.” • No such path currently exists for New England "IROL-critical" generators • Without compensation, long run incentives for timely, effective compliance are weakened

11. ISO Proposal – Cost of Service ApproachISO serves as “billing agent” for a facility’s incremental CIP costs filed with and approved by FERC Abbreviated From 2/28/19 TC Meeting • As described at the February TC meeting… • "IROL-critical" facilities submit a cost-of-service (CoS) to FERC for incremental CIP costs • Two types of incremental costs – recurring and non-recurring • Incremental costs approved by FERC will be: • Paid to the facility over a defined period • Non-recurring costs paid over 2 years in equal monthly amounts • Annualized recurring costs paid in equal monthly amounts that terminate after 3 years unless re-approved by FERC or no longer designated as "IROL-critical" • Charged to transmission customers on a monthly pro-rata basis

12. Can IROL-CIP compliance costs be recovered through the markets? New 3/27/19 • In general, when all resources must meet the same requirements, the answer is “yes” • When only a few competitors are faced with more stringent requirements, the answer is “no” • To clarify, “cost recovery” in this context is interpreted to mean a resource with additional CIP compliance costs imposed by NERC standards is financially no worse off than an identical non-critical facility • Infra-marginal resources may (or may not) earn sufficient revenues to cover total costs, including IROL-CIP costs, but the “IROL-critical” resource will be financially disadvantaged by the cost of CIP compliance

13. Can IROL-CIP compliance costs be recovered through the markets?Illustrative scenarios New 3/27/19 • Consider two identical existing resources, one “IROL-critical” and one not, with identical costs other than CIP compliance • In the energy market, CIP costs do not vary with production and would therefore not be reflected in a competitive energy offer • Both resources receive the same energy revenues • The “IROL-critical” resource earns no extra margin to offset compliance costs • In the Forward Capacity Market (FCM), both resources receive the same capacity revenues • The “IROL-critical” resource sees less earnings at the end of the day, due solely to designation by the ISO as “IROL-critical” • Suppose two identical new resources offer competitively into FCM, both are marginal when CIP compliance costs are excluded, but one will be designated in the future as “IROL-critical”: • A new resource will not know at the time of the Forward Capacity Auction (FCA) if it will be designated at some future time as "IROL-critical" (typical lead-time is 6-18 months prior to in-service date) • If both are infra-marginal in the FCA, they will receive the same capacity revenues • The "IROL-critical" resource has no opportunity to increase capacity revenues to offset CIP compliance costs

14. Important Elements of any IROL-CIP Cost Compensation Proposal New 3/27/19 • The ISO proposal has two principal parts, each of which can be considered independently • Determination of the just and reasonable incremental costs to be compensated • Specification of the way in which those costs will be allocated and charged out • Both aspects are discussed in the following slides

15. Determination of just and reasonable IROL-cip compliance costs Part 1

16. Part 1 - Determining the Costs to be CompensatedFeedback from Stakeholders – Preparing, filing, reviewing and contesting a CoS might be a significant effort New 3/27/19 • Concern that filings might be complex and time consuming to prepare • Numerous filings in the first months? • Similarly, concern that meaningful review and challenges might also be complex and time consuming • Would the ISO consider alternatives to the CoS proposal? • The ISO’s short answer – yes, if: • The proposal provides a cost estimation methodology that can be supported and defended as just and reasonable • The cost estimation methodology is broadly supported within NEPOOL • However, some words of caution – as discussed in February, the ISO tried unsuccessfully to develop a methodology that could meet these criteria • Very willing to hear and evaluate creative suggestions • Lacking broad support for an alternative, ISO currently plans to proceed with the CoS proposal • Plans could change! • FERC Technical Conference on March 28, 2019 on “Security Investments for Energy Infrastructure” • Discussion of compensation and incentives are on the agenda

17. Part 1 - Why propose a CoS Methodology?Why not a “proxy” rate or formula rate? Condensed From 2/28/19 TC Meeting • In 2017, ISO evaluated the possibility of creating a formula rate (i.e., a “proxy” rate. • Requested expenditure data on a voluntary, confidential basis, from the 21 facilities designated at that time as “IROL-critical” • Six participants responded, representing 7 stations (14 generators, ~3250 MW) • Reported costs included one-time capital investments and annually recurring O&M expenses • No obvious correlation to generator size, type, or vintage • Costs/MW tended to be lower for multiple designated units located at a single site • Possible reasons why costs are difficult to predict: • Cost may be very site-specific due to factors not readily apparent • Generators may be interpreting the NERC standards differently • Generators are designated as "IROL-critical" because of their unique characteristics and location on the grid in relation to interconnections with other control areas • There is no meaningful concept of a generic “replacement” for a specific "IROL-critical" generator • Survey data shows that costs cannot be reliably predicted • Development of a proxy rate for IROL-CIP costs is not feasible • Summary: ISO could not identify a supportable methodology to: • Determine clear and precise CIP requirements • Define an appropriate "IROL-critical" “proxy” generator • Estimate reasonable costs for unclear requirements for an undefined “proxy” generator

18. Part 1 - CoS Methodology and Implications Minor Mods From 2/28/19 TC Meeting • ISO would rely on FERC’s determination of acceptable costs for compensation • Facilities that wish to recover the cost of making the CoS filing should include that cost for FERC’s consideration • Some generators have incurred costs in the past when previously designated as “IROL-critical”, but are no longer "IROL-critical" • These costs will be eligible for compensation, if approved by FERC • Costs that are recovered through other means (e.g. a 3rd party contract, New England regional transmission rates) will not be eligible • Generator/facility CoS filings bear the burden of supporting all expenditures for which compensation is requested • Costs must be broken out by the specific generator or facility to which they apply • In the case of multiple IROL-designated generators at a station, common costs (if any) must be apportioned and allocated to a specific generator to enable the ISO to make appropriate payments based on ownership share • Costs not associated with a specific IROL-designated unit cannot be compensated through the new OATT schedule

19. Cost allocation Part 2

20. Part 2 - IROL-CIP Cost AllocationBackground New 3/27/19 • Accurate IROLs allow the ISO to maximize reliable utilization of the transmission system • The users of the transmission system, i.e. transmission customers, are the beneficiaries of a reliable transmission grid • The region has historically recovered transmission costs recovered through regional transmission rates, including RNS and TOUT • IROL-CIP costs are appropriately allocated to RNS and TOUT reserved capacity

21. Part 2 - IROL-CIP Cost AllocationGeneral Principles New 3/27/19 • Two standard cost allocation methodologies were considered • Cost causation • Beneficiary pays • “Cost Causation” - not particularly relevant in this situation • Although costs are incurred by "IROL-critical" facilities, the costs are not caused by the facilities • The cause is the need to comply with NERC standards, to ensure a stable, reliable transmission system • Neither the ISO nor NEPOOL participants could change behaviors to reduce or eliminate the cost • “Beneficiaries Pay” – most compelling principle in this situation • All users of the transmission system benefit from maximizing the reliable utilization of the grid resulting from accurate IROLs • Transmission system costs are currently recovered through regional transmission rates (RNS and TOUT) • Allocation of costs to generators creates an incentive to reduce compliance – this would not be a good reliability outcome

22. Part 2 - OP-24 Cost Allocation FollowupHow does the OP-24 cost allocation model relate to IROL-CIP costs? New 3/27/19 • A question was asked at the February TC meeting – why not allocate IROL-CIP costs to RTLO, as is being done with the ISO’s cost to construct generator relay software models? • What is “the OP-24 cost allocation model”? • ISO requires accurate relay models for transmission system reliability analysis • ISO plans to engage a consultant to build the necessary models using data supplied by generators • Cost of ISO’s consultant will be charged out via the ISO Self-funding Tariff (Schedule 3 – Reliability Administration Service) • ISO’s costs do not include participants’ costs for data submission costs or equipment (e.g. relays) • Schedule 3 includes the ISO’s administrative costs (energy dispatch, billing, studies, planning activities, market design and administration), and is allocated to RTLO • IROL-CIP costs are participants’ costs, not ISO costs • Not related to ISO’s administrative costs that flow through Schedule 3

23. Settlement timing

24. Compensation and Charges Timing Overview New 3/27/19 • Compensation/billing process begins in the month following notification by the "IROL-critical" facility of the incremental CIP cost amounts approved by FERC • If an acceptable formula rate alternative methodology is approved, the compensation/billing process could begin the month following ISO designation as "IROL-critical" • Payments and charges for that initial month appear on the monthly Non-Hourly Charges statement two months later • Billing determinants for the month are not available until late in the following month • This means the statement is always issued with a 2-month lag • Monthly payments for Non-Recurring costs continue for 24 months • This is to mitigate the potential for rate-shock • Payments for Non-Recurring costs do not terminate, even if the facility is no longer "IROL-critical" • Monthly payments for annualized Recurring costs continue for the earlier of: • 36 months • Removal of the facility from the list of "IROL-critical" designated facilities • Facility retirement • Notification of a new FERC order with a new approved cost amount • The 36-month window balances the risk of “stale costs” (e.g. costs that are no longer appropriate) against the costs required to prepare, submit and review a CoS filing

25. Settlement Timeline - ExampleAssuming facility receives FERC approval of costs in April 2020 New 3/27/19 • Facility owner/Lead Market Participant notifies ISO of the order and approved amounts before the end of April 2020 • Compensation process begins in May 2020, the month following ISO notification • Billing determinants for May 2020 only become available in late-June • First payment to the "IROL-critical" facility occurs in the monthly Non-Hourly Charges statement for July 2020 • First charges associated with that facility made to RNS & TOUT customers also occur in the monthly Non-Hourly Charges statement for June 2020 • Final payment & charges for approved Non-Recurring IROL-CIP costs would occur 24 months later, in June 2022 • The facility’s final associated payment & charges for Recurring IROL-CIP costs would occur 36 months later in June 2023 • Unless modified by new FERC order or terminated earlier due to removal from the "IROL-critical" designated facilities list

26. Stakeholder Schedule Updated 3/27/19 • Following the FERC Technical Conference, the ISO may need to reassess next steps with the committee on this proposal

27. ConclusionBased on the ISO’s current proposal Updated 3/27/19 • A new OATT schedule will be implemented to enable the ISO to act as a billing agent for “IROL-critical” facilities’ incremental CIP costs approved by FERC • ISO is proposing a solution where each “IROL-critical” facility seeking compensation submits a cost of service filing to FERC, and supporting the expenditures requested for cost recovery • This approach is feasible • ISO will consider alternatives that are widely acceptable to stakeholders • FERC technical conference on March 28, 2019 may be informative and may impact how ISO’s proposal evolves • Monthly CIP cost payments made to facilities will be charged monthly to transmission customers

28. Jon Lowell (413) 540-4658 | jlowell@iso-ne.com

29. Acronyms Used in this Presentation • BES = Bulk Electric System • CIP = Critical Infrastructure Protection • CoS = Cost of Service • ERO – Electric Reliability Organization • FCA = Forward Capacity Auction • FCM = Forward Capacity Market • IROL = Interregional Operating Limit • NERC = North American Electric Reliability Council • NPCC = Northeast Power Coordinating Council • OATT = Open Access Transmission Tariff • RTLO = Real Time Load Obligation

30. Appendix

31. Summary of Survey Results From 2/28/19 TC Meeting

32. Why is a Cost of Service / Billing Agent Approach Appropriate? From 2/28/19 TC Meeting • Medium Impact CIP compliance is not simply a “cost of doing business” that can be competitively priced into the market • Can’t be avoided by the generator – status is determined by the ISO based on factors beyond the generator’s control • Compliance is mandatory for the 15 stations (21 generators) currently designated as "IROL-critical" that must meet Medium Impact CIP requirements • The remaining 400+ New England generators larger than 1 MW are not required to meet this standard, or bear the associated cost • NERC CIP compliance is not a market service procured by the ISO under the terms of the ISO Tariff • The ISO has neither the authority, nor the expertise to determine if cost recovery is just and reasonable • Compliance is effectively a FERC requirement, and FERC has the requisite regulatory authority to determine the just and reasonable nature of the compliance costs