Maine utility regulators have opened an inquiry to examine issues for agricultural fairs, seasonal festivals, and other electricity customers that have seasonal, limited-duration, concentrated load profiles. The proceeding follows recently enacted legislation calling for support for agricultural fairs, who under utility rates pay significant charges for electricity year-round despite only consuming power seasonally.
During its 2019 session, the Maine state legislature enacted An Act to Address Electricity Costs of Agricultural Fairs, P.L. 2019, c. 169. Section 1 of the Act directs the Efficiency
Maine Trust to establish and administer an agricultural fair assistance program to
help agricultural fairs reduce electricity costs through the most cost-effective
opportunities available. The program is to be funded through a Public Utilities Commission
assessment on transmission and distribution utilities each year in an amount
equaling the total amount of demand charges paid by agricultural fairs during the prior year.
Section 2 of the Act directs the Commission to open a proceeding to examine
rate design and related issues for electricity customers that have seasonal, limited-duration,
concentrated load profiles, including but not limited to agricultural fairs,
seasonal festivals, and other similar entities. This section directs the Commission to examine options for alternative rate design, with particular attention to
electricity demand charges, and to identify electricity customers other than agricultural
fairs that may benefit from a program similar to that established in the Act. The
Commission is required to submit a report on these issues to the Energy, Utilities and
Technology Committee no later than December 1, 2019.
The Act was enacted as emergency legislation, so it applies to the upcoming 2019 agricultural fair season. On June 17, 2019, the Commission issued a notice of inquiry in a new proceeding, docketed as 2019-00136, and requested information and comments on three sets of issues. The issues include the design of the Agricultural Fair Assistance Program and its integration into other Trust programming, how much to assess to fund the program, and questions around rate design and the use of demand charges to recover costs from seasonal consumers. Comments are due by July 5, 2019.
Energy powers society; society's choices shape energy policy. A blog about our energy resources and the choices they present for society.
New Jersey rejoins RGGI carbon market
Tuesday, June 18, 2019
New Jersey has adopted regulations restricting the emission of carbon dioxide from electricity-generating power plants, allowing the state to rejoin the Regional Greenhouse Gas Initiative effective January 1, 2020.
The Regional Greenhouse Gas Initiative, or RGGI, is the first mandatory market-based program in the United States to reduce greenhouse gas emissions. RGGI was formed in 2007 by agreement of participating states. At present, nine states participate in RGGI: Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont. Each participating state has adopted regulations under its own state laws, based on a model rule which requires the electric power sector to cap and reduce CO2 emissions, and which creates markets for trading emission allowances. Originally, New Jersey was a participant in the RGGI program, but in 2011, Governor Chris Christie announced that New Jersey planned to cease its participation in the interstate compact.
On June 17. 2019, the New Jersey Department of Environmental Protection adopted rules implementing the state's participation in RGGI. The same day, the regional organization RGGI Inc. issued a public statement finding that New Jersey's final rule is consistent with the RGGI Model Rule and with existing state regulations, and that New Jersey's starting carbon dioxide allowance budget and emissions reduction trajectory demonstrate comparable stringency with the existing RGGI program. As a result, the RGGI states welcome New Jersey as a participant starting January 1, 2020.
Other states, including Virginia and Pennsylvania, have been considering joining RGGI, although legislation enacted in Virginia last month effectively blocks Virginia from joining RGGI for now.
The Regional Greenhouse Gas Initiative, or RGGI, is the first mandatory market-based program in the United States to reduce greenhouse gas emissions. RGGI was formed in 2007 by agreement of participating states. At present, nine states participate in RGGI: Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont. Each participating state has adopted regulations under its own state laws, based on a model rule which requires the electric power sector to cap and reduce CO2 emissions, and which creates markets for trading emission allowances. Originally, New Jersey was a participant in the RGGI program, but in 2011, Governor Chris Christie announced that New Jersey planned to cease its participation in the interstate compact.
On June 17. 2019, the New Jersey Department of Environmental Protection adopted rules implementing the state's participation in RGGI. The same day, the regional organization RGGI Inc. issued a public statement finding that New Jersey's final rule is consistent with the RGGI Model Rule and with existing state regulations, and that New Jersey's starting carbon dioxide allowance budget and emissions reduction trajectory demonstrate comparable stringency with the existing RGGI program. As a result, the RGGI states welcome New Jersey as a participant starting January 1, 2020.
Other states, including Virginia and Pennsylvania, have been considering joining RGGI, although legislation enacted in Virginia last month effectively blocks Virginia from joining RGGI for now.
Hydropower development in the wilderness
Monday, June 17, 2019
Can you build a hydroelectric project in a federally designated wilderness area? No, except where authorized by the President, according to federal law and a recent ruling by the Federal Energy Regulatory Commission.
Under federal law, the Federal Energy Regulatory Commission has jurisdiction over the construction, operation and maintenance of most hydropower projects in the U.S. On May 3, 2019, Premium Energy Holdings, LLC applied to the Commission for a preliminary permit to study the feasibility of the proposed 1,200- to 2,000-megawatt Haiwee Pumped Storage Project No. 14991, to be located in Inyo County, California. The proposed closed-loop pumped storage project would use water conveyed from the Los Angeles Aqueduct and would consist of two new reservoirs, a lower reservoir upstream of the existing North Haiwee Reservoir and an upper reservoir that would be located in either the Coso Range Wilderness (managed by the Bureau of Land Management) or South Sierra Wilderness (managed by the U.S. Forest Service).
But Section 4 of the federal Wilderness Act prohibits the establishment of power projects, transmission lines, and other facilities in designated wilderness areas, except where authorized by the President. In previous cases, the Commission has said that Section 4 of the Wilderness Act does not prohibit the Commission from issuing a preliminary permit for a proposed project -- but that the Commission's policy is to deny preliminary permit applications “where licensing of the project to be studied is clearly statutorily precluded, because no purpose would be served by issuing a permit for a proposed development that could not be licensed”, such as in a designated wilderness area.
Based on this precedent, because the proposed project would be located within a designated wilderness area, on June 13, 2019, the Commission issued an order denying Premium Energy's application for a preliminary permit for the Haiwee Pumped Storage Project.
Under federal law, the Federal Energy Regulatory Commission has jurisdiction over the construction, operation and maintenance of most hydropower projects in the U.S. On May 3, 2019, Premium Energy Holdings, LLC applied to the Commission for a preliminary permit to study the feasibility of the proposed 1,200- to 2,000-megawatt Haiwee Pumped Storage Project No. 14991, to be located in Inyo County, California. The proposed closed-loop pumped storage project would use water conveyed from the Los Angeles Aqueduct and would consist of two new reservoirs, a lower reservoir upstream of the existing North Haiwee Reservoir and an upper reservoir that would be located in either the Coso Range Wilderness (managed by the Bureau of Land Management) or South Sierra Wilderness (managed by the U.S. Forest Service).
But Section 4 of the federal Wilderness Act prohibits the establishment of power projects, transmission lines, and other facilities in designated wilderness areas, except where authorized by the President. In previous cases, the Commission has said that Section 4 of the Wilderness Act does not prohibit the Commission from issuing a preliminary permit for a proposed project -- but that the Commission's policy is to deny preliminary permit applications “where licensing of the project to be studied is clearly statutorily precluded, because no purpose would be served by issuing a permit for a proposed development that could not be licensed”, such as in a designated wilderness area.
Based on this precedent, because the proposed project would be located within a designated wilderness area, on June 13, 2019, the Commission issued an order denying Premium Energy's application for a preliminary permit for the Haiwee Pumped Storage Project.
FERC testifies to House subcommittee
Thursday, June 13, 2019
A panel of federal energy regulators testified yesterday before the House Committee on Energy and Commerce, Subcommittee on Energy. In written testimony and oral remarks, Federal Energy Regulatory Commission Chairman Neil Chatterjee and Commissioners Cheryl A. LaFleur, Richard Glick, and Bernard L. McNamee addressed the Commission's work and priorities.
Chairman Chatterjee's testimony focused on three issues: integrating storage resources into wholesale electric markets, protecting the bulk power system against cyber and physical threats, and reforming the Commission's regulations under the Public Utility Regulatory Policies Act of 1978 (PURPA).
On storage, Chairman Chatterjee expressed pride for the Commission's work to remove barriers to storage resources' participation in wholesale electric markets, including the Commission's Order No. 841 governing the capacity, energy, and ancillary services markets operated by regional transmission organizations (RTOs) and independent system operators (ISOs). He projected "an increase in the deployment of storage resources,which should result in greater reliability and lower prices for customers by enhancing competition."
On security, Chairman Chatterjee described America's critical infrastructure as "increasingly under attack by foreign adversaries." He noted that the Commission has approved reliability standards proposed by the North American Electric Reliability Corporation (NERC), which are now mandatory for covered entities, as well as voluntary efforts like outreach and interdepartmental coordination.
On PURPA, the Chair noted that the Commission's PURPA regulations were primarily adopted in the 1980s, but "the energy landscape that existed when PURPA was conceived more than four decades ago was fundamentally different from that of today." In light of changes including increased deployment of solar and wind power, open access to competitive markets, abundant natural gas, state renewable portfolio standards, and federal tax credits for renewable energy, the Chair said that the Commission has undertaken a review of its PURPA regulations, and that the Commission will "determine the best path forward on this issue."
Additional testimony by Commissioner LaFleur addressed "three major issues that are shaping the Commission’s work: (1) how individual states and regional electric markets select resources; (2) how those resources are compensated; and (3) how the Commission considers infrastructure decisions, particularly with respect to linear infrastructure like transmission lines and natural gas pipelines."
Commissioner Glick's testimony focused on the American electricity sector's "dramatic transformation to a less carbon-intensive, more distributed electric generation fleet that is increasingly customer-centric." He presented benefits of this transition, including reduced costs to consumers, and reduced greenhouse gas emissions and contributions to climate change. Noting that the Commission is not a "climate regulator," Commissioner Glick argued that "the potential climate consequences of the Commission's actions make it all the more important that the Commission faithfully execute its statutory mandates." He described the Commission's efforts to remove barriers to competition so that "new technologies and products can compete on a level playing field," while respecting "Congress’s decision to leave the states in charge of regulating the generation mix."
Commissioner McNamee's testimony addressed the Commission's roles in reviewing and approving applications to export liquefied natural gas (LNG) and for the construction and operation of interstate natural gas pipelines, in regulating interstate oil pipelines, and electricity markets.
Chairman Chatterjee's testimony focused on three issues: integrating storage resources into wholesale electric markets, protecting the bulk power system against cyber and physical threats, and reforming the Commission's regulations under the Public Utility Regulatory Policies Act of 1978 (PURPA).
On storage, Chairman Chatterjee expressed pride for the Commission's work to remove barriers to storage resources' participation in wholesale electric markets, including the Commission's Order No. 841 governing the capacity, energy, and ancillary services markets operated by regional transmission organizations (RTOs) and independent system operators (ISOs). He projected "an increase in the deployment of storage resources,which should result in greater reliability and lower prices for customers by enhancing competition."
On security, Chairman Chatterjee described America's critical infrastructure as "increasingly under attack by foreign adversaries." He noted that the Commission has approved reliability standards proposed by the North American Electric Reliability Corporation (NERC), which are now mandatory for covered entities, as well as voluntary efforts like outreach and interdepartmental coordination.
On PURPA, the Chair noted that the Commission's PURPA regulations were primarily adopted in the 1980s, but "the energy landscape that existed when PURPA was conceived more than four decades ago was fundamentally different from that of today." In light of changes including increased deployment of solar and wind power, open access to competitive markets, abundant natural gas, state renewable portfolio standards, and federal tax credits for renewable energy, the Chair said that the Commission has undertaken a review of its PURPA regulations, and that the Commission will "determine the best path forward on this issue."
Additional testimony by Commissioner LaFleur addressed "three major issues that are shaping the Commission’s work: (1) how individual states and regional electric markets select resources; (2) how those resources are compensated; and (3) how the Commission considers infrastructure decisions, particularly with respect to linear infrastructure like transmission lines and natural gas pipelines."
Commissioner Glick's testimony focused on the American electricity sector's "dramatic transformation to a less carbon-intensive, more distributed electric generation fleet that is increasingly customer-centric." He presented benefits of this transition, including reduced costs to consumers, and reduced greenhouse gas emissions and contributions to climate change. Noting that the Commission is not a "climate regulator," Commissioner Glick argued that "the potential climate consequences of the Commission's actions make it all the more important that the Commission faithfully execute its statutory mandates." He described the Commission's efforts to remove barriers to competition so that "new technologies and products can compete on a level playing field," while respecting "Congress’s decision to leave the states in charge of regulating the generation mix."
Commissioner McNamee's testimony addressed the Commission's roles in reviewing and approving applications to export liquefied natural gas (LNG) and for the construction and operation of interstate natural gas pipelines, in regulating interstate oil pipelines, and electricity markets.
Ludington pumped storage relicensed
Monday, June 10, 2019
U.S. hydropower regulators have issued a new license for a large pumped storage project in Michigan.
On June 6, 2019, the Federal Energy Regulatory Commission issued a new license to utilities Consumers Energy Company and DTE Electric Company to continue operation and maintenance of the Ludington Pumped Storage Hydroelectric Project. The project was originally licensed by the Federal Power Commission on July 30, 1969, for a fifty-year term running through June 30, 2019. The new license follows a 2017 settlement agreement and upgrades to the project facilities.
The Ludington project is located along the eastern shoreline of Lake Michigan; it can store energy by pumping water from the lake uphill into a project reservoir, and then generate up to 1,785 megawatts of energy by sending the stored water back downhill through turbine-generator units. Generation usually occurs during the day when demand is high, with the upper reservoir replenished at night when demand is low to meet the next day’s forecast load. The project can generate at maximum capacity for about 7 hours if the upper reservoir is full, and refilling the upper reservoir takes about 10 hours of pumping at maximum capacity.
Over a year, the project is expected to generate about 2,658,200 megawatt-hours, for sale into the MISO wholesale market. According to the Commission, the average annual project cost would be $215,075,715 or about $80.91/MWh. Since the average annual cost of alternative power would be $253,768,450, or about $95.47/MWh, the Commission asserts that the the project would produce power at a cost of $38,692,735 (or about $14.56/MWh) less than the cost of alternative power.
On June 6, 2019, the Federal Energy Regulatory Commission issued a new license to utilities Consumers Energy Company and DTE Electric Company to continue operation and maintenance of the Ludington Pumped Storage Hydroelectric Project. The project was originally licensed by the Federal Power Commission on July 30, 1969, for a fifty-year term running through June 30, 2019. The new license follows a 2017 settlement agreement and upgrades to the project facilities.
The Ludington project is located along the eastern shoreline of Lake Michigan; it can store energy by pumping water from the lake uphill into a project reservoir, and then generate up to 1,785 megawatts of energy by sending the stored water back downhill through turbine-generator units. Generation usually occurs during the day when demand is high, with the upper reservoir replenished at night when demand is low to meet the next day’s forecast load. The project can generate at maximum capacity for about 7 hours if the upper reservoir is full, and refilling the upper reservoir takes about 10 hours of pumping at maximum capacity.
Over a year, the project is expected to generate about 2,658,200 megawatt-hours, for sale into the MISO wholesale market. According to the Commission, the average annual project cost would be $215,075,715 or about $80.91/MWh. Since the average annual cost of alternative power would be $253,768,450, or about $95.47/MWh, the Commission asserts that the the project would produce power at a cost of $38,692,735 (or about $14.56/MWh) less than the cost of alternative power.
NH grid modernization investigation advances
Wednesday, June 5, 2019
As part of an ongoing investigation into the modernization of New Hampshire's electric grid, state utility regulators have established the next steps in a stakeholder process for developing the framework for electric distribution utility integrated distribution system plans.
In 2015, as required by state legislation, the New Hampshire Public Utilities Commission opened an investigation into electric grid modernization. The Commission defined grid modernization as "a broad topic that encompasses many elements, including replacement of aging infrastructure, outage management, the integration of distributed generation, and education of customers on how to manage their energy use for the benefit of the electric delivery system and to minimize energy costs."
After soliciting public comment on grid modernization, the Commission convened a working group of stakeholders, which resulted in a March 20, 2017 report titled Grid Modernization in New Hampshire. Following the working group's report, Commission staff spent two additional years investigating "workable frameworks for modernizing New Hampshire's electric distribution grid in a regulated industry."
Staff's work culminated in a January 31, 2019 report incorporating the policy recommendations of the working group report, and recommending a process and framework for utilities to develop integrated distribution system plans that would accommodate grid modernization. Following a technical session held on May 15, staff identified 11 issues that the stakeholders agreed merit proposals from the group:
In 2015, as required by state legislation, the New Hampshire Public Utilities Commission opened an investigation into electric grid modernization. The Commission defined grid modernization as "a broad topic that encompasses many elements, including replacement of aging infrastructure, outage management, the integration of distributed generation, and education of customers on how to manage their energy use for the benefit of the electric delivery system and to minimize energy costs."
After soliciting public comment on grid modernization, the Commission convened a working group of stakeholders, which resulted in a March 20, 2017 report titled Grid Modernization in New Hampshire. Following the working group's report, Commission staff spent two additional years investigating "workable frameworks for modernizing New Hampshire's electric distribution grid in a regulated industry."
Staff's work culminated in a January 31, 2019 report incorporating the policy recommendations of the working group report, and recommending a process and framework for utilities to develop integrated distribution system plans that would accommodate grid modernization. Following a technical session held on May 15, staff identified 11 issues that the stakeholders agreed merit proposals from the group:
- Cost Effectiveness Methodology
- Utility Cost Recovery
- Utility and Customer Data and Third Party Access
- Hosting Capacity/Locational Value Analysis/Interconnection
- Annual Reporting Requirements
- Rate Design Policy
- Strategic Electrification Policy
- Consolidated Billing/General Billing
- Consumer Advisory Council/Stakeholder Engagement
- Capital Budgeting Process
- LCIRP/IDP Integration
New England wholesale electricity market cost increased in 2018
Monday, June 3, 2019
New England's wholesale electricity markets operated at a total cost of $12.1 billion in 2018, an increase of about 32% over 2017, according to a recent report by the regional grid operator.
On May 23, 2019, the Internal Market Monitor for regional transmission organization ISO New England Inc. issued a report on the state of competition in the wholesale electricity markets operated by ISO-NE, covering the 2018 calendar year. According to that report, "Overall, the ISO New England capacity, energy, and ancillary service markets performed well and exhibited competitive outcomes in 2018." In general, the market monitor found that electricity prices reflect changes in underlying primary fuel prices and electricity demand, with relatively few periods of scarcity pricing.
However, the market monitor noted that the "total wholesale cost of electricity in 2018, at $12.1 billion, was considerably higher than 2017, increasing by 32%, or by $2.9 billion." The total cost equates to $98 per megawatt-hour of wholesale electricity demand, the highest over the past 5 years.
Nearly all of this overall increase -- 98% -- is accounted for by increased energy and capacity costs. Specifically, energy costs rose 34% (or $1.5 billion) to $6 billion, driven by higher natural gas power prices and higher power summer demand. Capacity costs rose by 61% (or $1.4 billion) to $3.6 billion, following higher capacity auction clearing prices in the wake of significant generator retirements.
Other major cost components include regional network load costs. These fees for the use of transmission facilities and other services reached $2.3 billion (an increase of about 2% relative to 2017), and reliability services added another $200 million in 2018.
On May 23, 2019, the Internal Market Monitor for regional transmission organization ISO New England Inc. issued a report on the state of competition in the wholesale electricity markets operated by ISO-NE, covering the 2018 calendar year. According to that report, "Overall, the ISO New England capacity, energy, and ancillary service markets performed well and exhibited competitive outcomes in 2018." In general, the market monitor found that electricity prices reflect changes in underlying primary fuel prices and electricity demand, with relatively few periods of scarcity pricing.
However, the market monitor noted that the "total wholesale cost of electricity in 2018, at $12.1 billion, was considerably higher than 2017, increasing by 32%, or by $2.9 billion." The total cost equates to $98 per megawatt-hour of wholesale electricity demand, the highest over the past 5 years.
Nearly all of this overall increase -- 98% -- is accounted for by increased energy and capacity costs. Specifically, energy costs rose 34% (or $1.5 billion) to $6 billion, driven by higher natural gas power prices and higher power summer demand. Capacity costs rose by 61% (or $1.4 billion) to $3.6 billion, following higher capacity auction clearing prices in the wake of significant generator retirements.
Other major cost components include regional network load costs. These fees for the use of transmission facilities and other services reached $2.3 billion (an increase of about 2% relative to 2017), and reliability services added another $200 million in 2018.
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