What happens when the holder of a hydropower license applies to the Federal Energy Regulatory Commission for a new license, but the original license expires before the relicensing case is resolved? Depending on which federal laws and regulations apply, possible outcomes can include the Commission issuing an annual license, or continued operation under the license terms, until a new license is issued or other disposition is ordered.
A recent FERC case illustrates this dynamic, involving the Don Pedro Hydroelectric Project, Project No. 2299, located on the Tuolumne River in California. Turlock Irrigation District and Modesto Irrigation District are the licensees for Project No. 2299, under a license issued for a period ending April 30, 2016.
Just over 2 years before the Don Pedro project's license expired, on April 28, 2014 the licensees filed an Application for a New License pursuant to the Federal Power Act (FPA) and the Commission's regulations thereunder. That relicensing application remains pending.
Section 15(a)(1) of the FPA, 16 U.S.C. 808(a)(1), requires the Commission, at the
expiration of a license term, to issue from year-to-year an annual
license to the then licensee under the terms and conditions of the prior
license until a new license is issued, or the project is otherwise
disposed of as provided in section 15 or any other applicable section of
the FPA. But some projects operate pursuant to licenses which include waivers of the applicability of Section 15 of the FPA.
In the Don Pedro project's case, on May 5, 2016, the Commission issued a Notice of Authorization for Continued Project Operation, including language covering both the scenario under which Section 15 applies, as well as the scenario under which the prior license waived Section 15's applicability.
If the project is subject to section 15 of the FPA, the Commission gave notice that an annual license for Project No. 2299 is issued to the licensee for a period effective May 1, 2016 through April 30, 2017 or until the issuance of a new license for the project or other disposition under the FPA, whichever comes first. If issuance of a new license (or other disposition) has not occurred by April 30, 2017, the Commission gave notice that, pursuant to 18 CFR 16.18(c), an annual license under section 15(a)(1) of the FPA is renewed automatically without further order or notice by the Commission, unless the Commission orders otherwise.
If Section 15 does not apply, the Commission gave notice that based on section 9(b) of the Administrative Procedure Act, 5 U.S.C. 558(c), and as set forth at 18 CFR 16.21(a), if the licensee of such project has filed an application for a subsequent license, the licensee may continue to operate the project in accordance with the terms and conditions of the license after the minor or minor part license expires, until the Commission acts on its application. If the licensee of such a project has not filed an application for a subsequent license, then it may be required, pursuant to 18 CFR 16.21(b), to continue project operations until the Commission issues someone else a license for the project or otherwise orders disposition of the project.
The irrigation districts' relicensing case remains pending.
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Showing posts with label irrigation. Show all posts
Showing posts with label irrigation. Show all posts
FERC staff recommends against Bear River dam
Wednesday, April 27, 2016
Staff of the U.S. Federal Energy Regulatory Commission have recommended against licensing a dam, reservoir, and hydropower project proposed for the Bear River near Preston, Idaho.
The case involves a 2013 application by Twin Lakes Canal Company to the FERC for a license to construct, operate, and maintain the Bear River Narrows Project. The project would be located on the main stem of the Bear River in Franklin County, Idaho, about 9 miles northeast of the city of Preston. It would feature a 109-foot-high dam impounding a 362-acre reservoir, and a powerhouse with an installed capacity of 10 megawatts and estimated average annual generation of of 48,531 megawatt-hours of electricity. The reservoir would also be used to provide up to 5,000 acre-feet of water to Twin Lakes’ irrigation system during dry years.
Under the Federal Power Act, the FERC is charged with processing licenses for most hydropower projects in the U.S. Federal law guides the FERC in this duty. Sections 4(e) and 10(a)(1) of that act require the Commission to give equal consideration to the power development purposes and to the purposes of energy conservation; the protection of, mitigation of damage to, and enhancement of fish and wildlife; the protection of recreational opportunities; and the preservation of other aspects of environmental quality. The Commission can only issue licenses that in its judgment are best adapted to a comprehensive plan for improving or developing a waterway or waterways for all beneficial public uses. Additionally, the National Environmental Policy Act of 1969 requires the agency to analyze and document the environmental effects of proposed federal actions such as granting Twin Lakes' application.
Commission staff released its final environmental impact statement on Twin Lakes' license application on April 27, 2016. That document, called an EIS, analyzes the effects of proposed project construction and operation, and recommends conditions for any license that may be issued for the project.
In the Bear River Narrows Project EIS, FERC staff considered Twin Lakes’ proposal for licensing, as well as three alternatives: (1) no-action (i.e. not licensing the project, so it can't be constructed); (2) the applicant’s proposal with staff modifications (staff licensing alternative); and (3) the staff licensing alternative with an additional condition requested by the Bureau of Land Management.
The EIS notes the existence of four Commission-licensed hydroelectric facilities located on the Bear River in Idaho with a combined installed capacity of more than 78 MW, including the Oneida development directly upstream. It also notes uses of the "Oneida Narrows" section of the Bear River that would be flooded by the Bear River Narrows Project impoundment, including a recreational trout fishery and boating opportunities, and habitat for sensitive wildlife species.
Based on a review of the anticipated environmental and economic effects of the proposed project and its alternatives, as well as the agency and public comments filed on this project, staff recommends no action (license denial) as the preferred alternative. In staff's words, "The overall, unavoidable adverse environmental effects of both action alternatives would outweigh the power and water storage benefits of the project."
For these reasons, FERC staff concluded that "any license issued for the proposed project could not be best adapted to a comprehensive plan for improving or developing the Bear River for all of its beneficial public uses, especially its substantial public recreation use at the proposed project site. We, therefore, recommend license denial."
Twin Lakes Canal Company's application to the Commission for a license to construct the project remains pending.
The case involves a 2013 application by Twin Lakes Canal Company to the FERC for a license to construct, operate, and maintain the Bear River Narrows Project. The project would be located on the main stem of the Bear River in Franklin County, Idaho, about 9 miles northeast of the city of Preston. It would feature a 109-foot-high dam impounding a 362-acre reservoir, and a powerhouse with an installed capacity of 10 megawatts and estimated average annual generation of of 48,531 megawatt-hours of electricity. The reservoir would also be used to provide up to 5,000 acre-feet of water to Twin Lakes’ irrigation system during dry years.
Under the Federal Power Act, the FERC is charged with processing licenses for most hydropower projects in the U.S. Federal law guides the FERC in this duty. Sections 4(e) and 10(a)(1) of that act require the Commission to give equal consideration to the power development purposes and to the purposes of energy conservation; the protection of, mitigation of damage to, and enhancement of fish and wildlife; the protection of recreational opportunities; and the preservation of other aspects of environmental quality. The Commission can only issue licenses that in its judgment are best adapted to a comprehensive plan for improving or developing a waterway or waterways for all beneficial public uses. Additionally, the National Environmental Policy Act of 1969 requires the agency to analyze and document the environmental effects of proposed federal actions such as granting Twin Lakes' application.
Commission staff released its final environmental impact statement on Twin Lakes' license application on April 27, 2016. That document, called an EIS, analyzes the effects of proposed project construction and operation, and recommends conditions for any license that may be issued for the project.
In the Bear River Narrows Project EIS, FERC staff considered Twin Lakes’ proposal for licensing, as well as three alternatives: (1) no-action (i.e. not licensing the project, so it can't be constructed); (2) the applicant’s proposal with staff modifications (staff licensing alternative); and (3) the staff licensing alternative with an additional condition requested by the Bureau of Land Management.
The EIS notes the existence of four Commission-licensed hydroelectric facilities located on the Bear River in Idaho with a combined installed capacity of more than 78 MW, including the Oneida development directly upstream. It also notes uses of the "Oneida Narrows" section of the Bear River that would be flooded by the Bear River Narrows Project impoundment, including a recreational trout fishery and boating opportunities, and habitat for sensitive wildlife species.
Based on a review of the anticipated environmental and economic effects of the proposed project and its alternatives, as well as the agency and public comments filed on this project, staff recommends no action (license denial) as the preferred alternative. In staff's words, "The overall, unavoidable adverse environmental effects of both action alternatives would outweigh the power and water storage benefits of the project."
For these reasons, FERC staff concluded that "any license issued for the proposed project could not be best adapted to a comprehensive plan for improving or developing the Bear River for all of its beneficial public uses, especially its substantial public recreation use at the proposed project site. We, therefore, recommend license denial."
Twin Lakes Canal Company's application to the Commission for a license to construct the project remains pending.
FERC settles 3rd Southwest blackout case
Wednesday, October 22, 2014
A California public utility has settled claims by federal electricity regulators related to the September 8, 2011, blackout in the southwestern United States. Following an investigation by the Federal Energy Regulatory Commission (FERC) and electric reliability organization North American Electric Reliability Corporation (NERC), Southern California Edison Company has agreed to pay a $650,000 civil penalty and undertake additional compliance actions.
According to previous investigative reports, the 2011 blackout started when a 500-kilovolt transmission line owned by Arizona Public Service Company tripped out of service, causing cascading power outages through automatic load shedding as other equipment quickly overloaded. In the end, the outage affected over 5 million customers, shedding 7,835 megawatts of peak demand and over 30,000 megawatt-hours of energy.
Following the blackouts, both FERC and NERC launched investigations into what had happened. As a federal agency, FERC has regulatory authority over the reliability of the electric bulk power system. NERC is a not-for-profit international regulatory authority whose mission is to ensure the reliability of the bulk power system in North America, and has been designated by FERC as the nation's electric reliability organization.
In July, FERC announced a $3.25 million settlement with Arizona Public Service. In August, FERC announced a $12 million settlement with California's Imperial Irrigation District.
Today, FERC announced that it has approved a stipulation and consent agreement between FERC’s Office of Enforcement, NERC, and Southern California Edison Company. Through a joint investigation, FERC Office of Enforcement staff and NERC determined that the utility violated the Protection and Control group of NERC's Reliability Standards. In particular, the investigation found that Southern California Edison failed to adequately coordinate its intertie separation scheme at the San Onofre nuclear generating station switchyard with certain other protection systems. Enforcement staff and NERC found this violation to be a serious deficiency that undermined reliable operation of the Bulk Power System.
Through the settlement, Southern California Edison will pay a civil penalty of $650,000. Of this penalty, $125,000 will be paid to the U.S. Treasury, $125,000 will be paid to NERC, and $400,000 will be invested in additional reliability enhancement measures.
With Southern California Edison's case resolved, all three of the vertically integrated utilities known to be implicated by FERC's investigation have now settled their alleged violations by agreeing to pay penalties. Will further penalties be forthcoming? Will the penalties and ordered reliability measures keep the lights on the next time the grid is stressed?
According to previous investigative reports, the 2011 blackout started when a 500-kilovolt transmission line owned by Arizona Public Service Company tripped out of service, causing cascading power outages through automatic load shedding as other equipment quickly overloaded. In the end, the outage affected over 5 million customers, shedding 7,835 megawatts of peak demand and over 30,000 megawatt-hours of energy.
Following the blackouts, both FERC and NERC launched investigations into what had happened. As a federal agency, FERC has regulatory authority over the reliability of the electric bulk power system. NERC is a not-for-profit international regulatory authority whose mission is to ensure the reliability of the bulk power system in North America, and has been designated by FERC as the nation's electric reliability organization.
In July, FERC announced a $3.25 million settlement with Arizona Public Service. In August, FERC announced a $12 million settlement with California's Imperial Irrigation District.
Today, FERC announced that it has approved a stipulation and consent agreement between FERC’s Office of Enforcement, NERC, and Southern California Edison Company. Through a joint investigation, FERC Office of Enforcement staff and NERC determined that the utility violated the Protection and Control group of NERC's Reliability Standards. In particular, the investigation found that Southern California Edison failed to adequately coordinate its intertie separation scheme at the San Onofre nuclear generating station switchyard with certain other protection systems. Enforcement staff and NERC found this violation to be a serious deficiency that undermined reliable operation of the Bulk Power System.
Through the settlement, Southern California Edison will pay a civil penalty of $650,000. Of this penalty, $125,000 will be paid to the U.S. Treasury, $125,000 will be paid to NERC, and $400,000 will be invested in additional reliability enhancement measures.
With Southern California Edison's case resolved, all three of the vertically integrated utilities known to be implicated by FERC's investigation have now settled their alleged violations by agreeing to pay penalties. Will further penalties be forthcoming? Will the penalties and ordered reliability measures keep the lights on the next time the grid is stressed?
FERC approves second Southwest blackout penalty
Thursday, August 7, 2014
A California irrigation district has agreed to pay a $12 million penalty to settle its role in a 2011 power outage affecting over 5 million people in California, Arizona, and Mexico.
The September 8, 2011 outage started when a 500-kilovolt transmission line owned by Arizona Public Service Company tripped out of service, causing cascading power outages through automatic load shedding as other equipment quickly overloaded. In the end, the outage deprived customers of 7,835 megawatts of peak demand and over 30,000 megawatt-hours of energy.
Swiftly on the heels of the outage, the Federal Energy Regulatory Commission and electric reliability organization NERC launched an investigation into what had happened -- and whether any laws or regulations had been violated. That investigation focused on APS and five other entities believed to have been involved: the California Independent System Operator, the Imperial Irrigation District, Southern California Edison, the Western Area Power Administration, and the Western Electricity Coordinating Council Reliability Coordinator. Last month, the Commission approved a $3.25 million settlement with APS.
Today, the Commission issued an order approving a stipulation and consent agreement resolving Imperial Irrigation District's role in the blackout. Imperial Irrigation District is a not-for-profit, publicly owned, vertically integrated utility and political subdivision of the State of California. The sixth largest utility in California, Imperial Irrigation District Electricity provides electric power to more than 145,000 customers in the Imperial Valley and parts of Riverside and San Diego counties.
Through their investigation, Commission enforcement staff and NERC found Imperial Irrigation District violated 10 requirements of four Reliability Standards on transmission operations and transmission planning, including a failure to coordinate its operations planning with neighboring systems. The Commission noted that these violations were serious deficiencies that undermined reliable operation of the Bulk Power System.
Through that stipulation, Imperial Irrigation District agreed to pay a civil penalty of $12 million. Of this amount, at least $1.5 million will go to the U.S. Treasury and another $1.5 million will go to NERC, and at least another $9 million will be invested in reliability enhancement measures that go beyond mitigation of the violations and the requirements of the mandatory Reliability Standards. These reliability enhancements will include construction of one or more utility-scale battery energy storage facilities within IID’s transmission operations area, with the money spent by December 31, 2016.
Two of the six entities known to be targeted by the Commission's investigation have now settled their alleged violations by agreeing to pay penalties. Perhaps more significantly, APS and Imperial Irrigation District represent two of the three vertically integrated utilities implicated. Will the FERC/NERC investigation lead to further settlements soon? What impact will the Imperial Irrigation District settlement and penalty agreement have?
The September 8, 2011 outage started when a 500-kilovolt transmission line owned by Arizona Public Service Company tripped out of service, causing cascading power outages through automatic load shedding as other equipment quickly overloaded. In the end, the outage deprived customers of 7,835 megawatts of peak demand and over 30,000 megawatt-hours of energy.
Swiftly on the heels of the outage, the Federal Energy Regulatory Commission and electric reliability organization NERC launched an investigation into what had happened -- and whether any laws or regulations had been violated. That investigation focused on APS and five other entities believed to have been involved: the California Independent System Operator, the Imperial Irrigation District, Southern California Edison, the Western Area Power Administration, and the Western Electricity Coordinating Council Reliability Coordinator. Last month, the Commission approved a $3.25 million settlement with APS.
Today, the Commission issued an order approving a stipulation and consent agreement resolving Imperial Irrigation District's role in the blackout. Imperial Irrigation District is a not-for-profit, publicly owned, vertically integrated utility and political subdivision of the State of California. The sixth largest utility in California, Imperial Irrigation District Electricity provides electric power to more than 145,000 customers in the Imperial Valley and parts of Riverside and San Diego counties.
Through their investigation, Commission enforcement staff and NERC found Imperial Irrigation District violated 10 requirements of four Reliability Standards on transmission operations and transmission planning, including a failure to coordinate its operations planning with neighboring systems. The Commission noted that these violations were serious deficiencies that undermined reliable operation of the Bulk Power System.
Through that stipulation, Imperial Irrigation District agreed to pay a civil penalty of $12 million. Of this amount, at least $1.5 million will go to the U.S. Treasury and another $1.5 million will go to NERC, and at least another $9 million will be invested in reliability enhancement measures that go beyond mitigation of the violations and the requirements of the mandatory Reliability Standards. These reliability enhancements will include construction of one or more utility-scale battery energy storage facilities within IID’s transmission operations area, with the money spent by December 31, 2016.
Two of the six entities known to be targeted by the Commission's investigation have now settled their alleged violations by agreeing to pay penalties. Perhaps more significantly, APS and Imperial Irrigation District represent two of the three vertically integrated utilities implicated. Will the FERC/NERC investigation lead to further settlements soon? What impact will the Imperial Irrigation District settlement and penalty agreement have?
Small hydro approved under fast process
Monday, September 19, 2011
This month, federal energy regulators approved a small hydroelectric project within two months of its formal proposal under an innovative streamlined regulatory path.
Recognizing the potential of small hydro projects, the Federal Energy Regulatory Commission (FERC) is interested in simplifying the regulatory process for small projects. Last year, FERC signed a Memorandum of Understanding with the state of Colorado to streamline the procedures for developing small-scale hydropower projects in that state. Colorado has identified hundreds of small (5 MW or smaller) or conduit hydropower projects (turbines in water pipes and irrigation canals) whose total capacity could exceed 1,400 MW. Under the Memorandum of Understanding, Colorado is developing a pilot program to test ways to simplify the processes through which project developers obtain exemptions for small projects. For example, the application is presented to multiple agencies for simultaneous comment, rather than a prolonged multi-agency back and forth process.
Last week, FERC approved Colorado's first hydroelectric project under the Memorandum of Understanding. Docketed as Project P-14230, the Meeker Wenschhof hydroelectric project will be developed on an existing ranch irrigation pipeline in northwestern Colorado. Historically, water flowing through the pipe has been slowed by a valve before being stored in an underground cistern. As approved by FERC, the rancher will install a 23-kilowatt turbine in place of the valve. The project is expected to generate 100,000 kilowatt-hours per year on average.
The Meeker Wenschhof project's engineering details are interesting, making innovative and efficient use of the power of flowing water. Equally interesting is the speed with which the project flew through the regulatory approval process, with the application granted just two months after it was filed with FERC. Admittedly, this expedited process is currently limited to small hydro and conduit projects. Nevertheless, the Meeker Wenschhof project's rapid approval illustrates how quickly the regulatory process can be completed if it is designed to accommodate developers' needs.
Recognizing the potential of small hydro projects, the Federal Energy Regulatory Commission (FERC) is interested in simplifying the regulatory process for small projects. Last year, FERC signed a Memorandum of Understanding with the state of Colorado to streamline the procedures for developing small-scale hydropower projects in that state. Colorado has identified hundreds of small (5 MW or smaller) or conduit hydropower projects (turbines in water pipes and irrigation canals) whose total capacity could exceed 1,400 MW. Under the Memorandum of Understanding, Colorado is developing a pilot program to test ways to simplify the processes through which project developers obtain exemptions for small projects. For example, the application is presented to multiple agencies for simultaneous comment, rather than a prolonged multi-agency back and forth process.
Last week, FERC approved Colorado's first hydroelectric project under the Memorandum of Understanding. Docketed as Project P-14230, the Meeker Wenschhof hydroelectric project will be developed on an existing ranch irrigation pipeline in northwestern Colorado. Historically, water flowing through the pipe has been slowed by a valve before being stored in an underground cistern. As approved by FERC, the rancher will install a 23-kilowatt turbine in place of the valve. The project is expected to generate 100,000 kilowatt-hours per year on average.
The Meeker Wenschhof project's engineering details are interesting, making innovative and efficient use of the power of flowing water. Equally interesting is the speed with which the project flew through the regulatory approval process, with the application granted just two months after it was filed with FERC. Admittedly, this expedited process is currently limited to small hydro and conduit projects. Nevertheless, the Meeker Wenschhof project's rapid approval illustrates how quickly the regulatory process can be completed if it is designed to accommodate developers' needs.
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