Addressing Potential Loss of FERC Jurisdiction over Demand Response

1. MAY 6, 2015 Henry Yoshimura Director, Demand Resource Strategy Contingency Plan Addressing the Potential Loss of FERC Jurisdiction Over Demand Response The Future of Demand Response in New England’s Wholesale Markets

2. Introduction Background and Legal/Regulatory Uncertainties

3. ISO issues a paper describing how demand response could provide operating reserve on a real-time and a forward basis September 2013 In response to Order 745, ISO proposes to fully integrate demand response into the energy markets August 2011 The ISO’s Development Objective Was to Fully Integrate Demand Response in Wholesale Markets The FERC accepts ISO’s proposal to fully integrate demand response into wholesale markets by June 1, 2017 January 2015 October 2014 ISO proposes rules allowing demand response to provide operating reserve, completing the full integration of demand response into wholesale markets April 2012 ISO proposes to modify capacity market rules to make capacity obligations of generators and demand response fully comparable

4. Legal Challenges Create Uncertainty for Demand Resources • March 15, 2011: FERC issues Order 745 requiring full LMP payment for demand response when the benefit to consumers of dispatching the demand response exceeds the cost of paying the LMP • May 23, 2014: In EPSA v. FERC (“EPSA”), the DC Circuit Court vacates Order 745 on the basis that: • The decision was arbitrary and capricious • FERC has no jurisdiction over demand response • Court mandate was stayed pending appeals • ISO continuing to administer current DR market rules • January 15, 2015: The Solicitor General files with the U.S. Supreme Court to review the DC Circuit Court decision on FERC’s behalf • By June 2015—Likely decision by the Supreme Court on whether to review EPSA • By June 2016—Supreme Court’s final order (if it decided to review EPSA in 2015)

5. Potential Future Outcomes Uncertain and Interdependent • If the Supreme Court declines to review EPSA, the DC Circuit’s decision will stand • Order 745 will be vacated • On remand, the FERC must establish compliance requirements that will depend heavily on whether it interprets EPSA narrowly or broadly • If the Supreme Court agrees to review EPSA, it will eventually issue a decision on the question of FERC jurisdiction over demand response, which could include new findings • The Supreme Court’s decision could be more restrictive or expansive compared to the DC Circuit’s decision • Based on the FERC’s interpretation of the Supreme Court’s decision, the FERC must then establish compliance requirements on remand • If the Supreme Court declines to review EPSA or affirms EPSA, the ISO will need to develop a different approach to integrating Demand Resources in ISO-administered markets

6. Implications of the Legal Proceedings to Date • Uncertainty over the final disposition of Order 745 presents the region with a market development dilemma • Suspending all development work delays the achievement of comparable treatment of resources in the markets if EPSA is ultimately reversed • If software and infrastructure are developed, resources would be wasted if EPSA is ultimately upheld • And more resources may be needed to dismantle that which was developed

7. Going-Forward and Contingency Planning for Demand Response in New England Given this uncertainty, the ISO believes that the best course ofaction at this time is as follows:

8. Complete work in progress To Improve Current Demand Resource Program Administration

9. ISO Will Propose Market Rule Changes to Improve Current Demand Resource Administration • Methodology for estimating Demand Response Baselines • Change the current 90/10 approach to a 10-day rolling average to maintain baseline accuracy while reducing administrative complexity • Auditing rules for Real-Time Demand Response (“RTDR”) and Real-Time Emergency Generation (“RTEG”) assets located at the same end-use customer facility • Modify the current auditing rules to prevent potential double counting of reductions credited to both the RTDR and RTEG asset at a facility while reducing the frequency of auditing facilities without co-located RTEG assets • The definition of Distributed Generation • Revise the definition of Distributed Generation – i.e., generators behind a Retail Delivery Point that reduce load served by the power system – to reflect actual or expected production and consumption • These improvements will be discussed separately from any contingency plan activities

10. Contingency planning – Part 1 Delay Full Integration

11. Regardless of Legal Proceedings and Interpretations, Demand Response Full Integration Must be Delayed • At minimum, full integration of demand response into the energy and reserve markets requires a two-year implementation • To meet a June 1, 2017 implementation date, therefore, the ISO would need to start expending substantial time, money, and effort now (at the expense of other projects) • Prudent resource management requires that the ISO hold off on full-integration implementation efforts • If EPSA review is declined, full integration of demand response must be permanently suspended and replaced by a yet-to-be-determined approach pursuant to Commission guidance on remand • If EPSA is reviewed and the ISO moved forward to implement full integration by June 1, 2017, substantial resources would be wasted if the Supreme Court ultimately upholds EPSA

12. Market Rule Changes Needed for a One-Year Delay • At least a one-year delay in the implementation of full integration is needed given uncertainty in the outcome of the legal and regulatory process • Accordingly, the ISO will propose that the currently effective rules for Real-Time Demand Response Resources be extended to apply to the eighth Capacity Commitment Period – i.e., June 1, 2017 through May 31, 2018 • If EPSA is ultimately upheld, the extension gives a better opportunity to develop and implement an alternative approach by June 2018 • If EPSA review is granted, a final decision is likely by June 2016, which should be sufficient time to implement full integration by June 2018 if EPSA is reversed

13. Contingency planning – PART 2 Responses to Different Interpretations of EPSA

14. Scenario 1 Narrow Interpretation of EPSA Prohibits Demand Response Participation on the Supply-Side of Energy Markets

15. A Narrow Interpretation of EPSA Excludes DR Participation in the Energy Markets Only • Order 745 required that demand reductions produced by demand response resources be paid the full LMP, subject to certain conditions • Passive Demand Resources – i.e., On-Peak or Seasonal-Peak Demand Resources – did not qualify for energy payment under Order 745, so vacating Order 745 has no effect on those resources in this scenario • A narrow interpretation of EPSA (from the FERC, or as affirmed by the Supreme Court) would have an immediate effect on demand response participation in the wholesale energy markets as a supply-side resource

16. Overview • Assuming a one-year delay in the full-integration of demand response, Demand Resources are not integrated into or required to participate in the energy markets before June 1, 2018 • RTDR and RTEG are paid the full LMP when dispatched in response to OP-4 and when audited • RTDR may also opt to participate in a transitional price-responsive demand program that pays participants the full LMP when its offer is in-merit • On and after June 1, 2018 (CCP 9 and beyond), demand response with a Capacity Supply Obligation (“CSO”) is integrated into and required to offer in the energy markets at a level at or above its CSO • Under a narrow interpretation of EPSA, demand response could not participate in the energy market, and thus cannot fulfill FCM requirements

17. Scenario 1: Demand Response in FCM • Before June 1, 2018 (presuming a one-year extension of the rules governing RTDR participation in the FCM), the following would be eliminated: • Energy payments to RTDR and RTEG resources • Transitional price-responsive demand program • On and after June 1, 2018, require demand response resources be subject to ISO dispatch to reduce demand prior to, or concurrent with, a scarcity condition under FCM Pay-for-Performance (PFP) construct • This approach gives demand response and generation resources comparable performance incentives

18. Scenario 1: Demand Response in FCM(continued) • The post-June 1, 2018 market design and associated rule changes must consider: • The price formation problem that demand response dispatch could create when resources are scarce and prices should be high • Potentially addressed by establishing an administratively-determined dispatch price for demand response resources • The application of FCM PFP penalties if the ISO does not dispatch demand response resources that were otherwise available during a scarcity condition • Developing performance rules for demand response resources comparable to those of generators • Allowing demand response to provide Operating Reserve if the resource meets the definition of a Fast Start Demand Response Resource

19. scenario 2 Broad Interpretation of EPSA Prohibits Demand Response Participation on the Supply-Side of Energy, Capacity, and Ancillary Service Markets

20. A Broad Interpretation of EPSA More Widely Excludes DR Participation in the Wholesale Markets • Linkages among the energy, capacity, and reserve markets may prompt a broad interpretation of EPSA, limiting Demand Resource participation across more than just the energy market • Forward Capacity Market (FCM) * • All Demand Resources types receive wholesale capacity payments for reducing retail customer demand • Potential vulnerability to a jurisdictional challenge on the basis of EPSA • Impact on all Demand Resources in the FCM, including Real-Time Emergency Generation, On-Peak Demand Resources and Seasonal Peak Demand Resources (i.e., Distributed Generation and/or Energy Efficiency), as well as demand response resources • Real-Time and Forward Reserves • Operating Reserve is provided by resources that can provide energy quickly (within 10 or 30 minutes) • Energy market offers used to designate resources to provide reserves * Applying EPSA to DR that cleared in past FCAs for future commitment periods adds complexity

21. Background • The analysis used by the DC Circuit to vacate Order 745 could be used to advance the notion that the FERC likewise lacks jurisdiction to allow Demand Resources to participate in the FCM and possibly the ancillary service markets • PJM approached this possibility by proposing an approach that allows demand resources to participate on the demand-side of the capacity market through load-serving entities (LSE) • Whitepaper issued October 6, 2014: The Evolution of Demand Response in the PJM Wholesale Market • Market Rule revisions filed January 14, 2015 • The Commission rejected the filing on March 31, 2015, based on the finding that it was premature

22. PJM Demand-Side ProposalSee Appendix A of accompanying paper for more details and examples • LSEs submit load reduction bids into the capacity market, which would be integrated into the demand curve of the market • Participation requires that the resource owner be an LSE themselves or work with an LSE to meet cleared load reduction obligations • Cleared load reduction bids decrease the amount of capacity purchased in the market and produce lower capacity clearing prices • There are no capacity and energy payments for load reductions • Rather, cleared load reductions decrease an LSE’s capacity obligation and creates a lower capacity charge • In real-time, any reduced load decreases an LSE’s energy charge priced at the full LMP

23. Overview of Demand-Side Options

24. Option 1: Reducing the ICR • Historical load data does not account for the impact of any additional Demand Resources that may be installed in the future • The future impact of additional Demand Resources can be addressed by reducing the ICR before conducting the FCA • This approach is already being used in transmission planning for energy efficiency, and is planned for PV-based distributed generation not participating in the wholesale markets • The temporal and behavioral nature of demand response makes forecasting the amount of demand response that may occur in a future period complex • There is a risk that the additional Demand Resources may not be installed by the relevant Capacity Commitment Period • Those installing Demand Resources do not get an immediate and proportional reduction in capacity charges, which reduce the incentive to install them • Since the additional Demand Resources upon which the ICR was reduced are not supply resources with a CSO, financial assurance requirements and performance penalties are not imposed on these resources • Qualification and critical path schedule monitoring process could help address this risk; performance incentives needed for demand response to perform in real time

25. Option 2A: Revise FCM Cost AllocationSee Appendix B of accompanying paper for a detailed set of formulas and examples • Similar to approach taken under FCMPFP for capacity suppliers, LSEs would incur a monthly base and performance charge for FCM costs • Base charges could be set using the current approach, which is based on customer coincident peak contribution percentages • The incentive improvement comes from the performance charge, which is applied to allLSEs • During a scarcity condition, LSEs consuming less than their allocated share of available capacity would see their performance charge and associated FCM charge go down; the converse is true for those consuming more • Any increase in charges billed to over-consuming LSEs would be used to decrease the FCM charges of under-consuming LSEs • This approach gives LSEs the incentive to use Demand Resources (where cost-effective) to control their customers’ energy consumption to a level at or below their allocated share of capacity that is available to meet energy requirements during a scarcity condition • The approach recognizes that is it the collective actions on both the supply- and demand-sides of the market that creates and alleviates scarcity conditions

26. Option 2B: Allow LSEs to Bid Demand ReductionsSimilar to PJM’s Demand-Side Approach—See paper’s Appendix B for formulas and examples • LSEs may bid and clear demand reduction offers, similar to the PJM demand-side approach • Allows LSEs to specify their sensitivity to capacity prices, and to implement additional, cost-effective Demand Resources to avoid high prices • An LSE’s allocated share of capacity – and thus its total FCM charge – is reduced by any cleared demand reduction obligations • An LSE’s base charge is reduced each and every month by any cleared demand reduction obligations • During a scarcity condition, an LSE consuming less than its allocated share of available capacity, which has been adjusted by any cleared demand reduction obligation, would see its performance charge and associated FCM charge go down; the converse is true for those consuming more • If any demand reduction offer clears the FCA, total capacity acquired through the FCA and the capacity clearing price are both reduced

27. Conclusion Contingency Planning Process Flow and Timing

28. Contingency Planning Process Flow Narrow Interpretation of EPSA DR may not participate in the wholesale energy markets as a supply-side resource; participation in capacity and ancillary service markets permissible Broad Interpretation of EPSA DR may not participate as a supply-side resource in the wholesale energy, capacity or ancillary service markets

29. Proposed Schedule

31. appendix Detailed Review of the Options Involving Revised FCM Cost Allocation

32. Option 2A: Revise FCM Cost Allocation • Similar to approach taken under FCM PFP for capacity suppliers, LSEs would incur a monthly base and performance charge for FCM costs • Base charges could be set using the current approach, which is based on customer coincident peak contribution percentages • The incentive improvement comes from the performance charge, which is applied to allLSEs • During a scarcity condition, LSEs consuming less than their allocated share of available capacity would see their performance charge and associated FCM charge go down; the converse is true for those consuming more • Any increase in charges billed to over-consuming LSEs would be used to decrease the FCM charges of under-consuming LSEs • This approach gives LSEs the incentive to use Demand Resources (where cost-effective) to control their customers’ energy consumption to a level at or below their allocated share of capacity that is available to meet energy requirements during a scarcity condition • The approach recognizes that is it the collective actions on both the supply- and demand-sides of the market that creates and alleviates scarcity conditions

33. Summary of Option 2A: FCM PFP for the Demand Side • FCM Charge = Base Charge + Performance Charge • Base Charge = (NRC Price × Share of Total CSO) • NRC Price = Net Regional Clearing Price • Share of Total CSO = SCPC % × Total CSO MW • SCPC % = Sum Coincident Peak Contribution Percentages • Performance Charge = Performance Payment Rate × Demand Score • Demand Score = Actual MW Consumption – (SCPC % × Available Capacity × Demand Balancing Ratio) • Demand Balancing Ratio = Total System Load Available Capacity

34. Two-Settlement Capacity Market Design for the Demand Side of the FCM • Monthly FCM costs could be charged in the form of a base and performance charge as shown in equation (1) below: (1) FCM Charge = Base Charge + Performance Charge • Generally, the Base Charge would be the product of the Net Regional Clearing Price, which is based on the Capacity Clearing Price for a Capacity Zone, and the LSE’s Share of Total CSO as shown in equation (2) (2) Base Charge = (NRC Price × Share of Total CSO) • The LSE’s Share of Total CSO could be based on the method currently used

35. LSE’s Share of Total CSO • Generally, an LSE’s Share of Total CSO is equal to the sum of the Coincident Peak Contribution percentages of the Load Assets served by that LSE in the month multiplied by the sum of all supplier CSOs – see equation (3) • A Coincident Peak Contribution percentage is a Load Asset’s (i.e., an individual customer or group of customers) energy consumption as a percentage of total New England energy consumption during the hour of the annual system coincident peak in the year prior to the Capacity Commitment Period (3) Share of Total CSO = SCPC % × Total CSO MW • Equations (2) and (3) reflect the way in which FCM costs are presently allocated • Charging FCM costs on a fixed basis gives LSEs a poor incentive to pursue demand response and other Demand Resources

36. The Critical Change in FCM Cost Allocation is the Performance Charge • The Performance Charge of an LSE would be the product of the Performance Payment Rate – the same rate used to provide capacity suppliers an incentives to perform during scarcity conditions – and a Demand Score. See equation (4): (4) Performance Charge = Performance Payment Rate × Demand Score • The Demand Score is based on the difference between an LSE’s customers’ actual consumption during a scarcity condition and the capacity allocated to the LSE to serve that consumption

37. The Demand Score (5) Demand Score = Actual MW Consumption – (SCPC % × Available Capacity × Demand Balancing Ratio) • The Demand Score is based on the amount of “Available Capacity” procured in the FCM to serve LSE energy requirements because Total CSO MW includes capacity expected to be unavailable to serve the system coincident peak in the Capacity Commitment Period • Available Capacity is equal to Total CSO MW minus the amount of capacity expected to be unavailable to serve coincident peak demand • SCPC % x Available Capacity = the amount of capacity procured to serve the LSE’s energy requirements at the time of the system coincident peak • Equation (5) shows the Demand Score of an LSE for a single scarcity condition event; the Demand Score for the month is the sum of all the Demand Scores for each scarcity condition in the month

38. The Demand Balancing Ratio • The Demand Balancing Ratio – is similar, but not identical to, the “balancing ratio” applied to capacity suppliers in FCM PFP: (6) Demand Balancing Ratio = Total System Load Available Capacity • The Demand Balancing Ratio is a proportionate adjustment to the amount of capacity procured through the FCM to serve energy requirements at the time of the annual system coincident peak • Ensures that LSEs receive lower FCM Charges for decreasing consumption below, and receive higher FCM Charges for increasing consumption above, its proportionate share of capacity available to serve system energy requirements at the time of a scarcity condition

39. Example 1a: Scarcity Condition with Total System Load Equal to Available Capacity • Assume the following: • Total System Load = Available Capacity • Available Capacity = 30 GW • LSEa with a SCPC % = 0.1 (5) Demand Score = Actual MW Consumption – (SCPC % × Available Capacity × Demand Balancing Ratio) • The Demand Balancing Ratio (i.e., Total System Load /Available Capacity) for this scarcity condition equals 1.0 • The term (SCPC % × Available Capacity × Demand Balancing Ratio) for LSEa equals 0.1 x 30 GW x 1.0 = 3.0 GW • If LSEa’s customers consume > 3.0 GW, the Demand Score is positive, resulting in a positive Performance Charge in equation (4), and thus a higher FCM Charge (see equation (1)) for the month • If LSEa’s customers consume < 3.0 GW, the Demand Score is negative, resulting in a negative Performance Charge in equation (4), and thus a lower FCM Charge (see equation (1)) for the month

40. Example 2a: Scarcity Condition with Total System Load 70% of Available Capacity • Assume the following: • Total System Load = 21 GW • Available Capacity = 30 GW • LSEa with a SCPC % = 0.1 (5) Demand Score = Actual MW Consumption – (SCPC % × Available Capacity × Demand Balancing Ratio) • The Demand Balancing Ratio (i.e., Total System Load /Available Capacity) for this scarcity condition equals 0.7 • The term (SCPC % × Available Capacity × Demand Balancing Ratio) for LSEa equals 0.1 x 30 GW x 0.7 = 2.1 GW • If LSEa’s customers consume > 2.1 GW, the Demand Score is positive, resulting in a positive Performance Charge in equation (4), and thus a higher FCM Charge (see equation (1)) for the month • If LSEa’s customers consume < 2.1 GW, the Demand Score is negative, resulting in a negative Performance Charge in equation (4), and thus a lower FCM Charge (see equation (1)) for the month

41. Option 2B: Allow LSEs to Bid Demand Reductions • LSEs may bid and clear demand reduction offers, similar to the PJM demand-side approach • Allows LSEs to specify their sensitivity to capacity prices, and to implement additional, cost-effective Demand Resources to avoid high prices • An LSE’s allocated share of capacity – and thus its total FCM charge – is reduced by any cleared demand reduction obligations • An LSE’s base charge is reduced each and every month by any cleared demand reduction obligations • During a scarcity condition, an LSE consuming less than its allocated share of available capacity, which has been adjusted by any cleared demand reduction obligation, would see its performance charge and associated FCM charge go down; the converse is true for those consuming more • If any demand reduction offer clears the FCA, total capacity acquired through the FCA and the capacity clearing price are both reduced

42. Summary of Option 2B: Integrating Demand Reduction Obligations into FCM Cost Allocation • FCM Charge = Base Charge + Performance Charge • Base Charge = (NRC Price × Share of Total CSO) • NRC Price = Net Regional Clearing Price (3a) Share of Total CSO = (SCPC % × Total CSO MW) – Demand Reduction Obligation • SCPC % = Sum Coincident Peak Contribution Percentages (4) Performance Charge = Performance Payment Rate × Demand Score (5a) Demand Score = Actual MW Consumption – {[(SCPC % × Available Capacity) – Demand Reduction Obligation] × Demand Balancing Ratio} • Demand Balancing Ratio = Total System Load Available Capacity

43. Integrating the PJM Approach into FCM Cost Allocation • If the ISO adopts this approach, the resulting Demand Reduction Obligation must be integrated into FCM cost allocation. For example: • LSEa with a SCPC % = 0.1 • Total CSO MW = 33 GW • LSEa clears a demand reduction bid = 0.3 GW • If LSEa had no Demand Reduction Obligation, LSEa’s Base Charge would be NRC Price x 3.3 GW • Since the LSEa is obligated to reduce load by 0.3 GW, its base charge should be reduced to 3.0 GW. Thus, equation 3 should be modified: (3a) Share of Total CSO = (SCPC % × Total CSO MW) – Demand Reduction Obligation • By clearing demand reduction bids, LSEa’s Base Charge is reduced each month, and Total CSO MW for the market as a whole is also lower

44. Performance Incentives for Demand Reduction Obligations • The LSE must have a performance incentive to reduce demand during a scarcity condition potentially up to its full Demand Reduction Obligation to better ensure that system reliability does not degrade • Therefore, the Demand Score must account for the Demand Reduction Obligation • The amount of demand reduction needed does not have to equal the full Demand Reduction Obligation for every scarcity condition • The Demand Reduction Obligation should be adjusted to account for real-time system requirements at the time of a scarcity condition • To do this, the Demand Balancing Ratio should be applied to the Demand Reduction Obligation • This implies that equation 5 be modified as follows: (5a) Demand Score = Actual MW Consumption – {[(SCPC % × Available Capacity) – Demand Reduction Obligation] × Demand Balancing Ratio}

45. Example 1b: Scarcity Condition with Total System Load Equal to Available Capacity • Assume the following: • Total System Load = Available Capacity • Available Capacity = 30 GW • LSEa with a SCPC % = 0.1 • LSEa with a Demand Reduction Obligation = 0.3 GW (5a) Demand Score = Actual MW Consumption – {[(SCPC % × Available Capacity) – Demand Reduction Obligation] × Demand Balancing Ratio} • The Demand Balancing Ratio (i.e., Total System Load /Available Capacity) for this scarcity condition equals 1.0 • The term [(SCPC % × Available Capacity) – Demand Reduction Obligation] × Demand Balancing Ratio for LSEa equals [(0.1 x 30 GW) – 0.3] x 1.0 = 2.7 GW • If LSEa’s customers consume > 2.7 GW, the Demand Score is positive, resulting in a positive Performance Charge in equation (4), and thus a higher FCM Charge (see equation (1)) for the month • If LSEa’s customers consume < 2.7 GW, the Demand Score is negative, resulting in a negative Performance Charge in equation (4), and thus a lower FCM Charge (see equation (1)) for the month

46. Example 2b: Scarcity Condition with Total System Load 70% of Available Capacity • Assume the following: • Total System Load = 21 GW • Available Capacity = 30 GW • LSEa with a SCPC % = 0.1 • LSEa with a Demand Reduction Obligation = 0.3 GW (5a) Demand Score = Actual MW Consumption – {[(SCPC % × Available Capacity) – Demand Reduction Obligation] × Demand Balancing Ratio} • The Demand Balancing Ratio (i.e., Total System Load /Available Capacity) for this scarcity condition equals 0.7 • The term [(SCPC % × Available Capacity) – Demand Reduction Obligation] × Demand Balancing Ratio for LSEa equals [(0.1 x 30 GW) – 0.3] x 0.7 = 1.89 GW • If LSEa’s customers consume > 1.89 GW, the Demand Score is positive, resulting in a positive Performance Charge in equation (4), and thus a higher FCM Charge (see equation (1)) for the month • If LSEa’s customers consume < 1.89 GW, the Demand Score is negative, resulting in a negative Performance Charge in equation (4), and thus a lower FCM Charge (see equation (1)) for the month