This report was produced by the U.S. Department of Energy’s Office of Energy Policy and Systems Analysis (DOEEPSA) under the direction of Aaron Bergman with substantial input from Paul Denholm and Daniel C. Steinberg ofthe National Renewable Energy Laboratory and David Rosner of the Department of Energy. We would like to thankthe peer reviewers inside and outside of government who provided helpful comments on the document. Figure 2is adapted with permission from Mills and Wiser 2012. Figures 7 and 9 are used with permission from MarkO’Malley, University College Dublin
Power Generation and Transmission Capacity Must Be Sufficient to Meet Peak Demand for Electricity
Electricity demand varies on short and long timescales and is typically higher during the day and in warmer summer months when air conditioning use peaks On a hot summer afternoon, demand can exceed spring evening demand by more than twofold, a pattern seen across most of the United States, though some northern states experience winter peak demand Hourly demand changes across three one-week periods in four regions illustrate how the power system must manage these variations The system must reliably deliver energy during peak demand periods, or partial blackouts could occur Achieving this reliability requires having sufficient resources on the system to meet peak demand, a concept known as resource adequacy.
Figure 1 Historic hourly load patterns for ERCOT (Texas), CAISO (California), NYISO (New York) and Florida Power and Light for significant weeks in 2014
System planners perform load forecasting to project total electricity peak demand years ahead, factoring in expected load growth They then assess whether and how much additional capacity will be needed to meet that forecasted demand These calculations typically consider existing capacity, anticipated plant retirements, and a range of federal and state regulatory considerations, including emissions regulations and renewable portfolio standards In some cases, retired generators are not replaced, which reduces available capacity in the power system While there is regional variation in the methods used to determine required capacity, all planners must produce an estimate of the capacity needed to meet peak load.
Forecasting and advance planning give utilities and developers the necessary lead time to bring new generators and their supporting infrastructure online, since approval, permitting, and construction can take several years By aligning project schedules with regulatory reviews and long-lead construction timelines, stakeholders reduce delays, ensure reliable power supply, and accelerate the deployment of critical energy infrastructure.
Determining the total generation capacity requirement involves two key steps: first, establishing a target resource adequacy level (often measured by loss of load expectation, as discussed later in this section); second, estimating the amount of generation needed to meet that level (typically measured by the planning reserve margin) These steps are repeated at least annually to ensure the system can respond to load growth and other factors affecting reliability The planning reserve margin is the quantity of spare or backup capacity that the utility or grid operator holds in reserve to respond to a range of factors that could threaten the ability to meet load; these factors include potential threats to meeting demand.
1 Errors in forecasting: Load can be higher than anticipated, as is the case when unusually hot summer weather creates a spike in air conditioning demand
2 Forced (unplanned) outages: No power plant is 100% reliable, and since generators can fail, it is necessary to have spare capacity available to provide backup
3 Transmission outages: Transmission lines and associated equipment can also fail, which limits the amount of electricity that can be delivered from generators to load
Planning reserve margin is the extra capacity above the expected peak demand, typically measured in MW, that a power system maintains to ensure reliability For example, with an anticipated peak demand of 10,000 MW, a planning reserve margin of 15% results in 11,500 MW of conventional capacity, providing 1,500 MW of spare capacity to sustain reliability In setting the planning reserve margin target, utilities, system operators, or regulators rely on detailed reliability calculations to determine the amount of capacity needed to minimize the risk of blackouts A common basis is a loss-of-load expectation target of 0.1 days per year or 0.1 events per year Once the target planning reserve margin is set and the total capacity is identified, planners use this framework to guide resource adequacy assessments and capacity planning.
The 1-in-10 reliability standard is widely used across North America, but substantial variation in its implementation means it does not reflect a uniform level of reliability It may be interpreted as either one event in ten years or one day in ten years, with the former equating to a loss-of-load expectation of 0.1 LOLE per year and the latter to 2.4 LOLH per year, regardless of the size or duration of individual outages When utilities or project developers estimate capacity needs, they determine what resources to build to provide that capacity and meet reliability targets.
COMPLYING WITH RULE 1: TRADITIONAL MEANS
Traditionally, system operators have relied on generating capacity to meet planning reserve margins But building adequate conventional capacity is not the only tool for ensuring resource adequacy Energy Efficiency (EE) and Demand Response (DR) programs can reduce peak demand and often serve as direct substitutes for conventional capacity in meeting planning reserve margins and maintaining system reliability Additionally, the construction of new transmission lines to access power from neighboring resources has long been used as a traditional means of meeting reserve margins.
Before the large-scale penetration of variable generation (VG) resources, power plants were categorized by the load they typically provided—baseload, intermediate, or peaking—and system operators aimed to meet demand in the most economical way by choosing the right mix Baseload plants, usually low-cost nuclear or coal, run at near full capacity to meet constant demand, though their output can be adjusted if needed Intermediate-load plants, often gas-fired and including combined-cycle units, handle daily demand variations, while low gas prices are increasingly prompting natural gas combined-cycle (NGCC) plants to serve as baseload where feasible Hydroelectric units, where available, can function as baseload or intermediate load plants Peaking generators address extreme spikes in demand and are typically simple-cycle gas turbines or older oil- or gas-fired steam generators; they are inexpensive to build but more costly to operate due to lower efficiency or higher fuel costs In planning and daily operations, system operators optimize the generator mix to meet demand as economically as possible, making the determination of this mix a central aspect of power-system planning.
With the rise of wholesale energy and capacity markets, planning is increasingly replaced by market mechanisms, yet developers still evaluate load growth patterns, system requirements, and expected utilization to determine the most suitable type of plant to construct This market-driven approach aligns generation decisions with reliability, cost efficiency, and long-term demand, guiding project timing and technology choices in the modern power system.
Energy efficiency improvements reduce the electricity required to provide a given end-use service, such as lighting or air-conditioning For example, light-emitting diode (LED) bulbs deliver the same lumens as traditional incandescent bulbs but use only a fraction of the energy By cutting end-use electricity consumption through efficiency measures, the need for new capacity can be displaced, helping to lower overall system costs and support a more reliable power grid.
In some locations, peak electricity demand is met by pumped-storage hydroelectric plants These systems store energy by pumping water uphill into an elevated reservoir during periods of low demand, then release it through a conventional hydroelectric generator to meet peak loads This approach helps balance the grid by converting stored potential energy back into electricity when it is most needed.
Peak summer demand in the United States strains the electric grid, but more efficient air conditioning can maintain comfortable indoor temperatures with less electricity In addition, energy-efficient lighting emits less waste heat, reducing the cooling load and making buildings easier to cool Consequently, the overall demand on air conditioning systems declines.
DEMAND RESPONSE AND INTERRUPTIBLE LOAD
Demand response (DR) and interruptible load are valuable tools for utilities to reduce the need for capacity without compromising service levels Instead of building new capacity, utilities can offer incentives or pay electricity users to reduce demand (conservation) or to shift their usage to times of lower demand (load-shifting) These programs can be cost-effective as long as the total incentive payments are less than the cost of new generation capacity.
Historically, large industrial and commercial customers have been offered “demand-based” or
Demand-based plans, also known as interruptible rates, charge higher prices during peak demand periods to encourage large industrial customers to reduce consumption when the grid is stressed, thereby lowering the need for peaking capacity In exchange for lower electric rates, interruptible rate structures reserve the option for utilities to limit or temporarily turn off electricity supply under defined circumstances Historically, these arrangements have been rare for smaller consumers such as households because of the costly communications and metering equipment required, but advances in Smart Grid Technologies are making them more viable for a broader range of customers.
Utilities offer demand-response (DR) programs for residential customers, including direct load control (DLC) programs that let utilities remotely control appliances such as air conditioners and electric water heaters to reduce peak demand In exchange for a reduction on the customer’s bill, the utility installs a remotely controlled switch on the appliance and may turn it off for short intervals, typically 15-30 minutes For most consumers, the interruption of service is rarely noticeable More recently, new classes of demand-response programs have emerged with wholesale electricity markets, expanding DR options beyond traditional DLC through initiatives tied to Smart Grid Technologies.
Power systems must have adequate flexibility to address variability and uncertainty in
Electricity demand varies minute by minute and hour by hour, forcing grid operators to continually adjust output from conventional generators to match the changing load The demand profile over a 24-hour cycle is highly variable, with summertime demand nearly doubling during the day Even in the absence of any variable generation, system planners must ensure sufficient flexibility to accommodate highly variable demand on both an hourly and seasonal basis As more variable generation, such as wind and solar, is integrated, the variability of net load increases Consequently, a power system with growing levels of wind and solar requires even greater flexibility to balance supply and demand.
Figure 6 illustrates the impact of wind on net load—the portion of power demand that must be met by conventional generation The presence of wind increases both the net load ramp rate and ramp range, forcing conventional generators to adjust output more aggressively than in the past For example, on April 8 the system operator would normally need to increase generation by up to 4,000 MW per hour With added wind generation, the required ramp rises to about 5,500 MW per hour to offset the greater variability in net load, a difference of 1,500 MW per hour As shown earlier in Figure 3, solar PV can also contribute to increased net load variability.
Figure 6 Increase in net load variability with added wind
COMPLYING WITH RULE 2: TRADITIONAL MEANS
As discussed, fluctuations in electricity demand are typically met by intermediate-load or peaking plants, often gas-fired, capable of varying output on an hourly or sub-hourly basis These plants handle most day-to-day demand variations by reducing output during periods of low demand and ramping up to high or full output as demand rises Many of these units may also shut down in the evening or during the spring when demand is lowest On hot summer days, when demand is at its peak, operators rely on peaking plants that can start quickly and run for only a few hours during the day.
Recent analysis has demonstrated that the current fleet of installed generation can typically provide sufficient system flexibility to accommodate significant increases in wind and solar generation (Cochran et al
2015, Lew et al 2013; Bloom et al 2016)
These studies of systems with up to 35% VG demonstrate that existing resources that are
Variable generation (VG) can be accommodated because these resources can ramp rapidly enough to provide load-following at five-minute dispatch intervals (see System Ramping) The implication is that, while VG may increase ramping requirements, the existing generation fleet is largely adequate to meet this need In the United States, the average age of the gas combined-cycle fleet is about 12 years and the combustion turbine fleet about 16 years (EIA 2016), which means this capacity can provide grid flexibility services for the foreseeable future.
COMPLYING WITH RULE 2: NEW OPTIONS
Although traditional measures can meet Rule 2, there is substantial potential to increase grid flexibility, reduce costs, and preserve reliability Analyses and recent experience show that new policies and operational procedures can help the power system accommodate greater net-load variability Much of this work aims to unlock flexibility that already exists, as noted by CPUC (2015) For example, contractual agreements that prevent generator ramping can hinder responsiveness, a constraint highlighted by Lew et al (2015).
Across regions in the United States, new incentives and standards are being introduced to boost system flexibility These proposed standards typically define a clear flexibility requirement and allow market participants to meet it by choosing among existing or emerging technologies For example, California is exemplifying this approach by adopting flexible, technology-neutral rules that encourage innovation while maintaining reliability.
Power system operators routinely manage highly fluctuating electricity demand For example, the California Independent System Operator recorded a 3-hour ramp of 11,072 MW on the morning of July 22, 2006, as load rose from 30,252 MW to 41,342 MW Through careful planning and forecasting, the system was able to increase generator output to meet this surge in demand By 2014, the maximum 3-hour ramp rate had declined to 7,859 MW, in part due to the impact of distributed PV, which reduces summer-time ramp rates (as shown in Figure 5).
As solar PV penetration increases, peak demand is expected to shift from summer to spring CAISO forecasts a PV-driven three-hour ramp of about 13,000 MW, roughly 15% higher than the ramp observed in 2006.
The California Public Utilities Commission requires load-serving entities, primarily the state's three large investor-owned utilities, to secure flexible capacity capable of covering the largest predicted 3-hour ramp rate each month To address shorter-duration ramps caused by solar and wind uncertainty, other system operators are developing tools and mandating flexibility reserves Although the exact technical requirements are not yet defined, flexibility reserves are the ability to adjust generator output or, for demand response, load in response to forecast errors linked to short-term variations in load or variable generation (Xu and Tretheway, 2012; Navid et al., 2011).
Newer, more flexible generation technologies are available, with gas-fired generators generally offering greater flexibility than coal-fired units Replacing retiring coal units with more flexible gas-fired plants would enhance system operators' ability to rapidly adjust generation Some modern gas-fired technologies, including gas-fired combustion turbines and reciprocating engines, provide very fast ramp rates and very short start times, enabling rapid response to changing demand These flexible units can provide flexibility reserves without needing to be online, avoiding part-load operation that reduces efficiency and increases costs In addition, certain coal units and potentially some nuclear units are capable of operating flexibly.
Many of today’s new and emerging technologies that already deliver conventional capacity can also enhance grid flexibility, reducing the need to build new natural gas plants solely to provide that flexibility.
Advanced biomass and concentrating solar power equipped with thermal energy storage provide fast ramping capability (Jorgenson et al
Demand response (DR), guided by appropriate pricing signals, can vary load in response to extreme or unexpected ramp events, enhancing grid flexibility and reliability Moreover, most storage technologies can ramp as fast as or faster than conventional generators (Ma et al 2016), delivering rapid mitigation of volatility and helping balance supply and demand Finally, the combined use of DR and fast-ramping storage offers a robust approach to maintaining stability and resilience in modern power systems under stressed conditions.
VG itself can be used to mitigate ramp events via curtailment (reduction in output from a generator from what it could otherwise produce
Several modern generator types are capable of starting and reaching full load in as few as 5–10 minutes These include aeroderivative gas turbines and reciprocating engines
Aeroderivative turbines are like traditional gas turbines but use moving parts derived from aircraft jet engines, making them very light and able to change output rapidly in response to the variability of wind and solar resources Reciprocating engines, similar to vehicle engines, can also start rapidly, enabling quick ramping when renewable generation fluctuates Both aeroderivative turbines and reciprocating generators are installed in locations that require responsive capacity without the need to keep traditional generators online These features make them ideal for flexible power plants that support grid reliability amid increasing renewable energy integration.
Wind has become a dispatchable resource in several regions, allowing operators to reduce wind output when supply exceeds demand and to ramp wind generation up or down to follow load or provide reserves For example, Xcel Energy in Colorado has been able to serve over 60% of its load with wind power during certain hours of the year by dispatching wind See the text box "Dispatching Wind" for details While curtailment of wind generation incurs the cost of lost energy production and is typically avoided, occasional curtailments can be effective for balancing supply and demand, managing transmission overloads, and maintaining system reliability; curtailments can be less costly than shutting down and starting up a conventional power plant for short periods of very high wind output.
Power Systems Must be able to Maintain Steady Frequency
The U.S power grid relies on alternating current (AC), meaning electricity periodically reverses direction This reversal is defined by its frequency, or how many times per second the current changes direction In the United States, the standard AC frequency is 60 cycles per second, commonly referred to as 60 Hertz (Hz).
Grid frequency is determined by how fast the generators spin All conventional fossil, nuclear, and hydroelectric generators are synchronous, meaning they are synchronized to spin at multiples of 60 Hz Figure 7 provides a simplified representation of the existing grid, with blue synchronous generators that act in unison to maintain a 60 Hz grid The coupling (synchronization) of the generators to the grid is depicted by the chains, illustrating how the generators stay in step to deliver stable power.
It is important for this frequency to remain constant Many motors and other machines are designed to operate based on receiving
60 Hz electricity relies on a stable frequency, and significant deviations can damage machines and electronics Automatic controls help prevent extreme damage by quickly responding to frequency changes When the frequency drops below a safe threshold, protection systems automatically trigger under-frequency load shedding and disconnect parts of the grid, such as neighborhoods or city blocks This intentional disconnection protects equipment but can cause localized blackouts Maintaining frequency stability is essential to prevent a single plant or transmission line failure from triggering a wide-spread power outage and to ensure overall power system reliability.
To keep the grid’s system frequency at 60 Hz and prevent power outages, operators rely on operating reserves—spare capacity ready to respond to unplanned events These events can occur within seconds or minutes due to unexpected changes in load or generation not captured by economic dispatch, or can persist for days or weeks if a transmission line or power plant fails Operating reserves provide the necessary cushion against this rapid variability in demand or supply, including unplanned outages that can happen suddenly If one generator were to fail unexpectedly, the remaining generators must have enough available capacity to supply the required electricity while maintaining the 60 Hz frequency.
Figure 7 Representation of the existing grid powered by synchronous generators
Understanding the relationship between grid frequency and operating reserves starts with examining the four reserve types that respond to large mismatches between supply and demand Although there is no universal set of definitions for operating reserves, many system operators describe four general classes of reserves that are used to maintain grid frequency and ensure reliable power delivery.
• Frequency responsive reserves (inertia and governor/primary frequency response)
During major events that can shift grid frequency—such as the outage of a large power plant—system reserves are deployed in a predefined sequence to restore balance These reserves are tapped as needed in order, following the sequence shown in Figure 8 and described below to ensure an orderly and reliable response.
Figure 8 Sequence of reserves activation in response to a contingency event such as a large power plant failure
Figure 8 illustrates the time scales for reserve deployment in response to an unexpected mismatch between electricity supply and demand The figure shows that reserves with different technical characteristics are activated at different speeds, typically progressing from very fast to slower options, with costs reflecting this spectrum This cascading sequence of reserves is designed to minimize total costs while maintaining grid reliability In some cases, not all reserve types are required to restore the grid to normal operation, a scenario referred to as economic dispatch The following sections describe each reserve type in the order in which they are deployed.
Spinning generators are online, grid-synchronized power generators directly coupled to the electric grid, allowing them to rapidly respond to system faults and help maintain system frequency (see Figure 7) They include hydroelectric generators, gas turbines, and steam generators that use heat from nuclear energy or the burning of fossil fuels.
An inertial response stabilizes grid frequency when there is a mismatch between electricity supply and demand, with the inertia of spinning generators slowing the frequency swing as kinetic energy is stored in the rotating machines The spinning generators already synchronized to the grid keep turning due to their stored inertia, delaying the frequency deviation as the energy imbalance grows The rate of frequency change is determined by the size of the load-generation mismatch and the total system inertia Large synchronous generators on the grid help slow the rate of change, buying time for grid monitoring and operators to detect the deviation and implement corrective actions.
B Primary Frequency Response Primary frequency response is one of two parts of the
Within the electric power system, the so-called “cruise control” is provided by primary frequency response, also known as governor response It detects changes in frequency and automatically adjusts the output of online generators to keep frequency within the desired range, ensuring grid stability and reliable power delivery after disturbances.
Frequency-sensing governors can be installed on conventional fossil, nuclear, or hydroelectric generators to help maintain grid stability However, grid disturbances are usually not large enough to require governors on every generator, so installation is targeted rather than universal.
Regulating reserves act as the second part of the power system’s cruise control, complementing inertia and primary frequency response that operate system-wide to prevent large frequency deviations While inertia and primary frequency response automatically stabilize the grid, additional local actions are required to restore the system to its pre-event state — spinning at 60 Hz with all generators operating as scheduled Regulating reserves monitor the unscheduled power flow into or out of regions where local generation does not match load, and computer systems can signal generators in those areas to adjust output as needed These reserves are provided by any synchronized (spinning) generation or storage resources that can receive automated signals and rapidly ramp, beginning within seconds and reaching the new setpoint within minutes.
Contingency spinning reserves are a dedicated class of reserves used by system operators to quickly respond to major failures, or contingencies, in the power grid When a contingency occurs, automated control systems attempt to restore frequency and power flows, but primary frequency response capacity and regulating reserves are often insufficient to handle large disturbances, and consuming these services reduces their effectiveness for additional responses To address large contingency events, operators rely on contingency spinning reserves—an additional synchronized engine that can be activated rapidly to maintain grid performance These reserves come from partially loaded conventional generation and storage resources with enough spare capacity to cover the loss of the single-largest power plant or transmission line in the system.
Non-spin, replacement, and supplemental reserves are maintained to ensure reliability after contingency events When contingency reserves are activated, system operators must restore them to full reserve status to preserve spare capacity for a potential second event To prevent shortages, power system operators hold supplemental reserves—fast-starting units that can begin generating within about 10 minutes These supplemental reserves are activated to relieve the contingency reserves so they are ready to be called upon again Any generator capable of starting within 10 minutes can provide these reserves.
5 Economic Dispatch (normal system operation) Non-spinning reserves are eventually replaced by the normal economic dispatch of conventional generators, as the system is restored to a pre- contingency state
COMPLYING WITH RULE 3: TRADITIONAL MEANS
Traditionally, conventional resources such as coal, gas, and nuclear power have provided most of the system’s inertia, primary frequency response, and regulating reserves While reserves are essential for reliable system operation, the amount of reserves required is relatively small compared with total capacity needs Table 1 summarizes the regulating and spinning contingency reserve requirements across different operators and shows that larger areas can typically carry proportionally fewer reserves due to greater aggregation of supply and demand, which reduces overall variability.
Table 1 Regulating and Spinning Contingency Reserve Requirements in U.S Wholesale Markets
Region Regulating Reserve Spinning Contingency Reserve 2013 Demand
CAISO average (varies): ~338 MW up, ~325 MW down
~850 MW (average) peak: 45,097 MW average: 26,461 MW
ERCOT average (varies): ~300 MW down, ~500 MW up range: 400–900 MW
2,800 MW (maximum of 50% from load) peak: 67,245 MW average: 37,900 MW
MISO range: 300–500 MW 1,000 MW (2,000 MW total and
1,000 MW of spin) peak: 98,576 MW average: 52,809 MW
PJM average: 753 MW in 2013 e 1,375 MW (Tier 2; maximum of
33% from DR) f peak: 157,508 MW average: 89,560 MW
ISO-NE average 60 MW range 30–150 MW
10-minute reserve: 1,750 MW 30-minute reserve: 2,430 MW peak: 27,400 MW average: 14,900 MW
NYISO 150–250 MW 10-minute spin: (330 east zone,
655 MW NY control area 10-minute total 1,310 MW peak: 33,956 MW average: 18,700 MW
545 MW peak: 45.256 MW average: 26,360 MW Source: Denholm et al 2015
COMPLYING WITH RULE 3: NEW OPTIONS
Power Systems Must Be Able to Maintain Steady Voltage at Various Points on the Grid
Ensuring electric system reliability hinges on maintaining both frequency and voltage While grid frequency remains constant across the network, voltage levels vary by location Figure 10 summarizes the voltage levels observed in different parts of the grid, illustrating the regional variations and the need for voltage regulation to maintain stable operation.
Figure 10 Power systems maintain voltage at different levels in different parts of the power system
Voltage in an electrical grid functions like pressure in a fluid system, with each part of the network designed to operate at a specific voltage level If voltage is too high or too low, electrical devices can malfunction or be damaged To ensure reliable service, power system operators continuously adjust voltage at various points on the grid to keep voltage stable within a defined tolerance Like frequency instability, voltage collapse can occur when there is insufficient voltage control after equipment failure on the grid Devices that provide voltage control are essential for maintaining proper voltage levels both under normal operating conditions and during fault conditions.
COMPLYING WITH RULE 4: TRADITIONAL MEANS
Power system operators regulate voltage across the grid using transformers and other electrical devices to keep the supply stable Conventional generators produce roughly 10,000–25,000 volts, which is stepped up to as much as 765,000 volts for transmission Elevating the voltage reduces energy losses over long distances, enabling efficient delivery of electricity As electricity reaches homes and businesses, the voltage is stepped down first for the distribution network and again to about 240 or 120 volts for residential and commercial customers These voltage changes throughout the transmission and distribution system are accomplished primarily by transformers.
Voltage is controlled by different methods at various points along the power grid, with the ability to inject or absorb reactive power as a key element of this control Reactive power, a property of alternating current, is needed to maintain the flow of power, and an imbalance—too much or too little reactive power—can reduce power flow and cause inadequate voltage Because reactive power cannot be transmitted effectively over long distances, voltage control must be performed at each of the three major parts of the grid.
• At the point of generation, by monitoring local voltage levels and adjusting the spinning synchronous generator’s reactive power output to maintain voltage at a specified level
Reactive power management in the transmission network relies on a mix of devices, including shunt capacitors that supply reactive power to raise voltage, shunt reactors that absorb reactive power to reduce voltage, load tap changing transformers that adjust the voltage level by changing the transformer's turns ratio, and power electronic equipment that actively injects or absorbs reactive power to regulate voltage and improve grid stability.
• At the distribution network, using similar types of devices as on the transmission network to provide local voltage control
16 An example of an event caused by voltage collapse was the 2003 East Coast blackout See U.S.-Canada Power System Outage Task Force 2004
17 For additional discussion of reactive power, see FERC 2005 Principles for Efficient and Reliable Reactive Power Supply and Consumption at http://www.ferc.gov/CalendarFiles/20050310144430-02-04-05-reactive-power.pdf
COMPLYING WITH RULE 4: NEW OPTIONS
Today, power electronics-based technologies supplement traditional voltage-control tools, enhancing the grid's ability to regulate voltage Power electronics can rapidly and efficiently absorb or generate reactive power to support voltage control They are typically inexpensive and are integrated into inverters used with energy storage devices or deployed as stand-alone systems, enabling versatile reactive-power management.
Power electronics embedded in wind turbines and PV inverters are well-suited to providing voltage control and reactive power In 2016, FERC issued Order 827 requiring VG units over 20 MW to provide reactive power, reflecting a broader trend where utilities and system operators had already been demanding voltage support from VG resources (Milligan et al 2015) Using the existing power electronics in VG resources to control voltage often requires little more than software changes rather than hardware upgrades.
Pumped storage and compressed air energy storage use synchronous generators that can provide voltage control just like conventional generators However, many other storage technologies, including flywheels and batteries, rely on power electronics to generate 60 Hz AC power This use of power electronics enables energy storage devices to deliver local voltage control in a manner similar to VG devices.
OTHER STAND-ALONE POWER ELECTRONIC DEVICES
Power system operators now have Flexible AC Transmission Systems (FACTS), power-electronics-based devices that provide fast voltage control at the transmission level during grid disturbances While FACTS have existed for decades, falling costs and new technologies give utilities more options These devices are typically scalable, allowing quick installation in the right size to perform the needed job and often reducing or deferring the need to build transmission lines or large power plants FACTS can be located close to areas of potential concern, enabling targeted voltage support Overall, modern power electronics can solve many voltage-control problems that historically required larger generators, transmission lines, or electro-mechanical devices.
Beyond these new technologies, as old generators are retired, some areas of the grid may have insufficient local reactive power to maintain voltage stability In these cases, the retired generator is sometimes put to a new use as a stand-alone synchronous condenser to provide local reactive power
18 They include static var compensators, static synchronous compensators, thyristor controlled phase shifting transformers, unified power flow controllers, and thyristor controlled series compensation See CIGRE, “Overview of Flexible AC Transmission Systems, FACTS” http://b4.cigre.org/content/download/1973/25265/version/2/file/FACTS+overview_Cigr%C3%A9+B4_What+is+FACTSID10VER39.pdf
America's reliable power system underpins our economy and quality of life, and its reliability has long been engineered into the grid Historically, system operators relied on a relatively limited toolkit—large spinning generators and specialized equipment to maintain voltage—to balance supply and demand and keep frequency and voltage within tight limits Those tools served well even as many traditional generators retire Today the grid is evolving, and a new toolbox for reliability is emerging: variable generation can support grid reliability in ways similar to the resources it replaces, while advances in power electronics open up new opportunities for demand response and other balancing resources With this modern toolkit, plus careful planning, coordination, and investment, reliability can remain a defining hallmark of our evolving power system.
Wind and Solar Energy Curtailment: Experience and Practices in the United States is a 2014 report by Bird, Cochran, and Wang for the National Renewable Energy Laboratory (NREL) that examines why wind and solar generation are curtailed, how curtailment has been managed across the U.S., and what operational and policy changes have reduced curtailment in practice Drawing on field experiences and grid-operational analyses, it identifies key drivers such as transmission constraints, ramping requirements, market rules, and resource variability, and it presents regional case studies, mitigation strategies, and recommendations to improve renewable integration, efficiency, and planning for utilities, policymakers, and industry stakeholders.
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Denholm, Paul, Kara Clark, and Matt O’Connell 2016 On the Path to SunShot: Emerging Issues and
Sorry, I can't provide a rewritten paragraph of that specific article from the link without the text If you paste the article content, I can summarize it into an SEO-friendly paragraph; alternatively, I can craft an original SEO-friendly paragraph on the general topic of challenges in integrating high levels of solar into the electrical generation and transmission system.