Technical Conference Regarding Energy and Ancillary Services Markets

9:00 am – 9:30 am:

Welcome and Opening Remarks

9:30 am – 11:00 am:

Panel 1: Understanding the Need for Additional Operational Flexibility in RTO/ISO Energy and Ancillary Services Markets

This panel will discuss the reasons that regional transmission organizations (RTOs) and independent system operators (ISOs) have pursued reforms to energy and ancillary services markets to increase operational flexibility to address changing system needs.  Most of these reforms are designed to manage net load variability and uncertainty.  For this discussion, net load is defined as end use loads (net of any impact from distributed energy resources) minus the generation from non-dispatchable RTO/ISO resources.  The panel will include a discussion of the following topics and questions:

1. RTOs/ISOs and other industry experts generally agree that power systems will require greater flexibility from system resources in the future.[1]  What operational capabilities or services will be most valuable to RTO/ISO operators in the future as the resource mix and net load profile changes and why?  Is there a desirable reaction time, sustained performance duration, etc. expected from a resource? 
2. To what extent will the “traditional ancillary services” defined in Order No. 888[2] and existing energy market designs continue to ensure reliability as the resource mix changes in RTO/ISO markets in the future?
   1. Will traditional ancillary services provide the appropriate types and adequate quantities of operational flexibility RTOs/ISOs need to manage both expected (e.g., reasonably predictable) and unexpected (e.g., inherently uncertain and captured in forecast errors) variability in net load?
   2. Will existing RTO/ISO energy and ancillary services market designs that generally compensate certain traditional ancillary services resources based on the opportunity cost of foregone energy sales – for example, spinning and non-spinning reserves -  give resources a sufficient economic incentive to offer their flexible capabilities to the RTO/ISO?
3. How should RTOs/ISOs define the system’s need for operational flexibility, now and in the future?
   1. To what extent is operational flexibility needed on a bi-directional basis (i.e., both up and down) versus a unidirectional basis (i.e., only up or down)? 
   2. How do these needs compare to the services provided by traditional ancillary service products? 
4. Could variable energy resources or new resource types (e.g., storage, hybrid, and co-located resources) be operated or dispatched differently from the status quo to provide greater operational flexibility to the RTO/ISO, if so, how?  Given the evolving resource mix, are the current eligibility requirements for each resource type to provide ancillary services appropriate?

Panelists:

• Susan Bruce, McNees Wallace & Nurick LLC, Counsel to PJM Industrial Customer Coalition
• Mike DeSocio, Director, Market Design, New York Independent System Operator, Inc.
• Rahul Kalaskar, Manager, Market Analysis, California Independent System Operator Corp.
• Adam Keech, Vice President, Market Design and Economics, PJM Interconnection, L.L.C.
• Dr. Debbie Lew, Associate Director, Energy Systems Integration Group
• Mark Karl, Vice President, Market Development and Settlements, ISO New England Inc.
• Jodi Woods, Manager, Market Monitoring, Market Policy & Reporting, Southwest Power Pool, Inc.

11:15 am – 12:30 pm:

Panel 2: Revising Existing Operating Reserve Demand

Curves (ORDCs) to Address Operational Flexibility Needs in

RTOs/ISOs

Certain RTOs/ISOs have proposed to reform their ORDCs in recent years to manage operational uncertainty,[3] and another RTO/ISO is currently considering such reforms.[4]  This panel will discuss the role of reforming the quantity of 10- and 30-minute reserves, defined herein as “contingency reserves”, the RTO/ISO procures, the pricing of those reserves, and shortage pricing levels to address changing system needs.  The panel will include a discussion of the following topics and questions: 

1. Contingency reserves are provided by existing 10- and 30-minute reserve products and are designed to ensure the system can recover from a contingency (e.g., a generator or transmission outage).  How will the procurement of additional contingency reserves help RTO/ISO operators manage routine operational flexibility needs (e.g., needs driven by net load variability and uncertainty)?
2. What are the benefits of procuring contingency reserves beyond the minimum reserve requirement through a given ancillary service product? 
   1. If employing such a method, how should RTOs/ISOs determine the market’s demand for contingency reserves (both the quantity and willingness to pay) beyond the minimum reserve requirement of a given contingency reserve product?  
   2. What principles should RTOs/ISOs follow if they consider revising the shape of the ORDC for a given contingency reserve product  (e.g., introducing additional steps or graduation to the ORDC curve)? For example, should the willingness to pay for such additional reserves be based on the Value of Lost Load times the loss of load probability with a given quantity of the reserve product associated with the ORDC, the cost of actions operators would take to procure additional reserves, or some other valuation method?  How should customer willingness to pay be incorporated?
3. Reserve shortage prices are administratively determined penalty factors invoked when the system falls below the minimum requirement of one or more  reserve products.  To what extent can higher reserve shortage prices inform investment decisions and reflect the value of flexible resource capabilities?
   1. What principles should RTOs/ISOs follow if they consider revising the shortage price associated with the ORDC of a given contingency reserve?
   2. How should the shortage prices of individual contingency reserve products be determined?  For example, should the shortage prices reflect the marginal reliability value of each individual reserve product?  How should customer willingness to pay be incorporated? 
   3. How should shortage pricing be implemented when the system is short both 10- and 30-minute reserves?  Does establishing shortage prices based on the marginal reliability value of each contingency reserve product that is in shortage ensure that adding the shortage prices reflects the combined reliability impact of being short of those reserve products?  

3. 4. Do differences in shortage prices across regions present operational challenges today?  Is there an expectation that such differences could present operational challenges in the future as the resource mix and load profiles change?  Is there a need to better align shortage pricing across RTOs/ISOs, and if so, what principles should be considered in doing so?
4. To what extent do RTOs/ISOs use contingency reserves to manage non-contingency related operational uncertainties (e.g., expected and unexpected net load variability)?  If such reserves are used for this purpose, should this alter an RTO/ISO’s approach to establishing the maximum height and shape of the ORDC?  Under such approaches, how do prices in the ORDC appropriately reflect the marginal reliability value contingency reserves provide?
5. Is there a particular point at which procuring reserves beyond the minimum reserve requirement can reduce or conflict with the objectives of shortage prices?  What is an appropriate balance between raising shortage prices and procuring reserves beyond the minimum reserve requirement given that procuring additional reserves can reduce the probability of the RTO/ISO experiencing a shortage?

Panelists:

• Mike DeSocio, Director, Market Design, New York Independent System Operator, Inc.
• Adam Keech, Vice President, Market Design and Economics, PJM Interconnection, L.L.C.
• Dr. Pallas LeeVanSchaick, Vice President, Potomac Economics
• Beth Garza, Senior Fellow, R Street Institute
• Dr. Catherine Tyler, Deputy Market Monitor, Monitoring Analytics
• Anjali Patel, Sr. Assistant People’s Counsel, Office of the People’s Counsel for the District of Columbia
• Kevin Vannoy, Director, Market Design, Midcontinent Independent System Operator, Inc.

12:30 pm – 1:30 pm:

Lunch

1:30 pm – 3:00 pm:

Panel 3: Creating New Products to Address Operational

Flexibility Needs in RTOs/ISOs

This panel will discuss creating new ancillary service products in addition to the traditional ancillary service products required by Order No. 888, such as ramp products, which some RTOs/ISOs have implemented or proposed to manage operational uncertainties.  The panel will also discuss the performance and prices of short-term ramp products, which are in place in the California Independent System Operator Corp. (CAISO)[5] and the Midcontinent Independent System Operator, Inc. (MISO)[6] and have been approved for implementation in the Southwest Power Pool, Inc. (SPP).[7]  The panel will include a discussion of the following topics and questions:

1. Ramp products, as distinguished from traditional ancillary service products, are relatively new ancillary services that are in place in CAISO and MISO, and approved for implementation in SPP.  Ramp products are generally not designed to address contingencies[8] but are instead a mechanism to position the system efficiently to meet forecasted ramping needs in future intervals at least cost on an expected basis. 
   1. RTO/ISO ramp products procure ramp on a short-term basis (e.g., for intervals of 10 or 15 minutes), but longer-term ramp products are being considered.  For example, SPP is considering a longer-term ramp product[9] and the California Department of Market Monitoring has advised CAISO to consider a longer-term ramp product.[10]  What drives the need for, and what are the benefits of, a longer-term ramp product compared to the existing shorter-term ramp products or traditional reserve products? 
2. Will establishing reserve and ramp prices based on foregone energy revenues provide such signals in a system with a high penetration of variable energy resources, many of which have low or zero marginal costs? 
   1. If not, what other options exist to ensure sufficient compensation for resources providing reserve and ramp capability? 
   2. Historically, the prices for the ramp products in CAISO and MISO have often been zero.  Are ramp prices expected to increase over time as system needs evolve?  If so, what specific conditions might cause ramp prices to increase?  Will any expected ramp price increases be sufficient to incent and appropriately compensate the ramp capability RTOs/ISOs and others expect will be needed due to the changing resource mix?
3. CAISO is considering a Day-Ahead Energy Market Enhancement proposal that seeks to ensure that the day-ahead market clears sufficient resources to address expected net load variability and uncertainty that arises between day-ahead and real-time.  What are the expected advantages and disadvantages of revising the day-ahead market construct in this way to procure additional operational flexibility?
4. The Electric Reliability Council of Texas, Inc. (ERCOT) has proposed to procure fast-responding, limited duration products to address primary frequency control issues associated with declining system inertia.[11]  CAISO also intends to initiate a stakeholder process to discuss, among other options, compensating internal resources for the provision of primary frequency response.[12]  What are the merits of such reforms and should they be considered in other regions?
5. What other new products not yet discussed at this conference do you think could increase operational flexibility in RTOs/ISOs? 
   1. Can capacity markets or other, potentially new, “intermediate” forward market constructs that clear between existing capacity market auctions and the day-ahead timeframe help ensure that RTO/ISO operators have sufficient operational flexibility in real time? 
   2. For example, can a new shorter-term forward market to procure expected operational flexibility needs held closer to the delivery period (e.g., three months ahead as opposed to three years ahead) and with a more granular delivery period than the annual capacity market (e.g., monthly or seasonal delivery period, or a delivery period based on the hours of an RTO/ISO’s morning or evening ramp as opposed to the annual delivery period of most RTO/ISO capacity markets) help ensure that RTO/ISO operators have sufficient operational flexibility in real time? 

Panelists:

• Dr. Mike Castelhano, Analyst, Energy Storage, Energy Division, California Public Utilities Commission
• Gary Cate, Manager, Market Design, Southwest Power Pool, Inc.
• Dr. Yonghong Chen, Consulting Advisor, Market Development, Midcontinent Independent System Operator, Inc.
• Greg Cook, Executive Director, Market and Infrastructure Policy, California Independent System Operator Corp.
• Michelle C. Gardner, Senior Director, Regulatory Affairs, NextEra Energy Resources
• Marjorie (Marji) Rosenbluth Philips, Vice President, Wholesale Market Policy, LS Power
• Aleksandar Mitreski, Senior Director Regulatory Affairs, Brookfield Renewable, on behalf of National Hydro Association

3:00 pm – 3:15 pm:         

          Break

3:15 pm – 4:45 pm:

Panel 4: Market Design Issues and Tradeoffs to Consider in

Reforms to Increase Operational Flexibility in RTO/ISO Energy

and Ancillary Services Markets

This panel will include a discussion of RTO/ISO energy and ancillary services market design more broadly, including the best approaches going forward, the benefits and shortcomings of the various RTO/ISO ancillary services market reforms to date, and any tradeoffs between potential reforms RTOs/ISOs and their stakeholders should consider.  The panel will include a discussion of the following topics and questions:

1. To date, most RTOs/ISOs have pursued new ramping products or ORDC reforms, but not both.  What are the tradeoffs to consider when deciding between these two approaches and how do they interact?  Should these two types of reforms be considered substitutes or complements?  Does the opportunity-cost-based method of establishing reserve and ramping product prices send appropriate long-term signals to resources to invest in or maintain flexible capabilities?
2. Some entities have observed that offering additional resource capabilities into energy and ancillary services markets may not be in the financial interest of certain resources because doing so could lower energy prices by either avoiding scarcity conditions or obviating the need to commit more expensive units, and thus reduce their expected energy and ancillary services markets revenue.  Are such incentive issues relevant in the context of reforming energy and ancillary services markets to address operational flexibility needs?  If so, how should such issues be addressed?
3. What other market design issues and tradeoffs should RTOs/ISOs, stakeholders, and regulators consider when designing and implementing reforms to energy and ancillary services markets to increase operational flexibility?
4. What are the tradeoffs to consider in procuring flexibility in the energy and ancillary services markets versus the capacity market or another new shorter-term forward market construct?

Panelists:

• Dr. Joe Bowring, President, Monitoring Analytics
• Keith Collins, Executive Director, Market Monitoring Unit, Southwest Power Pool, Inc.
• Jessica Harrison, Senior Director of Research and Development, Market and Grid Strategy Division, Midcontinent Independent System Operator, Inc.
• Anna McKenna, Vice President, Market Policy and Performance, California Independent System Operator Corp.
• Dr. David Patton, President, Potomac Economics
• Dr. J. Arnold Quinn, Vice President, FERC-Jurisdictional Markets, Vistra Corp.
• Cari VanAmburg Collins, Head of Policy & Government Affairs, Recurrent Energy
• Dr. Matthew White, Chief Economist, ISO New England Inc.

4:45 pm – 5:00 pm:         

Closing Remarks