Federal hydropower regulators have issued an original license to an Ohio city to construct, operate, and maintain a 50-megawatt hydroelectric project at an existing U.S. Army Corps of Engineers lock and dam site. If developed as licensed, the City of Wadsworth, Ohio's Robert C. Byrd Hydroelectric Project will join other projects focused on adding hydroelectric generation to existing dams.
The Army Corps owns 21 locks and dams on the Ohio River, which it operates for commercial and recreational navigation. These facilities include the RC Byrd Locks and Dam, originally built in the 1930s and renovated within the past 25 years.
On March 28, 2011, the City of Wadsworth, Ohio, applied to the Federal Energy Regulatory Commission for a license to construct, operate, and maintain the Robert C. Byrd Hydroelectric Project No. 12796. As proposed by the city, the project would include new intake and tailrace structures along with a powerhouse holding two turbine generator units with a total installed capacity of 50 megwatts, but not the existing Army Corps dam.
On August 30, 2017, the Federal Energy Regulatory Commission issued its Order Issuing Original License for the RC Byrd Project. The license, which authorizes the installation of 50 MW of new, renewable energy generation capacity, requires a number of measures to protect environmental resources at the project, including measures proposed by the licensee as well as additional terms and conditions developed by Commission staff and other agencies.
According to the licensing order, the project will generate approximately 266,000 megawatt-hours per year, with a levelized annual cost of constructing and operating the project of about $40,586,280, or $152.58/MWh. While the Commission found this to be more expensive than the cost of alternative power in the first year of licensure, the Commission also noted "that hydroelectric projects offer unique operational benefits to the electric utility system." These ancillary service benefits "include the ability to help maintain the stability of a power system, such as by quickly adjusting power output to respond to rapid changes in system load; and to respond rapidly to a major utility system or regional blackout by providing a source of power to help restart the fossil-fuel generating stations and put them back on line."
Consistent with the Commission's general policy regarding license term for projects located on a federal dam, the Commission issued the RC Byrd Project license for a term of 50 years, the maximum allowable under the Federal Power Act.
If developed as licensed, the RC Byrd Project would be part of a trend toward adding hydroelectric generating facilities to existing dams owned by the Army Corps or other dam owners. Congress and the Commission, as well as state agencies, have expressed support for adding hydropower to existing dams and lock structures.
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 ancillary services. Show all posts
Showing posts with label ancillary services. Show all posts
Electric storage and wholesale markets
Tuesday, April 12, 2016
As electric energy storage technology improves in capability and cost-effectiveness, what barriers exist to electric storage resources' participation in organized electricity markets in the U.S.? Staff of the Federal Energy Regulatory Commission have issued a series of data requests and a request for public comment in an effort to identify barriers that could lead to unjust and unreasonable wholesale electricity rates.
For purposes of this inquiry, Commission staff defines an electric storage resource as a facility that can receive electric energy from the grid and store it for later injection of electricity back to the grid. This includes all types of electric storage technologies, regardless of their size and storage medium, or whether they are interconnected to the transmission system, distribution system, or behind a customer meter.
Historically, electricity had to be consumed as soon as it was generated, and storing electricity was challenging and expensive. But a new industry has grown up around electric storage. Federal regulators have acted to support energy storage, such as in FERC Order No. 784 which lets cost-effective storage be paid fairly for the ancillary services it provides to the grid.
According to a series of April 11, 2016 letters from Commission staff to various regulated Regional Transmission Organization (RTO) and Independent System Operator (ISO) entities, "Commission staff has been examining the use of electric storage resources to help meet wholesale electricity needs for some time." In light of "key developments in the technology and cost-effectiveness of electric storage resources," the letters express staff's interest in "examining whether barriers exist to the participation of electric storage resources in the capacity, energy, and ancillary service markets in the RTOs and ISOs potentially leading to unjust and unreasonable wholesale rates." The letters also describe staff's expectation that if potential barriers exist, staff will examine whether any tariff changes are warranted.
A data request is attached to each letter. In those data requests, staff seeks information on rules that affect the participation of electric storage resources in the markets. These rules include those governing electric storage resources' eligibility to participate in the markets, the qualification and performance requirements for market participants, required bid parameters, and the treatment of electric storage resources when they are receiving electricity for later injection to the grid.
FERC staff's data requests are organized into 6 categories:
As noted in the data request letters, this is not the first time Commission staff has considered energy storage. Will this round of regulatory process identify barriers to electric storage resources' participation in wholesale markets? Will any barriers identified give rise to changes to grid operators' tariffs? The case has been docketed as Docket No. AD16-20-000, Electric Storage Participation in Regions with Organized Wholesale Electric Markets.
For purposes of this inquiry, Commission staff defines an electric storage resource as a facility that can receive electric energy from the grid and store it for later injection of electricity back to the grid. This includes all types of electric storage technologies, regardless of their size and storage medium, or whether they are interconnected to the transmission system, distribution system, or behind a customer meter.
Historically, electricity had to be consumed as soon as it was generated, and storing electricity was challenging and expensive. But a new industry has grown up around electric storage. Federal regulators have acted to support energy storage, such as in FERC Order No. 784 which lets cost-effective storage be paid fairly for the ancillary services it provides to the grid.
According to a series of April 11, 2016 letters from Commission staff to various regulated Regional Transmission Organization (RTO) and Independent System Operator (ISO) entities, "Commission staff has been examining the use of electric storage resources to help meet wholesale electricity needs for some time." In light of "key developments in the technology and cost-effectiveness of electric storage resources," the letters express staff's interest in "examining whether barriers exist to the participation of electric storage resources in the capacity, energy, and ancillary service markets in the RTOs and ISOs potentially leading to unjust and unreasonable wholesale rates." The letters also describe staff's expectation that if potential barriers exist, staff will examine whether any tariff changes are warranted.
A data request is attached to each letter. In those data requests, staff seeks information on rules that affect the participation of electric storage resources in the markets. These rules include those governing electric storage resources' eligibility to participate in the markets, the qualification and performance requirements for market participants, required bid parameters, and the treatment of electric storage resources when they are receiving electricity for later injection to the grid.
FERC staff's data requests are organized into 6 categories:
- The Eligibility of Electric Storage Resources to be Market Participants
- Qualification Criteria and Performance Requirements
- Bid Parameters for Electric Storage Resources
- Distribution-Connected and Aggregated Electric Storage Resources
- When Electric Storage Resources are Receiving Electricity
- Potential Changes to the Rules Affecting Electric Storage Resources
As noted in the data request letters, this is not the first time Commission staff has considered energy storage. Will this round of regulatory process identify barriers to electric storage resources' participation in wholesale markets? Will any barriers identified give rise to changes to grid operators' tariffs? The case has been docketed as Docket No. AD16-20-000, Electric Storage Participation in Regions with Organized Wholesale Electric Markets.
Waterbury hydro need and economics
Friday, February 26, 2016
A recent order issuing a new hydropower license to Green Mountain Power Corporation's Waterbury Hydroelectric Project sheds insight into the project's operations and economics.
The Waterbury project is located at a dam built in 1938, and licensed for hydropower development since 1954. After a 16-year relicensing process, the Federal Energy Regulatory Commission issued a new license for the project in February 2016, authorizing 5.52 megawatts of generating capacity. That relicensing process illustrates how the Commission considers the need for power from the project, as well as project economics, when considering whether to relicense a hydropower project.
By regulation, the Commission's process for reviewing a license application includes an evaluation of the "need of the applicant over the short and long term for the electricity generated by the project or projects to serve its customers." In the Waterbury project's relicensing case, this consideration of the applicant's "need for power" involved observations about the project's expected output as well as the regional power market. The order notes historic average generation from the Waterbury Project of 17,562 MWh annually, but observes that under the new license average annual generation will be reduced to 14,767 MWh.
The order then states, "Electricity generated from the Waterbury Project will help supply the power needs in northern Vermont." It also cites a 10-year forecast by electric reliability organization North American Electric Reliability Corporation (NERC) showing summer peak demand in the region is expected to increase at an average rate of 0.84 percent per year between 2014 and 2023. Based on this, the order concludes that "the project's power will help meet the regional need for power."
The Commission's process for determining whether to issue a new license for an existing hydroelectric project also includes consideration of public interest factors, such as the economic benefits of project power. A 1995 decision established the Commission’s approach to evaluating the economics of hydropower projects. Under that approach, the Commission uses current costs to compare the costs of the project and likely alternative power with no forecasts concerning potential future inflation, escalation, or deflation beyond the license issuance date. The Commission has described the basic purpose of this economic analysis as to provide a general estimate of the potential power benefits and the costs of a project, and of reasonable alternatives to project power, "to support an informed decision concerning what is in the public interest with respect to a proposed license."
For the Waterbury project, as ultimately licensed with mandatory conditions and staff measures, the Commission concluded that:
The Commission did note that its consideration of public interest factors also considers that "hydroelectric projects offer unique operational benefits to the electric utility system", including ancillary services like stability and rapid response. The order also notes that while staff did not explicitly account for the effects inflation may have on the future cost of electricity, hydropower generation is relatively insensitive to inflation compared to fossil fueled generators -- illustrating why "project economics is only one of the many public interest factors the Commission considers in determining whether or not, and under what conditions, to issue a license."
The Waterbury project is located at a dam built in 1938, and licensed for hydropower development since 1954. After a 16-year relicensing process, the Federal Energy Regulatory Commission issued a new license for the project in February 2016, authorizing 5.52 megawatts of generating capacity. That relicensing process illustrates how the Commission considers the need for power from the project, as well as project economics, when considering whether to relicense a hydropower project.
By regulation, the Commission's process for reviewing a license application includes an evaluation of the "need of the applicant over the short and long term for the electricity generated by the project or projects to serve its customers." In the Waterbury project's relicensing case, this consideration of the applicant's "need for power" involved observations about the project's expected output as well as the regional power market. The order notes historic average generation from the Waterbury Project of 17,562 MWh annually, but observes that under the new license average annual generation will be reduced to 14,767 MWh.
The order then states, "Electricity generated from the Waterbury Project will help supply the power needs in northern Vermont." It also cites a 10-year forecast by electric reliability organization North American Electric Reliability Corporation (NERC) showing summer peak demand in the region is expected to increase at an average rate of 0.84 percent per year between 2014 and 2023. Based on this, the order concludes that "the project's power will help meet the regional need for power."
The Commission's process for determining whether to issue a new license for an existing hydroelectric project also includes consideration of public interest factors, such as the economic benefits of project power. A 1995 decision established the Commission’s approach to evaluating the economics of hydropower projects. Under that approach, the Commission uses current costs to compare the costs of the project and likely alternative power with no forecasts concerning potential future inflation, escalation, or deflation beyond the license issuance date. The Commission has described the basic purpose of this economic analysis as to provide a general estimate of the potential power benefits and the costs of a project, and of reasonable alternatives to project power, "to support an informed decision concerning what is in the public interest with respect to a proposed license."
For the Waterbury project, as ultimately licensed with mandatory conditions and staff measures, the Commission concluded that:
- the levelized annual cost of operating the project is $711,735, or $48.20/MWh
- the proposed project would generate an average of 14,767 MWh of energy annually.
- average generation is multiplied by the alternative power cost of $44.12/MWh, for a total value of the project’s power is $651,520, in 2015 dollars.
The Commission did note that its consideration of public interest factors also considers that "hydroelectric projects offer unique operational benefits to the electric utility system", including ancillary services like stability and rapid response. The order also notes that while staff did not explicitly account for the effects inflation may have on the future cost of electricity, hydropower generation is relatively insensitive to inflation compared to fossil fueled generators -- illustrating why "project economics is only one of the many public interest factors the Commission considers in determining whether or not, and under what conditions, to issue a license."
FERC considers Primary Frequency Response reforms
Friday, February 19, 2016
U.S. energy regulators are considering whether reforms are needed to regulations for the provision and compensation of primary frequency response, a function essential to the electric grid's operation.
In general, the U.S. bulk power system operates on an alternating current. For reliability and interoperability, that current must maintain its frequency within predetermined boundaries above and below 60 Hertz. An interconnected grid’s ability to arrest and stabilize frequency deviations within those boundaries after a sudden loss of generation or load is called "frequency response." A grid's frequency response characteristics are affected by factors including inertial response (as spinning generators speed up or slow down when load changes), primary frequency response, and secondary frequency response. Historically, most primary frequency response has been provided by baseload synchronous generators as an ancillary service.
But the U.S. electric grid's energy mix is changing. In a Notice of Inquiry released on February 18, 2016, the Federal Energy Regulatory Commission notes that changes to the U.S. electric supply portfolio likely mean that fewer resources are now primary frequency response. In particular, the U.S. has seen broad retirement of coal-fired baseload synchronous generators, some of which provide primary frequency response, while some have been replaced with variable energy resources such as wind and solar which do not typically have primary frequency response capabilities.
In response, FERC solicited public input on whether and what action is needed, including whether to:
In general, the U.S. bulk power system operates on an alternating current. For reliability and interoperability, that current must maintain its frequency within predetermined boundaries above and below 60 Hertz. An interconnected grid’s ability to arrest and stabilize frequency deviations within those boundaries after a sudden loss of generation or load is called "frequency response." A grid's frequency response characteristics are affected by factors including inertial response (as spinning generators speed up or slow down when load changes), primary frequency response, and secondary frequency response. Historically, most primary frequency response has been provided by baseload synchronous generators as an ancillary service.
But the U.S. electric grid's energy mix is changing. In a Notice of Inquiry released on February 18, 2016, the Federal Energy Regulatory Commission notes that changes to the U.S. electric supply portfolio likely mean that fewer resources are now primary frequency response. In particular, the U.S. has seen broad retirement of coal-fired baseload synchronous generators, some of which provide primary frequency response, while some have been replaced with variable energy resources such as wind and solar which do not typically have primary frequency response capabilities.
In response, FERC solicited public input on whether and what action is needed, including whether to:
- Amend the pro forma Large Generator and Small Generator interconnection agreements to require that all new generation resources have frequency response capabilities as a precondition of interconnection;
- Implement primary frequency response requirements for existing generation resources; and
- Establish procurement and compensation mechanisms for primary frequency response.
FERC has docketed the matter as RM16-6-000, Essential Reliability Services and the Evolving Bulk-Power System — Primary Frequency Response. Comments on the Notice of Inquiry are due 60 days after publication in the Federal Register.
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.
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.
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