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3. Business Case
6. Success Criteria
7. Frequency Regulation Technologies
9. Next Steps
- Frequency regulation service is the injection or withdrawal of real power by facilities capable of responding appropriately to a transmission system operator’s automatic generator control (AGC) signal. When dispatched generation does not equal actual load plus losses on a moment-by-moment basis, the imbalance will cause the grid’s frequency to deviate from 60 Hertz, the standard in the U.S. While the system does deviate from 60 Hz in the normal operation of the grid, frequency deviations outside an acceptable range negatively affect energy consuming devices; major deviations caus generation and transmission equipment to disconnect from the grid, in the worst case leading to a cascading blackout. Frequency regulation service can help to prevent these adverse consequences by rapidly correcting deviations in the transmission system’s frequency to bring it within an acceptable range. The system operator calibrates the AGC signal sent to frequency regulation resources to respond to actual and anticipated frequency deviations or interchange power imbalance, both measured by area control error (ACE)
- Today, frequency regulation is largely provided by generators (e.g., water, steam and combustion turbines) that are specially equipped for this purpose. Provision by other resources is emerging, as technologies develop and tariff and market rules adapt to accommodate new resources. For example, the Texas Interconnection and MISO currently use controllable demand response in addition to generators to provide frequency regulation service. Such “regulation capable” generation, storage devices, and demand response resources can respond automatically to signals sent by the RTO or ISO, through AGC, to increase or decrease real power injections or withdrawals and thereby correct actual or anticipated frequency deviations or interchange schedule imbalance, as measured by the ACE. The faster a resource can ramp up or down, the more accurately it can respond to the AGC signal and avoid overshooting. Alternatively, when a resource ramps too slowly, its ramping limitations may cause it to work against the needs of the system and force the system operator to commit additional regulation resources to compensate
- The United States Federal Energy Regulatory Commission (FERC) defines the ancillary services as: "those services necessary to support the transmission of electric power from seller to purchaser given the obligations of control areas and transmitting utilities within those control areas to maintain reliable operations of the interconnected transmission system." and identifies six different kinds of ancillary services:
- scheduling and dispatch
- Reactive power and voltage control
- Loss compensation
- Load following - slower-ramping resources that ramp with the load over a five minute period
- System protection
- Energy imbalance
- the net energy that the resource injects into the system
- accurately following the RTO’s or ISO’s dispatch signal
- the absolute (rather than net) amount of energy injected or withdrawn.
- ACE – Area Control Error – Measures frequency deviations and interchange power imbalance. A measure of the quality of operation of the grid. ACE must be kept within grid operating requirements.
- Ancillary Services - Balancing services used to balance generation and demand in tightly limited situations to maintain the alternating current (AC) system frequency of 60 Hz. Energy storage is perfectly suited to provide this service by absorbing electric energy (charging cycle) whenever there is too much generation for a given demand and by injecting electric energy into the power grid discharging cycle) when there is too little generation. Traditionally, these services have been performed by conventional gas or steam turbine technologies. But rather than varying the torque of large rotary turbo-machinery on a second-by-second basis, electrochemical EES is much better suited to quickly respond to the grid needs.
- AGC - Automatic Generator Control - Frequency regulation service is the injection or withdrawal of real power by facilities capable of responding appropriately to a transmission system operator’s AGC signal.
- Ancillary Services Demand Response
- In the Ancillary Services DR market, end-use customers are allowed to bid load curtailments in ISO/RTO markets as operating reserves. Accepted bids are paid the market price for committing to be on standby. In order to participate in ancillary-service markets, end-use customers must be able to adjust load quickly during a DR event. The response requirement depends on the nature of the event and the type of reserve being supplied.
- Loads typically have a very short response time, usually specified in minutes, rather than in hours. These short timeframes and program requirements limit the type of resources that can participate. End-use loads that qualify for participation as an ancillary services option could include large industrial processes that can be curtailed safely and quickly without harm to equipment. Examples of loads are air products or electric arc steel furnaces, large water pumping load, or remote automatic control of appliances such as air conditioners.
- End-use customers participating in the ancillary services market receive a capacity payment for committing loads to be on standby. The capacity payment is based on the market clearing price for capacity (MCPC). If load curtailments are needed, and they are called by the ISO/RTO, participants are paid the spot-market energy price. There is typically a higher minimum size for reductions and customers are required to install advanced real-time telemetry because of the stringent program requirements.
- End-use loads that qualify for participation in the ancillary service option require capability to respond to an event notification that is going to occur within 30 minutes of the notification.
In general, when a resource submits its frequency regulation bid to the RTO or ISO, the bid is typically required to include its ramp rate in MW/min, its cost per megawatt-hours (MWh) of ramping ability, and the total capacity it is offering for frequency regulation.
The resource’s total amount of capacity is based on and limited by its ability to ramp up or down. For example, a resource with a relatively large amount of capacity, but a relatively slow ramp rate would be limited in how much capacity it could offer as frequency regulation capacity. If the resource can ramp one MW per minute, it would only be able to offer five MW of regulation capacity (for a five minute dispatch) regardless of its total capacity. On the other hand, a smaller capacity, faster ramping resource might not face such a constraint. For instance, a storage device that can hold a 20 MW charge and ramp at 10 MW per minute, could offer its full 20 MW of capacity for five minutes.
Order No. 755, generators or other entities providing this service will be compensated in a two-part structure.
- Capacity Payment - Regulation service providers will receive a capacity payment reflecting the opportunity costs of the marginal resource providing frequency regulation service during the settlement period. This approach acknowledges that a frequency response resource must hold some of its capacity in reserve to provide frequency regulation service when such service is needed, and therefore the resource forgoes the revenue it could otherwise earn through energy market sales.
Order No. 755 also allows for the recovery of inter-temporal opportunity costs, such as costs incurred by an energy storage device that must provide frequency response service at a time of day when it would be more cost-effective for it to buy energy to recharge the storage device. Order No. 755 leaves the specific methods for calculating such opportunity costs to individual regional markets, explaining that the operators of the separate regional organized markets are "in the best position to perform accurate cross-product opportunity cost calculations." With regard to inter-temporal costs, Order No. 755 requires that such costs be verifiable, but it allows individual regional market operators to determine whether these costs should be determined by the ISO or RTO or by market participants.
- Performance Based - The second component of regulation service compensation is "performance-based" and will reflect the amount of the up or down movement a resource provides in response to the system operator's dispatch signal and the resource's accuracy in responding to the dispatch signal. This approach accounts for the fact that a resource with faster ramping capability can provide a greater amount of capacity into the regulation market than can a slower-ramping resource.
An RTO or ISO is defined as an electric utility regulated by FERC, and most are non-profit. It is
funded by a grid management charge approved by FERC and paid by generators and load serving entities within the RTO/ISO’s balancing authority. It operates the electric transmission acilities under its authority in compliance with NERC approved mandatory reliability standards. In so doing, it provides nondiscriminatory access to transmission services for all qualified market participants.
Historically, some RTO/ISOs evolved from power pools, for example PJM, while others were created by state legislation which also mandated electric industry restructuring, for example CAISO, or through other voluntary associations, such as the Midwest ISO.
An RTO/ISO designs and administers within its balancing authority several types of auction markets, including day-ahead and real-time wholesale spot markets (including five minute dispatch) for electric energy and ancillary services, and forward markets for financial transmission rights; several also operate forward markets for capacity. These markets are characterized by transparent prices and have both ex ante and ex post rules that support workably competitive market outcomes.
- On October 20, 2011, pursuant to section 206 of the Federal Power Act, FERC revised its regulations to remedy undue discrimination in the procurement of frequency regulation in the organized wholesale electric markets and ensure that providers of frequency regulation receive just and reasonable and not unduly discriminatory or preferential rates. Frequency regulation service is one of the tools regional transmission organizations (RTOs) and independent system operators (ISOs) use to balance supply and demand on the transmission system, maintaining reliable operations. In doing so, RTOs and ISOs deploy a variety of resources to meet frequency regulation needs; these resources differ in both their ramping ability, which is their ability to increase or decrease their provision of frequency regulation service, and the accuracy with which they can respond to the system operator’s dispatch signal.
- The Commission found that current frequency regulation compensation practices of RTOs and ISOs result in rates that are unjust, unreasonable, and unduly discriminatory or preferential. Specifically, current compensation methods for regulation service in RTO and ISO markets fail to acknowledge the inherently greater amount of frequency regulation service being provided by faster-ramping resources. In addition, certain practices of some RTOs and ISOs result in economically inefficient economic dispatch of frequency regulation resources.
- For example, that CAISO, NYISO, MISO, and PJM pay a capacity payment to all resources that clear the frequency regulation market, and then net the amount of regulation up and regulation down provided by these resources in order to compensate for the energy costs they incur. A simplified example would be to consider two resources that clear with the same amount of capacity and are directed to provide regulation up and regulation down over the course of a five-minute interval. The fast-ramping resource might be directed to move around an initial output level up five MW, then down three MW, up one MW, down ten MW, and finally up nine MW. A netting approach to compensation would determine that the resource provided an additional two MW of energy to the system (+ 5 – 3 + 1 – 10 + 9 = +2) during that five minute interval. Meanwhile, a slower ramping resource may be directed to move up three MW and then down one MW for a net of two MW in relation to its initial output level. The operator is not able to direct more movement because the slower-ramping resource would not be able to respond in the requisite time frame. Both resources would receive identical compensation for their movement, despite the first resource providing more ACE correction
- By remedying these issues, the Commission is removing unduly discriminatory and preferential practices from RTO and ISO tariffs and requiring the setting of just and reasonable rates. Specifically, this Final Rule requires RTOs and ISOs to compensate frequency regulation resources based on the actual service provided, including a capacity payment that includes the marginal unit’s opportunity costs and a payment for performance that reflects the quantity of frequency regulation service provided by a resource when the resource is accurately following the dispatch signal
The primary economic benefit that some commenters expect to see is reduced costs of procuring frequency regulation capacity, with a secondary benefit of reduced energy costs. fFaster-ramping resources are able to provide more frequency regulation service from the same amount of frequency regulation capacity because faster-ramping resources can provide more ACE correction in real-time.
- Control Frequency - Provides frequency regulation to maintain the balance between the network's load and power generated. Provides stability, VAR support, power quality and transfer-leveling, and reliability.
- Faster Ramping Resources Cost Less - The final rule serves to remove barriers to the participation of faster-ramping and more accurate resources in the frequency regulation markets. The utilization of these more accurate resources will lead to reductions in the amount of regulation capacity that each balancing authority must procure – savings which can then be passed on to consumers. Furthermore, the rule will also allow the mostly thermal generation fleet that currently provides regulation to instead more efficiently operate in the energy markets at their optimum heat rates, where they can submit lower offers to supply energy and thus further lower costs to consumers. Because the energy market is much larger than the regulation market, this is where there may be greater savings.
- Improved Reliability - The final rule should enhance reliability as it incents new resources to come online and provide system operators in the ISOs and RTOs with additional tools and flexibility to manage the grid. As I have repeatedly indicated, we are asking our aging grid infrastructure to do more and more as regional electricity markets expand and we seek to transmit power over long distances from location constrained resources. We need to make sure that the operators of the grid are prepared to deal with these challenges with tools like the enhanced regulation market design we are directing today.
- Reduced Emissions - The final rule will result in an overall reduction in emissions from the generation fleet. Some of the new resource technologies that are faster and more accurate produce no emissions themselves. Further, the mostly thermal generation that traditionally has provided regulation will now be able to bid their capacity into the energy markets at their optimum heat rates. This will enable the thermal generators to maximize their efficiency, which in turn will reduce their emissions.
- The two-part rate is likely to be administratively-determined. There is no straightforward way for both the mileage payment and the capacity payment to be established through competitive offers. Therefore, the subjective judgment of the Commission and the operators of RTOs and ISOs will replace market forces in determining the value of frequency regulation service.
- Subjectivity = Controversy - Bbecause the rate will be administratively-determined, it will be controversial and subject
- The performance payment will increase payments that must be recovered through uplift, complicating existing settlement procedures and efforts to reduce uplift.
- Penalize Existing Technology A performance payment will unduly discriminate against existing technologies that could respond faster but for the presence of barriers that have not, to date, presented themselves as obstacles. These barriers include the use of static ramp rates that reflect typical performance under all conditions rather than peak performance under conditions that exist at a point in time.
- Potential for Manipulation - Multi-part offers require complex rules to deter market manipulation because it is difficult to differentiate between legitimate and illegitimate bidding behavior.
- Regulatory Treatment of Storage & Asset Classification - Today's regulatory structure and utility processes disfavors energy storage. Storage is neither supply nor demand in a traditional sense and existing regulatory framework is not set up to manage it. It is a matter of debate whether the cost of energy storage technologies utilized to shift transmission utilization to match capacity should be a generation or a transmission asset because of its multifaceted implications for business models, sources of financing, and regulatory cost recovery.
- Energy Storage is a transmission application because it is directly linked to the transmission system and its operation, without any bias towards its classification as such for regulatory or business model questions.
- Storage can also be used for energy price arbitraging and production leveling, which are normally generation functions and which developers prefer to perform on a merchant basis so that they can access market prices. Also, the operator takes ownership of the energy in redelivering it which isn’t a transmission function.
We need appropriate regulatory, market, and incentive treatments to encourage storage in support of renewable energy. When Storage is used in a multi-purpose application (as at a substation), it is unclear how to allocate costs and benefits for cost recovery. Because these benefits address different functions (generation vs. transmission), it may be difficult to measure the different benefits and allow for full cost recovery based on these benefits.
- FERC rules for energy storage asset class
6. Success Criteria
- Communications - In the case of short-term storage (seconds to minutes) for ancillary services, including frequency regulation, reactive supply and voltage support, requires fast and secure communications that allow for automatic control of the resource.
- Battery Storage (See my Blog Article - Battery Storage) - Utilities typically use batteries to provide an uninterruptible supply of electricity to power substation switchgear and to start backup power systems. However, there is an interest to go beyond these applications by performing load leveling and peak shaving with battery systems that can store and dispatch power over a period of many hours. Batteries also increase power quality and reliability for residential, commercial, and industrial customers by providing backup and ride-through during power outages.
- EDLC - Electrochemical Double Layer Capacitors - (Also known as supercapacitor, supercondenser, pseudocapacitor, or ultracapacitor) (See my blog article - Supercacitors) Store energy directly as charge. An EDLC is an electrochemical capacitor with relatively high energy density. Compared to conventional electrolytic capacitors the energy density is typically on the order of hundreds of times greater. In comparison with conventional batteries or fuel cells, EDLCs also have a much higher power density.
- Flywheel (See my Blog Article) – Flywheels are designed to smooth out transient fluctuations in load and supply, Changing power output causes greater wear and tear on equipment, and fossil generators that perform frequency regulation incur higher operating costs due to increased fuel consumption and maintenance costs. They also suffer a significant loss in "heat rate" efficiency and produce greater quantities of CO2 and other unwanted emissions when throttling up and down to perform frequency regulation services.
- SMES - Superconducting magnetic energy storage systems (See my blog article SMES) store energy in the magnetic field created by the flow of direct current in a superconducting coil which has been cryogenically cooled to a temperature below its superconducting critical temperature. A typical SMES system includes three parts: superconducting coil, power conditioning system and cryogenically cooled refrigerator. Once the superconducting coil is charged, the current will not decay and the magnetic energy can be stored indefinitely. The stored energy can be released back to the network by discharging the coil. The power conditioning system uses an inverter/rectifier to transform alternating current (AC) power to direct current or convert DC back to AC power.
Supercapacitors are DC energy sources and must be interfaced to the electric grid with a static power conditioner, providing 60-Hz output. A supercapacitor provides power during short duration interruptions and voltage sags. By combining a supercapacitor with a battery-based uninterruptible power supply system, the life of the batteries can be extended. The batteries provide power only during the longer interruptions, reducing the cycling duty on the battery. Small supercapacitors are commercially available to extend battery life in electronic equipment, but large supercapacitors are still in development, but may soon become a viable component of the energy storage field.
- Vehicle-to-grid (V2G) - (See my blog article V2G) - Describes a system in which power can be sold to the electrical power grid by an electric-drive motor of a hybrid vehicle that is connected to the grid when it is not in use for transportation. Alternatively, when the car batteries need to be fully charged, the flow can be reversed and electricity can be drawn from the electrical power grid to charge the battery
- FERC - The Federal Energy Regulatory Commission - United States federal agency with jurisdiction over interstate electricity sales, wholesale electric rates, hydroelectric licensing, natural gas pricing, and oil pipeline rates. FERC is also responsible for ensuring the reliability of the nation’s high-voltage interstate transmission system. Not all transmission is subject to FERC jurisdiction. Public power entities such as the Los Angeles Department of Water and Power are not under FERC jurisdiction. Federal agencies also self-govern, so the Bonneville Power Administration, the Western Area Power Administration and the Tennessee Valley Authority all fall outside FERC’s authority. Finally, most of Texas and all of Hawaii and Alaska are outside FERC jurisdiction because they are not connected, or not tightly connected, to the interstate transmission grid.
- While Order No. 755 applies only to organized ISO and RTO markets, FERC may act to broaden its application. On June 11, 2011, FERC issued a Notice of Inquiry ("NOI") seeking comment on whether the cost-based compensation methods for frequency regulation in regions outside of organized markets should be adjusted to address the same issues addressed in Order No. 755. Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies, Notice of Inquiry, 135 FERC ¶ 61,240 (2011). In the NOI, FERC sought comments on different frameworks under which the speed and accuracy of frequency regulation resources might be appropriately valued in non-RTO and non-ISO markets. The matter is pending before FERC.
- FERC - Final Rule October 20, 2011 - Frequency Regulation Compensation in the Organized Wholesale Power Markets Docket Nos. RM11-7-000
- CPUC - Demand Response Cost-Effectiveness Protocols - Final (MS-Word) - These protocols have been developed with the understanding that DR is in a transitional period. Historically, DR was largely employed for reliability purposes during system emergencies in the form of interruptible programs for large industrial customers, which could be triggered when an ISO would otherwise have to shed load during a system emergency or when a utility was faced with a serious distribution system emergency. However, the deployment of advanced metering technology and development of new energy markets is enabling greater use and flexibility of demand response by all types of customers. Increasingly, customers are able to manage their loads to provide different levels of load reduction in response to price signals or other incentives. These load reductions provide value to the grid not only during emergencies, but also during times of high energy prices or in the ancillary services market. As a result, the methods used to measure the costs and benefits of demand response must be flexible enough to capture these emerging benefits.