Utilities and electric grid coordinators are preparing for a total solar eclipse that is projected to temporarily reduce solar photovoltaic generation across parts of North America this summer.
The 2017 total solar eclipse will be the first in the U.S. in 26 years (since Hawaii 1991), and the first in the lower 48 states since 1979. While the duration of the total eclipse across the U.S. will be roughly 93 minutes, some areas in its path will experience up to 95% of the Sun being obscured.
The eclipse is projected to affect solar PV generation. Solar resources occupy an increasing role in the U.S. electric generating portfolio. Between 2000 and 2016, total U.S. solar capacity increased from 5 megawatts (MW) to 42,619 MW. But as more solar resources are connected to the grid, the potential impact of an eclipse on grid operations may change.
According to a May 1, 2017 presentation to the Board of Governors of the California ISO, the eclipse is projected to reduce solar output in the CAISO region by 4,194 megawatts, while gross load will increase by 1,365 MW. Taking into account estimated wind production, the presentation projects a net load increase of 6,008 MW during the eclipse.
The ramp rate, or speed at which supply and demand will change, is also a factor. The eclipse is projected to diminish solar output by about 70 MW per minute as it approaches totality, and about 90 MW per minute on the return. By contrast, a typical average ramp rate for CAISO might be 29 MW per minute. Thus the eclipse is projected to call for a greater degree of fast-ramping or flexible resources, compared to typical operating conditions.
But according to international electric reliability organization NERC, the August 21, 2017 total solar eclipse "is unlikely to cause any reliability issues to the North American bulk power system."
NERC documented its findings in an April 25, 2017 white paper, A Wide-Area Perspective on the August 21, 2017 Total Solar Eclipse. NERC's report identifies California and North Carolina as the states
most likely to experience the greatest impact from solar production
fall-off from the eclipse. At the same time, NERC recommends "that utilities in all states perform specific studies of the eclipse’s impact of solar photovoltaic power output on their systems and retain necessary resources to meet the increased electricity demand requirements." In particular, NERC notes that generation and system operators may greater visibility into utility-scale solar projects than into behind-the-meter or distributed solar photovoltaic resources, highlighting the need to model all scales of solar development.
Following the 2017 eclipse, the next total solar eclipse is projected to cross North America on April 8, 2024.
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Showing posts with label CAISO. Show all posts
Showing posts with label CAISO. Show all posts
DesertLink transmission project wins rate incentives under Section 219
Tuesday, August 23, 2016
Federal energy regulators have granted a petition by the developer of a proposed electric transmission project in Nevada for certain transmission rate incentives available under federal law. On August 19, the Federal Energy Regulatory Commission ruled on DesertLink, LLC's petition for declaratory order, with respect to DesertLink's new Harry Allen to Eldorado 500 kV transmission project. The order grants DesertLink's requests for transmission rate incentives under section 219 of the Federal Power Act, and illustrates how those incentives operate.
DesertLink, a member of the LS Power Group, is the developer of a transmission project to be located in Nevada, but connected to a substation in the grid controlled by the California Independent System Operator Corporation. CAISO designated the project for competitive bidding under its 2013-2014 transmission plan, and in January 2016 selected DesertLink as the approved project sponsor under its Order No. 1000-based process for eligible transmission developers to submit bids to develop and construct certain transmission projects. The project is designed to have an in-service date of May 2020.
Rate incentives can be available to promote capital investments in certain transmission infrastructure. The Federal Power Act authorizes the Federal Energy Regulatory Commission to regulate the transmission and wholesale sales of electricity in interstate commerce. Through the Energy Policy Act of 2005, Congress added a new section 219 to the Federal Power Act, directing the Commission to create rules establishing incentive-based rate treatments. The Commission's Order No. 679 sets forth the processes by which a public utility may seek transmission rate incentives under section 219, and the Commission has issued a Transmission Incentives Policy Statement offering guidance on how it evaluates applications for transmission rate incentives.
Section 219 and Order No. 679 require an applicant for rate incentives to show that “the facilities for which it seeks incentives either ensure reliability or reduce the cost of delivered power by reducing transmission congestion.” Order No. 679 established a rebuttable presumption that this standard is met if:
In DesertLink's case, on May 11, 2016, the applicant applied for transmission rate incentives, including (1) deferred recovery of all prudently incurred precommercial costs through the creation of a regulatory asset (regulatory asset incentive); (2) full recovery of 100 percent of prudently-incurred costs, including pre-commercial expenses and construction costs, if the Project is abandoned for reasons beyond DesertLink’s control (abandonment incentive); (3) use of a hypothetical capital structure consisting of 50 percent debt and 50 percent equity until the Project achieves commercial operation (hypothetical capital structure incentive); and (4) a 50-basis point adder to DesertLink’s Return on Equity (ROE) for participating in a Regional Transmission Organization (RTO), namely, CAISO (RTO participation incentive).
Last week, the Commission granted DesertLink's petition. First, the Commission found that DesertLink is entitled to the rebuttable presumption that the Project will ensure reliability or reduce the cost of delivered power by reducing transmission congestion, because the CAISO transmission planning process found annual production cost benefits of $9.4 million in 2019 to $8.4 million in 2024 and beyond, and annual capacity benefits of $19.7 million in 2020 to $8.8 million in 2025 and beyond.
Next, the Commission found that DesertLink had demonstrated that its total package of requested incentives is tailored to address the demonstrable risks or challenges faced by DesertLink. The Commission found that the regulatory asset treatment of pre-commercial costs appropriately addresses the risks and challenges of the Project, because it provides DesertLink with added upfront regulatory certainty, reduces interest expenses, and assists in the construction of the Project. On the abandonment incentive, the Commission found that recovery of abandonment costs was an effective means to encourage transmission development by reducing the risk of non-recovery of costs. Regarding a hypothetical capital structure, the Commission noted that its use "will aid DesertLink in raising capital during the construction phase of the Project, and will assist DesertLink in maintaining low debt costs while its actual debt-to-equity ratio varies." The Commission also found DesertLink would qualify for the RTO participation incentive, based on its commitment to become a member of CAISO and to transfer operational control of the project to CAISO after placing it in service.
The Commission's determination takes the form of a declaratory order granting authorization for the rate incentives, but it does not directly authorize DesertLink to include the incentives in its filed rates. As the Commission noted, "While our determination on DesertLink's Petition establishes whether it qualifies for the requested transmission rate incentives, if DesertLink seeks to put these incentives into effect, it must submit a subsequent filing under section 205 of the FPA." In such a case, the applicant will need to make a variety of showings before including certain incentives in its rate base, including the justness and reasonableness of costs relating to pre-commercial, formation, and plant abandonment. Nevertheless, securing the declaratory order gives DesertLink greater certainty about its qualification for these key incentives for electric transmission development.
DesertLink, a member of the LS Power Group, is the developer of a transmission project to be located in Nevada, but connected to a substation in the grid controlled by the California Independent System Operator Corporation. CAISO designated the project for competitive bidding under its 2013-2014 transmission plan, and in January 2016 selected DesertLink as the approved project sponsor under its Order No. 1000-based process for eligible transmission developers to submit bids to develop and construct certain transmission projects. The project is designed to have an in-service date of May 2020.
Rate incentives can be available to promote capital investments in certain transmission infrastructure. The Federal Power Act authorizes the Federal Energy Regulatory Commission to regulate the transmission and wholesale sales of electricity in interstate commerce. Through the Energy Policy Act of 2005, Congress added a new section 219 to the Federal Power Act, directing the Commission to create rules establishing incentive-based rate treatments. The Commission's Order No. 679 sets forth the processes by which a public utility may seek transmission rate incentives under section 219, and the Commission has issued a Transmission Incentives Policy Statement offering guidance on how it evaluates applications for transmission rate incentives.
Section 219 and Order No. 679 require an applicant for rate incentives to show that “the facilities for which it seeks incentives either ensure reliability or reduce the cost of delivered power by reducing transmission congestion.” Order No. 679 established a rebuttable presumption that this standard is met if:
(1) the transmission project results from a fair and open regional planning process that considers and evaluates the project for reliability and/or congestion and is found to be acceptable to the Commission; or (2) a project has received construction approval from an appropriate state commission or state siting authority.Order No. 679 also requires an applicant to demonstrate that there is a nexus between the incentive being sought and the investment being made. The Commission clarified in Order No. 679-A that this "nexus test" is met when an applicant demonstrates, on a project-specific basis, that the total package of incentives requested is “tailored to address the demonstrable risks or challenges faced by the applicant.”
In DesertLink's case, on May 11, 2016, the applicant applied for transmission rate incentives, including (1) deferred recovery of all prudently incurred precommercial costs through the creation of a regulatory asset (regulatory asset incentive); (2) full recovery of 100 percent of prudently-incurred costs, including pre-commercial expenses and construction costs, if the Project is abandoned for reasons beyond DesertLink’s control (abandonment incentive); (3) use of a hypothetical capital structure consisting of 50 percent debt and 50 percent equity until the Project achieves commercial operation (hypothetical capital structure incentive); and (4) a 50-basis point adder to DesertLink’s Return on Equity (ROE) for participating in a Regional Transmission Organization (RTO), namely, CAISO (RTO participation incentive).
Last week, the Commission granted DesertLink's petition. First, the Commission found that DesertLink is entitled to the rebuttable presumption that the Project will ensure reliability or reduce the cost of delivered power by reducing transmission congestion, because the CAISO transmission planning process found annual production cost benefits of $9.4 million in 2019 to $8.4 million in 2024 and beyond, and annual capacity benefits of $19.7 million in 2020 to $8.8 million in 2025 and beyond.
Next, the Commission found that DesertLink had demonstrated that its total package of requested incentives is tailored to address the demonstrable risks or challenges faced by DesertLink. The Commission found that the regulatory asset treatment of pre-commercial costs appropriately addresses the risks and challenges of the Project, because it provides DesertLink with added upfront regulatory certainty, reduces interest expenses, and assists in the construction of the Project. On the abandonment incentive, the Commission found that recovery of abandonment costs was an effective means to encourage transmission development by reducing the risk of non-recovery of costs. Regarding a hypothetical capital structure, the Commission noted that its use "will aid DesertLink in raising capital during the construction phase of the Project, and will assist DesertLink in maintaining low debt costs while its actual debt-to-equity ratio varies." The Commission also found DesertLink would qualify for the RTO participation incentive, based on its commitment to become a member of CAISO and to transfer operational control of the project to CAISO after placing it in service.
The Commission's determination takes the form of a declaratory order granting authorization for the rate incentives, but it does not directly authorize DesertLink to include the incentives in its filed rates. As the Commission noted, "While our determination on DesertLink's Petition establishes whether it qualifies for the requested transmission rate incentives, if DesertLink seeks to put these incentives into effect, it must submit a subsequent filing under section 205 of the FPA." In such a case, the applicant will need to make a variety of showings before including certain incentives in its rate base, including the justness and reasonableness of costs relating to pre-commercial, formation, and plant abandonment. Nevertheless, securing the declaratory order gives DesertLink greater certainty about its qualification for these key incentives for electric transmission development.
4th California blackout FERC enforcement case settles
Friday, December 5, 2014
Federal regulators have approved a settlement with another federal agency over its role in a 2011 blackout in California, Arizona, and Mexico.
On September 8, 2011, the Southwest's electric grid was hit with a widespread power outage that left over 5 million people in California, Arizona and Baja California, Mexico, without power for up to 12 hours. Previous investigations by the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC) found that the blackout occurred when Arizona Public Service Company's 500-kilovolt Hassayampa-N.Gila transmission line tripped out of service, overloading the remaining elements of the regional grid.
Earlier this year, FERC approved stipulations and consent agreements among its Office of Enforcement, NERC, and three public utilities. Arizona Public Service agreed to pay $3.25 million in civil penalties, California's Imperial Irrigation District agreed to a $12 million settlement, and Southern California Edison Company agreed to pay a $650,000 civil penalty and undertake additional compliance actions.
FERC approved a fourth settlement on November 24, 2014, with the Western Area Power Administration – Desert Southwest Region (Western-DSW). One of four power marketing administrations within the United States Department of Energy, the Western Area Power Administration (WAPA) markets and transmits electricity to a fifteen-state region from hydroelectric power facilities at the Hoover, Parker, and Davis dams. Western-DSW is one of four regions carrying out this mission for WAPA, serving customers in Arizona, Southern California, and Southern Nevada. It sells more than ten billion kilowatt hours of hydroelectric power to approximately seventy municipalities, cooperatives, federal and state agencies, and irrigation districts. Western-DSW also operates and maintains more than forty substations and 3,100 miles of transmission lines.
In the FERC Order Approving Stipulation and Consent Agreement, the Commission notes that Western-DSW violated four Requirements of three Reliability Standards in the Transmission Operations (TOP) and Voltage and Reactive Control (VAR) categories. These groups of standards cover the responsibilities and decision making authority for reliable operations and maintenance of Bulk Power system facilities within voltage and reactive power limits to protect equipment and ensure reliable operation of the interconnection. In particular, FERC Enforcement staff and NERC found that Western-DSW failed to operate its portion of the transmission system within voltage system operating limits and to maintain sufficient situational awareness prior to and during the event, undermining reliable operation of the Bulk Power System.
Western-DSW stipulated to the facts in the agreement and agreed to implement compliance measures necessary to mitigate the violations and improve overall reliability, including improving its models, better coordination with neighboring entities, and improving its situational awareness by adding a real-time monitoring tool that analyzes and alerts operators to potential contingencies. Western-DSW also agreed to make semi-annual compliance reports to Enforcement staff and NERC for at least one year. Notably, the stipulation does not require Western-DSW to pay a civil penalty.
FERC's general investigative report on the incident identified six potential targets for enforcement action. With cases settled against Western-DSW, SoCal Edison, the Imperial Irrigation District, and Arizona Public Service, only the California Independent System Operator and the Western Electricity Coordinating Council Reliability Coordinator have not yet been parties to a stipulation and consent agreement.
On September 8, 2011, the Southwest's electric grid was hit with a widespread power outage that left over 5 million people in California, Arizona and Baja California, Mexico, without power for up to 12 hours. Previous investigations by the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC) found that the blackout occurred when Arizona Public Service Company's 500-kilovolt Hassayampa-N.Gila transmission line tripped out of service, overloading the remaining elements of the regional grid.
Earlier this year, FERC approved stipulations and consent agreements among its Office of Enforcement, NERC, and three public utilities. Arizona Public Service agreed to pay $3.25 million in civil penalties, California's Imperial Irrigation District agreed to a $12 million settlement, and Southern California Edison Company agreed to pay a $650,000 civil penalty and undertake additional compliance actions.
FERC approved a fourth settlement on November 24, 2014, with the Western Area Power Administration – Desert Southwest Region (Western-DSW). One of four power marketing administrations within the United States Department of Energy, the Western Area Power Administration (WAPA) markets and transmits electricity to a fifteen-state region from hydroelectric power facilities at the Hoover, Parker, and Davis dams. Western-DSW is one of four regions carrying out this mission for WAPA, serving customers in Arizona, Southern California, and Southern Nevada. It sells more than ten billion kilowatt hours of hydroelectric power to approximately seventy municipalities, cooperatives, federal and state agencies, and irrigation districts. Western-DSW also operates and maintains more than forty substations and 3,100 miles of transmission lines.
In the FERC Order Approving Stipulation and Consent Agreement, the Commission notes that Western-DSW violated four Requirements of three Reliability Standards in the Transmission Operations (TOP) and Voltage and Reactive Control (VAR) categories. These groups of standards cover the responsibilities and decision making authority for reliable operations and maintenance of Bulk Power system facilities within voltage and reactive power limits to protect equipment and ensure reliable operation of the interconnection. In particular, FERC Enforcement staff and NERC found that Western-DSW failed to operate its portion of the transmission system within voltage system operating limits and to maintain sufficient situational awareness prior to and during the event, undermining reliable operation of the Bulk Power System.
Western-DSW stipulated to the facts in the agreement and agreed to implement compliance measures necessary to mitigate the violations and improve overall reliability, including improving its models, better coordination with neighboring entities, and improving its situational awareness by adding a real-time monitoring tool that analyzes and alerts operators to potential contingencies. Western-DSW also agreed to make semi-annual compliance reports to Enforcement staff and NERC for at least one year. Notably, the stipulation does not require Western-DSW to pay a civil penalty.
FERC's general investigative report on the incident identified six potential targets for enforcement action. With cases settled against Western-DSW, SoCal Edison, the Imperial Irrigation District, and Arizona Public Service, only the California Independent System Operator and the Western Electricity Coordinating Council Reliability Coordinator have not yet been parties to a stipulation and consent agreement.
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