Design Considerations for an Alberta Capacity Market Monitoring Analytics September 21, 2016 © Monitoring Analytics 2016 | www.monitoringanalytics.com This page intentionally left blank. © Monitoring Analytics 2016 | www.monitoringanalytics.com Executive Summary
The Government of Alberta’s Climate Leadership Plan defines a transition for wholesale power generation that includes elimination of coal fired generation by 2030 and a corresponding increase in renewable energy production to 30 percent of total power generation.1 This transition will require a thorough evaluation of the wholesale power market design and is likely to require modifications to the market design to ensure that the market remains competitive and sustainable. A capacity market is one option that should be considered by Alberta in this evaluation. If Alberta were to decide that a capacity market should be part of the market modifications, there are multiple design details that need to be addressed. This report presents a possible design for an Alberta Capacity Market that would maintain market incentives while accommodating the introduction of a significant amount of renewable energy that relies on revenues from outside the market. This report also identifies a number of options and issues related to capacity market design. The proposed Alberta Capacity Market design would include: a physical definition of capacity; a must offer requirement for capacity; a must buy requirement for capacity; a deliverability requirement; a forward auction run three years prior to the delivery year, for one delivery year; locational pricing; a sloped demand curve based on reliability requirements; a net revenue offset mechanism that aligns the energy and capacity markets; strong performance incentives; and effective market power mitigation rules. Introduction of a capacity market is recognized to be part of a complete evaluation of the market design. The wholesale power market design consists of multiple components that must be carefully integrated. For example, introduction of a capacity market would require changes to the energy market. Corresponding changes to the Alberta energy market design, integrated with a capacity market, would include: day‐ahead and real‐
time markets; locational pricing (LMP); financial transmission rights; central economic, security constrained dispatch; a must offer requirement for capacity resources in the energy market; and market power mitigation rules. The introduction of a capacity market would be a significant change to the design of the Alberta wholesale power market. The development of capacity market rules and the transition to a capacity market is a complex undertaking with potential unintended consequences. The development of an Alberta Capacity Market should include the development of a detailed design for the capacity market and a detailed design for other elements of the Alberta wholesale power market that require related changes. Thorough 1 “Climate Leadership Report to Minister.” Climate Change Advisory Panel, Government of Alberta (November 20, 2015) <http://www.alberta.ca/documents/climate/climate‐leadership‐
report‐to‐minister.pdf>. © Monitoring Analytics 2016 | www.monitoringanalytics.com 1 simulation testing of the integrated market design should be performed. Participants should be provided a complete opportunity to raise issues and have questions answered. If a capacity market is to function effectively as part of a market redesign, market participants must have confidence that the market operator and regulators have made a clear commitment to the capacity market and the design goals of a capacity market as part of that redesign. Once a decision has been made to implement a new design, investors’ behavior will be a function of the new design and not the old design. Introduction
The Government of Alberta’s Climate Leadership Plan defines a transition for wholesale power generation that includes elimination of coal fired generation by 2030 and a corresponding increase in renewable energy production to 30 percent of total power generation. This report reviews efficient capacity market design options for the Alberta wholesale power market that are consistent with maintaining a competitive and reliable wholesale power market given this planned transition, based on Monitoring Analytics experience with capacity market designs. One expected result of an increase in renewable energy production is a reduction in system prices when renewables are on line because the marginal costs and expected offers of renewables are frequently zero or close to zero. The result of lower prices is lower net revenues to thermal generation. The result of sustained lower net revenues to thermal generation is that it will be uneconomic to continue to operate thermal generation and thermal units will retire. Modifications to the design of Alberta’s wholesale power market could maintain the sustainability of the market. The time frame established for the elimination of coal and the introduction of renewables permits market design modifications and provides adequate time for owners of thermal generation to respond to the new design. Wholesale power market design conceptually comprises three main elements: energy market, capacity market and ancillary services markets. Sustainable market designs can include one or more of these elements. The current Alberta market design includes only an energy market and ancillary services markets. Sustainable energy only markets depend on market signals related to the relative supply and demand balance. In years when the supply of available generation exceeds load by a significant margin, even on peak, prices will be lower. In years when the supply demand balance is tighter, prices will be higher. Over time, generators will enter the market if expected net revenues equal or exceed the level sufficient to cover short run marginal costs, avoidable costs and fixed costs and provide the required return. Generators will remain in the market if expected net revenues equal or exceed the level sufficient to cover short run marginal costs and avoidable costs. In an energy only market, relatively short periods of tight supply demand conditions and higher prices can provide the required revenues. If, as a result of the introduction of significant levels of subsidized renewable resources, the supply demand balance is no longer a function primarily of the investment decisions © Monitoring Analytics 2016 | www.monitoringanalytics.com 2 of private investors in thermal generation, the energy only market is less likely to provide appropriate price signals to the thermal generators that are required to provide reliable wholesale electricity. Net revenues are likely to be reduced to a level below that consistent with reliable supply for 8,760 hours per year. The fundamental issue of wholesale power market design facing Alberta and facing all wholesale power markets is how to design a market that is sustainable, meaning that the endogenous market signals result in adequate incentives to build new capacity when and where needed without regulatory intervention, and adequate incentives to continue to invest in existing capacity. The wholesale power market design must also be robust to exogenous changes including policy changes and technology changes. Wholesale power market design must also address other social policy initiatives including requirements to incorporate defined levels of renewable energy, especially wind and solar. The target levels of renewable energy are generally reached through the introduction of subsidies which can take the form of tax incentives or the required purchase by loads or load serving entities of renewable energy credits subject to penalties for shortfalls. As renewable energy generally has a short run marginal cost close to zero or less than zero with production related tax subsidies, increased renewable energy production tends to reduce energy market prices and therefore net revenues. Capacity markets are one solution to this market design issue. Other solutions are to reregulate generation and provide cost of service rates or to provide individual unit bilateral contracts. Capacity markets are a market solution while other solutions are regulatory solutions. Capacity markets are not simple and capacity markets are not a panacea. The details of capacity market design matter and the interactions between capacity markets and energy markets matter. All of these approaches have been implemented and all result in higher revenues and higher profits, but each has different attributes and market and efficiency consequences.2 Relying on cost of service regulation, whether in the traditional rate base, rate of return sense or via bilateral contracts, is a simple, direct way to ensure revenue adequacy for generating units. By definition, this approach is not a market approach and it does not create market incentives for entry from new participants, for investment in existing units, or for retirement of uneconomic units. The traditional state regulatory approach provides revenues only to the vertically integrated utilities that own generating plants 2 Of the six organized wholesale power markets in the U.S., PJM, NYISO, and ISO‐NE have capacity markets, CAISO requires utilities to purchase capacity through bilateral contracts subject to regulatory review, MISO relies on state level cost of service regulation to ensure adequate revenues and adequate capacity while including a voluntary capacity market, and ERCOT relies on a form of scarcity pricing. © Monitoring Analytics 2016 | www.monitoringanalytics.com 3 and is inconsistent with the market restructuring that has occurred in large parts of the U.S. The bilateral contract approach permits new entry, but competition is limited to an administrative process which results in a guaranteed flow of revenues to selected units for a defined period of time, typically less than the asset life, and is not transparent to potential competitors. Both approaches rely on regulatory decisions to determine the location and technology of new generation and the revenues received by new capacity. There is no market clearing price and capacity resources are paid different prices. There is no opportunity for merchant generation to compete directly based on price. There is no capacity market signal for demand side resources. There is no integration with the energy market to permit market based adaptation to higher levels of renewable resources. Creating capacity markets can result in net revenues for generating units consistent with a sustainable market if the definition of capacity, the definition of demand for capacity, market power mitigation rules, the integration with the energy market design, and other market rules are all established in a consistent manner. Capacity markets permit the definition of reliability targets which can be achieved directly through the market design. Achieving reliability targets depends on market response to the resultant price signals. Reliance on capacity markets also includes a potential element of uncertainty related to the details and implementation of the actual market design; this uncertainty is minimized in a well designed market. Capacity markets can work well with scarcity pricing and a well defined net revenue offset mechanism can result in incorporating the best attributes of both approaches to market design. The performance incentives associated with an energy only market are a strength of the energy only approach and are a key benchmark for assessing performance incentives in any wholesale power market design. The performance incentives in an energy only market are simple. A resource is paid the market price, when it produces energy, for the amount of the energy produced and it is not paid when it does not produce energy. The more complex market designs, including capacity market designs, have in many cases attenuated these fundamental incentives. It is essential that the market designs replicate these performance incentives. Capacity markets address the issues created by the introduction of large amounts of subsidized renewable resources by creating a market mechanism to value reliability that is closely integrated with the energy market. When available capacity is less than the forecast need for capacity and energy market net revenues do not provide an adequate incentive to enter the market, capacity market prices will increase to provide that incentive. Capacity markets have not been universally adopted in U.S. wholesale power markets. Only PJM, ISO‐NE and NYISO have capacity markets in the U.S. MISO relies on cost of service regulation. CAISO relies on unit specific contracts which are the functional equivalent of cost of service regulation on a unit by unit basis. ERCOT relies on scarcity pricing in the energy market. © Monitoring Analytics 2016 | www.monitoringanalytics.com 4 In the design of capacity markets, the fundamental design criterion is that the only purpose of a capacity market is to make the energy market work efficiently and effectively. The design of the capacity market should retain the same incentives as the energy market. When a generator does not produce energy, the generator does not get paid. When a generator does not produce energy during very high demand conditions, the generator does not get paid. This approach can be summarized as no excuses. Just as in an energy only market, if the generator does not produce energy the generator does not receive revenues, regardless of the reason. The basic elements of a successful capacity market are reasonably well understood as a result of some difficult learning experiences in U.S. markets. The basic elements include: a physical definition of capacity; a must offer requirement for capacity; a must buy requirement for capacity; a deliverability requirement; a one year, three year forward auction; locational pricing; sloped demand curves based on reliability requirements; a net revenue offset mechanism that aligns the energy and capacity markets; strong performance incentives; and effective market power mitigation rules. A capacity market is preferable to the cost of service approach used in MISO or the contract approach used in CAISO because a capacity market relies on a transparent market mechanism and competition to provide capacity at the lowest possible cost. As in any market, capacity markets assign the risk of investing to investors rather than customers. There is no guarantee that a resource will clear the market; for a resource to clear the market it must make a competitive offer. In MISO, merchant generation cannot compete to provide capacity. There is no competition to provide capacity and prices are higher and innovation lower than would be the case with competition. In MISO, cost of service regulation provides guaranteed payments and profits to regulated generators; results in excess capacity designed to meet reliability requirements; results in correspondingly low energy prices; and as a result creates no incentives for merchant generators, who receive only energy market revenues, to enter the market.3 In CAISO, merchant generation cannot see the prices being paid for capacity, can compete only in an opaque contracting process, and cannot compete to provide capacity once a long term contract has been locked in. There is a poorly defined and noncompetitive process for addressing resources at the end of their ten year (typically) contracts. The nonmarket alternatives can and do work to provide reliable energy but the nonmarket alternatives shift risks to customers, are not least cost, are not efficient and prevent competitive forces from operating. 3 In MISO there is a nominal, voluntary capacity market which results in de minimis capacity prices. The MISO capacity market does not meet the minimum definition of a capacity market and the associated revenues do not provide an incentive for merchant generation to enter the market. © Monitoring Analytics 2016 | www.monitoringanalytics.com 5 The key elements of energy market design, integrated with a capacity market, include day‐ahead and real‐time markets; locational pricing (LMP); financial transmission rights; central economic, security constrained dispatch; a must offer requirement for capacity resources in the energy market; administrative scarcity pricing rules; and market power mitigation rules. Energy markets in the U.S. include all of these elements, although the detailed designs differ across markets. Day‐ahead energy markets have positive and negative features. The positive features include a full, day‐ahead, market‐based commitment and dispatch solution and associated prices with corresponding financial obligations for both generation and load. The negative features in U.S. markets have included the introduction of nodal virtual products which have not enhanced efficiency, and the introduction of complex uplift issues. The implementation of a day‐ahead energy market and the multiple possible elements of a day‐ahead market should be considered as part of the overall evaluation of the wholesale power market design. Locational pricing (LMP) is a preferred option in wholesale power markets because it reveals the fact that the marginal cost of energy varies by location when there are transmission constraints. Locational pricing provides locational price signals for generation investment and for transmission investment and ensures that the prices paid to generation and paid by load reflect the marginal costs. All markets have congestion. If a market does not have congestion, locational pricing looks exactly the same as no locational pricing. It is possible to have locational pricing but that load in zones all pay the same zonal price rather than the nodal price. Locational pricing is generally packaged with financial transmission rights (FTRs) that, when designed correctly, return congestion payments to load. Central, security constrained dispatch is a preferred option particularly in the presence of significant renewable resources. Central dispatch provides the dispatch signal to generation consistent with the demand for power on the system. In the presence of large amounts of renewable resources that can ramp up and ramp down very quickly, central dispatch will permit system operators to maintain control of the system and ensure adequate thermal resources to balance the intermittent output of renewables. Market power mitigation rules are an important element of energy and capacity market design. In PJM, the three pivotal supplier (TPS) test is used in both the energy and capacity markets. The three pivotal supplier test or a similar test should be incorporated in both the energy and capacity market designs in Alberta. Renewable Resources
Renewable resources typically include wind and solar. While wind resources are generally grid scale, solar resources are both grid scale and customer scale. Renewable resources are intermittent resources, meaning that output from renewable resources cannot be dispatched but results from substantially unpredictable weather conditions including wind speed and duration and solar availability. © Monitoring Analytics 2016 | www.monitoringanalytics.com 6 Renewable resource technology continues to evolve rapidly. As a matter of market design, it would be preferable to minimize the term of any subsidies to renewables in order to avoid locking customers in to paying for obsolete technologies that may be priced well above market in the near future. It would also make sense to evaluate the most cost effective and flexible method for subsidizing renewable resources. Tax subsidies or production tax credits may be more flexible and cost effective than contracts with specific resources. Capacity Market Basics
Capacity markets are not a panacea. Capacity markets can be badly designed and can have significant negative unintended consequences. The details of capacity market design matter. Alberta can benefit from avoiding the mistakes made in capacity market design in the U.S. A capacity market design that incorporates defined basic elements could be the basis for an Alberta Capacity Market that will allow for the transition away from coal fired generation to a generation mix that includes a significant level of new renewable energy generation and gas fired thermal generation. The basic elements of a capacity market design include: a physical definition of capacity; a deliverability requirement; a must offer requirement; a must buy requirement for all load; strong performance incentives; a net revenue offset mechanism that aligns the energy and capacity markets; a sloped demand curve with defined inflection points; a forward auction; a locational market definition; and effective market power mitigation rules. Introduction of the PJM Capacity Market
The early wholesale power market designs, including PJM’s, replicated the efficient dispatch of a tight power pool, compensated generators based on locational marginal prices and charged loads based on zonally aggregated locational marginal prices. In PJM, the integrated utilities that were the members of PJM, had to meet a reliability requirement even prior to the introduction of wholesale markets, including a defined reserve margin over forecast peak load designed to meet the one in ten year loss of load target. This requirement remained after the introduction of markets. The result was that the energy market was generally long and energy prices lower than they would have been in the absence of the reliability requirement. The early market designs did not address the source of revenues required to cover investment costs and thus did not address the sustainability of the market design in the presence of a required reserve margin. In PJM, the result of an energy only market in the presence of excess supply was a shortfall in net revenues compared to the annualized costs of building a new generating unit and in some areas compared to the annual costs of maintaining existing units. Absent a market design change, markets faced a reduction in reserve margins and © Monitoring Analytics 2016 | www.monitoringanalytics.com 7 locational reliability issues because the market was not generating sufficient revenues to make it attractive to invest in new generating capacity and was not expected to generate sufficient revenues. Early excesses in market reserve margins that resulted from new investments based on expectations about the operation of the new market were reduced as a result of unit retirements and load growth. Several years of actual data on market prices and total net revenue led to more realistic investor expectations and a reduction in new investment in generating units. In response, PJM developed and implemented a new capacity market design in 2007, the Reliability Pricing Model (RPM). The design of the RPM market was intended to address the fundamental issue of whether the market was sustainable, meaning whether the market signals would result in adequate incentives to build new capacity when and where it was needed without regulatory intervention. In 2015, PJM implemented a modified RPM capacity market design, termed the Capacity Performance design. The Capacity Performance design was intended to address the weak incentives to produce energy in high demand periods and the inconsistent definition of demand side products. The RPM and Capacity Performance market designs were intended to address all of the elements of a successful capacity market design. Definition of Capacity
Capacity is not a standalone product. Capacity is not required to run machines or air conditioners. The only reason for a capacity market is to make the energy market viable. The design of the capacity market should reflect this tight integration between energy and capacity markets. Capacity resources must be physical. Capacity resources must be specific physical units at a specific location with identified physical characteristics. Capacity resources are not a slice of system. Capacity resources are not financial. The energy from capacity resources must be deliverable to all loads in the market. The energy from capacity resources must be offered into the energy market every day. The energy from capacity resources must be recallable in an emergency. Capacity resources must report outage data. Physical capacity is needed in order to provide the reliable delivery of energy under all system conditions. In practice that means, for example, that a firm liquidated damages contract is not physical and cannot be capacity. Payment of liquidated damages is not considered an acceptable substitute for the delivery of energy during a period when load approaches the capability of the generating capacity. In general, imports of capacity from outside the electrical boundaries of the market are not comparable to capacity inside the market and should not be included as capacity resources. The PJM capacity market design does not yet have an adequate approach to external capacity. Deliverability means that the transmission system must be capable of delivering the energy output from the resource under peak conditions to load anywhere in the control area. Deliverability is enforced by requiring the builder of new capacity to pay for any © Monitoring Analytics 2016 | www.monitoringanalytics.com 8 transmission upgrades necessary to ensure that the energy is deliverable, according to transmission system analysis done by the entity responsible for transmission planning, the Alberta Electric System Operator (AESO) in Alberta. The capacity resource receives capacity injection rights in return. This provides a strong incentive to locate where the transmission system is robust and also provides a market signal about the full cost of new capacity when transmission system upgrades are required. If a resource chooses to be an energy only resource, the resource is generally required to make minimal upgrades to the transmission system to permit delivery of energy, the resource does not purchase capacity injection rights and the resource cannot sell capacity. If the capacity market design is locational, the energy market design should also be locational. The price signal to generation for entry and ongoing investment is a function of both capacity and energy prices. Locational capacity prices are a function of energy prices in that location, whether or not energy prices are locational prices. If locational energy prices should be high in an area because the actual local marginal cost of energy is high, capacity prices would be lower as a result. If locational energy prices are based on average prices and are therefore lower than the actual local marginal cost of energy, the result would be to overpay new capacity in that location. If locational energy prices should be low in an area because the actual local marginal cost of energy is low, capacity prices would be higher as a result. If locational energy prices are based on average prices and are therefore higher than the actual local marginal cost of energy, the result would be to underpay new capacity in that location. In recognition of the tight integration between energy and capacity markets to ensure reliability and appropriate incentives for investment and the payment by load for capacity, capacity resources should be required to offer energy output equal to their full installed capacity value into the energy market every day. Energy from all resources that have a capacity obligation should be recallable by the system operator in an emergency. This ensures that even when such energy is being exported, the customers who paid for the capacity to ensure reliability, have a call on that energy at the market clearing price if the energy is needed to meet load in the control area. Rules are also needed to determine how much of a generator’s installed capacity is eligible to clear as a capacity. While traditional thermal resources are required to offer their full capacity, intermittent renewable resources do not have such a requirement and are limited to offering capacity expected to be available at times of peak demand. Renewables should be included in the market mechanism to ensure that the market is comprehensive and to provide a potential revenue source to replace subsidies with market revenues as renewable resources mature. In the near term, the subsidy payments would be included in the net revenue for the renewable resources which would reduce offer levels from renewable resources in the capacity market. This is strongly preferable to a capacity market design that includes only thermal resources. In the thermal only design, renewable resources would rely on out of market subsidies as a substitute for a © Monitoring Analytics 2016 | www.monitoringanalytics.com 9 capacity market. But the same issues need to be addressed whether renewable resources are included in the capacity market design or not. The forecasted peak demand for energy is a key parameter of the capacity market demand curve. If renewable resources are not included in the capacity market, the forecasted peak demand to be met by thermal resources would have to be reduced by the expected reliable contribution to meeting peak load by renewable resources. If renewable resources are included in the capacity market the forecasted peak demand for energy would not be reduced to account for the energy from renewable resources. Instead, offers from renewable resources equal to their expected reliable contribution to meeting peak load would be included in the capacity market. While the basic logic is the same, inclusion in the market ensures that all supply and demand are explicitly included and priced. The result is that the market is internally consistent and capacity sellers have a clear and transparent price to value their resources. Must Buy and Must Sell
The only way in which a capacity market can result in a price that reflects the actual supply and demand conditions without the exercise of market power through withholding is if all capacity offers to sell capacity and all load bids to buy capacity equal to forecasted peak load plus a reserve margin. A fundamental requirement is that capacity resources be available to produce energy when needed. The capacity market rules must include provisions that govern the availability of capacity resources in the energy market. This can be accomplished through a combination of performance incentives and nonperformance penalties, and must offer rules in the energy market. The PJM market requires capacity resources to offer into the day‐ahead market. Participation and performance rules for an Alberta Capacity Market will need to be part of an overall, consistent, integrated market design. Fundamental concepts that will guide the creation of these rules are forfeiture of capacity market revenue for resources that clear in the capacity market and fail to perform when needed for energy, and performance payments for resources that produce energy in excess of the capacity market obligation. In the current PJM Capacity Performance capacity market design, all units that perform at a level higher than their capacity obligation during identified high demand hours receive performance bonus payments funded by penalty payments from underperforming capacity resources. Renewable resources that are not capacity performance resources also receive such performance payments. This is an important potential source of revenue for renewable resources that do not offer 100 percent of nameplate capacity into the capacity market based on the intermittent characteristics of the resources. Demand Curve
The capacity auction includes a demand curve defined by the market rules. Individual customers or load serving entities (LSEs) do not bid into capacity market auctions. The © Monitoring Analytics 2016 | www.monitoringanalytics.com 10 cost of purchased capacity is allocated to customers. The allocator defines the amount of capacity to be paid for by each entity and the price is determined by the capacity market. The amount of capacity allocated to each entity includes an allocated share of the reserve margin. The allocation rules should account for the relationship between customer demands and the need to have capacity. Simple rules like using a single coincident peak (CP) or five coincident peaks can miss important features of that relationship. In PJM, capacity costs are assigned to zones based on a single CP and assigned to individual customers generally based on five CP. But these allocators were based on premarket cost of service history and do not adequately address the cost allocation issues. The cost allocation should be addressed in the initial design because it is very difficult to change the allocation later. Both new and existing bilateral contracts for capacity are accommodated in the capacity market design. Bilateral contracts can be structured as contracts for differences (CFDs) against the capacity market clearing price. There is no reason to have the intermediate steps that are included in the PJM capacity market design. The AESO could directly assign the capacity costs from the auction to customers and/or LSEs based on the defined allocation factors. The capacity market demand curve is administratively defined. The issues in the design of the demand curve include the definition of the net revenue offset, the nature of the reference unit used to define the cost of capacity, the MW and price of the inflection points and the resultant slope of the curve between inflection points. The demand curve for system capacity in the PJM capacity market design is downward sloping. In the PJM design, the shape and inflection points of the demand curve are based on the reliability requirement and the net cost of new entry for a peaking unit. The net cost of new entry includes the gross costs net of the net energy and ancillary services revenues offset. This offset reflects the investment incentive purpose of the capacity market and the integration of the capacity and energy markets. Although net revenues in the PJM design are the three year historical average, the net revenues should be forward looking, based, to the extent possible, on forward curves for energy and fuel. The reference unit can be a peaking unit or it can be the unit type most likely to enter the market. Given current market conditions, the design choice is generally between a combustion turbine and a combined cycle unit. As an illustration of the elements that are incorporated in the capacity market demand curve, Figure 1 is the demand curve for the PJM Base Residual Auction for the entire RTO for the 2019/2020 delivery year.4 The auction was run in May 2016. The highest 4 The Variable Resource Requirement (VRR) curve in Figure 1 includes the RPM energy efficiency (EE) add back mechanism. RPM rules allow Energy Efficiency Resources to © Monitoring Analytics 2016 | www.monitoringanalytics.com 11 price part of the demand curve is flat from the y or price axis at a price equal to 1.5 times the net cost of new entry, or the gross cost of new entry if that is higher.5 The flat portion extends to point A, where the quantity equals the reliability requirement plus approximately one percent. The MW quantity at point A was a design choice intended to ensure that enough capacity is purchased to meet the reliability requirement. The curve slopes downward to point B, where the price is equal to 75 percent of the net cost of new entry. The MW quantity at point B is the reliability requirement plus approximately three percent. The demand curve then drops to point C on the x axis. The MW quantity at point C is the reliability requirement plus approximately eight percent and price is $0/MW‐day. The inflection points are design choices. It is recommended that simulations of the Alberta market be run and analyzed in the process of defining the inflection points for an Alberta Capacity Market. The demand curve shown in Figure 1 is for the entire RTO without accounting for locational differences. There are separate supply and demand curves for each locational deliverability area (LDA) with a potentially binding transmission constraint. LDAs are subregional areas with potentially binding transmission constraints that would affect the ability to deliver the output of capacity resources. participate on the supply side. An adjustment is made to the demand curve through the EE add back mechanism to avoid double counting, since, beginning with the 2019/2020 BRA, EE for the delivery year is reflected in the revised load forecast model for the same delivery year. 5 The prices are all adjusted to be on an unforced capacity basis. Unforced capacity is installed capacity or gross capacity adjusted for the relevant forced outage rate. © Monitoring Analytics 2016 | www.monitoringanalytics.com 12 Figure 1 Demand Curve for 2019/2020 RPM Base Residual Auction $600
$500
Point A:
158,714.1 MW
$448.95 per MW-day
$ per MW-day
$400
$300
Point B:
162,894.3 MW
$224.48 per MW-day
$200
$100
Point C:
170,850.0 MW
$0.00 per MW-day
$0
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
Capacity (Unforced MW)
The demand curve design incorporates a form of scarcity pricing. In this example, the clearing price is at the maximum level if supply, at offer prices less than the maximum price, is less than approximately 101 percent of the reliability requirement. For example, if the reliability requirement were 100,000 MW, the price would be set to the maximum whenever the supply, at an offer price less than the maximum, was less than approximately 101,000 MW. The scarcity price also serves as a price cap. The demand curve design sets the quantity associated with the expected equilibrium price at a level slightly higher than the reliability requirement. This means that the market clearing price will equal the net cost of new entry at a quantity approximately 2.8 percent greater than the reliability requirement. As a result, the demand curve sets the price for the reliability requirement at greater than the net cost of entry. The downward slope requires the purchase of capacity greater than the reliability requirement if consistent with offer prices and requires the purchase of capacity less than the reliability requirement if consistent with offer prices. The downward sloping demand curve is also intended to add some elasticity compared to a vertical demand curve. The goals of adding elasticity are to mitigate market power and to recognize that capacity beyond the defined reliability requirement has value greater than zero. The impact on market power is de minimis. The downward sloping feature is an alternative to the use of a vertical demand curve equal to the reliability requirement which may result in arbitrarily volatile capacity market prices, depending on the shape of the supply curve, and which © Monitoring Analytics 2016 | www.monitoringanalytics.com 13 values any MW of capacity above the reliability requirement at zero. The exact shape of the curve is determined by the specific objectives of the market design. In an Alberta Capacity Market, all these parameters would be selected based on Alberta’s market design objectives. True Up Auctions
The PJM capacity market design provides for the primary Base Residual Auctions (BRA) and subsequent Incremental Auctions (IA) to permit market participants to true up positions as necessary. For example, incremental auctions provide a market mechanism for participants to replace capacity that fails or has an increased forced outage rate. Incremental auctions may also be used to adjust the level of procured capacity if the peak load forecast that defines the demand for capacity increases or decreases after the initial auction. PJM buys or sells excess capacity in the incremental auctions based on changes in the forecast compared to capacity purchased in the base auction. In the PJM capacity market design, capacity obligations are annual. There is one base auction for each delivery year, followed by three incremental auctions. In an Alberta Capacity Market, the number of incremental or true up auctions would be selected based on Alberta’s market design objectives. The design goal should be to keep the design as simple as possible given the objective. There is no reason to have more than one incremental auction, run within a few months of the delivery year. There is no reason to have the market operator sell excess capacity in any incremental auction. Forward Procurement
The design should reflect supply and demand at a defined point in the future. The PJM Capacity Market sets a price for one year, three years in the future. The goal of a forward procurement is to permit competition from new entry, to provide an opportunity to market test decisions to invest in existing units, to provide for advance decisions about unit retirements and to provide for a window to resolve reliability issues revealed in market outcomes before they occur. A forward procurement allows the market to react to external factors like changes in environmental regulations and provides an incentive to make retirement decisions prior to the capacity auction. The design goal for the forward period is to permit competition from new units and to provide adequate time for a typical new unit to be constructed and put in commercial operation. Too short a period limits competition and too long a period adds unnecessary uncertainty. The period should be from three to five years to meet the design goal. The three year forward period in PJM is within that range. PJM initially proposed four years in 2007 when the forward period was first introduced. There is no reason to have the capacity market product be a multiyear product. PJM experience has demonstrated that a one year product provides incentives for new entry. To the extent they deem necessary, market participants enter into commercial, bilateral longer term contracts, including the sale of energy market price hedges and tolling © Monitoring Analytics 2016 | www.monitoringanalytics.com 14 agreements, which reflect market participants’ views of future market conditions. A longer definition of the capacity product changes the allocation of risk in ways that may increase risk to older units that are near retirement. Market participants must have confidence that the capacity market will continue in the future. No investor would build a new power plant in response to a capacity market design that provided one year of revenue and that was expected to last only for one year. It is essential that the market operator and regulators make a clear commitment to the capacity market and the design goals of a capacity market in order to create an effective capacity market mechanism. It has to be made clear that a market design including a capacity market is clearly consistent with a range of policy objectives and will not change as a result of a change in such objectives. For example, a capacity market can facilitate the introduction of renewables, but the capacity market would continue to work even if that policy objective changed to either increase or decrease the target level of renewables. Locational Markets
The capacity design should include the potential for locational price separation to reflect locational differences in capacity supply and demand conditions. The demand curves in individual areas should be defined in exactly the same way as the system demand curve except that the locational reliability requirements would be used in place of the system reliability requirements and locational net cost of new entry values would be used for the price points. There will be locational price separation when the demand for capacity in an area cannot be met by the supply taken in merit order over the entire system, including capacity within the area and capacity imported into the area, but must be met by higher cost supply located in the area. This is analogous to locational marginal pricing in the energy market. At the introduction of the RPM capacity market design in PJM, there were significant locational differences in the balance of supply and demand within the PJM footprint. There were incipient reliability issues in some areas and in other areas there was excess capacity. A single capacity market price would have underpriced capacity where it was most needed and overpriced capacity where it was not needed. The PJM Capacity Market would not have worked without locational price separation. Even if locational differences in market conditions are not currently considered significant in Alberta, the locational aspect of the capacity market design cannot be ignored. If locational differences in market conditions are not significant, the inclusion of a locational design would result in no locational price differences but would provide the option to let actual supply and demand conditions result in locational price differences when appropriate. In addition, market participants would know that locational price differences would be permitted in the future if based on supply and demand conditions. Inclusion of locational pricing in the initial design would also avoid the need for a © Monitoring Analytics 2016 | www.monitoringanalytics.com 15 significant market redesign in the future if locational price differences emerged. Including a locational design is a critical part of a commitment by the market operator and regulators that the capacity market will continue in the future and that market prices will reflect actual supply and demand fundamentals. Performance Incentives
The goal of the capacity market performance incentives should be to match the incentives that would result from a competitive energy only market. The most basic market incentive is that sellers are not paid when they do not provide a product. Given that all generation is counted on for comparable contributions to system reliability, it would be efficient for all generation types to face the same performance incentives. Recent modifications (Capacity Performance design) to the PJM capacity market design incorporate stronger performance incentives. In order for the capacity market to help ensure the smooth integration of renewables, there must be incentives for flexible units. Part of the performance incentives in the capacity market is the requirement that capacity resources have operating parameters consistent with the OEM (original equipment manufacturer) defined capabilities of the units. Part of the overall market design should also include five minute settlements in the energy market and five minute scarcity pricing in the energy market. Both design features provide a strong incentive for flexibility by compensating units based on current prices rather than based on an average hourly price which can substantially attenuate the price signal and therefore the incentive to respond immediately. An administrative scarcity pricing mechanism in the energy market is an important part of the performance incentives in an integrated capacity and energy market design. Net Revenue Offset
Net revenues are the key link between the capacity and energy markets. Net revenues should be incorporated in key parameters of the capacity market demand curve and net revenues should be incorporated in offer caps in the capacity market. The net cost of new entry is a parameter of the capacity market demand curve. The net cost of new entry is defined to be the annualized gross cost of new entry, net of the net revenues such a unit would be expected to earn during the delivery year. The reference unit type selected for the cost of new entry parameter is a peaking unit, or the most common new entrant technology. The gross cost of new entry is the levelized annual cost over a 20 year period of purchasing and installing such a unit including site related costs, the cost of interconnecting to the electric grid and the cost of interconnecting to a source of fuel. Net revenue is the equilibrating mechanism between the energy market and the capacity market. The capacity market net cost of new entry parameter should be designed to provide the level of net revenue required to cover the annualized fixed cost of the © Monitoring Analytics 2016 | www.monitoringanalytics.com 16 reference unit after accounting for the net revenue from the energy and ancillary services markets. Net revenue is the difference between gross revenue from selling power at the relevant energy market price and short run marginal costs, which include the cost of fuel, short run marginal operating costs and emissions costs. The method of calculating the forward net revenues must be clearly specified. While a net revenue offset reflects the appropriate level of energy and ancillary market revenues, the use of historical net revenues is likely to distort the level of the offset and have potentially significant impacts on market outcomes. A design question is whether to include defined net revenues in the parameters and offers of capacity resources and/or to require that the actual net revenues of the reference resource be returned to loads, based on market conditions in the delivery year. In PJM, historical net revenues are used both for demand curve parameters and for capacity market offers. An integrated energy and capacity market design can incorporate a carbon price resulting from any carbon pricing mechanism. The carbon price is part of the marginal cost of generation for carbon emitting resources and affects energy market clearing prices and net revenues for affected units to the extent that units with such marginal costs affect energy market prices. Demand Side Resources
Markets require both a supply side and a demand side to function effectively. The demand side of wholesale electricity markets is underdeveloped and many organized wholesale markets have implemented demand response programs as a proxy for full participation. The basic concept of a demand side resource is that it provides a market option to customers that do not want to pay for capacity. But if a customer does not pay for capacity it must also agree to interrupt its load when there is not enough capacity to meet total load, and when those customers who do pay for capacity need that capacity. The treatment of demand side resources in the PJM capacity market design has been an illustration of what not to do. It is not necessary to include demand side resources explicitly in the capacity market design in order to provide appropriate incentives for demand side resources in the overall market design. The treatment of demand side resources in the PJM capacity market design has been inconsistent with market fundamentals from the inception of the capacity market and subsequent modifications to the market design have made matters worse. Prior to inclusion in the capacity market, demand side response reduced the demand for capacity either as a result of customers responding to price signals or as a result of utility © Monitoring Analytics 2016 | www.monitoringanalytics.com 17 rate reduction options in the regulated environment. Under the PJM capacity market design, demand side resources are offered as supply, included in the capacity market supply curve and compete directly with offers from generating units as if they were equivalent. Both before and after the introduction of PJM markets, some large customers interrupted their own load on high load days in order to reduce their payments for capacity. Capacity payments were assigned to customers based on their share of load on the five coincident peak load days, so a reduction in load on peak days meant a reduction in payments for capacity as well as distribution costs linked to peak demand. The market design logic associated with demand side resources has been confused. The result of the inclusion of demand side resources in the capacity market as if it were supply has been to significantly suppress the price and the quantity of capacity purchased. No market can work efficiently without an active demand side. The capacity market design should provide clear price signals to demand and facilitate the ability of load to reduce demand when the capacity they do not want to pay for is needed by those who paid for the capacity. It is essential that load see a transparent capacity market price signal, have the ability to react to the price signal and to benefit from the reaction to the price signal without a long lag. Capacity Transmission Rights (CTRs)
If the capacity market design is locational, the capacity market design needs to define the rights to capacity market congestion revenues in the same way that FTRs define the rights to energy market congestion in a locational energy market. These rights, termed capacity transmission rights (CTRs) should be assigned to the loads that pay for the transmission system and that pay the capacity market congestion revenues. When the capacity import capability into an area is binding, the load inside the capacity constrained area pays congestion revenues equal to the capacity price difference between the importing and exporting areas times the transmission import capability. Those revenues are not paid to any capacity resource and should be returned to load. The PJM Capacity Market includes this provision. The capacity market design can also support transmission upgrade offers in a capacity auction. RPM has a provision for Qualifying Transmission Upgrades (QTUs). A QTU is an offer to increase the transmission capability into a constrained area. If it clears the auction, the entity that submits the offer is paid the price difference between the importing and exporting areas for each MW of incremental import capacity cleared. Cogeneration
The capacity market facilitates the continued participation of cogeneration resources in the wholesale power markets. Cogeneration resources can offer their available capacity in a capacity market and receive the clearing price. Based on the requirement to be © Monitoring Analytics 2016 | www.monitoringanalytics.com 18 deliverable, cogeneration resources, like all resources, can offer into the capacity market only if they have obtained corresponding capacity injection rights. If the gross load of the cogeneration host is 500 MW and the cogeneration facility has a capacity of 700 MW, the cogenerator could offer 200 MW if they had obtained 200 MW of capacity injection rights but no more than 200 MW. If the cogenerator wished to offer 200 MW into the capacity market, it would have to make a 200 MW energy offer into the market every day and be prepared to have the 200 MW be dispatched economically. For cogeneration facility output that is not sold in the capacity market, performance payments for generation output in excess of cleared capacity awards during high load hours are another source of revenue in a capacity market. Market Power
Market design is the primary means of achieving and promoting competitive outcomes in a wholesale electricity market. Market power mitigation goals should focus on market designs that promote competition and on limiting market power mitigation to instances where market structure is not competitive and thus where market design alone cannot mitigate market power. Market power is the ability of a market participant to increase the market price above the competitive level or to decrease the market price below the competitive level. A comprehensive market power mitigation plan must establish conditions under which the market structure is not competitive and define a competitive offer. If the market structure is not competitive, offer prices exceed competitive levels and the clearing price would be increased, then mitigation should be applied by replacing noncompetitive offers with competitive offers to arrive at a competitive market result. This framework applies to the energy market and the capacity market, although the implementation differs substantially. The introduction of a capacity market implies that strong market power mitigation rules should be implemented in the energy market. An Alberta Capacity Market would be designed to replace the exercise of market power in the energy market as the source of incentives to invest in new and existing capacity. With an Alberta Capacity Market, there would no longer be a design basis for permitting the exercise of market power in the energy market. An efficient, competitive energy market would be a key element of a redesigned Alberta wholesale power market. Market Power and Market Power Mitigation
Capacity markets are generally tight; the supply of capacity is approximately equal to the demand for capacity. An Alberta Capacity Market would be tight at an aggregate level, with a number of market participants who are individually pivotal and a high probability of failing the three pivotal supplier test under all market conditions. A generation owner is individually pivotal if the market cannot clear without the capacity © Monitoring Analytics 2016 | www.monitoringanalytics.com 19 of that owner.6 When the market structure is characterized by one, two or three pivotal suppliers, it is considered to exhibit structural market power. The locational markets also exhibit structural market power. Structural market power would be endemic to the Alberta Capacity Market. As a result, functional market power mitigation rules are required to ensure that capacity market outcomes are competitive. The capacity design should include explicit and detailed market power mitigation rules which require competitive behavior when there is structural market power. The market power mitigation rules should require that any capacity owner that fails the three pivotal supplier test must offer existing capacity at a price equal to the marginal cost of capacity if their offer absent mitigation would increase the clearing price. Planned generation is generally presumed to be competitive but should be subject to maximum offers linked to the cost of new entry if pivotal. The capacity market design should include a must offer requirement for all capacity resources as a basic protection against withholding. The capacity market design should include a must buy requirement as a basic protection against under procurement. Together, these two rules require that the supply of and demand for capacity are fully incorporated in the capacity market. Offer Caps in Capacity Markets
In order to evaluate whether actual prices reflect the exercise of market power, it is necessary to evaluate whether market offers are consistent with competitive offers, and if structural market power exists. Offer caps should be applied in cases where a capacity offer exceeds the competitive offer level, the capacity resource is determined to have structural market power, and the noncompetitive offer impacted the capacity price. The default offer cap under the PJM Capacity Performance rules is net CONE * B, where the net CONE is the cost of new entry, net of PJM energy and ancillary service market revenues, and B is the balancing ratio or the average ratio of actual generation to committed generation capacity. Net CONE * B also defines a competitive offer under the Capacity Performance design. The logic of the default offer cap is that if expected bonus performance payments as an energy only resource are greater than the avoidable cost, net of energy and ancillary service market revenues or opportunity costs, the resource would not take on a capacity obligation unless it would be better off. In order to offer and take on an obligation, the capacity price must be high enough that the expected 6 The residual supplier index (RSI) is a measure of whether one or more asset owners are pivotal. The RSI equals (total market supply less the supply of the owner or owners in question) divided by (total market demand). Thus an owner, or group of owners, is pivotal if the RSI for that owner, or group of owners, is less than or equal to 1.0. The three pivotal supplier test includes the supply of the top three owners in the RSI equation. © Monitoring Analytics 2016 | www.monitoringanalytics.com 20 profits as a Capacity Performance resource equal or exceed the profits it would make as an energy only resource. This competitive offer is net Cone * B. Avoidable costs are the costs that a generation owner would not incur if the generating unit did not operate for one year, in particular the capacity delivery year. In effect, avoidable costs are the costs that a generation owner would not incur if the generating unit were mothballed for the year. In the calculation of avoidable costs, there is no presumption that the unit would retire as the alternative to operating, although that possibility could be reflected if the owner documented that retirement was the alternative. Unit owners have the option of using a precalculated default avoidable cost rate based on technology type and delivery year, or calculating unit specific avoidable costs. In both cases, the avoidable costs are offset with actual unit specific net revenues. If actual avoidable costs are to be used they must be documented and verified. While this is initially a data intensive exercise, it is doable and experience makes it easier to do as it is possible to compare costs across units and over time. The marginal cost of capacity should also include the full costs of any incremental investments required to maintain the ability of an existing generating unit to be a capacity resource. For example, the annualized fixed costs of an investment in new environmental technology can be added to the offer cap or the costs of a turbine overhaul can be added to the offer cap. The ability to include in the mitigated offer price the annualized fixed costs associated with the capital expenditures needed to maintain a unit as a capacity resource is an essential part of the market power mitigation process. The ability to add the fixed costs associated with necessary capital additions to offer prices permits a market test of the need for the investment. If the investment cost is added and the unit clears, the resulting higher market price signals the appropriate cost of incremental capacity. If the investment is added and the unit does not clear, the market signal is that the unit is no longer needed with the required investment. The rules on adding annualized fixed costs could permit such costs to be added for a duration linked to the expected remaining life of the asset. Thus, a new investment can result in a substantially higher cost based offer that persists for the balance of the asset life.7 For those units that cannot profitably provide energy without a capacity payment because their net avoidable costs exceeds their expected performance payments, a competitive capacity offer is equal to the net avoidable cost, plus expected 7 Such an offer is not actually the marginal cost of the unit. A competitive offer from the unit after the first year would exclude the annualized fixed costs. Any price received in excess of the actual marginal cost would contribute to covering fixed costs and would mean that it is economically rational to continue operation. © Monitoring Analytics 2016 | www.monitoringanalytics.com 21 nonperformance charges, minus expected performance payments, plus any appropriate nonperformance risk premium. This is the appropriate offer cap for such units. An opportunity cost option allows capacity resource owner to input a documented price available in an external market, subject to export limits. If the capacity market clears above the opportunity cost, the capacity resource is sold in the capacity market. If the opportunity cost is greater than the clearing price and the capacity resource does not clear in the RPM market, it is available to sell in the external market. Parameter Rules for Capacity Resources
Capacity resources can also withhold by reducing their dispatch flexibility in the energy market. For example, a capacity resource may offer less capacity in the energy market than it cleared in the capacity market by reducing its maximum capability in the energy market, or by reducing its ramp rate. Capacity resources can also modify minimum runtime and minimum downtime offer parameters as a mechanism for economic withholding. This issue can be addressed by a requirement for capacity resources to submit unit specific parameters that reflect the physical capability of the technology type of the resource. Buyer Side Market Power
There is also concern about the potential exercise of market power and manipulation that could result from the submittal of offers that are too low. An offer that is too low may indicate an offer that is not a bona fide physical offer. An offer that is too low may indicate an attempt to engage in monopsony or buyer side market power. An offer that is too low may be an attempt by a fleet owner to obtain an unfair competitive advantage for some units in its fleet over nonaffiliated competing units. Although it does not appear to be a potential issue in Alberta, one mechanism for the exercise of buyer side market power in the U.S. has been intervention by an individual state which would sign a long term bilateral contract for capacity with payments guaranteed by state ratepayers, typically at an above market price, and require that the capacity be offered into the capacity market at a zero price. Another mechanism has been the construction of capacity by a utility subject to cost of service ratemaking. Ratepayers would guarantee recovery of investment costs while the capacity was offered into the market at zero. Vertically integrated utilities that receive cost of service rates are effectively receiving an out of market guaranteed long term contract for the sale of capacity. The result in both cases would be to suppress capacity market prices below the competitive level. The capacity market design should include market power mitigation rules to limit the extent to which capacity buyers can suppress the price below the competitive level. © Monitoring Analytics 2016 | www.monitoringanalytics.com 22 Recommended Features of an Alberta Capacity Market
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Physical definition of capacity 
Deliverability requirement for capacity 
Must offer requirement for capacity 
Must buy requirement for capacity 
Three year forward procurement of capacity for one delivery year 
Locational pricing of capacity 
Capacity transmission rights 
Forward looking net revenue offset 
Sloped capacity market demand curve based on reliability requirements 
Strong performance incentives 
Effective market power mitigation rules in the capacity market 
Allocation of capacity costs 
One base auction and one incremental auction 
Incorporate renewables in capacity market 
Demand side resources paid outside the capacity market 
Capacity imports not included Recommended Design Features of the Integrated Energy Market
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Must offer in energy market requirement for capacity resources 
Market power mitigation rules in the energy market 
Central, security constrained dispatch in energy market 
Locational pricing in energy market 
Financial transmission rights 
Administrative scarcity pricing in energy market Transition Issues to an Alberta Capacity Market
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Timeline for implementation 
Analysis/market simulations 
Existing long term bilateral contracts for capacity 
Deliverability requirements 
IT requirements © Monitoring Analytics 2016 | www.monitoringanalytics.com 23 Monitoring Analytics, LLC
Monitoring Analytics has over fifteen years of experience as the independent market monitor
for PJM. Monitoring Analytics, LLC was established as an independent company in 2008,
created by spinning off the Market Monitoring Unit of PJM Interconnection. Since 1999, the PJM
Market Monitoring Unit has been responsible for promoting a robust, competitive and
nondiscriminatory electric power market. Monitoring Analytics has also provided consulting
support to market operators, regulators, and consumer advocates throughout the world.
Monitoring
Analytics
reports
and
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http://www.monitoringanalytics.com.
Dr. Joseph Bowring
Dr. Bowring is the President of Monitoring Analytics. Since 1999, Dr. Bowring has been the
Market Monitor for PJM, responsible for all market monitoring activities of PJM
Interconnection. He has extensive experience in applied energy and regulatory economics. Dr.
Bowring is called upon to testify before state and federal regulators. Dr. Bowring has taught
economics as a member of the faculty at Bucknell University and Villanova University. He has
served as senior staff economist for the New Jersey Board of Public Utilities and as Chief
Economist for the New Jersey Department of the Public Advocate’s Division of Rate Counsel.
Dr. Bowring has also worked as an independent consulting economist. Dr. Bowring has a Ph.D.
in Economics from the University of Massachusetts.
Alexandra Salaneck
Alexandra Salaneck is a Senior Analyst at Monitoring Analytics. She is the lead Market Monitor
staff member responsible for analyzing and monitoring capacity markets, including PJM’s
Reliability Pricing Model (RPM). Ms. Salaneck prepares detailed analyses and reports about the
design and performance of the capacity markets and develops software models of the operation
of the PJM capacity market. Ms. Salaneck is the Market Monitor’s expert on the capacity market
rules in the PJM Tariff and contributes to the design of the RPM capacity market. Ms. Salaneck
leads the Market Monitoring efforts on the detailed review of unit specific offers in the capacity
market auctions, including engaging in detailed discussions with market participants’ technical
experts. Ms. Salaneck has a Bachelor of Science in Math and Economics from Albright College.
Dr. John Hyatt
Dr. Hyatt is a Senior Economist at Monitoring Analytics, where he is responsible for analysis of
the PJM capacity market and market modeling. He joins Monitoring Analytics from the
Southwest Power Pool Market Monitoring Unit, where as MMU Principal, he was the project
lead on critical deliverables such as the State of the Market Report as well as key MMU research
and development projects. Prior to working at SPP, Dr. Hyatt worked for the Arkansas Public
Service Commission. Dr. Hyatt has a Ph.D. in Applied Mathematics from the Colorado School
of Mines.
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