On May 16, 2019, the Federal Energy Regulatory Commission issued an order generally affirming an earlier order which established reforms to remove barriers to the participation of electric storage resources in certain organized wholesale markets. The Commission's Order No. 841-A denied various requests for rehearing of last year's Order No. 841.
In 2018's Order No. 841, the Commission found that existing rules for electricity markets operated by regional transmission organizations and independent system operators were unjust and unreasonable in light of barriers that they present to the participation of electric storage. Based on this finding, the Commission ordered wholesale market makers to revise their tariffs to "establish a participation model consisting of market rules that, recognizing the physical and operational characteristics of electric storage resources, facilitates their participation in the RTO/ISO markets." Order No. 841 required each regional organization's participation model to (1) ensure that a resource using the participation model for electric storage resources is eligible to provide all capacity, energy, and ancillary services that it is technically capable of providing in the RTO/ISO markets; (2) ensure that a resource using the participation model for electric storage resources can be dispatched and can set the wholesale market clearing price as both a wholesale seller and wholesale buyer consistent with existing market rules that govern when a resource can set the wholesale price; (3) account for the physical and operational characteristics of electric storage resources through bidding parameters or other means; and (4) establish a minimum size requirement for participation in the RTO/ISO markets that does not exceed 100 kW. Order No. 841 also required that the sale of electric energy from the RTO/ISO markets to an electric storage resource that the resource then resells back to those markets must be at the wholesale locational marginal price.
In Order No. 841-A, the Commission generally affirmed these findings, while clarifying a handful of relatively limited points. The ruling ends for now some of the uncertainty over the scope and applicability of Order No. 841.
As regional wholesale markets develop tariff revisions to integrate electric storage resources, there could be significant opportunities to develop and benefit from electric storage. Reports have suggested significant potential for electric storage deployment -- with one 2018 study suggesting the U.S. could be home to between 7 and 50 gigawatts of storage, if costs continue to decline and sufficient policy support is available.
Energy powers society; society's choices shape energy policy. A blog about our energy resources and the choices they present for society.
Showing posts with label battery. Show all posts
Showing posts with label battery. Show all posts
New England 2019 Regional Energy Outlook describes shifts, challenges
Thursday, March 21, 2019
New England's electricity system is shifting toward a "hybrid grid," according to the operator of New England's wholesale electricity markets and electric transmission system. A recent report by ISO New England, Inc. describes the electric sector's transition towards generating resources with lower carbon emissions and the resulting implications for the environment and the economy.
ISO New England is the federally-designated regional transmission organization serving New England. The grid operator recently released its 2019 Regional Energy Outlook, a document described as “one of the many ways the ISO keeps stakeholders informed about the current state of the grid, issues affecting its future, and ISO initiatives to ensure a modern, reliable power system for New England.”
In the report, ISO New England emphasizes the region’s decarbonization and shifting resource mix, noting that “carbon emissions from the grid have fallen by roughly a third... the region is on its way from having an electric grid dominated by fossil-fuel and nuclear generation to one that includes large amounts of wind and hydro generation and hundreds of thousands of small solar and storage systems spanning the six states. The states’ next step in their decarbonization journey is to transition the emissions-heavy heating and transportation sectors to low-carbon electricity.”
ISO-NE describes the way these changes are happening as “challenging reliable system operations and competitive wholesale electricity markets.” ISO says that “for the foreseeable future, the region will remain vulnerable to energy shortfalls and wholesale price volatility as more and more resources with limited-energy ‘inventories’ (natural gas generation, wind, solar, battery storage) displace resources with on-site fuel that can sustain operation for extended periods (oil, coal, nuclear, dual-fuel generation).”
ISO New England says its competitive markets weren’t designed to telegraph future energy scarcity conditions, compensate resources for fuel inventory, achieve carbon reduction goals, or specifically lead to renewable development. It notes that state-sponsored resources suppress market prices when in markets, but would lead to overbuild if outside markets. ISO advocates, “Establishing a realistic price on carbon remains a more seamless and simpler way to achieve clean-energy goals through markets without distorting competition, but this is not in the ISO’s jurisdiction. State or federal policymakers could pursue this direction but have not done so to date.” ISO notes, “Nuclear resources will prove critical to meeting both decarbonization and energy-security goals for years to come, but how they can remain financially viable is still unclear.”
ISO-NE says it is focused on 3 elements to support the transition to the “hybrid grid”: supporting the rapid transformation of the region’s electricity supply and demand mix, maintaining a robust transmission system, and ensuring energy security.
The grid operator also noted limitations on what tools it can use to address these challenges: “Importantly, ISO New England does not have the authority to dictate investments in energy infrastructure that can help ensure that the region’s energy needs can be met in all seasons, under all conditions. Our toolkit is to create financial stimuli through the wholesale electricity markets that will drive action. Opposition or impediments to infrastructure decisions will only exacerbate the region’s energy-security constraints.”
ISO New England is the federally-designated regional transmission organization serving New England. The grid operator recently released its 2019 Regional Energy Outlook, a document described as “one of the many ways the ISO keeps stakeholders informed about the current state of the grid, issues affecting its future, and ISO initiatives to ensure a modern, reliable power system for New England.”
In the report, ISO New England emphasizes the region’s decarbonization and shifting resource mix, noting that “carbon emissions from the grid have fallen by roughly a third... the region is on its way from having an electric grid dominated by fossil-fuel and nuclear generation to one that includes large amounts of wind and hydro generation and hundreds of thousands of small solar and storage systems spanning the six states. The states’ next step in their decarbonization journey is to transition the emissions-heavy heating and transportation sectors to low-carbon electricity.”
ISO-NE describes the way these changes are happening as “challenging reliable system operations and competitive wholesale electricity markets.” ISO says that “for the foreseeable future, the region will remain vulnerable to energy shortfalls and wholesale price volatility as more and more resources with limited-energy ‘inventories’ (natural gas generation, wind, solar, battery storage) displace resources with on-site fuel that can sustain operation for extended periods (oil, coal, nuclear, dual-fuel generation).”
ISO New England says its competitive markets weren’t designed to telegraph future energy scarcity conditions, compensate resources for fuel inventory, achieve carbon reduction goals, or specifically lead to renewable development. It notes that state-sponsored resources suppress market prices when in markets, but would lead to overbuild if outside markets. ISO advocates, “Establishing a realistic price on carbon remains a more seamless and simpler way to achieve clean-energy goals through markets without distorting competition, but this is not in the ISO’s jurisdiction. State or federal policymakers could pursue this direction but have not done so to date.” ISO notes, “Nuclear resources will prove critical to meeting both decarbonization and energy-security goals for years to come, but how they can remain financially viable is still unclear.”
ISO-NE says it is focused on 3 elements to support the transition to the “hybrid grid”: supporting the rapid transformation of the region’s electricity supply and demand mix, maintaining a robust transmission system, and ensuring energy security.
The grid operator also noted limitations on what tools it can use to address these challenges: “Importantly, ISO New England does not have the authority to dictate investments in energy infrastructure that can help ensure that the region’s energy needs can be met in all seasons, under all conditions. Our toolkit is to create financial stimuli through the wholesale electricity markets that will drive action. Opposition or impediments to infrastructure decisions will only exacerbate the region’s energy-security constraints.”
FERC Order 841 and electric storage markets
Monday, February 19, 2018
U.S. energy regulators have issued a final rule designed to help electric storage resources participate in the capacity, energy and ancillary services markets operated by regional grid operators. The Federal Energy Regulatory Commission said its Order No. 841 would remove barriers to the participation of electric storage resources in wholesale markets operated by regional transmission organization and independent system operators.
Electricity storage technologies have been around for some time, and some technologies like pumped hydropower storage have been deployed on a significant scale -- but new electric technologies are developing on top of these traditional technologies. New England's regional grid operator recently cited fast-responding energy storage devices as among the new technologies entering its markets. Many states have recognized the opportunities created by storage, and are enacting incentives to support its development and integration into microgrids. At the same time, regulators are grappling with how to fit energy storage resources into existing markets and incentive programs, like retail net metering.
The Federal Energy Regulatory Commission has considered electric storage for some time, including stakeholder workshops, data requests, and technical conferences. The Commission expressed concerns that barriers to electric storage resources participation in organized wholesale markets could lead to unjust and unreasonable wholesale electricity rates. In November 2016, the Commission proposed a rule to facilitate electric storage resources' participation in organized wholesale markets. In January 2017, the Commission issued a policy statement addressing how electric storage resources may provide services at a mix of cost-based and market-based rates.
In issuing Order No. 841 on February 15, 2018, the Commission adopted a final rule requiring each RTO and ISO to revise its tariff to establish a "participation model" for electric storage resources. As envisioned by the Commission, these participation models will consist of market rules that facilitate electric storage resources' participation in organized wholesale markets, while recognizing storage resources' physical and operational characteristics.
The new rule provides that each RTO and ISO must adopt its own participation model for electric storage resources, within certain guidelines. First, the participation model must ensure that storage resources using it are eligible to provide all capacity, energy, and ancillary services they are technically capable of providing. Second, the participation model must ensure that participating storage resources can be dispatched and can set the wholesale market clearing price as both a wholesale seller and wholesale buyer, consistent with rules that govern the conditions under which a resource can set the wholesale price. Third, the participation model must account for the physical and operational characteristics of electric storage resources through bidding parameters or other means Fourth, it must a minimum size requirement for participation in the RTO and ISO markets that does not exceed 100 kW.
The rule also requires that the sale of electric energy from the RTO or ISO market to an electric storage resource that the resource then resells back to those markets must be at the wholesale locational marginal price.
In an accompanying statement, Commissioner LaFleur described electric storage as "like a 'Swiss army knife' that can serve customers in multiple ways," including including providing energy, particularly in conjunction with variable renewable generation (example: Deepwater Wind has proposed offshore wind plus storage in response to the pending Massachusetts offshore wind solicitation) as well as providing frequency regulation and other ancillary services, and helping defer distribution and transmission needs. Commissioner Powelson noted its consistency with the Commission's "longstanding commitment to fostering innovation and competition by reducing and eliminating barriers to entry." Commissioner Glick said Order No. 841 "will facilitate the development of a class of technologies—ranging from batteries to pumped hydro—that has the potential to play a leading role in the transition to the electricity system of the future, but that has heretofore been hindered by market rules that were designed primarily to accommodate more conventional means of electric generation."
Once it takes effect, the final rule gives RTOs and ISOs 270 days to develop and file their proposed rule changes, and a year for their implementation.
Electricity storage technologies have been around for some time, and some technologies like pumped hydropower storage have been deployed on a significant scale -- but new electric technologies are developing on top of these traditional technologies. New England's regional grid operator recently cited fast-responding energy storage devices as among the new technologies entering its markets. Many states have recognized the opportunities created by storage, and are enacting incentives to support its development and integration into microgrids. At the same time, regulators are grappling with how to fit energy storage resources into existing markets and incentive programs, like retail net metering.
The Federal Energy Regulatory Commission has considered electric storage for some time, including stakeholder workshops, data requests, and technical conferences. The Commission expressed concerns that barriers to electric storage resources participation in organized wholesale markets could lead to unjust and unreasonable wholesale electricity rates. In November 2016, the Commission proposed a rule to facilitate electric storage resources' participation in organized wholesale markets. In January 2017, the Commission issued a policy statement addressing how electric storage resources may provide services at a mix of cost-based and market-based rates.
In issuing Order No. 841 on February 15, 2018, the Commission adopted a final rule requiring each RTO and ISO to revise its tariff to establish a "participation model" for electric storage resources. As envisioned by the Commission, these participation models will consist of market rules that facilitate electric storage resources' participation in organized wholesale markets, while recognizing storage resources' physical and operational characteristics.
The new rule provides that each RTO and ISO must adopt its own participation model for electric storage resources, within certain guidelines. First, the participation model must ensure that storage resources using it are eligible to provide all capacity, energy, and ancillary services they are technically capable of providing. Second, the participation model must ensure that participating storage resources can be dispatched and can set the wholesale market clearing price as both a wholesale seller and wholesale buyer, consistent with rules that govern the conditions under which a resource can set the wholesale price. Third, the participation model must account for the physical and operational characteristics of electric storage resources through bidding parameters or other means Fourth, it must a minimum size requirement for participation in the RTO and ISO markets that does not exceed 100 kW.
The rule also requires that the sale of electric energy from the RTO or ISO market to an electric storage resource that the resource then resells back to those markets must be at the wholesale locational marginal price.
In an accompanying statement, Commissioner LaFleur described electric storage as "like a 'Swiss army knife' that can serve customers in multiple ways," including including providing energy, particularly in conjunction with variable renewable generation (example: Deepwater Wind has proposed offshore wind plus storage in response to the pending Massachusetts offshore wind solicitation) as well as providing frequency regulation and other ancillary services, and helping defer distribution and transmission needs. Commissioner Powelson noted its consistency with the Commission's "longstanding commitment to fostering innovation and competition by reducing and eliminating barriers to entry." Commissioner Glick said Order No. 841 "will facilitate the development of a class of technologies—ranging from batteries to pumped hydro—that has the potential to play a leading role in the transition to the electricity system of the future, but that has heretofore been hindered by market rules that were designed primarily to accommodate more conventional means of electric generation."
Once it takes effect, the final rule gives RTOs and ISOs 270 days to develop and file their proposed rule changes, and a year for their implementation.
Deepwater Wind proposes offshore wind, battery storage for MA RFP
Friday, August 4, 2017
Massachusetts energy regulators are reviewing bids to supply clean energy from new sources -- including a combined offshore wind and energy storage project proposed by developer Deepwater Wind.
Rhode Island-based Deepwater Wind is the developer of America's first commercial offshore wind project, the 30 MW Block Island Wind Farm which began commercial operations in December 2016. Other projects in early-stage development by the company include the 90 MW South Fork Wind Farm serving Long Island and the 120 MW Skipjack Wind Farm serving Maryland.
Earlier this year, prompted by 2016 state legislation, the Massachusetts electric distribution companies, in coordination with the Massachusetts Department of Energy Resources, issued a Request for Proposals for Long-term Contracts for Clean Energy Projects pursuant to Section 83D. Through the RFP, the Massachusetts utilities solicited proposals for clean energy generation in an amount roughly equal to 9,450,000 MWh.
According to Deepwater Wind, it responded to the Massachusetts clean energy RFP by proposing the Revolution Wind farm, paired with a battery storage system. The company's prime proposal features 144 MW of wind generation, coupled with a 40 MWh battery system, which it says will "help to defer the need to construct costly new peaking generating facilities and controversial transmission lines." The project would be sited on the Outer Continental Shelf off Massachusetts, about 30 miles from the mainland and about 12 miles off Martha's Vineyard, under a lease from the federal government. It would be adjacent to Deepwater Wind’s South Fork Wind Farm. Emphasizing flexibility and scalability, as well as the ability to complete construction in one season, alternative bids submitted by the company envisioned a larger 288 MW version of Revolution Wind and a smaller 96 MW version.
Deepwater Wind says it also intends to submit an offshore wind proposal under a separate solicitation process under way in under Section 83C of Massachusetts law, with bids due by December 2018.
Rhode Island-based Deepwater Wind is the developer of America's first commercial offshore wind project, the 30 MW Block Island Wind Farm which began commercial operations in December 2016. Other projects in early-stage development by the company include the 90 MW South Fork Wind Farm serving Long Island and the 120 MW Skipjack Wind Farm serving Maryland.
Earlier this year, prompted by 2016 state legislation, the Massachusetts electric distribution companies, in coordination with the Massachusetts Department of Energy Resources, issued a Request for Proposals for Long-term Contracts for Clean Energy Projects pursuant to Section 83D. Through the RFP, the Massachusetts utilities solicited proposals for clean energy generation in an amount roughly equal to 9,450,000 MWh.
According to Deepwater Wind, it responded to the Massachusetts clean energy RFP by proposing the Revolution Wind farm, paired with a battery storage system. The company's prime proposal features 144 MW of wind generation, coupled with a 40 MWh battery system, which it says will "help to defer the need to construct costly new peaking generating facilities and controversial transmission lines." The project would be sited on the Outer Continental Shelf off Massachusetts, about 30 miles from the mainland and about 12 miles off Martha's Vineyard, under a lease from the federal government. It would be adjacent to Deepwater Wind’s South Fork Wind Farm. Emphasizing flexibility and scalability, as well as the ability to complete construction in one season, alternative bids submitted by the company envisioned a larger 288 MW version of Revolution Wind and a smaller 96 MW version.
Deepwater Wind says it also intends to submit an offshore wind proposal under a separate solicitation process under way in under Section 83C of Massachusetts law, with bids due by December 2018.
Electric storage resources technical conference set
Tuesday, October 4, 2016
U.S. energy regulators have scheduled a technical conference to discuss electric storage resources and how they could fit into the electric grid -- and how they might be compensated for doing so. The Federal Energy Regulatory Commission will convene the discussion on November 9, 2016.
An electric storage resource is a facility that can receive electric energy from the grid and store it for later injection of electricity back to the grid. Different projects might use different storage mediums -- for example, batteries, flywheels, or pumped hydropower. A storage resource could be as small as a household battery, or as large as gigawatt-scale pumped storage. Projects could be interconnected in various ways -- such as to the transmission system, distribution system, or behind a customer meter -- and could serve different markets, ranging from regional transmission organizations and independent system operators, to transmission or distribution utilities, to customers or end users of electricity.
While each energy storage resource configuration offers its own different advantages and disadvantages from various perspectives, overall the Commission has noted that "storage resources may fit into one or more of the traditional asset functions of generation, transmission, and distribution." In the Commission's Notice of Technical Conference, it expressed a desire "to explore the circumstances under which it may be appropriate for electric storage resources to provide multiple services, whether the RTO/ISO tariffs need to include provisions to accommodate these business models, and how the Commission may ensure just and reasonable compensation for these resources in the RTO/ISO markets."
The specific subject of the conference described in the Notice is "the utilization of electric storage resources as transmission assets compensated through transmission rates, for grid support services that are compensated in other ways, and for multiple services." The Notice also sets up discussion of other issues including
Energy storage is attracting increased interest. In another open docket, the Commission issued a series of data requests and a request for public comment in an effort to identify barriers to electric storage resources' participation in organized electricity markets in the U.S that could lead to unjust and unreasonable wholesale electricity rates. In 2009, then-Chairman Wellinghoff testified before the Senate Committee on Energy and Natural Resources on the role of grid-scale energy storage as it relates to U.S. energy and climate goals, including its ability to integrate variable resources such as wind and solar into the grid. Meanwhile, states too are pursuing storage opportunities. A Massachusetts state energy office has issued a report finding that Massachusetts has the potential to develop for 600 MW of energy storage by 2025, which could lower costs, reduce carbon emissions, and improve grid reliability.
An electric storage resource is a facility that can receive electric energy from the grid and store it for later injection of electricity back to the grid. Different projects might use different storage mediums -- for example, batteries, flywheels, or pumped hydropower. A storage resource could be as small as a household battery, or as large as gigawatt-scale pumped storage. Projects could be interconnected in various ways -- such as to the transmission system, distribution system, or behind a customer meter -- and could serve different markets, ranging from regional transmission organizations and independent system operators, to transmission or distribution utilities, to customers or end users of electricity.
While each energy storage resource configuration offers its own different advantages and disadvantages from various perspectives, overall the Commission has noted that "storage resources may fit into one or more of the traditional asset functions of generation, transmission, and distribution." In the Commission's Notice of Technical Conference, it expressed a desire "to explore the circumstances under which it may be appropriate for electric storage resources to provide multiple services, whether the RTO/ISO tariffs need to include provisions to accommodate these business models, and how the Commission may ensure just and reasonable compensation for these resources in the RTO/ISO markets."
The specific subject of the conference described in the Notice is "the utilization of electric storage resources as transmission assets compensated through transmission rates, for grid support services that are compensated in other ways, and for multiple services." The Notice also sets up discussion of other issues including
(1) potential models for cost recovery for electric storage resources utilized as transmission assets, while also selling energy, capacity or ancillary services at wholesale;FERC will webcast and transcribe the conference, in addition to allowing in-person attendance. The Commision directed those wishing to participate to submit a nomination form online by 5:00 p.m. on October 14, 2016.
(2) potential models to enable an electric storage resource to provide a compensated grid support service (like a generator providing ancillary services under a reliability must-run contract) rather than being compensated for providing transmission service; and
(3) practical considerations for electric storage resources providing multiple services at once (i.e., providing both wholesale service(s) and retail and/or end-use service(s)).
Energy storage is attracting increased interest. In another open docket, the Commission issued a series of data requests and a request for public comment in an effort to identify barriers to electric storage resources' participation in organized electricity markets in the U.S that could lead to unjust and unreasonable wholesale electricity rates. In 2009, then-Chairman Wellinghoff testified before the Senate Committee on Energy and Natural Resources on the role of grid-scale energy storage as it relates to U.S. energy and climate goals, including its ability to integrate variable resources such as wind and solar into the grid. Meanwhile, states too are pursuing storage opportunities. A Massachusetts state energy office has issued a report finding that Massachusetts has the potential to develop for 600 MW of energy storage by 2025, which could lower costs, reduce carbon emissions, and improve grid reliability.
Massachusetts energy storage report
Friday, September 23, 2016
A Massachusetts state energy office has issued a report finding that Massachusetts has the potential to develop for 600 MW of energy storage by 2025, which could lower costs, reduce carbon emissions, and improve grid reliability. Legislation earlier this year authorized the creation of an energy storage procurement target; the Department of Energy Resource’s State of Charge report could lead to further policy changes supportive of storage.
While electricity has traditionally been challenging to store efficiently, advanced energy storage technologies – such as batteries, flywheels, thermal and compressed air technologies – now allow utilities and consumers to store and release energy as needed. Last year, the Baker-Polito administration launched an Energy Storage Initiative to advance the energy storage segment of the Massachusetts clean energy industry.
This summer, the Massachusetts legislature enacted a broad energy diversification law, authorizing among other things the creation of an energy storage procurement target, if the Department of Energy Resources deems such a target prudent. Section 15 of H.4568 requires the Department of Energy Resources to determine, by December 31, 2016, whether to set “appropriate targets for electric companies to procure viable and cost-effective energy storage systems” to be achieved by January 1, 2020. If the Department finds it appropriate to adopt procurement targets, the law requires it to do so by July 1, 2017, with reevaluations of the procurement targets not less than every 3 years.
Meanwhile, on September 16, 2016, the administration released its State of Charge report. The report found that energy storage could yield significant cost savings for Massachusetts ratepayers, reduce the impacts of peak demand on the state’s energy infrastructure, and enable improved integration of renewable resources and reduced carbon emissions.
The report recommends policy changes, ranging from regional coordination on energy storage, broadening the Alternative Portfolio Standard (APS) with respect to advanced energy storage, to using energy storage in existing energy efficiency programs or as a utility grid modernization asset, and seeking “renewables plus storage” contracts in future long-term clean energy procurements.
According to the report, adopting these recommendations could yield 600 MW of advanced energy storage technologies deployed on the Massachusetts grid by 2025, with projected ratepayer cost savings of over $800 million and approximately 350,000 metric tons reduction in greenhouse emissions over a 10 year time span.
The Department of Energy Resources will now hold a stakeholder engagement process relating to energy storage, starting with a meeting scheduled for September 27. DOER is expected to determine whether Massachusetts should establish an energy storage procurement target before the end of 2016.
While electricity has traditionally been challenging to store efficiently, advanced energy storage technologies – such as batteries, flywheels, thermal and compressed air technologies – now allow utilities and consumers to store and release energy as needed. Last year, the Baker-Polito administration launched an Energy Storage Initiative to advance the energy storage segment of the Massachusetts clean energy industry.
This summer, the Massachusetts legislature enacted a broad energy diversification law, authorizing among other things the creation of an energy storage procurement target, if the Department of Energy Resources deems such a target prudent. Section 15 of H.4568 requires the Department of Energy Resources to determine, by December 31, 2016, whether to set “appropriate targets for electric companies to procure viable and cost-effective energy storage systems” to be achieved by January 1, 2020. If the Department finds it appropriate to adopt procurement targets, the law requires it to do so by July 1, 2017, with reevaluations of the procurement targets not less than every 3 years.
Meanwhile, on September 16, 2016, the administration released its State of Charge report. The report found that energy storage could yield significant cost savings for Massachusetts ratepayers, reduce the impacts of peak demand on the state’s energy infrastructure, and enable improved integration of renewable resources and reduced carbon emissions.
The report recommends policy changes, ranging from regional coordination on energy storage, broadening the Alternative Portfolio Standard (APS) with respect to advanced energy storage, to using energy storage in existing energy efficiency programs or as a utility grid modernization asset, and seeking “renewables plus storage” contracts in future long-term clean energy procurements.
According to the report, adopting these recommendations could yield 600 MW of advanced energy storage technologies deployed on the Massachusetts grid by 2025, with projected ratepayer cost savings of over $800 million and approximately 350,000 metric tons reduction in greenhouse emissions over a 10 year time span.
The Department of Energy Resources will now hold a stakeholder engagement process relating to energy storage, starting with a meeting scheduled for September 27. DOER is expected to determine whether Massachusetts should establish an energy storage procurement target before the end of 2016.
DOE Hydropower Vision report
Tuesday, August 9, 2016
The U.S. Department of Energy (DOE) has released a report on the future of domestic hydropower. Its Hydropower Vision finds that U.S. hydropower could grow from 101 gigawatts of capacity in 2015 to nearly 150 gigawatts by 2050. More than 50% of this growth could be realized by 2030, according to the report. Much of the new capacity would come from pumped storage, with the remainder coming from upgrades to existing plants, adding power at existing dams and canals, and "limited development of new stream-reaches."
DOE's Wind and Water Power Technologies Office describes its report, Hydropower Vision: A New Chapter for America’s First Renewable Electricity Source, as presenting "a first-of-its-kind comprehen sive analysis to evaluate future pathways for low-carbon, renewable hydropower (hydropower generation and pumped storage) in the United States, focused on continued technical evolution, increased energy market value, and environmental sustainability." While it does not evaluate or recommend new policy actions, the report does analyze the "feasbility and certain benefits and costs of various credible scenarios, all of which could inform policy decisions at the federal, state, tribal, and local levels."
The report's Executive Summary presents an overview of the report, and its three "pillars" or foundational principles developed in collaboration with stakeholders: optimizing the value and power generation contribution of the existing hydropower fleet, exploring the feasibility of "credible long-term deployment scenarios for responsible growth of hydropower capacity and energy production," and sustainability. Analyzing data and modeled scenarios, the report found that "under a credible modeled scenario in which technology advancement lowers capital and operating costs, innovative market mechanisms increase revenue and lower financing costs, and a combination of environmental considerations are taken into account—U.S. hydropower including PSH could grow from 101 GW of capacity in 2015 to 150 GW by 2050."
Chapter 1 of the Hydropower Vision describes how technical resource assessments and computational models can be used to interpret hydropower's future market potential. It also evaluates potential innovations or nontraditional approaches to technology and project development that could affect the future development of new hydropower projects.
Chapter 2 of the Hydropower Vision presents a snapshot of the state of the U.S. hydropower industry as of year-end 2015, from the Energy Department's perspective. It notes that hydropower generation and pumped storage have "provided a stable and consistently low-cost energy source throughout decades of fluctuations and fundamental shifts in the electric sector, supporting development of the U.S. power grid and the nation’s industrial growth in the 20th century and into the 21st century." The report points to 2015 data showing 2,198 active hydropower plants in the U.S. with a total capacity of 79.6 gigawatts, plus 42 pumped storage hydro plants totaling another 21.6 gigawatts. In 2015, hydropower provided about 6.2% of net U.S. electricity generation, and 48% of all U.S. renewable power.
Chapter 3 of the report explores over 50 possible future scenarios for the hydropower industry, to assess the nation's hydropower potential. It presents an extensive body of analysis, considering potential contributions over time to the electric sector of both the existing hydropower fleet and new hydropower deployment resulting from: upgrades at existing plants, powering of non-powered dams (NPD), pumped storage hydropower (PSH), and new stream-reach development (NSD). It found that the greatest influence on potential growth scenarios comes from 3 variables: technological innovation, environmental considerations, and financial improvement.
The report's fourth chapter lays out a roadmap of 64 potential actions for stakeholder consideration, "to optimize hydropower’s continued contribution to a clean, reliable, low-carbon, domestic energy generation portfolio while ensuring that the nation’s natural resources are adequately protected or conserved." These actions are organized around 5 topical areas: technology advancement, sustainable development and operation, enhanced revenue and market structures, regulatory process optimization, and enhanced collaboration, education, and outreach.
As noted by the Energy Department, while utility-scale battery storage projects are starting to be developed, most U.S. electricity storage capacity takes the form of pumped storage. Flexible and reliable generating or storage resources can support efforts to integrate increasing amounts of intermittent renewable energy sources, like wind and solar, into the grid.
DOE's Wind and Water Power Technologies Office describes its report, Hydropower Vision: A New Chapter for America’s First Renewable Electricity Source, as presenting "a first-of-its-kind comprehen sive analysis to evaluate future pathways for low-carbon, renewable hydropower (hydropower generation and pumped storage) in the United States, focused on continued technical evolution, increased energy market value, and environmental sustainability." While it does not evaluate or recommend new policy actions, the report does analyze the "feasbility and certain benefits and costs of various credible scenarios, all of which could inform policy decisions at the federal, state, tribal, and local levels."
The report's Executive Summary presents an overview of the report, and its three "pillars" or foundational principles developed in collaboration with stakeholders: optimizing the value and power generation contribution of the existing hydropower fleet, exploring the feasibility of "credible long-term deployment scenarios for responsible growth of hydropower capacity and energy production," and sustainability. Analyzing data and modeled scenarios, the report found that "under a credible modeled scenario in which technology advancement lowers capital and operating costs, innovative market mechanisms increase revenue and lower financing costs, and a combination of environmental considerations are taken into account—U.S. hydropower including PSH could grow from 101 GW of capacity in 2015 to 150 GW by 2050."
Chapter 1 of the Hydropower Vision describes how technical resource assessments and computational models can be used to interpret hydropower's future market potential. It also evaluates potential innovations or nontraditional approaches to technology and project development that could affect the future development of new hydropower projects.
Chapter 2 of the Hydropower Vision presents a snapshot of the state of the U.S. hydropower industry as of year-end 2015, from the Energy Department's perspective. It notes that hydropower generation and pumped storage have "provided a stable and consistently low-cost energy source throughout decades of fluctuations and fundamental shifts in the electric sector, supporting development of the U.S. power grid and the nation’s industrial growth in the 20th century and into the 21st century." The report points to 2015 data showing 2,198 active hydropower plants in the U.S. with a total capacity of 79.6 gigawatts, plus 42 pumped storage hydro plants totaling another 21.6 gigawatts. In 2015, hydropower provided about 6.2% of net U.S. electricity generation, and 48% of all U.S. renewable power.
Chapter 3 of the report explores over 50 possible future scenarios for the hydropower industry, to assess the nation's hydropower potential. It presents an extensive body of analysis, considering potential contributions over time to the electric sector of both the existing hydropower fleet and new hydropower deployment resulting from: upgrades at existing plants, powering of non-powered dams (NPD), pumped storage hydropower (PSH), and new stream-reach development (NSD). It found that the greatest influence on potential growth scenarios comes from 3 variables: technological innovation, environmental considerations, and financial improvement.
The report's fourth chapter lays out a roadmap of 64 potential actions for stakeholder consideration, "to optimize hydropower’s continued contribution to a clean, reliable, low-carbon, domestic energy generation portfolio while ensuring that the nation’s natural resources are adequately protected or conserved." These actions are organized around 5 topical areas: technology advancement, sustainable development and operation, enhanced revenue and market structures, regulatory process optimization, and enhanced collaboration, education, and outreach.
As noted by the Energy Department, while utility-scale battery storage projects are starting to be developed, most U.S. electricity storage capacity takes the form of pumped storage. Flexible and reliable generating or storage resources can support efforts to integrate increasing amounts of intermittent renewable energy sources, like wind and solar, into the grid.
FERC rules off-grid micro-hydro needs no license
Thursday, March 24, 2016
Federal hydropower regulators have granted reconsideration of a 2015 order finding licensing required for an off-grid micro-hydropower project proposed in Massachusetts. Based on newly submitted evidence that the proposed project would not be connected to an interstate grid, the order granting reconsideration finds that Section 23(b)(1) of the Federal Power Act does not require licensing of the proposed Egnaczak Net Zero Hydro Project.
The case involves a project proposed by Kenneth and Susan Egnaczak, to be located at an existing water-powered mill complex on the Hoosic River in Cheshire, Massachusetts. The so-called "Egnaczak Net Zero Hydro Project" would have a total generating capacity of 10.7 kilowatts. The power would be used at a home and workshop proposed for construction along the river.
Under Section 23(b)(1) of the Federal Power Act, an entity proposing a hydropower project must generally file with the Federal Energy Regulatory Commission either a hydropower license application, or a Declaration of Intention to determine if the proposed project requires a license. The Egnaczaks filed a Declaration of Intention for the project in February 2015. On September 11, 2015, Commission staff issued an order finding that the Federal Power Act requires a license to be issued for the project's construction, maintenance, and operation.
Section 23(b)(1) of the Federal Power Act requires a non-federal hydroelectric project to be licensed if it falls into any of four categories: (1) is located on “navigable waters of the United States;” (2) occupies lands or reservations of the United States; (3) uses surplus water or water power from a federal dam; or (4) is located on a non-navigable stream which is subject to the authority of Congress under the Commerce Clause, affects the interests of interstate or foreign commerce, and is constructed or enlarged after August 26, 1935.
In its September 2015 order on the Egnaczak project, Commission staff analyzed the facts as applied to these facts. On category 1, staff found that there is insufficient evidence to determine whether the Hoosic River is navigable at the project site. Staff readily dispensed with categories 2 and 3, finding that the project would neither occupy any public lands or reservations of the United States nor use surplus water or waterpower from a Federal government dam.
In September, staff found that the project fell into the fourth category. In the order, staff noted that it would be located on a non-navigable Commerce Clause stream, would be constructed after 1935, and would affect the interests of interstate commerce because the project would offset both electrical and heating needs for the applicants’ home and workshop that would have been otherwise supplied by the interstate grid. The order cited judicial precedent, noting, "It is well settled that small hydroelectric projects that are connected to the interstate grid affect interstate commerce by displacing power from the grid, and the cumulative effect of the national class of these small projects is significant for purposes of FPA section 23(b)(1)." Staff therefore determined that the project requires licensing under FPA section 23(b)(1).
But on January 6, 2016, the applicants filed a request for reconsideration and additional evidence in support of their argument that the project does not require licensing. This evidence focused on the fact that the project would not be connected to the interstate grid and thus would not affect interstate commerce. As later described by the Commission:
The March 24 order does include a warning: "if the project or the applicants’ unconstructed home or workshop are connected to the interstate grid in the future, section 23(b)(1) of the FPA would require licensing and the Commission could require the applicants to apply for a license under section 4(g) of the FPA."
Thus in at least this one case, the off-grid nature of the micro-hydro project was a critical factor in the order finding that Section 23(b)(1) of the Federal Power Act does not require licensing of the proposed Egnaczak Net Zero Hydro Project. The key to the revised finding that the project would have no effect on interstate commerce appears to be the fact that power would be consumed in buildings not yet built, with no existing grid tie.
The case involves a project proposed by Kenneth and Susan Egnaczak, to be located at an existing water-powered mill complex on the Hoosic River in Cheshire, Massachusetts. The so-called "Egnaczak Net Zero Hydro Project" would have a total generating capacity of 10.7 kilowatts. The power would be used at a home and workshop proposed for construction along the river.
Under Section 23(b)(1) of the Federal Power Act, an entity proposing a hydropower project must generally file with the Federal Energy Regulatory Commission either a hydropower license application, or a Declaration of Intention to determine if the proposed project requires a license. The Egnaczaks filed a Declaration of Intention for the project in February 2015. On September 11, 2015, Commission staff issued an order finding that the Federal Power Act requires a license to be issued for the project's construction, maintenance, and operation.
Section 23(b)(1) of the Federal Power Act requires a non-federal hydroelectric project to be licensed if it falls into any of four categories: (1) is located on “navigable waters of the United States;” (2) occupies lands or reservations of the United States; (3) uses surplus water or water power from a federal dam; or (4) is located on a non-navigable stream which is subject to the authority of Congress under the Commerce Clause, affects the interests of interstate or foreign commerce, and is constructed or enlarged after August 26, 1935.
In its September 2015 order on the Egnaczak project, Commission staff analyzed the facts as applied to these facts. On category 1, staff found that there is insufficient evidence to determine whether the Hoosic River is navigable at the project site. Staff readily dispensed with categories 2 and 3, finding that the project would neither occupy any public lands or reservations of the United States nor use surplus water or waterpower from a Federal government dam.
In September, staff found that the project fell into the fourth category. In the order, staff noted that it would be located on a non-navigable Commerce Clause stream, would be constructed after 1935, and would affect the interests of interstate commerce because the project would offset both electrical and heating needs for the applicants’ home and workshop that would have been otherwise supplied by the interstate grid. The order cited judicial precedent, noting, "It is well settled that small hydroelectric projects that are connected to the interstate grid affect interstate commerce by displacing power from the grid, and the cumulative effect of the national class of these small projects is significant for purposes of FPA section 23(b)(1)." Staff therefore determined that the project requires licensing under FPA section 23(b)(1).
But on January 6, 2016, the applicants filed a request for reconsideration and additional evidence in support of their argument that the project does not require licensing. This evidence focused on the fact that the project would not be connected to the interstate grid and thus would not affect interstate commerce. As later described by the Commission:
They state that, because neither their home nor workshop has been constructed, they have no existing grid connection. Further, they explain that the project alone will power their home and workshop. The applicants state that the project would produce hydro-mechanical power using a waterwheel, Archimedes Screw, or turbine. The mechanical power would be connected to the hydro generator units to produce electricity or to power rotating equipment, such as a sawmill. In addition, the applicants state that they will use backup power from a fossil fuel electric generator and storage batteries, which would be charged by the hydro generators or the fossil fuel electric generator.In a March 24, 2016 order, the Commission staff found that the applicants had demonstrated that the Net Zero Project would not be connected to an interstate grid. That order finds that the micro-hydro project would not displace power that would otherwise be supplied by the grid and thus would not affect interstate commerce. As a result, it concludes that "section 23(b)(1) of the FPA does not require licensing of the proposed Net Zero Project."
The March 24 order does include a warning: "if the project or the applicants’ unconstructed home or workshop are connected to the interstate grid in the future, section 23(b)(1) of the FPA would require licensing and the Commission could require the applicants to apply for a license under section 4(g) of the FPA."
Thus in at least this one case, the off-grid nature of the micro-hydro project was a critical factor in the order finding that Section 23(b)(1) of the Federal Power Act does not require licensing of the proposed Egnaczak Net Zero Hydro Project. The key to the revised finding that the project would have no effect on interstate commerce appears to be the fact that power would be consumed in buildings not yet built, with no existing grid tie.
Wind, solar lead new generation in Jan. 2016
Wednesday, March 9, 2016
Wind and solar projects accounted for all new electric power generation placed in service in the U.S. in January 2016, according to a report by federal energy regulators.
The Federal Energy Regulatory Commission's Office of Energy Projects releases a monthly Energy Infrastructure Update. These reports provide summary data and narrative highlights of energy infrastructure developments in the past month. Energy Infrastructure Update reports typically cover natural gas, nonfederal hydropower, electric generation, and electric transmission.
The report for January 2016 shows that all tracked electric generation placed in service that month was powered by either wind or solar. The report notes 5 wind projects placed in service in January 2016, with a total installed capacity of 468 megawatts. These projects are:
The January 2016 infrastructure update also notes that a battery storage project in Ohio has come online. Willey Battery Utility LLC’s Willey Battery Storage Project in Hamilton County, Ohio is described as providing supply-demand balancing service for the frequency regulation market in the PJM region. Under FERC Order No. 755, battery storage and other innovative technologies can be compensated for offering frequency regulation to the grid.
The Federal Energy Regulatory Commission's Office of Energy Projects releases a monthly Energy Infrastructure Update. These reports provide summary data and narrative highlights of energy infrastructure developments in the past month. Energy Infrastructure Update reports typically cover natural gas, nonfederal hydropower, electric generation, and electric transmission.
The report for January 2016 shows that all tracked electric generation placed in service that month was powered by either wind or solar. The report notes 5 wind projects placed in service in January 2016, with a total installed capacity of 468 megawatts. These projects are:
- MidAmerican Energy Co.’s 153.4 MW Adams Wind Project in Adams County, Iowa
- Fowler Ridge IV Wind Farm LLC’s 150 MW Amazon Wind Farm Expansion Project in Benton County, Indiana -- developed by Pattern Energy; power generated is sold to Amazon Web Services under long-term contract
- Los Vientos Windpower IV LLC’s 110 MW Los Vientos Windpower Phase 2 Expansion Project in Starr County, Texas -- power generated is sold to Bryan Texas Utilities, Garland Power and Light, and Greenville Electric Utility System under long-term contract
- Milo Wind Project LLC’s 50 MW Milo Wind Project in Roosevelt County, New Mexico -- power generated is sold to Southwestern Public Service Co. under long-term contract
- Patriot Renewables LLC’s 4.5 MW Beaver Ridge Hill Wind Project in Waldo County, Maine
The January 2016 infrastructure update also notes that a battery storage project in Ohio has come online. Willey Battery Utility LLC’s Willey Battery Storage Project in Hamilton County, Ohio is described as providing supply-demand balancing service for the frequency regulation market in the PJM region. Under FERC Order No. 755, battery storage and other innovative technologies can be compensated for offering frequency regulation to the grid.
Chicago-area battery storage projects announced
Wednesday, November 12, 2014
Energy developer Renewable Energy Systems Americas Inc. has announced two grid-scale energy storage projects near Chicago.
Battery-based energy storage projects can offer benefits to the electricity grid by keeping the alternating current's frequency steady, and can do so at a lower cost than alternatives like ramping generators up and down. Thanks in part to new federal policies, battery projects capable of providing frequency regulation can now earn increased revenue for their owners.
This week RES Americas announced plans to pursue two energy storage projects in Illinois. The company describes itself as a specialist in third-party development and construction services for the renewable energy, transmission, and energy storage industries. It also builds renewable energy and storage projects that it owns itself.
In an apparent tribute to the Blues Brothers, its two newly announced projects will be named Jake and Elwood. The Elwood Energy Storage Center will be sited in West Chicago, while the Jake Energy Storage Center will be in Joliet. Beyond names and locations, the projects bear greater resemblance to each other than to the Blues Brothers. Both projects were acquired from Glidepath Power in September. Each will be interconnected to the Commonwealth Edison Co. electric grid, and will have an operational life expectancy of at least ten years. Each will use lithium iron phosphate batteries with a 19.8 megawatt capacity, capable of storing 7.8 megawatt-hours of energy.
RES Americas expects to begin construction on both projects this winter, and to complete them by August 2015. When complete, the battery projects will be able to provide real-time frequency regulation service to the PJM Interconnection LLC ancillary services market. Thanks to recent federal orders including FERC Order No. 784, faster and more accurate regulation resources -- like battery storage arrays -- should be compensated more highly. These policies both increase consumer demand and reduce developers' barriers to entry into battery-based energy storage projects.
Other battery projects are moving forward, based on values other than frequency regulation. Last month, Southern California Edison Company brought its Tehachapi Wind Energy Storage Project online. That $50 million project, the largest currently operating in North America, is capable of storing 32 megawatt-hours, deliverable as an 8 megawatt stream of energy for 4 hours. The Tehachapi system is designed to help even out the flow of power produced by wind farms, which is naturally variable and intermittent. Battery systems can also be designed to improve local reliability, support microgrids, or serve as non-transmission alternatives to building more utility wires.
For more information about battery energy storage projects, recent policies favoring energy storage and the opportunities they create, contact Todd Griset at Preti Flaherty at 207-791-3000.
Battery-based energy storage projects can offer benefits to the electricity grid by keeping the alternating current's frequency steady, and can do so at a lower cost than alternatives like ramping generators up and down. Thanks in part to new federal policies, battery projects capable of providing frequency regulation can now earn increased revenue for their owners.
This week RES Americas announced plans to pursue two energy storage projects in Illinois. The company describes itself as a specialist in third-party development and construction services for the renewable energy, transmission, and energy storage industries. It also builds renewable energy and storage projects that it owns itself.
In an apparent tribute to the Blues Brothers, its two newly announced projects will be named Jake and Elwood. The Elwood Energy Storage Center will be sited in West Chicago, while the Jake Energy Storage Center will be in Joliet. Beyond names and locations, the projects bear greater resemblance to each other than to the Blues Brothers. Both projects were acquired from Glidepath Power in September. Each will be interconnected to the Commonwealth Edison Co. electric grid, and will have an operational life expectancy of at least ten years. Each will use lithium iron phosphate batteries with a 19.8 megawatt capacity, capable of storing 7.8 megawatt-hours of energy.
RES Americas expects to begin construction on both projects this winter, and to complete them by August 2015. When complete, the battery projects will be able to provide real-time frequency regulation service to the PJM Interconnection LLC ancillary services market. Thanks to recent federal orders including FERC Order No. 784, faster and more accurate regulation resources -- like battery storage arrays -- should be compensated more highly. These policies both increase consumer demand and reduce developers' barriers to entry into battery-based energy storage projects.
Other battery projects are moving forward, based on values other than frequency regulation. Last month, Southern California Edison Company brought its Tehachapi Wind Energy Storage Project online. That $50 million project, the largest currently operating in North America, is capable of storing 32 megawatt-hours, deliverable as an 8 megawatt stream of energy for 4 hours. The Tehachapi system is designed to help even out the flow of power produced by wind farms, which is naturally variable and intermittent. Battery systems can also be designed to improve local reliability, support microgrids, or serve as non-transmission alternatives to building more utility wires.
For more information about battery energy storage projects, recent policies favoring energy storage and the opportunities they create, contact Todd Griset at Preti Flaherty at 207-791-3000.
North America's largest battery energy storage online
Wednesday, October 29, 2014
A California public utility has brought the largest battery energy storage in North America online. Funded partially by federal stimulus funds, Southern California Edison's Tehachapi Wind Energy Storage Project is designed to demonstrate the effectiveness of large-scale battery storage systems.
Southern California Edison Company is the largest electricity supply company in Southern California. As part of the U.S. Department of Energy's implementation of the American Recovery and Reinvestment Act of 2009, the utility won funding to develop a major battery energy storage system (or BESS). The Tehachapi Wind Energy Storage project consists of an array of lithium-ion batteries capable of storing 32 megawatt-hours, deliverable as an 8 megawatt stream of energy for 4 hours. The LG Chem batteries rely on the same lithium-ion cells installed in battery packs for General Motors’ Chevrolet Volt electric vehicle, and feature 608,832 individual battery cells arrayed in 10,872 battery modules and 604 battery racks. Along with two 4MW/4.5MVA smart inverters, the project will be housed in a 6,300 square foot facility sited at SCE's existing Monolith substation.
Of the project's $49,956,528 total budget, half will be paid for by SCE, while federal funds will cover $24,978,264. In return, the project will examine whether and how the battery energy storage system improves grid performance and helps integrate wind and other large-scale variable energy resourced generation. Project performance will be measured by 13 specific operational uses, most of which either shift other generation resources to meet peak load and other electricity system needs with stored electricity, or resolve grid stability and capacity concerns that result from the interconnection of variable energy resources. These uses include: providing voltage support and grid stabilization; decreasing transmission losses; diminishing congestion; increasing system reliability; deferring transmission investment; optimizing renewable-related transmission; providing system capacity and resources adequacy; integrating renewable energy (smoothing); shifting wind generation output; frequency regulation; spin/non-spin replacement reserves; ramp management; and energy price arbitrage. In addition, the project will demonstrate how lithium-ion battery storage can provide nearly instantaneous back-up capacity, minimizing the need for fossil fuel-powered back-up generation.
Between technological advances and a series of recent policy decisions, battery energy storage could be poised for rapid growth. For example, in 2011 the Federal Energy Regulatory Commission issued Order No. 755, requiring the grid operators in organized markets to compensate battery energy storage systems and other fast-ramping frequency regulation resources based on the actual service they provide. Last year's Order No. 784 required public utilities to take into account the speed and accuracy of regulation resources such as batteries. Meanwhile, batteries are hoped to help balance into the grid large amounts of energy from intermittent renewable resources such as solar and wind projects.
After two years, the Tehachapi Wind Energy Storage Project will have completed its initial demonstration run. Will the project lead to greater deployment of battery energy storage systems in the U.S.?
Southern California Edison Company is the largest electricity supply company in Southern California. As part of the U.S. Department of Energy's implementation of the American Recovery and Reinvestment Act of 2009, the utility won funding to develop a major battery energy storage system (or BESS). The Tehachapi Wind Energy Storage project consists of an array of lithium-ion batteries capable of storing 32 megawatt-hours, deliverable as an 8 megawatt stream of energy for 4 hours. The LG Chem batteries rely on the same lithium-ion cells installed in battery packs for General Motors’ Chevrolet Volt electric vehicle, and feature 608,832 individual battery cells arrayed in 10,872 battery modules and 604 battery racks. Along with two 4MW/4.5MVA smart inverters, the project will be housed in a 6,300 square foot facility sited at SCE's existing Monolith substation.
Of the project's $49,956,528 total budget, half will be paid for by SCE, while federal funds will cover $24,978,264. In return, the project will examine whether and how the battery energy storage system improves grid performance and helps integrate wind and other large-scale variable energy resourced generation. Project performance will be measured by 13 specific operational uses, most of which either shift other generation resources to meet peak load and other electricity system needs with stored electricity, or resolve grid stability and capacity concerns that result from the interconnection of variable energy resources. These uses include: providing voltage support and grid stabilization; decreasing transmission losses; diminishing congestion; increasing system reliability; deferring transmission investment; optimizing renewable-related transmission; providing system capacity and resources adequacy; integrating renewable energy (smoothing); shifting wind generation output; frequency regulation; spin/non-spin replacement reserves; ramp management; and energy price arbitrage. In addition, the project will demonstrate how lithium-ion battery storage can provide nearly instantaneous back-up capacity, minimizing the need for fossil fuel-powered back-up generation.
Between technological advances and a series of recent policy decisions, battery energy storage could be poised for rapid growth. For example, in 2011 the Federal Energy Regulatory Commission issued Order No. 755, requiring the grid operators in organized markets to compensate battery energy storage systems and other fast-ramping frequency regulation resources based on the actual service they provide. Last year's Order No. 784 required public utilities to take into account the speed and accuracy of regulation resources such as batteries. Meanwhile, batteries are hoped to help balance into the grid large amounts of energy from intermittent renewable resources such as solar and wind projects.
After two years, the Tehachapi Wind Energy Storage Project will have completed its initial demonstration run. Will the project lead to greater deployment of battery energy storage systems in the U.S.?
FERC Order No. 784 boosts energy storage
Wednesday, July 24, 2013
Energy storage - the ability to store electricity and deliver it to the grid as needed - has the potential to create great value for society. New technologies, ranging from batteries to mechanical flywheels, are expanding options for energy storage. Now, a federal rule issued last week known as Order No. 784 significantly expands opportunities for energy storage providers to capitalize on these advances.
Traditionally, electricity has been difficult to store. While society has been able to generate electricity for over a century, technologies to store that electricity once it has been generated have been elusive. As a result, electric grid operators have needed to balance the supply and demand for electricity in real-time, leading to costly inefficiencies like the continual need to ramp generators up and down. To keep the grid balanced, grid operators rely on so-called "ancillary services" like regulation and frequency response made possible by fine-tuning generators' output -- or now by energy storage technologies.
Despite recent federal rulings like the Federal Energy Regulatory Commission's Order No. 755 enabling enhanced compensation for energy storage, the market for energy storage has been restricted by regulation. Until last week, the Federal Energy Regulatory Commission restricted third parties from selling ancillary services at market-based rates to public utility transmission providers under a 1999 ruling known as the Avista order. Under Avista, transmission customers had two choices for how to procure their share of the grid's ancillary services. First, customers could purchase ancillary services from their local public utility. Second, customers could self-supply regulation and frequency response services - but could only do so from resources deemed comparable to those used by their public utility. This restriction stripped away the benefit of self-supplying ancillary services because customers couldn't tailor their purchase of regulation and frequency response services to their own needs, but rather had to buy services based on their transmission provider's overall resource mix. For example, customers were powerless to choose resources that could respond more quickly or more accurately than those used by their utility, meaning customers faced the risk of buying too much - or too little - ancillary services.
Order No. 784 significantly reforms the Commission's ancillary service regulations. By November, public utilities must take into account the speed and accuracy of regulation resources, which opens the door for greater efficiency in transmission customers' purchase of regulation resources. For example, Order No. 784 allows customers to save money by buying a smaller amount of faster or more accurate energy storage resources.
This flexibility creates a premium value for providers of these fast or accurate energy storage solutions. Order No. 784 also eases the barriers for third-party entry into ancillary service markets, and revises accounting and reporting requirements to improve market transparency and better account for public utilities' use of energy storage devices.
Order No. 784 creates significant opportunities for utility customers, as it opens the door for lower-cost and more precise ancillary services. The order also creates opportunities for innovative companies developing and implementing energy storage technologies like batteries, compressed air, and flywheels, as Order No. 784 both increases consumer demand for these technologies and reduces developers' barriers to entry into the markets.
For more information about Order No. 784 and the opportunities it creates, contact Todd Griset at Preti Flaherty at 207-623-5300.
Traditionally, electricity has been difficult to store. While society has been able to generate electricity for over a century, technologies to store that electricity once it has been generated have been elusive. As a result, electric grid operators have needed to balance the supply and demand for electricity in real-time, leading to costly inefficiencies like the continual need to ramp generators up and down. To keep the grid balanced, grid operators rely on so-called "ancillary services" like regulation and frequency response made possible by fine-tuning generators' output -- or now by energy storage technologies.
Despite recent federal rulings like the Federal Energy Regulatory Commission's Order No. 755 enabling enhanced compensation for energy storage, the market for energy storage has been restricted by regulation. Until last week, the Federal Energy Regulatory Commission restricted third parties from selling ancillary services at market-based rates to public utility transmission providers under a 1999 ruling known as the Avista order. Under Avista, transmission customers had two choices for how to procure their share of the grid's ancillary services. First, customers could purchase ancillary services from their local public utility. Second, customers could self-supply regulation and frequency response services - but could only do so from resources deemed comparable to those used by their public utility. This restriction stripped away the benefit of self-supplying ancillary services because customers couldn't tailor their purchase of regulation and frequency response services to their own needs, but rather had to buy services based on their transmission provider's overall resource mix. For example, customers were powerless to choose resources that could respond more quickly or more accurately than those used by their utility, meaning customers faced the risk of buying too much - or too little - ancillary services.
Order No. 784 significantly reforms the Commission's ancillary service regulations. By November, public utilities must take into account the speed and accuracy of regulation resources, which opens the door for greater efficiency in transmission customers' purchase of regulation resources. For example, Order No. 784 allows customers to save money by buying a smaller amount of faster or more accurate energy storage resources.
This flexibility creates a premium value for providers of these fast or accurate energy storage solutions. Order No. 784 also eases the barriers for third-party entry into ancillary service markets, and revises accounting and reporting requirements to improve market transparency and better account for public utilities' use of energy storage devices.
Order No. 784 creates significant opportunities for utility customers, as it opens the door for lower-cost and more precise ancillary services. The order also creates opportunities for innovative companies developing and implementing energy storage technologies like batteries, compressed air, and flywheels, as Order No. 784 both increases consumer demand for these technologies and reduces developers' barriers to entry into the markets.
For more information about Order No. 784 and the opportunities it creates, contact Todd Griset at Preti Flaherty at 207-623-5300.
Vermont, Quebec announce electric vehicle corridor
Tuesday, June 18, 2013
Will a newly announced electric vehicle charging corridor in Vermont and Quebec lead to more electric vehicles in the region?
Electric vehicles are receiving increased interest, as drivers and policymakers look for ways to reduce the use of gasoline in the transportation sector. For pure plug-in cars, the vehicle's range and the logistics of recharging the vehicle's battery are critically important. Electric vehicle manufacturers try to address range anxiety through technological advances, while policymakers focus on ensuring that drivers have access to conveniently-spaced recharging infrastructure.
Today Vermont Governor Peter Shumlin and Quebec Premier Pauline Marois unveiled the first sites of the Vermont-Québec Electric Charging Corridor. The 138-mile corridor will eventually connect Burlington, Vermont to Montreal, Quebec, using existing highways including I-89 and Canadian routes A-10, 104 and 133. The plan calls for over the development of over 20 charging stations along the way. Some stations are already in place, including charging stations in Sharon, Montpelier, South Burlington and Waterbury.
How quickly charging stations can recharge batteries depends on the technology used. According to the U.S. Department of Energy's Plug-In Electric Vehicle Handbook, light-duty vehicle charging stations can be broken into three categories. Level 1 stations offer 2 to 5 miles of added driving range per hour of charging. Level 2 stations provide 10 to 20 miles of added range per hour of charge. Much more expensive Level 3 or "DC fast charging" stations can add 60 to 80 miles of range in 20 minutes of charging.
Level 2 stations are proposed for the Vermont-Quebec corridor. These stations will allow electric vehicle drivers to top off their batteries at the stations, and possibly to fully recharge their batteries overnight. While the charge rate is still significantly slower than refilling a conventional vehicle's tank with gasoline, Vermont and Quebec hope that the cost and environmental benefits of electric vehicles will drive their greater adoption.
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| Solar panels on the roof of the Farm Barn at Shelburne Farms, in Shelburne, Vermont. |
Electric vehicles are receiving increased interest, as drivers and policymakers look for ways to reduce the use of gasoline in the transportation sector. For pure plug-in cars, the vehicle's range and the logistics of recharging the vehicle's battery are critically important. Electric vehicle manufacturers try to address range anxiety through technological advances, while policymakers focus on ensuring that drivers have access to conveniently-spaced recharging infrastructure.
Today Vermont Governor Peter Shumlin and Quebec Premier Pauline Marois unveiled the first sites of the Vermont-Québec Electric Charging Corridor. The 138-mile corridor will eventually connect Burlington, Vermont to Montreal, Quebec, using existing highways including I-89 and Canadian routes A-10, 104 and 133. The plan calls for over the development of over 20 charging stations along the way. Some stations are already in place, including charging stations in Sharon, Montpelier, South Burlington and Waterbury.
How quickly charging stations can recharge batteries depends on the technology used. According to the U.S. Department of Energy's Plug-In Electric Vehicle Handbook, light-duty vehicle charging stations can be broken into three categories. Level 1 stations offer 2 to 5 miles of added driving range per hour of charging. Level 2 stations provide 10 to 20 miles of added range per hour of charge. Much more expensive Level 3 or "DC fast charging" stations can add 60 to 80 miles of range in 20 minutes of charging.
Level 2 stations are proposed for the Vermont-Quebec corridor. These stations will allow electric vehicle drivers to top off their batteries at the stations, and possibly to fully recharge their batteries overnight. While the charge rate is still significantly slower than refilling a conventional vehicle's tank with gasoline, Vermont and Quebec hope that the cost and environmental benefits of electric vehicles will drive their greater adoption.
Copper thief apparently zapped
Thursday, May 31, 2012
Copper wires and other electricity-related assets can be attractive targets for thieves -- but stealing electrical infrastructure carries risks beyond the legal realm.
The Associated Press is reporting that police have found evidence of an attempt to steal $100 worth of copper wiring from an electrical substation in Haverhill, Massachusetts. The evidence, which reportedly includes a melted hacksaw covered in soot, suggests that a thief broke into the substation and came in contact with live wires carrying 23,000 volts. Yesterday's incident apparently caused a small explosion and temporarily disrupted the power supply to the local area. The police have stated that the would-be thief is likely severely injured or dead.
Copper thieves are presumably hoping to cut the metal out of its installation and sell it for scrap. While the value of bulk quantities of scrap copper has been at a relative historic high, the Wall Street Journal reported yesterday that copper pricing has fallen due to expected decreases in European economic activity, selling on the New York Mercantile Exchange's Comex division for $3.39 per pound. It would be a desperate thief indeed who risks electrocution for any price, let alone copper's scrap value.
This incident follows on a report earlier this month of the arguably more sophisticated theft of solar panels, inverters and batteries from U.S. Forest Service facilities in the White Mountain National Forest of New Hampshire.
The Associated Press is reporting that police have found evidence of an attempt to steal $100 worth of copper wiring from an electrical substation in Haverhill, Massachusetts. The evidence, which reportedly includes a melted hacksaw covered in soot, suggests that a thief broke into the substation and came in contact with live wires carrying 23,000 volts. Yesterday's incident apparently caused a small explosion and temporarily disrupted the power supply to the local area. The police have stated that the would-be thief is likely severely injured or dead.
Copper thieves are presumably hoping to cut the metal out of its installation and sell it for scrap. While the value of bulk quantities of scrap copper has been at a relative historic high, the Wall Street Journal reported yesterday that copper pricing has fallen due to expected decreases in European economic activity, selling on the New York Mercantile Exchange's Comex division for $3.39 per pound. It would be a desperate thief indeed who risks electrocution for any price, let alone copper's scrap value.
This incident follows on a report earlier this month of the arguably more sophisticated theft of solar panels, inverters and batteries from U.S. Forest Service facilities in the White Mountain National Forest of New Hampshire.
Ener1 bankruptcy and DOE grant
Friday, January 27, 2012
Battery maker Ener1 is in news for yesterday's Chapter 11 bankruptcy filing, two years after its subsidiary was awarded a $118.5 million grant from the U.S. Department of Energy.
Ener1 Inc. holds several operating companies. Its subsidiary EnerDel produces automotive-industry thin cell lithium-ion batteries in Indiana. Other subsidiaries focus on fuel cells and nanotechnology, as well as manufacturing automotive-grade lithium-ion batteries in South Korea.
Battery making unit EnerDel won the $118.5 federal grant in 2009 for its proposal to expand two battery factories in Indiana and add a third facility. Many of the details of the proposal are available in the final Environmental Assessment prepared by the Department of Energy in support of the incentive:
Yesterday's bankruptcy filing by Ener1 comes at a time when policymakers are scrutinizing the energy department's grant and loan programs. Following the recent failures of other DOE loan guarantee and grant recipients such as Solyndra LLC and flywheel energy storage developer Beacon Power, Ener1's bankruptcy will likely add to the debate over the proper model for federal investment in the private sector energy industry.
Ener1 Inc. holds several operating companies. Its subsidiary EnerDel produces automotive-industry thin cell lithium-ion batteries in Indiana. Other subsidiaries focus on fuel cells and nanotechnology, as well as manufacturing automotive-grade lithium-ion batteries in South Korea.
Battery making unit EnerDel won the $118.5 federal grant in 2009 for its proposal to expand two battery factories in Indiana and add a third facility. Many of the details of the proposal are available in the final Environmental Assessment prepared by the Department of Energy in support of the incentive:
EnerDel received a $118.5 grant pursuant to a cost-sharing arrangement. Ener1 has since said that electric vehicles haven't caught on with drivers as quickly as it expected. Key customer, Norwegian electric vehicle maker Think Global, went bankrupt in June 2011.
The proposed financial assistance would help EnerDel expand its manufacturing and testing capabilities at two existing facilities and start up a third facility for future development into a complete lithium-ion battery manufacturing plant. The existing EnerDel facilities consist of a 92,000-square-foot building in Indianapolis and a 32,000-square-foot building in Noblesville, just north of Indianapolis. The lithium-ion battery manufacturing capacity of the Indianapolis facility would increase through the addition of equipment, and the Noblesville location would transition into full use as a prototype development and battery testing facility through the addition and change-out of equipment. The exteriors of the Indianapolis and Noblesville facilities would be unchanged. The third facility is a newly acquired vacant warehouse near Greenfield, Indiana, just east of Indianapolis. This 423,000-square-foot building would require minor construction and equipment installation on the exterior of the building; however, essentially all of the work necessary to transform it into a manufacturing plant would consist of installation of equipment inside the building.
Yesterday's bankruptcy filing by Ener1 comes at a time when policymakers are scrutinizing the energy department's grant and loan programs. Following the recent failures of other DOE loan guarantee and grant recipients such as Solyndra LLC and flywheel energy storage developer Beacon Power, Ener1's bankruptcy will likely add to the debate over the proper model for federal investment in the private sector energy industry.
Utah pumped storage project seeks license
Thursday, January 26, 2012
Electricity can be tricky to store once it is generated. Batteries, flywheels, and other energy storage technologies can provide some storage capacity, but pumped storage -- using electricity to pump water uphill during times of low power pricing, and letting it fall back down to generate electricity when needed -- is the most-used bulk electricity storage medium in the US. As of 2010, the United States was home to 21.5 gigawatts of pumped storage generating capacity. Pumped storage can be used both to balance supply and demand on the electric grid and to arbitrage fuel and electricity costs.
While some question whether electricity produced through pumped storage should qualify as renewable energy, pumped storage in the US is regulated by the Federal Energy Regulatory Commission as hydropower. Most pumped storage projects will ultimately need a FERC license, but obtaining a preliminary permit is a typical first step in the approval process. A preliminary permit gives a developer the right to investigate the feasibility of a project, typically for a three-year term, and convey exclusive first priority to file for a full license during that window.
This month, a proposed pumped storage in the Utah desert applied for a preliminary permit. Utah Independent Power, Inc. filed its application to FERC for a preliminary permit for the Long Canyon Pumped Storage Project (18-page PDF). Utah Independent Power proposes to build two dams to store water drawn from the Colorado River near Moab, Utah. These dams would create an upper reservoir on the high plateau above Long Canyon and a lower reservoir at the end of Long Canyon. The developer suggests that the power required for pumping would be supplied to the proposed project through the transmission grid using existing off peak power, while power would be produced by the project during peak periods and sold through the Western Electricity Coordinating Council grid at competitive peak rates.
The principals behind Utah Independent Power are no strangers to investigating pumped storage projects, having been involved in other proposals in the desert Southwest in recent decades. Indeed, in 2008, Utah Independent Power applied for and obtained a preliminary permit for the Long Canyon Pumped Storage project. (Here is Utah Independent Power's 2008 application, and the Commission's 2008 order issuing preliminary permit.) Utah Independent Power surrendered that preliminary permit in 2011, along with another preliminary permit for the nearby Bull Canyon Pumped Storage project. Its 2012 Long Canyon application bears significant similarities to its earlier proposal, with some differences including a slightly lower upper dam.
Utah Independent Power's proposal is likely to trigger significant interest. On the one hand, being able to use existing natural resources -- in this case, Colorado River water and canyon topography -- to store electricity may be an attractive proposition. On the other hand, Colorado River water is already scarce and at the center of water right fights. Moreover, the Long Canyon project would lie close to scenic and protected lands, such as Dead Horse Point State Park and Canyonlands National Park. An existing jeep road runs along Long Canyon, and the area receives both motorized and non-motorized recreation. In 2008, the State of Utah filed comments questioning the applicant's rights to the necessary water and land, as well as the impacts to the viewshed and natural landscape from the dams, transmission lines, and other project facilities.
While some question whether electricity produced through pumped storage should qualify as renewable energy, pumped storage in the US is regulated by the Federal Energy Regulatory Commission as hydropower. Most pumped storage projects will ultimately need a FERC license, but obtaining a preliminary permit is a typical first step in the approval process. A preliminary permit gives a developer the right to investigate the feasibility of a project, typically for a three-year term, and convey exclusive first priority to file for a full license during that window.
This month, a proposed pumped storage in the Utah desert applied for a preliminary permit. Utah Independent Power, Inc. filed its application to FERC for a preliminary permit for the Long Canyon Pumped Storage Project (18-page PDF). Utah Independent Power proposes to build two dams to store water drawn from the Colorado River near Moab, Utah. These dams would create an upper reservoir on the high plateau above Long Canyon and a lower reservoir at the end of Long Canyon. The developer suggests that the power required for pumping would be supplied to the proposed project through the transmission grid using existing off peak power, while power would be produced by the project during peak periods and sold through the Western Electricity Coordinating Council grid at competitive peak rates.
The principals behind Utah Independent Power are no strangers to investigating pumped storage projects, having been involved in other proposals in the desert Southwest in recent decades. Indeed, in 2008, Utah Independent Power applied for and obtained a preliminary permit for the Long Canyon Pumped Storage project. (Here is Utah Independent Power's 2008 application, and the Commission's 2008 order issuing preliminary permit.) Utah Independent Power surrendered that preliminary permit in 2011, along with another preliminary permit for the nearby Bull Canyon Pumped Storage project. Its 2012 Long Canyon application bears significant similarities to its earlier proposal, with some differences including a slightly lower upper dam.
Utah Independent Power's proposal is likely to trigger significant interest. On the one hand, being able to use existing natural resources -- in this case, Colorado River water and canyon topography -- to store electricity may be an attractive proposition. On the other hand, Colorado River water is already scarce and at the center of water right fights. Moreover, the Long Canyon project would lie close to scenic and protected lands, such as Dead Horse Point State Park and Canyonlands National Park. An existing jeep road runs along Long Canyon, and the area receives both motorized and non-motorized recreation. In 2008, the State of Utah filed comments questioning the applicant's rights to the necessary water and land, as well as the impacts to the viewshed and natural landscape from the dams, transmission lines, and other project facilities.
Frequency regulation and Order 755
Wednesday, January 18, 2012
Managing an electric grid requires a constant balancing act: instantaneously matching supply and demand. Grid operators maintain this real-time balance using a variety of tools, from traditional generation dispatch to innovative demand response.
Among the many parameters that must be balanced is the frequency of the alternating current on the grid. Each element of the grid must operate not only in synch but at the same frequency -- in the U.S., typically about 60 hertz. If supply and demand become imbalanced, the frequency of the grid power shifts away from 60 Hz, causing equipment damage, reliability problems, and even safety risks.
Traditionally, grid operators instructed generators to ramp up or ramp down small amounts as needed to maintain frequency regulation. While this generator-based approach works by injecting additional power into the transmission grid where needed, new technologies exist that may be able to provide frequency regulation more effectively. Compared to generation resources, flywheels, batteries, and other energy storage technologies may be able to regulate the grid's frequency not only at a lower cost but also with fewer emissions and other environmental impacts, as they do not rely on incremental fuel consumption. Storage is considered more capable of matching the grid operator's constantly-changing regulation signal.
Energy storage resources can also respond more quickly to grid frequency disturbances, providing a valuable fast-response frequency regulation service.
A recent federal order is designed to compensate those who can provide fast-response frequency regulation most effectively. FERC Order 755 (123 page PDF) requires grid operators to compensate frequency regulation resources based on the actual service they provide. Previously, grid operators paid fast responders the same price for frequency response as that paid to other providers, without regard to the more valuable speed and power quality provided by fast responders.
Under Order 755, grid operators will have to pay fast-responding frequency regulation resources a quality-based price. Given the energy storage technologies now under development, many anticipate that Order No. 755 will give birth to an expanded frequency regulation industry. For example, estimates of the total frequency regulation market size for the organized electric markets in the U.S. range from 4,000 megawatts to 7,500 MW.
Among the many parameters that must be balanced is the frequency of the alternating current on the grid. Each element of the grid must operate not only in synch but at the same frequency -- in the U.S., typically about 60 hertz. If supply and demand become imbalanced, the frequency of the grid power shifts away from 60 Hz, causing equipment damage, reliability problems, and even safety risks.
Traditionally, grid operators instructed generators to ramp up or ramp down small amounts as needed to maintain frequency regulation. While this generator-based approach works by injecting additional power into the transmission grid where needed, new technologies exist that may be able to provide frequency regulation more effectively. Compared to generation resources, flywheels, batteries, and other energy storage technologies may be able to regulate the grid's frequency not only at a lower cost but also with fewer emissions and other environmental impacts, as they do not rely on incremental fuel consumption. Storage is considered more capable of matching the grid operator's constantly-changing regulation signal.
Energy storage resources can also respond more quickly to grid frequency disturbances, providing a valuable fast-response frequency regulation service.
A recent federal order is designed to compensate those who can provide fast-response frequency regulation most effectively. FERC Order 755 (123 page PDF) requires grid operators to compensate frequency regulation resources based on the actual service they provide. Previously, grid operators paid fast responders the same price for frequency response as that paid to other providers, without regard to the more valuable speed and power quality provided by fast responders.
Under Order 755, grid operators will have to pay fast-responding frequency regulation resources a quality-based price. Given the energy storage technologies now under development, many anticipate that Order No. 755 will give birth to an expanded frequency regulation industry. For example, estimates of the total frequency regulation market size for the organized electric markets in the U.S. range from 4,000 megawatts to 7,500 MW.
FERC Order 755 promotes energy storage
Wednesday, December 21, 2011
New technologies have the promise to help electric grid operators perform the challenging task of balancing supply and demand at all times. This means making sure there the exact amount of electricity is being generated across the region as is demanded by consumers at that very moment. Line losses and the constraints of each local transmission and distribution system add complication. If the grid gets out of balance, problems arise with the electricity's frequency and power quality. In the worst case, failure can lead to cascading blackout, and safety can be at issue.
Historically, the balancing act has involved sending coordinated dispatch instructions to generators and demand response resources. Rules typically guide the grid operator in telling individual generating units to operate at specific levels. For example, flows through hydroelectric turbines can be varied, or fuel can be added to boilers or combustion turbines at a faster or slower rate. Through careful management, these conventional generation resources have been used to balance supply and demand, providing services known as frequency response and frequency regulation.
Though it is partly automated and well-practiced, this conventional resource dispatch process does take some time to take effect. Energy storage technologies such as flywheels, and batteries can not only provide frequency regulation, but can engage and ramp up much faster than conventional resources can. These faster-ramping resources could provide the grid relief in real time, as opposed to ramping up more slowly like conventional generation.
In most US markets, providers of efficient fast-ramping frequency regulation have been compensated the same as when conventional units provide regulation service, even when using fast-ramping resources is more efficient. At times this has meant that conventional resources have been dispatched when fast-ramping ones would have been lower-cost (and less polluting). For these reasons, this October the Federal Energy Regulatory Commission found that the current frequency regulation compensation practices "result in rates that are unjust, unreasonable, and unduly discriminatory or preferential."
In Order No. 755, FERC issued a final rule requiring the grid operators in organized markets to compensate frequency regulation resources based on the actual service they provide. Under Order 755 (123 page PDF), this must include separate payments for capacity (the marginal unit’s opportunity costs of being available) and for your actual performance.
Winners under Order 755 include providers of fast-ramping frequency response. These could include developers and operators of flywheel energy storage companies like Beacon Power, battery storage facilities, and compressed air energy storage, and other resources still in the conceptual phase. Winners also include energy consumers in the markets affected by Order 755, who should benefit from lower costs through improved operational and economic efficiency.
Historically, the balancing act has involved sending coordinated dispatch instructions to generators and demand response resources. Rules typically guide the grid operator in telling individual generating units to operate at specific levels. For example, flows through hydroelectric turbines can be varied, or fuel can be added to boilers or combustion turbines at a faster or slower rate. Through careful management, these conventional generation resources have been used to balance supply and demand, providing services known as frequency response and frequency regulation.
Though it is partly automated and well-practiced, this conventional resource dispatch process does take some time to take effect. Energy storage technologies such as flywheels, and batteries can not only provide frequency regulation, but can engage and ramp up much faster than conventional resources can. These faster-ramping resources could provide the grid relief in real time, as opposed to ramping up more slowly like conventional generation.
In most US markets, providers of efficient fast-ramping frequency regulation have been compensated the same as when conventional units provide regulation service, even when using fast-ramping resources is more efficient. At times this has meant that conventional resources have been dispatched when fast-ramping ones would have been lower-cost (and less polluting). For these reasons, this October the Federal Energy Regulatory Commission found that the current frequency regulation compensation practices "result in rates that are unjust, unreasonable, and unduly discriminatory or preferential."
In Order No. 755, FERC issued a final rule requiring the grid operators in organized markets to compensate frequency regulation resources based on the actual service they provide. Under Order 755 (123 page PDF), this must include separate payments for capacity (the marginal unit’s opportunity costs of being available) and for your actual performance.
Winners under Order 755 include providers of fast-ramping frequency response. These could include developers and operators of flywheel energy storage companies like Beacon Power, battery storage facilities, and compressed air energy storage, and other resources still in the conceptual phase. Winners also include energy consumers in the markets affected by Order 755, who should benefit from lower costs through improved operational and economic efficiency.
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