The Federal Energy Regulatory Commission (FERC) approved sweeping changes to PJM’s reserve products on May 21, 2020 in a filing called “Enhanced Price Formation in Reserve Markets of PJM Interconnection.” In this edition of Customer Insights, we’ll discuss key changes to the reserve products, plus the cost implications to reserves, energy and capacity.
PJM is a dispatch operator
PJM dispatchers coordinate energy production among generators, demand resources and market participants to ensure businesses like yours have enough power to operate. Operational decisions, such as when to request the change of power output from a resource or whether to start a resource, come in two forms – programmatic and human intervention. Dispatch software used by PJM provides their dispatchers a variety of recommended solutions. Once the solution is chosen, dispatch signals are sent to the resources participating in PJM’s market. This process repeats itself every five minutes. However, an event may occur requiring the PJM dispatcher to use their discretion and override the system recommendations.
Perhaps the dispatcher received new information or new unanticipated changes in system conditions occurred. When manual interventions occur, costs associated with these measures are most often not reflected in the locational marginal price (LMP) nor can they be reflected in the price comprised of the various reserve products.
Why are reserves important?
PJM must maintain sufficient reserves, ensuring that available energy can be called upon and available within fifteen minutes. The event causing the need, or contingency, is typically in one of two forms: the loss of a large generator or the loss of a transmission element(s) carrying energy from power generators to customers. In addition, PJM must also have sufficient reserves to respond to changes in customer usage, load forecast error, generator output and performance and transmission system operational constraints. During periods of insufficient reserves, there is greater risk of emergency actions that PJM may utilize to ensure reliability. These emergency actions, such as calling upon uneconomic resources, curtailing load, reducing voltage on the system or even purchasing emergency energy all come at a cost to customers.
Today vs. future
Today, PJM must have a certain minimum quantity of reserve products available to meet its North American Electric Reliability Corporation (NERC) reliability requirements (we’ll discuss the reserve products later in this edition). PJM only pays generators if there is an insufficient amount of a certain product needed on the system, such as Synchronized Reserves, which are used to respond to a sudden change on the system.
There are two types of Synchronized Reserves – Tier 1 and Tier 2.
Tier 1 reserves are defined as the energy or reduction (demand response) capability of an online resource having ‘extra’ energy output which can be obtained within ten minutes. PJM will not pay a resource providing Tier 1 reserves unless they have an insufficient quantity available.
Tier 2 reserves become necessary only if PJM has an insufficient quantity of Tier 1 reserves. PJM obtains these additional reserves by dispatching units to a different operational output so that additional energy can be made available, upon request (spinning reserve event). There is a cost of doing so, and that is incorporated into a cleared quantity and price. This result is cleared Tier 2 reserves. Only in the event of Tier 2 reserves being awarded and cleared will those resources that are providing Tier 1 reserves be paid for the value of reserves.
In the event PJM needs the actual energy, they will initiate a spinning reserve event. This event signals all available resources to increase energy output or for customers to immediately reduce energy consumption, so a balance can be achieved between energy consumption and production. Those that respond are eligible to obtain an additional $50/ MWh adder to the LMP from the start time until the event end time.
If there is value in having the reserve products available, why are resources only being paid when there is a shortage, or scarcity of the product? An interesting question, and one that garners many opinions. It was the impetus for the changes PJM has implemented.
In the future, PJM has decided to pay for these reserve products, regardless of whether there is ample supply to meet the minimum need. This is a major change in how the PJM system operates and procures reserve supply. The changes made to the procurement and pricing of reserves not only impacts the reserve market, the energy market costs will be impacted as well.
The Operating Reserve Demand Curve and Penalty Factors
PJM already utilizes a little-known concept called an Operating Reserve Demand Curve (ORDC) for each new or modified reserve product we are discussing. Within the curve is a Penalty Factor. The penalty factor is the maximum amount PJM will pay for the quantity of product if there is insufficient supply. Let’s look at an ORDC and penalty factor for Synchronized Reserves and see how it is utilized. Today’s ORDC utilizes step-factors to reach the penalty factors; the future ORDC will use a sloped curve.
In Exhibit A below, the horizontal line represents reserve megawatts (MW) and the vertical line is price. As reserves are reduced, we approach the graph coming from the right- hand side, moving to the left. We also need to introduce a concept called the Minimum Reserve Requirement (MRR), which represents the point at which the lower actual reserves (shown by arrow indicating ‘Actual Reserves’ moving to the left on the x axis) designates a shortage condition. As we move leftward, starting on the right side, let’s ignore Step 2B, because it’s optional and is only used when the PJM dispatcher has reason to believe they need even more reserves. Step 2A represents the MRR plus190 MW. As PJM reserves are reduced, at the beginning of Step 2A (first pricing point), moving to the left on the horizontal axis, we experience a penalty factor price of $300/MWh for the synchronous reserve product.
As our reserves continue to shrink, we move leftward again until we hit the point of the MRR, which then causes the price to instantaneously increase to $850/MWh (second pricing point).
The result – the Synchronized Reserve product began essentially at $0/MWh because there were sufficient sufficient reserves and as those reserves were reduced, we experienced pricing step changes of $300/MWh and then ending at $850/MWh.
In the future, PJM will use sloped demand curves (instead of step-changes) within the ORDC. With this concept, PJM eliminates Steps 1, 2A and 2B as shown above. The sloped curve will indicate the price of reserves above the minimum requirement. PJM will have differently shaped ORDCs per product and per season and will also include time-of-day related provisions.
In the proposed ORDC, the MRR remains, but instead of step changes, PJM introduces a price curve representing the Probability of Falling Below the Minimum Reserve Requirement (PBMRR) times the penalty factor (PF). Using this method, PJM will price reserves and charge customers more, even though they may have ample supply from a NERC reliability perspective.
The PF is another significant change within the ORDC because the factor is increased from $850/MWh at the highest point to $2,000/MWh. PJM justifies this higher price by indicating it is consistent with the maximum level at which an energy offer can be offered and is eligible to set LMP.
The width of the downward curve, from the MRR to the zero price on the horizontal axis, is based on recent historical uncertainty. This includes items such as uncertainty of renewable resource output forecasts, load forecast error, forced outages and even net interchange forecast error (for secondary reserve product which will be discussed later). Finally, PJM will implement the ORDCs for the entire regional transmission organization (RTO) and for sub-regions within it, during times in which there may be insufficient import capability.
As we mentioned early on in this edition, PJM must have a certain minimum quantity of reserve products available to meet its NERC reliability requirements. Although PJM refers to these as products, it may be easier to think of these as essential items required to ensure the continued delivery of safe and reliable power to your businesses. The products and the way in which PJM procures the supply from resources, such as generators, affects the price you pay.
1. Synchronous Reserve Product
Synchronized Reserves will be consolidated into one product, with Tier 1 and Tier 2 being eliminated. Once implemented, Synchronized Reserves will be settled in both the day-ahead and real-time markets. For example, if a resource is awarded to provide the product in the day-ahead market, the resource must also provide the capability in the real-time market.
If the resource fails to do so in the real-time market, the resource is expected to purchase the Synchronized Reserves back (imbalance) at the real-time price of the product for each hour it received an award.If the resource had been self- committing itself to provide reserves, the resource will need to purchase the product back until the point in time in which it last performed successfully, but no greater than 20 days (the number of days is computed on an annual basis).
PJM eliminated a supplier including an additional $7.50/ MWh margin within the offer associated with synchronous reserves. Rather, PJM will only allow a PJM-computed penalty rate considering the average penalty rate and the probability the resource will underperform during an event. PJM proposed $0.02/MWh, but this value may be recomputed prior to implementation of these changes.
PJM also intends to eliminate the variable and operations maintenance (VOM) from the Synchronized Reserve offer because it can be recovered in the energy offer. Finally, PJM will eliminate the $50/MWh LMP adder for response during a spinning reserve event.
Operational parameters associated with a resource’s capability to provide the product is submitted within the energy offer itself. Resources can offer additional capability in the real-time market, mostly by adjusting ramp capability (speed of response in MW per minute) and the Synchronous Reserve maximum MW available.
Clearing prices for this product are generally equal to the highest sum of a resource’s Synchronized Reserve offer and any specific opportunity cost of the resource.
2. Non-Synchronous Reserve Product
The primary change to the Non-Synchronous Reserve product is the utilization of the sloped curve called Operating Reserve Demand Curve (ORDC), which has a $2,000/MWh penalty factor that was discussed earlier. Non-Synchronous Reserves represents non-emergency generation resources that can be fully converted to energy within ten minutes and are not electrically synchronized to the transmission system. The maximum price a resource can offer this service is zero.
3. Day-Ahead Scheduling Reserve Product
Day-Ahead Scheduling Reserves (DASR) is a 30-minute reserve product in the day-ahead market. The goal is to have a sufficient amount of reserve conceptually available in the real-time market. The DASR amount required was based on the average day-ahead load forecast error and average expectation of forced outages in real-time. This product is being eliminated and replaced with Secondary Reserves.
4. Secondary Reserves Product
Secondary Reserves is PJM’s new product replacing DASR. This product represents resources that can provide PJM energy (or by lowering energy consumption) within ten to thirty minutes. A resource does not need to be online to provide Secondary Reserves. The product will clear for customers in differing areas, such as the RTO, or in a reserve sub-zone, such as the Mid-Atlantic Dominion area (which is within the RTO reserve zone).
The Secondary Reserve product will have both day-ahead and real-time components. If a resource is awarded day-ahead and does not have the capability in the real-time market, the resource will buyback the product at the applicable real- time price. If the resource is no longer providing the product because it is following PJM dispatch signal, it must still pay PJM for replacement, but may be eligible for a make-whole payment if the product the resource is now providing ,such as energy or perhaps regulation service, does not provide adequate compensation for the money owed to PJM.
In the event PJM declares a transmission emergency, such as a Voltage Reduction or Load Dump Action in your applicable area (zone or sub-zone), the price of real-time synchronous reserves could rise in each applicable zone(s) to the penalty factor price of $2,000/MWh.
Because there are no voltage or load dump actions taken in the day-ahead market, we should not expect to see prices reach $2,000/MWh for this product in the day-ahead market, unless the price associated with energy offers are near or at that price level.
For Secondary Reserves, resource offer prices will be capped at a zero price ($0.00/MWh).
Must-offer requirement for these products
All generation capacity resources must offer all available reserve capability at all times, regardless of whether the resource is online or offline. This includes Synchronized, Non-Synchronized and Secondary Reserve.
Non-capacity resources must also make the products available to PJM if PMM believes the resource can offer such products. This may include but is not necessarily limited to examples such as storage and hydroelectric resources.
Resources who cannot provide a specific quantity of energy within ten or thirty minutes on a consistent basis and who are not reliable nor dependable will not be required to offer reserves. Nuclear, wind and solar will not be considered for participation in the must-offer requirement. However, these resources may do so if they notify PJM they can reliably provide reserves.
Participation cap elimination
There will no longer be caps on the amount of demand resources that can provide reserve products.
What will these changes cost?
PJM has estimated an annual incremental cost of $556 million. PJM stated some of these costs should be offset by resources needing less revenue from the capacity market. Of the $556 million identified in the study, the load-weighted average LMP increased $0.46/MWh and load payments for energy by approximately $366 million. The remaining $189.1 million is an increase in reserve revenue that will be paid to resources supplying the new products plus $1 million in net costs once Tier 1 is eliminated.
PJM must make some changes to their concepts and file those for approval with FERC. One of the larger modifications is that FERC expects that updated Energy and Ancillary Service offsets must be used (considering incremental revenues) to offset the cost of new entry values used in the 2022/23 Base Residual Auction, whose date is still unknown. This should help reduce the minimum price offers of some subsidized resources that have a capability of providing these products.
Although there is no current firm implementation date for these changes to become effective, the soonest the cost could be seen is in late 2020; but more likely the first or second quarter of 2021.
PJM’s proposed reserve pricing reforms is a very large change in how reserves are computationally valued and procured, with potentially unforeseen costs to businesses. PJM studied only one year to conclude the potential estimated impact to the marketplace. Secondly, PJM noted that if certain rare conditions occur, such as shortages of many products in multiple areas, total energy and reserve costs in the real-time markets for a business in one of these areas could reach $12,000/MWh. However, even if your business is located outside of one of these highly constrained areas (sub zones), the penalty factors associated with the scarcity of products, such as Shortage Pricing (energy), Synchronized, Non-Synchronized and Secondary Reserves, could cause real-time prices to reach $2,000/MWh for each of these four products equating to $8,000/MWh.
Understanding PJM’s operation and their market can be challenging for businesses. At AEP Energy, we feel it’s our obligation to keep you informed of regulatory changes affecting your energy costs. Our subject matter experts, like Brock Ondayko, Director of Real-Time Market Operations, with 24 years of experience, provides you with the facts you need to know. If you are already working with an AEP Energy Sales Representative, they will happily answer your questions and help you mitigate some of these pricing risks or click here to connect with one of our trusted sales representatives.
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