Setting up a significant expansion of New Hampshire's energy efficiency programming, utility regulators have approved the implementation of a $176 million three-year energy efficiency plan for 2018 through 2020 for the state’s gas and electric utilities.
In 2016, the New Hampshire Public Utilities Commission established an Energy Efficiency Resource Standard or EERS, a framework within which the Commission’s energy efficiency programs would be implemented effective January
1, 2018. A group of gas and electric utilities filed a proposed a three-year plan in September 2017, modified in December by a settlement supported by all parties to the case before the Commission.
On January 2, 2018, the New Hampshire Public Utilities Commission issued its Order No. 26,095, approving that settlement. The order approves a three-year plan which "significantly
expands the energy efficiency
(“EE”) programs
implemented for the past several years, known as the Core Programs, to meet the EERS goals
established in the 2016 EERS Order."
The plan presents residential and commercial & industrial (including municipal) energy efficiency programs for 2018, 2019, and 2020. Its total three-year
electric program budget is $146,115,000, and its total three-
year
gas program budget is $30,089,000, in each case allocated across customer sectors. These funds would come from charges on electricity and gas customers, plus proceeds from Regional Greenhouse Gas Initiative and regional Forward Capacity Market auctions. It also calls for annual plan updates, which are subject to review and approval by the Commission.
The Commission found that as modified by the settlement agreement, the three-year plan was consistent with the public interest and with state laws governing energy efficiency and resource planning.
Energy powers society; society's choices shape energy policy. A blog about our energy resources and the choices they present for society.
FERC ends DOE resilience rulemaking, opens new proceeding
Tuesday, January 9, 2018
U.S. energy regulators have terminated a fast-tracked proceeding opened last fall to consider rules proposed by the Department of Energy that would have compensated certain electric generating plants for reliability and resilience values; instead, the Federal Energy Regulatory Commission has opened a broader case to examine the resilience of the bulk power system.
On September 29, 2017, Secretary of Energy Rick Perry directed the Commission to consider a proposed rulemaking to ensure that "traditional baseload resources, such as coal and nuclear" are rewarded for their reliability and resilience attributes. As proposed, the rule would have required grid operators to set rates for compensation paid to certain "grid reliability and resiliency resources" with a 90-day fuel supply on site and capable of providing "essential energy and ancillary reliability services, including but not limited to voltage support, frequency services, operating reserves, and reactive power."
The request under Section 403 of the Department of Energy Organization Act bore an expedited timeline. The Commission solicited public comments on the proposed rulemaking, and Commission staff issued a series of questions to frame the discussion. Many comments expressed concerns that rapid changes to wholesale markets could have harmful or perverse effects, and prior to yesterday's most seated Commissioners had publicly expressed reservations.
On January 8, 2018, the Commission issued its Order Terminating Rulemaking Proceeding, Initiating New Proceeding, and Establishing Additional Procedures. In doing so, it recognized "that we must remain vigilant with respect to resilience challenges, because affordable and reliable electricity is vital to the country’s economic and national security." The order recites a history of the evolution of the electric power industry and the Commission's efforts to help ensure bulk power system resilience, including the adoption of NERC reliability standards, reforms to capacity markets and gas-electric coordination.
But the Commission found that neither the Department of Energy's proposed rulemaking nor the record in the case satisfied a key legal standard for Commission action under Section 206 of the Federal Power Act. Specifically, it concluded that the existing tariffs had not been demonstrated to be unjust, unreasonable, unduly discriminatory or preferential.
The Commission also noted potential problems with the proposed rule. For example, it said that allowing all eligible resources to receive a cost-of -service rate regardless of need or cost to the system had not been demonstrated to be just and reasonable, and that the proposed rule's on-site 90-day fuel supply requirement hadn't been shown not to be unduly discriminatory or preferential -- but that it would exclude some resources with resilience attributes.
At the same time, the order states, "The resilience of the bulk power system will remain a priority of this Commission." It continued, "Although the Proposed Rule failed to satisfy the fundamental legal requirements of section 206 of the FPA, the Proposed Rule and the record developed to date have shed additional light on resilience more generally and on the need for further examination by the Commission and market participants of the risks that the bulk power system faces and possible ways to address those risks in the changing electric markets." Noting "a variety of economic, environmental, and policy drivers that are changing the way electricity is procured and used," the Commission said these changes "present new opportunities and challenges regarding the reliability, affordability, and environmental profile of each region’s electric system."
To address these changes, the Commission initiated a new proceeding, Docket No. AD18- 7-000, to take additional steps to explore resilience issues in organized wholesale electricity markets. According to the order, the goal of this proceeding is: "(1) to develop a common understanding among the Commission, industry, and others of what resilience of the bulk power system means and requires; (2) to understand how each RTO and ISO assesses resilience in its geographic footprint; and (3) to use this information to evaluate whether additional Commission action regarding resilience is appropriate at this time."
The Commission directed six regional transmission organizations and independent system operators to respond within 60 days with comments on the definition of resilience, plus how they assess and mitigate threats to resilience. The Commission also solicited public comment within 30 days of the grid operators' due date.
On September 29, 2017, Secretary of Energy Rick Perry directed the Commission to consider a proposed rulemaking to ensure that "traditional baseload resources, such as coal and nuclear" are rewarded for their reliability and resilience attributes. As proposed, the rule would have required grid operators to set rates for compensation paid to certain "grid reliability and resiliency resources" with a 90-day fuel supply on site and capable of providing "essential energy and ancillary reliability services, including but not limited to voltage support, frequency services, operating reserves, and reactive power."
The request under Section 403 of the Department of Energy Organization Act bore an expedited timeline. The Commission solicited public comments on the proposed rulemaking, and Commission staff issued a series of questions to frame the discussion. Many comments expressed concerns that rapid changes to wholesale markets could have harmful or perverse effects, and prior to yesterday's most seated Commissioners had publicly expressed reservations.
On January 8, 2018, the Commission issued its Order Terminating Rulemaking Proceeding, Initiating New Proceeding, and Establishing Additional Procedures. In doing so, it recognized "that we must remain vigilant with respect to resilience challenges, because affordable and reliable electricity is vital to the country’s economic and national security." The order recites a history of the evolution of the electric power industry and the Commission's efforts to help ensure bulk power system resilience, including the adoption of NERC reliability standards, reforms to capacity markets and gas-electric coordination.
But the Commission found that neither the Department of Energy's proposed rulemaking nor the record in the case satisfied a key legal standard for Commission action under Section 206 of the Federal Power Act. Specifically, it concluded that the existing tariffs had not been demonstrated to be unjust, unreasonable, unduly discriminatory or preferential.
The Commission also noted potential problems with the proposed rule. For example, it said that allowing all eligible resources to receive a cost-of -service rate regardless of need or cost to the system had not been demonstrated to be just and reasonable, and that the proposed rule's on-site 90-day fuel supply requirement hadn't been shown not to be unduly discriminatory or preferential -- but that it would exclude some resources with resilience attributes.
At the same time, the order states, "The resilience of the bulk power system will remain a priority of this Commission." It continued, "Although the Proposed Rule failed to satisfy the fundamental legal requirements of section 206 of the FPA, the Proposed Rule and the record developed to date have shed additional light on resilience more generally and on the need for further examination by the Commission and market participants of the risks that the bulk power system faces and possible ways to address those risks in the changing electric markets." Noting "a variety of economic, environmental, and policy drivers that are changing the way electricity is procured and used," the Commission said these changes "present new opportunities and challenges regarding the reliability, affordability, and environmental profile of each region’s electric system."
To address these changes, the Commission initiated a new proceeding, Docket No. AD18- 7-000, to take additional steps to explore resilience issues in organized wholesale electricity markets. According to the order, the goal of this proceeding is: "(1) to develop a common understanding among the Commission, industry, and others of what resilience of the bulk power system means and requires; (2) to understand how each RTO and ISO assesses resilience in its geographic footprint; and (3) to use this information to evaluate whether additional Commission action regarding resilience is appropriate at this time."
The Commission directed six regional transmission organizations and independent system operators to respond within 60 days with comments on the definition of resilience, plus how they assess and mitigate threats to resilience. The Commission also solicited public comment within 30 days of the grid operators' due date.
FERC denies petition re Maine ownership of Forest City dam
Monday, January 8, 2018
A privately owned dam and reservoir spanning the U.S.-Canada border licensed as a hydropower development would continue to require licensing even if owned by a Maine state agency, according to federal regulators -- a ruling which could cast doubt on whether the state will acquire the facilities as has been conditionally authorized.
The Forest City Project on the East Branch of the St. Croix River currently operates under a license issued by the Federal Energy Regulatory Commission to Woodland Pulp LLC on November 23, 2015. While the project does not include electric generation facilities, the Commission has held that its project works are part of a complete unit of development or improvement which includes separate, unlicensed generation facilities.
In 2016, the licensee applied to the Commission to surrender its license and decommission the project because its operating costs as licensed would significantly exceed the downstream hydroelectric generation benefits. State-level interest in maintaining the existence of the impoundment led the Maine legislature to enact a resolve authorizing Maine Department of Inland Fisheries and Wildlife to assume ownership of the Forest City Dam if two conditions are satisfied: (1) the Commission finds that the Forest City Project will not require a license from the Commission if Maine DIFW owns the U.S. portion of the dam; and (2) Maine DIFW executes an agreement with Woodland Pulp that provides that Woodland Pulp and its successors will operate and maintain the Forest City Dam consistent with the manner in which the dam was operated in most recent 12 months, at the direction of the State, and at no cost to the State, for a period of 15 years.
After the Maine legislative resolve became law, the state agency and the licensee executed an operation and management agreement on July 27, 2017, and licensee petitioned the Federal Energy Regulatory Commission for a declaratory order declaring that if Woodland Pulp transfers ownership of the U.S. portion of the project to the Maine DIFW, DIFW will not require a license from the Commission to continue to operate and maintain the Forest City Dam.
But on December 21, 2017, the Commission denied the licensee's petition for a declaratory order to that effect. According to the Commission, this was the licensee's fourth petition seeking a ruling that the Forest City Project does not require licensing, with a fairly lengthy history of litigation. While the Commission noted its power to reexamine findings on jurisdiction where facts such as project ownership have changed, the Commission also noted that "ownership of project works by a state or state agency has no impact on a jurisdictional determination," and that "it is the potential effect on generation of an impoundment – and not its ownership or the operator’s specific intent – that guides our determination of whether a reservoir is necessary or appropriate to a given unit of development under FPA section 3(11) and operates for the purpose of developing electric power under FPA section 23(b)."
The Commission concluded, "we find that the Forest City Project would require licensing even if it was owned by Maine DIFW." In reaching this conclusion, it said, "We understand the concerns regarding Woodland Pulp’s proposed surrender of the Forest City Project and appreciate Woodland Pulp’s and the State of Maine’s effort to avoid adverse effects to local property owners and the local economy." But at the same time, "while we are sensitive to potential effects on local socioeconomics and the environment associated with Woodland Pulp’s proposed license surrender, we cannot consider these effects in determining whether we have jurisdiction over the project."
Given the Commission's ruling that transfering the project to a state agency would not affect its need for licensure, the 2017 state legislative resolve does not authorize the Maine Department of Inland Fisheries and Wildlife to assume ownership of the facility. The project's fate has yet to be determined; the licensee's petition to surrender the license remains pending before the Federal Energy Regulatory Commission.
The Forest City Project on the East Branch of the St. Croix River currently operates under a license issued by the Federal Energy Regulatory Commission to Woodland Pulp LLC on November 23, 2015. While the project does not include electric generation facilities, the Commission has held that its project works are part of a complete unit of development or improvement which includes separate, unlicensed generation facilities.
In 2016, the licensee applied to the Commission to surrender its license and decommission the project because its operating costs as licensed would significantly exceed the downstream hydroelectric generation benefits. State-level interest in maintaining the existence of the impoundment led the Maine legislature to enact a resolve authorizing Maine Department of Inland Fisheries and Wildlife to assume ownership of the Forest City Dam if two conditions are satisfied: (1) the Commission finds that the Forest City Project will not require a license from the Commission if Maine DIFW owns the U.S. portion of the dam; and (2) Maine DIFW executes an agreement with Woodland Pulp that provides that Woodland Pulp and its successors will operate and maintain the Forest City Dam consistent with the manner in which the dam was operated in most recent 12 months, at the direction of the State, and at no cost to the State, for a period of 15 years.
After the Maine legislative resolve became law, the state agency and the licensee executed an operation and management agreement on July 27, 2017, and licensee petitioned the Federal Energy Regulatory Commission for a declaratory order declaring that if Woodland Pulp transfers ownership of the U.S. portion of the project to the Maine DIFW, DIFW will not require a license from the Commission to continue to operate and maintain the Forest City Dam.
But on December 21, 2017, the Commission denied the licensee's petition for a declaratory order to that effect. According to the Commission, this was the licensee's fourth petition seeking a ruling that the Forest City Project does not require licensing, with a fairly lengthy history of litigation. While the Commission noted its power to reexamine findings on jurisdiction where facts such as project ownership have changed, the Commission also noted that "ownership of project works by a state or state agency has no impact on a jurisdictional determination," and that "it is the potential effect on generation of an impoundment – and not its ownership or the operator’s specific intent – that guides our determination of whether a reservoir is necessary or appropriate to a given unit of development under FPA section 3(11) and operates for the purpose of developing electric power under FPA section 23(b)."
The Commission concluded, "we find that the Forest City Project would require licensing even if it was owned by Maine DIFW." In reaching this conclusion, it said, "We understand the concerns regarding Woodland Pulp’s proposed surrender of the Forest City Project and appreciate Woodland Pulp’s and the State of Maine’s effort to avoid adverse effects to local property owners and the local economy." But at the same time, "while we are sensitive to potential effects on local socioeconomics and the environment associated with Woodland Pulp’s proposed license surrender, we cannot consider these effects in determining whether we have jurisdiction over the project."
Given the Commission's ruling that transfering the project to a state agency would not affect its need for licensure, the 2017 state legislative resolve does not authorize the Maine Department of Inland Fisheries and Wildlife to assume ownership of the facility. The project's fate has yet to be determined; the licensee's petition to surrender the license remains pending before the Federal Energy Regulatory Commission.
US proposes offshore oil and gas leasing expansion
Friday, January 5, 2018
The Trump administration is taking steps that could ultimately lead to a significant expansion of U.S. outer continental shelf acreage available for oil and gas leasing.
Under federal law, the U.S. Bureau of Ocean Energy Management is charged with administering site leasing for energy development on the outer continental shelf. The Outer Continental Shelf Lands Act requires the Secretary of the Interior, through BOEM, to develop a five-year national plan for oil and gas sales in federal waters. The law requires the Secretary to balance criteria including environmental impacts, energy needs and resources, and adverse effects on the coastal zone.
On January 4, 2018, Secretary of the Interior Ryan Zinke announced a new Draft Proposed Program. He described its release as "an early step in a multi-year process to develop a final National OCS Program for 2019-2024," and as consistent with an April 2017 Executive Order implementing an "America-First Offshore Energy Strategy."
The Draft Proposed Program includes 47 potential lease sales -- the largest number of lease sales ever proposed for the National OCS Program’s 5-year lease schedule. The plan includes 19 sales off Alaska, 7 in the Pacific Region, 12 in the Gulf of Mexico, and 9 in the Atlantic Region. Some of these areas have not seen leases sold in decades; for example, there have been no sales in the Atlantic since 1983 and there are no existing leases.
By contrast, the draft program includes 8 Atlantic lease sales between 2020 and 2024, covering federal waters offshore Maine, New Hampshire, Massachusetts, Connecticut, Rhode Island, New York, New Jersey, Delaware, Virginia, North Carolina, South Carolina, Georgia, and Florida. The Pacific leases would similarly be the first sold in that region since 1984.
According to the press release announcing the draft's release, "Inclusion of an area in the DPP is not a final indication that it will be included in the approved Program or offered in a lease sale, because many decision points still remain. By proposing to open these areas for consideration, the Secretary ensures that he will receive public input and analysis on all of the available OCS to better inform future decisions on the National OCS Program."
Even if an area is offered in a lease sale, it may not draw commercial interest; even if leased, an area might not actually be used for exploration and production. But the draft plan significantly expands the acreage that would be available for leasing -- according to the Secretary, "the current program puts 94 percent of the OCS off limits," while the proposed program "proposes to make over 90 percent of the total OCS acreage and more than 98 percent of undiscovered, technically recoverable oil and gas resources in federal offshore areas available to consider for future exploration and development."
BOEM has solicited public comment on the draft plan, which will inform several further rounds of proposals and comment, before a Proposed Final Program (PFP) is considered. In the meantime, until a new program is finalized and adopted, the present 2017-2022 Five Year Program remains in effect.
Under federal law, the U.S. Bureau of Ocean Energy Management is charged with administering site leasing for energy development on the outer continental shelf. The Outer Continental Shelf Lands Act requires the Secretary of the Interior, through BOEM, to develop a five-year national plan for oil and gas sales in federal waters. The law requires the Secretary to balance criteria including environmental impacts, energy needs and resources, and adverse effects on the coastal zone.
On January 4, 2018, Secretary of the Interior Ryan Zinke announced a new Draft Proposed Program. He described its release as "an early step in a multi-year process to develop a final National OCS Program for 2019-2024," and as consistent with an April 2017 Executive Order implementing an "America-First Offshore Energy Strategy."
The Draft Proposed Program includes 47 potential lease sales -- the largest number of lease sales ever proposed for the National OCS Program’s 5-year lease schedule. The plan includes 19 sales off Alaska, 7 in the Pacific Region, 12 in the Gulf of Mexico, and 9 in the Atlantic Region. Some of these areas have not seen leases sold in decades; for example, there have been no sales in the Atlantic since 1983 and there are no existing leases.
By contrast, the draft program includes 8 Atlantic lease sales between 2020 and 2024, covering federal waters offshore Maine, New Hampshire, Massachusetts, Connecticut, Rhode Island, New York, New Jersey, Delaware, Virginia, North Carolina, South Carolina, Georgia, and Florida. The Pacific leases would similarly be the first sold in that region since 1984.
According to the press release announcing the draft's release, "Inclusion of an area in the DPP is not a final indication that it will be included in the approved Program or offered in a lease sale, because many decision points still remain. By proposing to open these areas for consideration, the Secretary ensures that he will receive public input and analysis on all of the available OCS to better inform future decisions on the National OCS Program."
Even if an area is offered in a lease sale, it may not draw commercial interest; even if leased, an area might not actually be used for exploration and production. But the draft plan significantly expands the acreage that would be available for leasing -- according to the Secretary, "the current program puts 94 percent of the OCS off limits," while the proposed program "proposes to make over 90 percent of the total OCS acreage and more than 98 percent of undiscovered, technically recoverable oil and gas resources in federal offshore areas available to consider for future exploration and development."
BOEM has solicited public comment on the draft plan, which will inform several further rounds of proposals and comment, before a Proposed Final Program (PFP) is considered. In the meantime, until a new program is finalized and adopted, the present 2017-2022 Five Year Program remains in effect.
VT considers standard offer program changes
Thursday, January 4, 2018
Vermont utility regulators are reviewing the effectiveness of a program which awards contracts to renewable energy providers for the sale of power to Vermont’s electric distribution utilities. The Vermont Public Utility Commission says its review of the state's standard-offer program could lead to changes to how it selects projects.
Vermont law establishes a standard-offer program for reasons including providing “support and incentives to locate renewable energy plants of small and moderate size in a manner that is distributed across the State’s electric grid, including locating such plants in areas that will provide benefit to the operation and management of that grid through such means as reducing line losses and addressing transmission and distribution constraints." The statute empowers the Commission to select resources for participation in the standard-offer program, and to set prices paid to standard-offer resources, “with a goal of ensuring timely development at the lowest feasible cost."
Between 2013 and 2017, the Commission (under its former name Vermont Public Service Board) conducted annual requests for proposals for distributed energy projects through the standard-offer program. Under its current market-based approach established in 2013, the Commission sets minimum requirements for responsive proposals and selects the lowest-priced eligible proposals in several technology categories.
But as the Commission noted in its December 29, 2017 order opening a proceeding to review the effectiveness of the standard-offer program, "The field of distributed generation in Vermont has evolved significantly since 2013, when the Commission first announced many of the requirements of the standard-offer RFP process." For example, the order notes "significant deployment of net-metered photovoltaic systems and other photovoltaic systems." The Commission says, "some areas of the state have experienced such significant growth in photovoltaic systems that portions of the distribution grid cannot accommodate additional generation resources without investments in additional infrastructure."
In this context, the Commission opened a proceeding "to generally assess the effectiveness of the current RFP process and the criteria that the Commission uses to award standard-offer contracts." In its order opening the proceeding, the Commission articulated a series of questions addressing project selection criteria and possible integration of energy storage systems.
The Commission requested comments by February 2, 2018, and stated its expectation "that any improvements to the standard-offer program developed in this proceeding would not take effect until the 2019 RFP, or later."
Vermont law establishes a standard-offer program for reasons including providing “support and incentives to locate renewable energy plants of small and moderate size in a manner that is distributed across the State’s electric grid, including locating such plants in areas that will provide benefit to the operation and management of that grid through such means as reducing line losses and addressing transmission and distribution constraints." The statute empowers the Commission to select resources for participation in the standard-offer program, and to set prices paid to standard-offer resources, “with a goal of ensuring timely development at the lowest feasible cost."
Between 2013 and 2017, the Commission (under its former name Vermont Public Service Board) conducted annual requests for proposals for distributed energy projects through the standard-offer program. Under its current market-based approach established in 2013, the Commission sets minimum requirements for responsive proposals and selects the lowest-priced eligible proposals in several technology categories.
But as the Commission noted in its December 29, 2017 order opening a proceeding to review the effectiveness of the standard-offer program, "The field of distributed generation in Vermont has evolved significantly since 2013, when the Commission first announced many of the requirements of the standard-offer RFP process." For example, the order notes "significant deployment of net-metered photovoltaic systems and other photovoltaic systems." The Commission says, "some areas of the state have experienced such significant growth in photovoltaic systems that portions of the distribution grid cannot accommodate additional generation resources without investments in additional infrastructure."
In this context, the Commission opened a proceeding "to generally assess the effectiveness of the current RFP process and the criteria that the Commission uses to award standard-offer contracts." In its order opening the proceeding, the Commission articulated a series of questions addressing project selection criteria and possible integration of energy storage systems.
The Commission requested comments by February 2, 2018, and stated its expectation "that any improvements to the standard-offer program developed in this proceeding would not take effect until the 2019 RFP, or later."
FERC may change natural gas pipeline policy
Wednesday, January 3, 2018
U.S. energy regulators have signaled potential changes to a decades-old policy on the certification and pricing of new interstate natural gas pipelines.
The Federal Energy Regulatory Commission is charged by the Natural Gas Act with regulating the transmission and sale of natural gas for resale in interstate commerce, and approving the siting and abandonment of interstate natural gas pipelines and storage facilities.
In 1999, the Commission issued a Statement of Policy "to provide the industry with guidance as to how the Commission will evaluate proposals for certificating new construction." The FERC's 1999 policy statement came about at a time when the Commission faced both pressure "to authorize new pipeline capacity to meet an anticipated increase in the demand for natural gas" and "to act with caution to avoid unnecessary rights-of-way and the potential for overbuilding with the consequent effects on existing pipelines and their captive customers." In adopting the 1999 policy statement, the Commission said its publication was intended "to provide more certainty as to how the Commission will analyze certificate applications to balance these concerns."
But the Commission could soon change its policies. Last month, on December 21, 2017, Commission Chairman Kevin J. McIntyre issued a statement that the Commission will consider changes to the 1999 policy statement, "as part of a pledge he made during his Senate confirmation to take a fresh look at all aspects of the agency’s work."
According to that statement, while next steps will soon be announced and scheduled, "any review of this type would be thorough, and the Commission would invite the views of all stakeholders to ensure that FERC accurately and efficiently assesses the pipeline applications it receives."
The Federal Energy Regulatory Commission is charged by the Natural Gas Act with regulating the transmission and sale of natural gas for resale in interstate commerce, and approving the siting and abandonment of interstate natural gas pipelines and storage facilities.
In 1999, the Commission issued a Statement of Policy "to provide the industry with guidance as to how the Commission will evaluate proposals for certificating new construction." The FERC's 1999 policy statement came about at a time when the Commission faced both pressure "to authorize new pipeline capacity to meet an anticipated increase in the demand for natural gas" and "to act with caution to avoid unnecessary rights-of-way and the potential for overbuilding with the consequent effects on existing pipelines and their captive customers." In adopting the 1999 policy statement, the Commission said its publication was intended "to provide more certainty as to how the Commission will analyze certificate applications to balance these concerns."
But the Commission could soon change its policies. Last month, on December 21, 2017, Commission Chairman Kevin J. McIntyre issued a statement that the Commission will consider changes to the 1999 policy statement, "as part of a pledge he made during his Senate confirmation to take a fresh look at all aspects of the agency’s work."
According to that statement, while next steps will soon be announced and scheduled, "any review of this type would be thorough, and the Commission would invite the views of all stakeholders to ensure that FERC accurately and efficiently assesses the pipeline applications it receives."
New England's electric grid and winter 2017-18
Monday, December 11, 2017
New England's electricity grid is ready for reliable operations this winter, says the region's grid operator -- but special operating procedures might be required in the case of unexpected outages or fuel delivery constraints.
According to ISO New England Inc., the independent, not-for-profit regional transmission organization responsible for almost all of New England, supplies of electricity should be sufficient to meet regional consumer demand this winter. The grid operator projects a peak demand of 21,197 megawatts under normal winter temperatures (about 7 degrees Fahrenheit), or 21,895 megawatts of peak demand if extreme weather occurs (2 degrees F).
These projections are higher than last winter's actual peak demand (19,647 MW on December 15, 2016, during the hour from 5 to 6 p.m.), but lower than the region's all-time winter peak (22,818 MW, on January 15, 2004) or the record peak (28,180 MW on August 2, 2006). ISO-NE notes that total energy consumption and regional peak demand have remained flat in recent years "as a result of increased use of energy-efficiency measures and behind-the-meter solar photovoltaic (PV) systems."
The grid operator projects that it has commitments from enough power plants and demand-side resources to meet the forecast peak demand under both normal and extreme weather conditions. ISO-NE also points to its fifth seasonal Winter Reliability Program provides incentives for generators to stock up on oil or contract for liquefied natural gas, and also for demand-side resources committing to be available. As noted by the grid operator, the availability of generators with fuel has been a key reliability factor during recent cold winters, thanks in part to the past winter reliability programs. ISO-NE says its new capacity market performance incentive rules which take effect June 1, 2018 should eliminate the need for future special programs.
At the same time, the grid operator warns of its "continuing concern" over the availability of fuel for those power plants to generate electricity when needed. In a press release, ISO-NE noted, "The region’s natural gas delivery infrastructure has expanded only incrementally, while reliance on natural gas as the predominant fuel for both power generation and heating continues to grow." It observed that over 4,000 megawatts of natural-gas-fired generating capacity is at risk of not being able to get fuel when needed, due to natural gas pipeline constraints.
The grid operator also cites changes to the regional portfolio of generating resources, such as the May 2017 retirement of a 1,500 MW coal- and oil-fired power plant. According to ISO-NE, the Brayton Point power plant's closure "removed a facility with stored fuel that helped meet demand when natural gas plants were unavailable." The reliability benefits of stockpiled fuel and baseload power and related proposals are currently under examination by the Federal Energy Regulatory Commission.
The grid operator listed challenges that could affect power system operations such as "if demand is higher than projected, if the region loses a large generator, electricity imports are affected, or when natural gas pipeline constraints limit the fuel available to natural-gas-fired power plants," as well as the special operating procedures it would invoke in those circumstances.
According to ISO New England Inc., the independent, not-for-profit regional transmission organization responsible for almost all of New England, supplies of electricity should be sufficient to meet regional consumer demand this winter. The grid operator projects a peak demand of 21,197 megawatts under normal winter temperatures (about 7 degrees Fahrenheit), or 21,895 megawatts of peak demand if extreme weather occurs (2 degrees F).
These projections are higher than last winter's actual peak demand (19,647 MW on December 15, 2016, during the hour from 5 to 6 p.m.), but lower than the region's all-time winter peak (22,818 MW, on January 15, 2004) or the record peak (28,180 MW on August 2, 2006). ISO-NE notes that total energy consumption and regional peak demand have remained flat in recent years "as a result of increased use of energy-efficiency measures and behind-the-meter solar photovoltaic (PV) systems."
The grid operator projects that it has commitments from enough power plants and demand-side resources to meet the forecast peak demand under both normal and extreme weather conditions. ISO-NE also points to its fifth seasonal Winter Reliability Program provides incentives for generators to stock up on oil or contract for liquefied natural gas, and also for demand-side resources committing to be available. As noted by the grid operator, the availability of generators with fuel has been a key reliability factor during recent cold winters, thanks in part to the past winter reliability programs. ISO-NE says its new capacity market performance incentive rules which take effect June 1, 2018 should eliminate the need for future special programs.
At the same time, the grid operator warns of its "continuing concern" over the availability of fuel for those power plants to generate electricity when needed. In a press release, ISO-NE noted, "The region’s natural gas delivery infrastructure has expanded only incrementally, while reliance on natural gas as the predominant fuel for both power generation and heating continues to grow." It observed that over 4,000 megawatts of natural-gas-fired generating capacity is at risk of not being able to get fuel when needed, due to natural gas pipeline constraints.
The grid operator also cites changes to the regional portfolio of generating resources, such as the May 2017 retirement of a 1,500 MW coal- and oil-fired power plant. According to ISO-NE, the Brayton Point power plant's closure "removed a facility with stored fuel that helped meet demand when natural gas plants were unavailable." The reliability benefits of stockpiled fuel and baseload power and related proposals are currently under examination by the Federal Energy Regulatory Commission.
The grid operator listed challenges that could affect power system operations such as "if demand is higher than projected, if the region loses a large generator, electricity imports are affected, or when natural gas pipeline constraints limit the fuel available to natural-gas-fired power plants," as well as the special operating procedures it would invoke in those circumstances.
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