Vail Resorts, Inc. -- the largest ski and mountain resort operator in the world -- has announced a comprehensive sustainability commitment that calls for "zero net emissions by 2030, zero waste to landfill by 2030 and zero net operating impact to forests and habitat." According to the company, Vail Resorts' "Epic Promise for a Zero Footprint" will give resort guests and employees "the opportunity to enjoy the natural environment and resources without leaving an impact."
Vail Resorts' subsidiaries operate 11 mountain resorts and three urban ski areas, including Vail, Beaver Creek, Breckenridge and Keystone in Colorado; Park City in Utah; Heavenly, Northstar and Kirkwood in the Lake Tahoe area of California and Nevada; Whistler Blackcomb in British Columbia, Canada; Perisher in Australia; Stowe in Vermont; Wilmot Mountain in Wisconsin; Afton Alps in
Minnesota and Mt. Brighton in Michigan. The company also owns and operates hotels as well as a real estate planning and development subsidiary.
In a July 25, 2017, press release, Vail Resorts announced its "Epic Promise for a Zero Footprint" sustainability commitment. Pointing to Whistler Blackcomb's environmental commitment as inspiration, Vail Resorts announced its intent "to go beyond setting a partial emissions reduction target by executing on a more expansive and ambitious plan."
With respect to net zero emissions from operations by 2030, the Vail Resorts plan calls for continued reduction of the company's electricity and gas use by improving operating practices and investing $25 million
in innovative, energy-saving projects, such as low-energy snowmaking
equipment, green building design and construction, and more efficient
grooming practices and equipment. Among other measures, it envisions purchasing 100 percent renewable energy equivalent to Vail Resorts'
total electrical energy use and working with utilities and local,
regional and national governments to bring more renewable energy to the
grids where the company operates its resorts. As an interim goal, the plan states the company's intent to achieve a 50 percent reduction in its net emissions by 2025, based on 2016 levels.
Other 2030 goals set in the Vail Resorts plan include "zero waste to landfill" (by diverting
100 percent of the waste from its operations to more sustainable
pathways) and "zero net operating impact to forests and habitat" (by measures including mitigation, tree planting and forest restoration, and minimizing or eliminating the impact of any future resort development).
Energy powers society; society's choices shape energy policy. A blog about our energy resources and the choices they present for society.
Showing posts with label environmental. Show all posts
Showing posts with label environmental. Show all posts
Coal power plants retiring in 2015
Thursday, May 21, 2015
The U.S. portfolio of electric power plants will continue to shift in 2015, according to a federal assessment projecting that nearly 16 gigawatts (GW) of generating capacity will retire in 2015. Most of the capacity to be retired this year is coal-fired generation. This continues a multi-year trend away from coal, and toward natural gas and renewable resources.
According to the U.S. Energy Information Administration, nearly 16 GW of generating capacity is expected to retire in 2015. Of this, 81% (12.9 GW) is coal-fired generation. Generator retirements are heavily composed of coal-fired generation, split between bituminous coal (10.2 GW) and subbituminous coal (2.8 GW). Most of this retiring coal capacity is found in the Appalachian region, with slightly more than 8 GW combined in Ohio, West Virginia, Kentucky, Virginia, and Indiana.
New environmental regulations and struggles to remain cost-competitive explain most of these retirements. This year, the Environmental Protection Agency's Mercury and Air Toxics Standards (MATS) take effect. MATS requires existing large coal- and oil-fired electric generators to meet stricter emissions standards by retrofitting the units with new emissions control technologies. While some units have been granted extensions to operate through April 2016, some power plant operators are choosing to retire units instead of making cost-prohibitive investments in pollution control.
Most of the coal-fired units slated for retirement are smaller and operate at a lower capacity factor than average coal-fired units in the United States. According to EIA, the to-be-retired units have an average summer nameplate capacity of 158 MW, just 60% as big as the 261 MW average for other coal-fired units. In 2014, the average capacity factor for all coal units was 61%, but the subset of coal units retiring in 2015 had an average capacity factor of just 36%. The relatively small size and low capacity factor of these power plants make it harder for them to compete economically against other generation sources. This competition is especially difficult if sufficient natural gas-fired generating capacity is available, as the cost of natural gas has fallen to levels not seen since 2012.
The coal capacity retiring in 2015 accounted for 1.6% of total U.S. generation during 2014. At the same time, electric generating companies expect to add more than 20 GW of utility-scale generating capacity to the power grid. This new capacity is dominated by wind (9.8 GW), natural gas (6.3 GW), and solar (2.2 GW), which together compose 91% of expected new capacity in 2015.
According to the U.S. Energy Information Administration, nearly 16 GW of generating capacity is expected to retire in 2015. Of this, 81% (12.9 GW) is coal-fired generation. Generator retirements are heavily composed of coal-fired generation, split between bituminous coal (10.2 GW) and subbituminous coal (2.8 GW). Most of this retiring coal capacity is found in the Appalachian region, with slightly more than 8 GW combined in Ohio, West Virginia, Kentucky, Virginia, and Indiana.
New environmental regulations and struggles to remain cost-competitive explain most of these retirements. This year, the Environmental Protection Agency's Mercury and Air Toxics Standards (MATS) take effect. MATS requires existing large coal- and oil-fired electric generators to meet stricter emissions standards by retrofitting the units with new emissions control technologies. While some units have been granted extensions to operate through April 2016, some power plant operators are choosing to retire units instead of making cost-prohibitive investments in pollution control.
Most of the coal-fired units slated for retirement are smaller and operate at a lower capacity factor than average coal-fired units in the United States. According to EIA, the to-be-retired units have an average summer nameplate capacity of 158 MW, just 60% as big as the 261 MW average for other coal-fired units. In 2014, the average capacity factor for all coal units was 61%, but the subset of coal units retiring in 2015 had an average capacity factor of just 36%. The relatively small size and low capacity factor of these power plants make it harder for them to compete economically against other generation sources. This competition is especially difficult if sufficient natural gas-fired generating capacity is available, as the cost of natural gas has fallen to levels not seen since 2012.
The coal capacity retiring in 2015 accounted for 1.6% of total U.S. generation during 2014. At the same time, electric generating companies expect to add more than 20 GW of utility-scale generating capacity to the power grid. This new capacity is dominated by wind (9.8 GW), natural gas (6.3 GW), and solar (2.2 GW), which together compose 91% of expected new capacity in 2015.
Constitution Pipeline environmental impact statement
Monday, October 27, 2014
A 124-mile natural gas transmission pipeline proposed from Pennsylvania to New York has received its final environmental impact statement from federal regulators, finding that while the project would cause some adverse environmental impacts but that mitigation would reduce them to less-than-significant levels.
The proposed Constitution Pipeline is designed connect natural gas supplies in northern Pennsylvania with major northeastern markets. Proposed by Constitution Pipeline Company, LLC, a group whose investors include Williams, Cabot Oil & Gas, Piedmont Natural Gas, and WGL Holdings, the 30-inch underground pipeline would have a design capacity of 650,000 dekatherms of natural gas per day. Constitution has pitched the project as a response to natural gas market demands in the New York and the New England areas, and interest from natural gas shippers that require transportation capacity from Susquehanna County, Pennsylvania to the existing Tennessee Gas Pipeline Company LLC (TGP) and Iroquois systems in Schoharie County, New York.
Developing an interstate natural gas pipeline requires a series of federal, state, and local approvals. Under the federal Natural Gas Act, interstate pipelines must obtain a Certificate of Public Convenience and Necessity from the Federal Energy Regulatory Commission prior to construction. Constitution started the pre-filing process in April 2012, and filed its certificate application under Section 7(c) of the Natural Gas Act with the FERC on June 13, 2013.
Under the National Environmental Policy Act, federal agencies must analyze and document the environmental effects of proposed federal actions such as issuing a certificate of public convenience and necessity for an interstate pipeline. For the Constitution Pipeline and its associated Wright Interconnect compressor transfer station, FERC staff evaluated the projects' impacts on natural resources including geology, soils, groundwater, surface water, wetlands, vegetation, wildlife, fisheries, special status species, land use, visual resources, socioeconomics, cultural resources, air quality, noise, and safety. Staff considered the projects' cumulative impacts along with other past, present, and reasonably foreseeable actions in the projects’ area. Staff also evaluated over 400 alternatives to the projects, including the "no-action" alternative, system alternatives, major and minor route alternatives, and minor route variations. In a collaborative effort, FERC staff also collected input from cooperating agencies including the U.S. Environmental Protection Agency, the U.S. Army Corps of Engineers, the Federal Highway Administration, and the New York State Department of Agriculture and Markets.
FERC staff issued their Final Environmental Impact Statement, or EIS, for the Constitution Pipeline and Wright Interconnect projects on October 24, 2014. In that document, staff concluded that construction and operation of the Constitution Pipeline and the associated Wright Interconnect would result in some adverse environmental impacts, but these impacts would be reduced to less-than-significant levels with the implementation of mitigation measures proposed by the company and additional measures proposed by FERC. These mitigation measures include implementing plans for upland erosion control, revegetation, and maintenance plan, protecting wetlands and waterbodies, spill plans for oil and hazardous materials, an organic farm protection plan, and a karst mitigation plan. FERC staff also proposed an environmental inspection and mitigation monitoring program to ensure compliance with all mitigation measures that become conditions of the FERC authorizations and other approvals.
For the Constitution Pipeline project, the EIS represents a relatively favorable recommendation by FERC staff to the Commissioners. The ultimate decision whether FERC will issue the project a certificate rests solely with the Commissioners themselves, but regulators typically rely heavily on their technical staff's evaluation of environmental impacts. Likewise, while FERC's final EIS is not necessarily binding on cooperating agencies, they may adopt it if it satisfies their own statutory mandates for environmental reviews.
While the applicants had initially proposed to start construction in 2014, FERC staff acknowledged that "the proposed dates for the start of construction are no longer feasible." Constitution now proposes to start construction in February of 2015 and continue through the end of 2015, pending receipt of all applicable federal authorizations. The Federal Energy Regulatory Commission may rule on the projects' certificate applications as early as late November this year.
The proposed Constitution Pipeline is designed connect natural gas supplies in northern Pennsylvania with major northeastern markets. Proposed by Constitution Pipeline Company, LLC, a group whose investors include Williams, Cabot Oil & Gas, Piedmont Natural Gas, and WGL Holdings, the 30-inch underground pipeline would have a design capacity of 650,000 dekatherms of natural gas per day. Constitution has pitched the project as a response to natural gas market demands in the New York and the New England areas, and interest from natural gas shippers that require transportation capacity from Susquehanna County, Pennsylvania to the existing Tennessee Gas Pipeline Company LLC (TGP) and Iroquois systems in Schoharie County, New York.
Developing an interstate natural gas pipeline requires a series of federal, state, and local approvals. Under the federal Natural Gas Act, interstate pipelines must obtain a Certificate of Public Convenience and Necessity from the Federal Energy Regulatory Commission prior to construction. Constitution started the pre-filing process in April 2012, and filed its certificate application under Section 7(c) of the Natural Gas Act with the FERC on June 13, 2013.
Under the National Environmental Policy Act, federal agencies must analyze and document the environmental effects of proposed federal actions such as issuing a certificate of public convenience and necessity for an interstate pipeline. For the Constitution Pipeline and its associated Wright Interconnect compressor transfer station, FERC staff evaluated the projects' impacts on natural resources including geology, soils, groundwater, surface water, wetlands, vegetation, wildlife, fisheries, special status species, land use, visual resources, socioeconomics, cultural resources, air quality, noise, and safety. Staff considered the projects' cumulative impacts along with other past, present, and reasonably foreseeable actions in the projects’ area. Staff also evaluated over 400 alternatives to the projects, including the "no-action" alternative, system alternatives, major and minor route alternatives, and minor route variations. In a collaborative effort, FERC staff also collected input from cooperating agencies including the U.S. Environmental Protection Agency, the U.S. Army Corps of Engineers, the Federal Highway Administration, and the New York State Department of Agriculture and Markets.
FERC staff issued their Final Environmental Impact Statement, or EIS, for the Constitution Pipeline and Wright Interconnect projects on October 24, 2014. In that document, staff concluded that construction and operation of the Constitution Pipeline and the associated Wright Interconnect would result in some adverse environmental impacts, but these impacts would be reduced to less-than-significant levels with the implementation of mitigation measures proposed by the company and additional measures proposed by FERC. These mitigation measures include implementing plans for upland erosion control, revegetation, and maintenance plan, protecting wetlands and waterbodies, spill plans for oil and hazardous materials, an organic farm protection plan, and a karst mitigation plan. FERC staff also proposed an environmental inspection and mitigation monitoring program to ensure compliance with all mitigation measures that become conditions of the FERC authorizations and other approvals.
For the Constitution Pipeline project, the EIS represents a relatively favorable recommendation by FERC staff to the Commissioners. The ultimate decision whether FERC will issue the project a certificate rests solely with the Commissioners themselves, but regulators typically rely heavily on their technical staff's evaluation of environmental impacts. Likewise, while FERC's final EIS is not necessarily binding on cooperating agencies, they may adopt it if it satisfies their own statutory mandates for environmental reviews.
While the applicants had initially proposed to start construction in 2014, FERC staff acknowledged that "the proposed dates for the start of construction are no longer feasible." Constitution now proposes to start construction in February of 2015 and continue through the end of 2015, pending receipt of all applicable federal authorizations. The Federal Energy Regulatory Commission may rule on the projects' certificate applications as early as late November this year.
Connecticut coal-fired power plant air permit issued
Thursday, November 8, 2012
The U.S. Environmental Protection Agency has approved a five-year permit for the last coal-fired power plant operating in Connecticut. The plant, PSEG Power LLC's Bridgeport Harbor Generating Station, can generate 529 megawatts of energy by combusting coal and oil.
While the plant has operated since 1961, its permit renewal was questioned for economic and environmental reasons. Across the nation, operators of coal plants have announced plans to close or convert plants to other fuels such as natural gas and biomass. Between the low cost of natural gas - projected to stay low for the foreseeable future - and tighter environmental regulations affecting the electric utility sector, many older and smaller coal-fired power plants are no longer economic to operate. Additionally, environmental activists have targeted coal-burning plants as polluters, and had argued against the Bridgeport Harbor plant's new permit.
Under the federal Clean Air Act, existing major stationary sources (i.e. those capable of emitting 100 tons per year or more of any criteria air pollutant) must obtain a so-called Title V permit every five years. Generally, Title V permits are issued by the state or local air pollution control agency, but EPA has 45 days to review any proposed permit and request changes. In September, Connecticut recommended that EPA renew Bridgeport Harbor's permit. After the 45-day review process, EPA approved the permit's issuance.
What does the Bridgeport Harbor air permit mean? Most directly, it means PSEG may continue to operate its plant for another five years -- if it wants to. According to the Connecticut Post, by mid-summer the plant had only operated 24 days this year. The Bridgeport Harbor plant can provide both baseload power and peaking power needed to satisfy peak consumer demand, but generally the fewer days an asset operates, the harder it is to recover the cost of ownership and operations.
Moreover, coal-fired power plants are declining in the U.S. This is particularly true in New England, a region far from coal mining. Will PSEG hold onto the Bridgeport Harbor station and seek another Title V permit in 2017? For how long will the plant continue to burn coal? Will PSEG or another owner seek to repurpose the plant to burn other fuels?
While the plant has operated since 1961, its permit renewal was questioned for economic and environmental reasons. Across the nation, operators of coal plants have announced plans to close or convert plants to other fuels such as natural gas and biomass. Between the low cost of natural gas - projected to stay low for the foreseeable future - and tighter environmental regulations affecting the electric utility sector, many older and smaller coal-fired power plants are no longer economic to operate. Additionally, environmental activists have targeted coal-burning plants as polluters, and had argued against the Bridgeport Harbor plant's new permit.
Under the federal Clean Air Act, existing major stationary sources (i.e. those capable of emitting 100 tons per year or more of any criteria air pollutant) must obtain a so-called Title V permit every five years. Generally, Title V permits are issued by the state or local air pollution control agency, but EPA has 45 days to review any proposed permit and request changes. In September, Connecticut recommended that EPA renew Bridgeport Harbor's permit. After the 45-day review process, EPA approved the permit's issuance.
What does the Bridgeport Harbor air permit mean? Most directly, it means PSEG may continue to operate its plant for another five years -- if it wants to. According to the Connecticut Post, by mid-summer the plant had only operated 24 days this year. The Bridgeport Harbor plant can provide both baseload power and peaking power needed to satisfy peak consumer demand, but generally the fewer days an asset operates, the harder it is to recover the cost of ownership and operations.
Moreover, coal-fired power plants are declining in the U.S. This is particularly true in New England, a region far from coal mining. Will PSEG hold onto the Bridgeport Harbor station and seek another Title V permit in 2017? For how long will the plant continue to burn coal? Will PSEG or another owner seek to repurpose the plant to burn other fuels?
FERC seeks demand response standards
Monday, April 23, 2012
Demand response, an innovative strategy to ensuring the integrity of electric grids, is growing in popularity, prompting federal regulators to consider standardizing how demand response performance is measured.
Managing an electric grid entails ensuring a constant balance between electric generation and customer demand for electricity. As customer demand rises, grid operators have traditionally called on more and more generating units. In most markets, grid operators dispatch the lowest-cost units first to keep overall costs down. As a result, generating units needed to meet peak demand tend to be more expensive than baseload generation. Many peaking units also emit more pollutants per unit of energy than baseload units.
In a demand response program, customers can volunteer to be available to reduce their load during times of peak demand. When done right, this reduction in customer demand can play much the same role as dispatching additional generation, but at a lower cost in dollars and environmental impacts. Energy efficiency resources can also play a similar role.
The U.S. Congress and the Federal Energy Regulatory Commission have both recognized that demand response can be a decentralized, crowd-sourced alternative to peaking power plants. Utilities and regional transmission organizations across the nation are implementing demand response programs.
As demand response grows in importance, the question of how to measure a customer's performance is important. Different utilities and regions have adopted varying standards for how performance is measured. In an attempt to standardize the measurement and verification of demand response and energy efficiency resources participating in organized wholesale electricity markets, the FERC has proposed to amend its regulations to incorporate by reference the demand-side management and energy efficiency business practice standards of the North American Energy Standards Board. NAESB describes itself as "an industry forum for the development and promotion of standards which will lead to a seamless marketplace for wholesale and retail natural gas and electricity, as recognized by its customers, business community, participants, and regulatory entities."
In its Notice of Proposed Rulemaking (29-page PDF), Standards for Business Practices and Communication Protocols for Public Utilities, 139 FERC ¶ 61,041, FERC states its hope that "[a]doption of these standards is intended to improve the methods and procedures used to accurately measure demand response and energy efficiency resource performance" and that their adoption should help regional grid operators "properly credit demand response and energy efficiency resources for their services".
Managing an electric grid entails ensuring a constant balance between electric generation and customer demand for electricity. As customer demand rises, grid operators have traditionally called on more and more generating units. In most markets, grid operators dispatch the lowest-cost units first to keep overall costs down. As a result, generating units needed to meet peak demand tend to be more expensive than baseload generation. Many peaking units also emit more pollutants per unit of energy than baseload units.
In a demand response program, customers can volunteer to be available to reduce their load during times of peak demand. When done right, this reduction in customer demand can play much the same role as dispatching additional generation, but at a lower cost in dollars and environmental impacts. Energy efficiency resources can also play a similar role.
The U.S. Congress and the Federal Energy Regulatory Commission have both recognized that demand response can be a decentralized, crowd-sourced alternative to peaking power plants. Utilities and regional transmission organizations across the nation are implementing demand response programs.
As demand response grows in importance, the question of how to measure a customer's performance is important. Different utilities and regions have adopted varying standards for how performance is measured. In an attempt to standardize the measurement and verification of demand response and energy efficiency resources participating in organized wholesale electricity markets, the FERC has proposed to amend its regulations to incorporate by reference the demand-side management and energy efficiency business practice standards of the North American Energy Standards Board. NAESB describes itself as "an industry forum for the development and promotion of standards which will lead to a seamless marketplace for wholesale and retail natural gas and electricity, as recognized by its customers, business community, participants, and regulatory entities."
In its Notice of Proposed Rulemaking (29-page PDF), Standards for Business Practices and Communication Protocols for Public Utilities, 139 FERC ¶ 61,041, FERC states its hope that "[a]doption of these standards is intended to improve the methods and procedures used to accurately measure demand response and energy efficiency resource performance" and that their adoption should help regional grid operators "properly credit demand response and energy efficiency resources for their services".
"Small hydro" bill before Congress
Tuesday, March 6, 2012
Today the full U.S. House of Representatives considers a bill to create jobs and expand production of clean and renewable energy
by eliminating red tape on hydropower
projects in some small canals and pipelines. Sponsored by Rep. Scott Tipton of Colorado, H.R. 2842 is better known as the Bureau of Reclamation Small Conduit Hydropower Development and Rural Jobs Act of 2011.
The U.S. Bureau of Reclamation is a federal water management agency within the Department of the Interior. The Bureau has built over 600 dams and reservoirs in 17 Western states, and is the largest wholesaler of water in the country as well as the second largest producer of hydroelectric power in the western United States. The Bureau's 58 powerplants produce over 40 billion kilowatt hours annually, generating nearly a billion dollars in revenue for the federal government.
Beyond these traditional hydroelectric plants, the Bureau of Reclamation's infrastructure systems include canals and pipes holding water capable of producing hydroelectricity but which are not currently doing so. H.R. 2842 would streamline the regulatory process and reduce administrative costs for small hydropower development at existing Bureau of Reclamation canals and pipes. It would allow the Bureau to contract with water utilities or other small hydro developers to install up to 1.5 MW of electric generation equipment into an existing canal or conduit without triggering environmental review requirements under the National Environmental Policy Act (NEPA). It would also direct the Bureau to offer preference to water user organizations for the development of such projects under a federal lease of power privilege.
Some environmentalists have criticized the bill for relaxing environmental protections, although the House Natural Resources Committee found that the environmental impact of adding hydropower to these assets would be minimal to none because they existing man-made facilities on disturbed ground. If the bill passes, the Congressional Budget Office estimates that it could generate $5 million in additional federal revenues through increased hydropower production over the next decade.
Additionally, the bill could be seen as empowering small hydro projects, although its current scope is limited to projects using existing Bureau of Reclamation canals and conduits. Nevertheless, if the bill is enacted following today's House action, it could represent a tip toward renewed small hydro development in the U.S.
The U.S. Bureau of Reclamation is a federal water management agency within the Department of the Interior. The Bureau has built over 600 dams and reservoirs in 17 Western states, and is the largest wholesaler of water in the country as well as the second largest producer of hydroelectric power in the western United States. The Bureau's 58 powerplants produce over 40 billion kilowatt hours annually, generating nearly a billion dollars in revenue for the federal government.
Beyond these traditional hydroelectric plants, the Bureau of Reclamation's infrastructure systems include canals and pipes holding water capable of producing hydroelectricity but which are not currently doing so. H.R. 2842 would streamline the regulatory process and reduce administrative costs for small hydropower development at existing Bureau of Reclamation canals and pipes. It would allow the Bureau to contract with water utilities or other small hydro developers to install up to 1.5 MW of electric generation equipment into an existing canal or conduit without triggering environmental review requirements under the National Environmental Policy Act (NEPA). It would also direct the Bureau to offer preference to water user organizations for the development of such projects under a federal lease of power privilege.
Some environmentalists have criticized the bill for relaxing environmental protections, although the House Natural Resources Committee found that the environmental impact of adding hydropower to these assets would be minimal to none because they existing man-made facilities on disturbed ground. If the bill passes, the Congressional Budget Office estimates that it could generate $5 million in additional federal revenues through increased hydropower production over the next decade.
Additionally, the bill could be seen as empowering small hydro projects, although its current scope is limited to projects using existing Bureau of Reclamation canals and conduits. Nevertheless, if the bill is enacted following today's House action, it could represent a tip toward renewed small hydro development in the U.S.
Environmental regulations and grid reliability
Friday, January 6, 2012
As newly approved air emissions regulations for electric utility plants begin to take effect, federal and state regulators are forming plans to maintain the reliability of the electric grid while complying with the new regulations. Last month, the U.S. Environmental Protection Agency issued its final Mercury and Air Toxics Standards. The MATS rules require many utility generation units to use "maximum achievable control technology". For this reason, the rules are sometimes also known as "utility MACT".
Before the rules were finalized, the nation's electric reliability organization NERC expressed concerns that the new air emissions rules could increase the risk of power outages and stress on the grid by forcing the early retirement of a significant portion of the nation's coal-fired generating stations. In a battle of words that played out over November and December 2011, EPA and the U.S. Department of Energy countered by pointing out flaws in NERC's analysis. The federal agencies also noted that NERC seemed to assume that no one would plan for or manage grid reliability in the face of coal plant retirements. Nevertheless, the mercury standards and other anticipated rules are likely to affect the electric power industry to some degree.
Now that the air standards are final, federal and state energy regulators are planning a series of meetings to explore reliability issues provoked by these new and pending environmental rules for the power sector. Commissioners from the Federal Energy Regulatory Commission (FERC) and will meet with members of the National Association of Regulatory Utility Commissioners (NARUC), the national organization of state public utilities commissioners.
FERC and NARUC hope that the open forum will provoke a broad discussion of utility issues in the wake of the new environmental regulations. The first meeting of the FERC-NARUC Forum on Reliability and the Environment will take place in Washington on February 7, 2012.
Before the rules were finalized, the nation's electric reliability organization NERC expressed concerns that the new air emissions rules could increase the risk of power outages and stress on the grid by forcing the early retirement of a significant portion of the nation's coal-fired generating stations. In a battle of words that played out over November and December 2011, EPA and the U.S. Department of Energy countered by pointing out flaws in NERC's analysis. The federal agencies also noted that NERC seemed to assume that no one would plan for or manage grid reliability in the face of coal plant retirements. Nevertheless, the mercury standards and other anticipated rules are likely to affect the electric power industry to some degree.
Now that the air standards are final, federal and state energy regulators are planning a series of meetings to explore reliability issues provoked by these new and pending environmental rules for the power sector. Commissioners from the Federal Energy Regulatory Commission (FERC) and will meet with members of the National Association of Regulatory Utility Commissioners (NARUC), the national organization of state public utilities commissioners.
FERC and NARUC hope that the open forum will provoke a broad discussion of utility issues in the wake of the new environmental regulations. The first meeting of the FERC-NARUC Forum on Reliability and the Environment will take place in Washington on February 7, 2012.
EPA regs and electric grid reliability
Wednesday, November 30, 2011
Debate is ongoing about the effect of new environmental regulations on the U.S. electric grid. Some worry that tighter environmental controls will force certain electric generators to shut down, driving up the cost of electricity or putting electric reliability at risk. Others believe that the grid's integrity can be maintained, and that the new regulations are necessary to protect human health and the environment.
Support for the concerned side of the equation comes from a recent report by the North American Electric Reliability Corporation. NERC is the nation's electric reliability organization, charged with ensuring the reliability of the North American bulk power system. In NERC's 2011 Long-Term Reliability Assessment (559 page PDF), NERC notes that recent and future environmental regulations may force the early retirement of a significant portion of the nation's coal-fired generating plants. These regulations include the recently-finalized Cross-State Air Pollution Rule, plus rules under development governing utility plants' water intakes and air emissions. According to NERC's report, EPA's new cooling water intake structures and mercury and air toxics standards rules "may significantly affect bulk power system reliability depending on the scope and timing of the rule implementation and the mechanisms in place to preserve reliability."
At the same time, others observe that NERC's report assumes multiple worst-case scenarios and ignored the health and environmental benefits of the rules. After reviewing a near-final draft of the NERC report, EPA itself wrote NERC a letter (4 page PDF), stating "it appears likely your report may contain ... faulty characterizations of our rules." EPA pointed to several flaws in NERC's analysis, including that NERC assumed generators would be forced to adopt the most expensive solutions immediately, rather than selecting the most cost-effective technologies for each facility. EPA noted that the bulk of threatened plant retirements suggested in NERC's report would come from the cooling water intake regulations -- regulations which are still under development. Finally, EPA pointed out that NERC's analysis appears to assume that no one tries to preserve grid reliability as the regulations begin to take effect, "an outcome that flies in the face of our 40 years of implementing the Clean Air Act and Clean Water Act." Given the positive impacts of the regulations -- with the Cross-State Air Pollution Rule alone projected to prevent 34,000 premature deaths and 400,000 cases of aggravated asthma per year -- EPA defended their value and refuted NERC's analysis.
Reliability of the grid is important, enough so that the Federal Energy Regulatory Commission convened a technical conference yesterday and today to discuss grid reliability and policy. While that proceeding may result in interim orders or changes to policy, it may take years for the environmental regulations to both take effect and to impact generating plants. At the same time, generators are keeping a close watch on federal environmental regulation as it develops.
Support for the concerned side of the equation comes from a recent report by the North American Electric Reliability Corporation. NERC is the nation's electric reliability organization, charged with ensuring the reliability of the North American bulk power system. In NERC's 2011 Long-Term Reliability Assessment (559 page PDF), NERC notes that recent and future environmental regulations may force the early retirement of a significant portion of the nation's coal-fired generating plants. These regulations include the recently-finalized Cross-State Air Pollution Rule, plus rules under development governing utility plants' water intakes and air emissions. According to NERC's report, EPA's new cooling water intake structures and mercury and air toxics standards rules "may significantly affect bulk power system reliability depending on the scope and timing of the rule implementation and the mechanisms in place to preserve reliability."
At the same time, others observe that NERC's report assumes multiple worst-case scenarios and ignored the health and environmental benefits of the rules. After reviewing a near-final draft of the NERC report, EPA itself wrote NERC a letter (4 page PDF), stating "it appears likely your report may contain ... faulty characterizations of our rules." EPA pointed to several flaws in NERC's analysis, including that NERC assumed generators would be forced to adopt the most expensive solutions immediately, rather than selecting the most cost-effective technologies for each facility. EPA noted that the bulk of threatened plant retirements suggested in NERC's report would come from the cooling water intake regulations -- regulations which are still under development. Finally, EPA pointed out that NERC's analysis appears to assume that no one tries to preserve grid reliability as the regulations begin to take effect, "an outcome that flies in the face of our 40 years of implementing the Clean Air Act and Clean Water Act." Given the positive impacts of the regulations -- with the Cross-State Air Pollution Rule alone projected to prevent 34,000 premature deaths and 400,000 cases of aggravated asthma per year -- EPA defended their value and refuted NERC's analysis.
Reliability of the grid is important, enough so that the Federal Energy Regulatory Commission convened a technical conference yesterday and today to discuss grid reliability and policy. While that proceeding may result in interim orders or changes to policy, it may take years for the environmental regulations to both take effect and to impact generating plants. At the same time, generators are keeping a close watch on federal environmental regulation as it develops.
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