Two fish - the Atlantic sturgeon and the river herring - have been invoked to threaten the relicensing of a nuclear power plant in Plymouth, Massachusetts.
The Pilgrim Nuclear Power Station, the only operating commercial nuclear power plant in Massachusetts, is a 688 MW boiling water nuclear reactor owned by Entergy. Originally commissioned in 1972 by utility Boston Edison, its original license had the maximum 40-year term allowed under the Atomic Energy Act. That license is due to expire on June 8, 2012.
Entergy applied to the Nuclear Regulatory Commission for a license renewal, seeking the 20 year term allowed for relicensing. That case remains pending. Stakeholders have raised a number of concerns about the plant's relicensing. For example, Pilgrim Station is built around a General Electric Mark I reactor, the same type and design as used in the ill-fated Fukushima I Nuclear Power Plant; like Fukushima, the Plymouth plant is located on the coast. While the Pilgrim plant was designed to handle anticipated natural disasters, some believe the U.S. nuclear industry should be reevaluated in light of the Fukushima incident.
Now, U.S. Congressman Ed Markey of Massachusetts has sent a letter to NRC Chairman Gregory Jaczko requesting that the NRC not re-license Pilgrim Station "until all legal requirements stipulated by the Endangered Species Act (ESA) have been met." Specifically, Congressman Markey notes that two threatened fish species - the Atlantic sturgeon and the river herring - inhabit the waters near the plant but were not considered in a key assessment of threatened or endangered species likely to be affected by relicensure. His letter also notes that the National Marine Fisheries Service has not yet issued a written biological opinion proposing a plan to protect threatened or endangered species, nor has the NMFS issued a written concurrence with the NRC's biological opinion.
These species were known to live in the area in 2007 when the NRC wrote its biological assessment, but were not designated as threatened at that time. NMFS designated the Gulf of Maine distinct population segment of Atlantic Sturgeon as threatened in February 2012, and two species of river herring are currently candidates for listing.
Based on these newly designated statuses, Congressman Markey asked NRC not to re-license the Pilgrim project until after the development of a new biological assessment to include the sturgeon and herring, along with any conditions needed to protect those species.
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Maine tidal project wins pilot license
Tuesday, February 28, 2012
Federal regulators have issued a pilot project license to a tidal energy project proposed in Maine's Cobscook Bay. Yesterday, the Federal Energy Regulatory Commission issued an order granting Ocean Renewable Power Company Maine, LLC an 8-year pilot project license to construct, operate, and maintain its proposed Cobscook Bay Tidal Energy Project. As licensed, the 300 kilowatt project will be located in Cobscook Bay north and east of Seaward Neck and west of Shackford Head State Park in Eastport, Maine.
ORPC Maine applied for its pilot license in September 2011. Last month, FERC issued its Environmental Assessment of the Cobscook project, finding generally that licensing the hydrokinetic project with appropriate environmental protective measures would not constitute a major federal action that would significantly affect the quality of the human environment.
FERC granted the pilot project license just 179 days after the license application was filed, a relatively quick timeline for hydropower permitting made possible by FERC's hydrokinetic pilot project licensing process. As envisioned by FERC staff, the ideal pilot project should be (1) small, (2) short term, (3) located in non-sensitive areas based on the Commission’s review of the record, (4) removable and able to be shut down on short notice, (5) removed, with the site restored, before the end of the license term (unless a new license is granted), and (6) initiated by a draft application in a form sufficient to support environmental analysis. In ORPC Maine's case, FERC staff agreed that the Cobscook project was a good fit for pilot project licensing process after reviewing the developer's application.
FERC's order approving the license includes an analysis of the economic benefits of project power. As licensed, FERC found that the levelized annual cost of operating the project would be about $1,419,600, or $1.13/kWh. Based on an estimated average generation of 1,250,000 kWh as licensed, the annual value of alternative grid-based power would be $90,400, or 7.2 cents/kWh. Therefore, in the first year of operation the project power would cost $1,329,200, or $1.06/kWh, more than the cost of alternative power.
As FERC found, "The project has relatively high capital and operation and maintenance costs with respect to the amount of power produced. Although our analysis shows that the project as licensed herein would cost more to operate than our estimated cost of alternative power, it is the applicant who must decide whether to accept this license and any financial risk that entails. This project’s value, however, lies in its successful testing and demonstration of ORPC Maine’s turbine technology, and the project’s ability to raise the profile of, and advance, the emergent tidal energy industry."
ORPC Maine applied for its pilot license in September 2011. Last month, FERC issued its Environmental Assessment of the Cobscook project, finding generally that licensing the hydrokinetic project with appropriate environmental protective measures would not constitute a major federal action that would significantly affect the quality of the human environment.
FERC granted the pilot project license just 179 days after the license application was filed, a relatively quick timeline for hydropower permitting made possible by FERC's hydrokinetic pilot project licensing process. As envisioned by FERC staff, the ideal pilot project should be (1) small, (2) short term, (3) located in non-sensitive areas based on the Commission’s review of the record, (4) removable and able to be shut down on short notice, (5) removed, with the site restored, before the end of the license term (unless a new license is granted), and (6) initiated by a draft application in a form sufficient to support environmental analysis. In ORPC Maine's case, FERC staff agreed that the Cobscook project was a good fit for pilot project licensing process after reviewing the developer's application.
FERC's order approving the license includes an analysis of the economic benefits of project power. As licensed, FERC found that the levelized annual cost of operating the project would be about $1,419,600, or $1.13/kWh. Based on an estimated average generation of 1,250,000 kWh as licensed, the annual value of alternative grid-based power would be $90,400, or 7.2 cents/kWh. Therefore, in the first year of operation the project power would cost $1,329,200, or $1.06/kWh, more than the cost of alternative power.
As FERC found, "The project has relatively high capital and operation and maintenance costs with respect to the amount of power produced. Although our analysis shows that the project as licensed herein would cost more to operate than our estimated cost of alternative power, it is the applicant who must decide whether to accept this license and any financial risk that entails. This project’s value, however, lies in its successful testing and demonstration of ORPC Maine’s turbine technology, and the project’s ability to raise the profile of, and advance, the emergent tidal energy industry."
New England offshore wind advances
Friday, February 24, 2012
Plans to generate electricity from offshore winds off the southern New England coast appear to be gathering some momentum, as a series of events unrolling this month favor offshore wind development.
On February 3, the U.S. Bureau of Ocean Energy Management took the initial steps in its process to lease sites for offshore wind projects in federal waters off Massachusetts. BOEM requested information about uses of an area of sea about about 12 nautical miles south of the islands of Martha’s Vineyard and Nantucket, as well as expressions of interest by developers identifying particular sites. Responses to the call for information and nominations, as the key document is known, are due in mid-March.
Last week, Massachusetts officials announced a proposed settlement that would allow utilities NSTAR and Northeast Utilities to merge, but only on the condition that the resulting utility sign a long-term contract to buy power from the proposed Cape Wind project. Cape Wind already has a power purchase agreement with utility National Grid for half the project's output; if the NSTAR deal is approved, Cape Wind would have power purchase agreements in place for 77.5% of its expected output. Proponents hope that this increased certainty around the project's revenues could enable the project to be financed and built.
This week, Boston hosted a major offshore wind industry conference. Today, the U.S. Bureau of Ocean Energy Management plans to make an announcement "latest milestone in commercial wind energy planning and leasing in the area of mutual interest offshore of Rhode Island and Massachusetts."
None of these steps alone may be sufficient to spur offshore wind development in New England waters, but collectively these steps illustrate how multiple levels of government are promoting offshore wind. Will their collective result produce power in the near term?
On February 3, the U.S. Bureau of Ocean Energy Management took the initial steps in its process to lease sites for offshore wind projects in federal waters off Massachusetts. BOEM requested information about uses of an area of sea about about 12 nautical miles south of the islands of Martha’s Vineyard and Nantucket, as well as expressions of interest by developers identifying particular sites. Responses to the call for information and nominations, as the key document is known, are due in mid-March.
Last week, Massachusetts officials announced a proposed settlement that would allow utilities NSTAR and Northeast Utilities to merge, but only on the condition that the resulting utility sign a long-term contract to buy power from the proposed Cape Wind project. Cape Wind already has a power purchase agreement with utility National Grid for half the project's output; if the NSTAR deal is approved, Cape Wind would have power purchase agreements in place for 77.5% of its expected output. Proponents hope that this increased certainty around the project's revenues could enable the project to be financed and built.
This week, Boston hosted a major offshore wind industry conference. Today, the U.S. Bureau of Ocean Energy Management plans to make an announcement "latest milestone in commercial wind energy planning and leasing in the area of mutual interest offshore of Rhode Island and Massachusetts."
None of these steps alone may be sufficient to spur offshore wind development in New England waters, but collectively these steps illustrate how multiple levels of government are promoting offshore wind. Will their collective result produce power in the near term?
Preparing for an ice-free Arctic?
Thursday, February 23, 2012
As the Arctic climate changes, the possibility of an ice-free Arctic Ocean is looming. In recent history, almost all of the Arctic Ocean is covered by sea ice in winter, and perennial ice persists throughout the year over much of the basin. Arctic sea ice is now reducing in both volume and coverage. Some predictions, including the National Oceanic and Atmospheric Administration (NOAA), suggest that based on observed 2007/2008 summer sea ice extents, the Arctic could be nearly sea ice free in summertime within 30 years.
Setting aside the root causes of these changes, Arctic nations are preparing for a less icy future. Many stakeholders, like US Senator Lisa Murkowski of Alaska, believe that reduced ice cover over the Arctic could lead to future subsea resource discoveries. Indeed, the Arctic sea floor is already known to be home
to abundant energy resources including petroleum, natural gas, as well as metal and mineral deposits. In addition, the ocean and sea bed are home to significant marine life.
Beyond opening up potential for underwater resource extraction, a reduction in ice cover could also open up commercial navigation across the fabled Northwest Passage or other routes. This could reduce the cost of shipping goods across the globe, but could significantly increase marine traffic in the Arctic Ocean.
Arctic nations are gearing up for this possible future. For example, Canada has ordered new icebreakers and offshore patrol boats, and the head of the Royal Canadian Navy has recommended increasing military staffing in the region.
What will the future hold for the Arctic? Will perennial ice cover be significantly reduced within decades? If so, what will it mean for the environments, economies, and national security interests of countries in the Arctic region?
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| Rainbow over Canada's icy St. Lawrence River near Petite-Riviere-Saint-Francois, Quebec. |
Beyond opening up potential for underwater resource extraction, a reduction in ice cover could also open up commercial navigation across the fabled Northwest Passage or other routes. This could reduce the cost of shipping goods across the globe, but could significantly increase marine traffic in the Arctic Ocean.
Arctic nations are gearing up for this possible future. For example, Canada has ordered new icebreakers and offshore patrol boats, and the head of the Royal Canadian Navy has recommended increasing military staffing in the region.
What will the future hold for the Arctic? Will perennial ice cover be significantly reduced within decades? If so, what will it mean for the environments, economies, and national security interests of countries in the Arctic region?
Apple data center goes solar, biogas
Wednesday, February 22, 2012
As part of Apple's commitment to reducing the environmental impact of its facilities, the computer giant has announced plans to develop a large solar photovoltaic array and biogas-based fuel cell system at its new data center in Maiden, North Carolina.
Data centers are significant consumers of electricity. Apple designed its Maiden facility to earn LEED Platinum certification from the U.S. Green Building Council, making it among the most energy-efficient data centers in the U.S. Apple's plans now include developing a 20 MW solar facility on land adjacent to the data center, as well as a 5 MW biogas-based fuel cell system. Apple describes these as "the nation’s largest end user-owned solar array" "the largest nonutility fuel cell installation in the United States."
Apple reportedly expects to produce 42 GWh annually from the solar system and 40 GWh annually from the fuel cell, which would significantly increase Apple's consumption of renewable energy.
Data centers are significant consumers of electricity. Apple designed its Maiden facility to earn LEED Platinum certification from the U.S. Green Building Council, making it among the most energy-efficient data centers in the U.S. Apple's plans now include developing a 20 MW solar facility on land adjacent to the data center, as well as a 5 MW biogas-based fuel cell system. Apple describes these as "the nation’s largest end user-owned solar array" "the largest nonutility fuel cell installation in the United States."
Apple reportedly expects to produce 42 GWh annually from the solar system and 40 GWh annually from the fuel cell, which would significantly increase Apple's consumption of renewable energy.
Penobscot River dam removal
Tuesday, February 21, 2012
An ambitious project to remove dams on Maine's Penobscot River is moving forward. Under the terms of a settlement agreement among previous dam owners, environmental and conservation groups, and governmental agencies, two of the dams -- Veazie and Great Works -- will be removed, while fish passage will be installed at the Howland dam on the Piscataquis River.
This dam removal project is the ultimate result of the 2004 Lower Penobscot Basin Comprehensive Settlement Accord. In 2010, the Federal Energy Regulatory Commission approved the dam owner's surrender of its licenses to operate hydroelectric facilities and proposed dam removal. Later that year, dam owner PPL conveyed the dams to the Penobscot River Restoration Trust.
As part of the dam removal process, FERC requires the Trust to develop a schedule for mitigating the adverse impacts of dam removal on infrastructure. For example, an industrial facility draws water from the Great Works impoundment, and a wastewater treatment plant discharges 1.5 million gallons per day into the reservoir. A railroad bridge also crosses the area, and buried beneath the waters lies an older incarnation of the Great Works Dam which may block fish passage once the modern dam is removed. The Trust proposed to remove that older dam's submerged portions as part of the primary dam removal project.
Earlier this month, FERC approved the Trust's mitigation schedule for the Great Works project. FERC also granted the Trust an extension until the end of 2012 to file similar mitigation plans for the Veazie and Howland projects.
This dam removal project is the ultimate result of the 2004 Lower Penobscot Basin Comprehensive Settlement Accord. In 2010, the Federal Energy Regulatory Commission approved the dam owner's surrender of its licenses to operate hydroelectric facilities and proposed dam removal. Later that year, dam owner PPL conveyed the dams to the Penobscot River Restoration Trust.
As part of the dam removal process, FERC requires the Trust to develop a schedule for mitigating the adverse impacts of dam removal on infrastructure. For example, an industrial facility draws water from the Great Works impoundment, and a wastewater treatment plant discharges 1.5 million gallons per day into the reservoir. A railroad bridge also crosses the area, and buried beneath the waters lies an older incarnation of the Great Works Dam which may block fish passage once the modern dam is removed. The Trust proposed to remove that older dam's submerged portions as part of the primary dam removal project.
Earlier this month, FERC approved the Trust's mitigation schedule for the Great Works project. FERC also granted the Trust an extension until the end of 2012 to file similar mitigation plans for the Veazie and Howland projects.
Order 755-A confirms frequency regulation payment
Friday, February 17, 2012
In a move likely to please innovative energy resources capable of keeping the electric grid stable, federal regulators have affirmed a decision to require grid operators to pay fairly for frequency regulation service. In FERC Order No. 755-A, released yesterday, the Federal Energy Regulatory Commission declined to deviate from its previous Order No. 755 which transformed the way grid operators pay for frequency regulation.
Frequency regulation service involves adding or withdrawing energy from the electric grid in real time to ensure that supply and demand remain balanced. Electricity is surprisingly challenging to store, so historically grid operators have asked generators to ramp their production up or down in response to changes in the balance of supply and demand. This is known as frequency regulation service.
New energy storage technologies, like flywheels or batteries, appear to be able to provide frequency regulation service quicker and more cost-effectively than generation can. On the premise that existing payment structures are unfair, Order No. 755 required grid operators to shift to a two-part payment for frequency regulation service, including: (1) a capacity payment that includes the marginal unit’s opportunity costs; and (2) a payment for performance that reflects the quantity of frequency regulation service provided by a resource when the resource is accurately following the dispatch signal.
SoCal Edison had asked FERC for rehearing of Order No. 755 on two grounds involving eligibility for payments. In Order No. 755-A, FERC denied rehearing.
Order No. 755-A thus represents a confirmation of the basic premise in Order No. 755: grid operators must restructure the way they pay for frequency regulation service. Companies capable of providing frequency regulation, and the grid as a whole, stand to gain.
Frequency regulation service involves adding or withdrawing energy from the electric grid in real time to ensure that supply and demand remain balanced. Electricity is surprisingly challenging to store, so historically grid operators have asked generators to ramp their production up or down in response to changes in the balance of supply and demand. This is known as frequency regulation service.
New energy storage technologies, like flywheels or batteries, appear to be able to provide frequency regulation service quicker and more cost-effectively than generation can. On the premise that existing payment structures are unfair, Order No. 755 required grid operators to shift to a two-part payment for frequency regulation service, including: (1) a capacity payment that includes the marginal unit’s opportunity costs; and (2) a payment for performance that reflects the quantity of frequency regulation service provided by a resource when the resource is accurately following the dispatch signal.
SoCal Edison had asked FERC for rehearing of Order No. 755 on two grounds involving eligibility for payments. In Order No. 755-A, FERC denied rehearing.
Order No. 755-A thus represents a confirmation of the basic premise in Order No. 755: grid operators must restructure the way they pay for frequency regulation service. Companies capable of providing frequency regulation, and the grid as a whole, stand to gain.
MA utility merger may help Cape Wind
Thursday, February 16, 2012
A $17.5 billion merger proposal by two Massachusetts utilities seems more likely to win regulatory approval after yesterday's announcement of a settlement that would provide offshore wind developer Cape Wind a buyer for more of its electricity.
The two utilities, NSTAR and Northeast Utilities, had asked the Department of Public Utilities to approve their merger, but the case dragged on and faced challenges from ratepayer advocates. Yesterday, Governor Deval Patrick announced that his administration had negotiated an agreement to settle the case. In exchange for allowing the merger, the proposed settlement contains a number of provisions that are said to create enhanced ratepayer benefit. For example, the utilities must provide customers a one-time credit totalling $21 milllion, and NSTAR must fund an independent audit of its returns and assets.
The proposed settlement would also require the merged utility to enter into a contract to buy part of the electricity to be produced by the Cape Wind offshore wind project. NSTAR would enter into a 15-year contract to purchase 129 MW, or about 27.5% of Cape Wind's projected electricity output. This would be on top of the agreement to sell National Grid buy half of Cape Wind's power for a price starting at 18.7 cents per kilowatt-hour. The terms of this agreement have yet to be approved by the DPU, but the settlement contemplates that NSTAR could look elsewhere for its renewable electricity if Cape Wind has not started physical construction by 2016. Buying power from an offshore wind project is seen as important in helping the utilities comply with the Green Communities Act and the Massachusetts renewable portfolio standard or RPS.
If the merger settlement is approved, the utility would then negotiate the terms of a power purchase agreement with Cape Wind and submit them to the DPU for approval. Would having signed PPAs for 77.5% of the project's output be enough for Cape Wind's project to be financed and built?
The two utilities, NSTAR and Northeast Utilities, had asked the Department of Public Utilities to approve their merger, but the case dragged on and faced challenges from ratepayer advocates. Yesterday, Governor Deval Patrick announced that his administration had negotiated an agreement to settle the case. In exchange for allowing the merger, the proposed settlement contains a number of provisions that are said to create enhanced ratepayer benefit. For example, the utilities must provide customers a one-time credit totalling $21 milllion, and NSTAR must fund an independent audit of its returns and assets.
The proposed settlement would also require the merged utility to enter into a contract to buy part of the electricity to be produced by the Cape Wind offshore wind project. NSTAR would enter into a 15-year contract to purchase 129 MW, or about 27.5% of Cape Wind's projected electricity output. This would be on top of the agreement to sell National Grid buy half of Cape Wind's power for a price starting at 18.7 cents per kilowatt-hour. The terms of this agreement have yet to be approved by the DPU, but the settlement contemplates that NSTAR could look elsewhere for its renewable electricity if Cape Wind has not started physical construction by 2016. Buying power from an offshore wind project is seen as important in helping the utilities comply with the Green Communities Act and the Massachusetts renewable portfolio standard or RPS.
If the merger settlement is approved, the utility would then negotiate the terms of a power purchase agreement with Cape Wind and submit them to the DPU for approval. Would having signed PPAs for 77.5% of the project's output be enough for Cape Wind's project to be financed and built?
Massachusetts offshore wind meetings held
Wednesday, February 15, 2012
Federal ocean managers plan to lease ocean waters south of Massachusetts to developers of offshore wind energy projects. This month the Bureau of Ocean Energy Management opened its leasing process for 826,241 acres of water about 12 nautical miles south of Martha's Vineyard and Nantucket.
The newly opened leasing area is relatively large -- about 6% larger than the state of Rhode Island, or about 50 times larger than the 25 square mile footprint proposed for the Cape Wind project. Nevertheless it is less than half of the size of the area originally proposed for offshore wind leasing off Massachusetts.
BOEM's "Smart from the Start" leasing process includes holding public meetings to allow stakeholders to weigh in. This week BOEM held meetings in Vineyard Haven, New Bedford, and Boston.
BOEM's Call for Information and Nominations for the waters off Massachusetts asks developers to indicate interest by March 22, 2012.
The newly opened leasing area is relatively large -- about 6% larger than the state of Rhode Island, or about 50 times larger than the 25 square mile footprint proposed for the Cape Wind project. Nevertheless it is less than half of the size of the area originally proposed for offshore wind leasing off Massachusetts.
BOEM's "Smart from the Start" leasing process includes holding public meetings to allow stakeholders to weigh in. This week BOEM held meetings in Vineyard Haven, New Bedford, and Boston.
BOEM's Call for Information and Nominations for the waters off Massachusetts asks developers to indicate interest by March 22, 2012.
Solar project faces fox disease, native sites
Monday, February 13, 2012
A solar energy project proposed for the California desert has hit siting setbacks, including diseases foxes and a possible Native American cremation site.
The Genesis Solar Energy Project is one of 12 solar power plants proposed to be built in Southern California. The Genesis project would be built on federal Bureau of Land Management land 25 miles west of Blythe, CA, in the desert of Riverside County. Proposed by a wholly owned subsidiary of NextEra Energy Resources LLC, the project would rely on concentrating solar power by using mirrors to concentrate the sun's rays to produce steam. This steam would be used to spin steam turbine generators, much as in a traditional thermal power plant. For a total estimated cost of $1 billion, the Genesis project would consist of two independent solar electric generating facilities with a total net electrical output of 250 MW. $825 million of the project's financing is backed by a Department of Energy loan guarantee.
Now, the LA Times reports the project faces challenges including a deadly outbreak of distemper among wild kit foxes and the discovery of a potential burial or cremation site used by Native Americans.
Will the Genesis Solar Energy Project move forward?
The Genesis Solar Energy Project is one of 12 solar power plants proposed to be built in Southern California. The Genesis project would be built on federal Bureau of Land Management land 25 miles west of Blythe, CA, in the desert of Riverside County. Proposed by a wholly owned subsidiary of NextEra Energy Resources LLC, the project would rely on concentrating solar power by using mirrors to concentrate the sun's rays to produce steam. This steam would be used to spin steam turbine generators, much as in a traditional thermal power plant. For a total estimated cost of $1 billion, the Genesis project would consist of two independent solar electric generating facilities with a total net electrical output of 250 MW. $825 million of the project's financing is backed by a Department of Energy loan guarantee.
Now, the LA Times reports the project faces challenges including a deadly outbreak of distemper among wild kit foxes and the discovery of a potential burial or cremation site used by Native Americans.
Will the Genesis Solar Energy Project move forward?
NRC approves Georgia nuclear reactors
Friday, February 10, 2012
Federal regulators have approved the construction of two nuclear reactors in Georgia. The Nuclear Regulatory Commission approved the addition of two Toshiba/Westinghouse AP1000to Southern Co.'s existing Vogtle nuclear power plant, despite a dissenting vote by NRC Chairman Gregory Jaczko. (Here is the NRC order.) This represents the first NRC approval for construction of a new reactor since 1978.
31 states are already home to commercial nuclear reactors. The U.S. power industry's nuclear fleet includes 104 reactors at 65 power plants. (EIA provides a nice map with generalized locations of nuclear power plants.) Most are located near water sources, in the eastern half of the country. Illinois alone is home to 11 reactors.
Over the last two decades, nuclear energy has provided about 20% of our electricity supply. For example, in 2010, U.S. nuclear plants generated 807 billion kilowatt-hours out of nearly 3,884 billion kWh total supply. This amounts to about 8% of the total energy consumed in the U.S. from all sources.
The Vogtle project's projected cost is $14 billion, with a targeted operational date as early as 2016. The reactors approved for Georgia each have a nameplate capacity of 1,154 megawatts, making them significant sources of power. The reactors chosen for the project are designed to have simple fail-safe mechanisms to protect against the kind of catastrophe that occurred at Fukushima.
The NRC approved the project by a 4-1 vote. Chairman Jaczko cast the dissenting vote, noting in his written dissent, "I simply cannot authorize issuance of these licenses without any binding obligation that these plants will have implemented the lessons learned from the Fukushima accident before they operate."
By majority vote, the NRC authorized its Director of the Office of New Reactors to issue the work authorizations and licenses needed to allow the construction and operation of Vogtle Units 3 and 4.
31 states are already home to commercial nuclear reactors. The U.S. power industry's nuclear fleet includes 104 reactors at 65 power plants. (EIA provides a nice map with generalized locations of nuclear power plants.) Most are located near water sources, in the eastern half of the country. Illinois alone is home to 11 reactors.
Over the last two decades, nuclear energy has provided about 20% of our electricity supply. For example, in 2010, U.S. nuclear plants generated 807 billion kilowatt-hours out of nearly 3,884 billion kWh total supply. This amounts to about 8% of the total energy consumed in the U.S. from all sources.
The Vogtle project's projected cost is $14 billion, with a targeted operational date as early as 2016. The reactors approved for Georgia each have a nameplate capacity of 1,154 megawatts, making them significant sources of power. The reactors chosen for the project are designed to have simple fail-safe mechanisms to protect against the kind of catastrophe that occurred at Fukushima.
The NRC approved the project by a 4-1 vote. Chairman Jaczko cast the dissenting vote, noting in his written dissent, "I simply cannot authorize issuance of these licenses without any binding obligation that these plants will have implemented the lessons learned from the Fukushima accident before they operate."
By majority vote, the NRC authorized its Director of the Office of New Reactors to issue the work authorizations and licenses needed to allow the construction and operation of Vogtle Units 3 and 4.
Inflatable flashboards at hydro dams
Thursday, February 9, 2012
Dam owners are increasingly enhancing their revenue by using inflatable flashboards to optimize their hydroelectric production. This new technology offers dam owners and operators increased safety and increased hydroelectric generation, as well as opening the door to tax credits and other incentives.
Flashboards have traditionally been a palisade of wooden boards inserted into the top of a dam's crest. Flashboards increase a dam's capacity to hold water. They are typically used seasonally in temperate climates, and are removed before winter. Flooding or even high water can wash flashboards away, impairing the dam's ability to hold water until they can be replaced. Replacing flashboards can entail danger to personnel, and it might be a long time before water levels recede enough to allow safe reinstallation. In the meantime, a dam's ability to safely store water can be reduced.
Inflatable flashboards allow operators to increase or decrease the effective height of the flashboard system remotely. The ability to quickly and safely restore pond elevation after a high flow event translates into increased electricity generation. For example, inflatable flashboards at the Deer Rips - Androscoggin 3 Hydroelectric Project on the Androscoggin River in Lewiston and Auburn, Maine, have been calculated as likely to increase electric generation by 4.56% compared to a historical baseline.
This incremental hydropower generation can be valuable to the dam owner. Not only does it allow the facility to produce more electricity, but it may also qualify the project for federal and state tax incentives. For example, Section 45 of the Internal Revenue Code provides a renewable energy tax credit to owners or operators of qualified renewable electric generation facilities. That credit was extended to the incremental production gains from efficiency improvements or capacity additions developed between 2005 and 2013. Developers can ask the Federal Energy Regulatory Commission to certify a historic baseline of power produced at existing dams, as well as the incremental increase in hydropower production due to qualifying investments. Once FERC has issued this certification, dam owners can provide that to the Internal Revenue Service to receive the tax credit.
Flashboards have traditionally been a palisade of wooden boards inserted into the top of a dam's crest. Flashboards increase a dam's capacity to hold water. They are typically used seasonally in temperate climates, and are removed before winter. Flooding or even high water can wash flashboards away, impairing the dam's ability to hold water until they can be replaced. Replacing flashboards can entail danger to personnel, and it might be a long time before water levels recede enough to allow safe reinstallation. In the meantime, a dam's ability to safely store water can be reduced.
Inflatable flashboards allow operators to increase or decrease the effective height of the flashboard system remotely. The ability to quickly and safely restore pond elevation after a high flow event translates into increased electricity generation. For example, inflatable flashboards at the Deer Rips - Androscoggin 3 Hydroelectric Project on the Androscoggin River in Lewiston and Auburn, Maine, have been calculated as likely to increase electric generation by 4.56% compared to a historical baseline.
This incremental hydropower generation can be valuable to the dam owner. Not only does it allow the facility to produce more electricity, but it may also qualify the project for federal and state tax incentives. For example, Section 45 of the Internal Revenue Code provides a renewable energy tax credit to owners or operators of qualified renewable electric generation facilities. That credit was extended to the incremental production gains from efficiency improvements or capacity additions developed between 2005 and 2013. Developers can ask the Federal Energy Regulatory Commission to certify a historic baseline of power produced at existing dams, as well as the incremental increase in hydropower production due to qualifying investments. Once FERC has issued this certification, dam owners can provide that to the Internal Revenue Service to receive the tax credit.
Flywheel co Beacon Power sold
Wednesday, February 8, 2012
Flywheel-based energy storage developer Beacon Power Corp. may have a new lease on life, as private equity firm Rockland Capital proposes to buy the bankrupt company for $30.5 million.
Beacon Power patented a composite flywheel technology for use in balancing supply and demand on the nation's electric grid, an application known as frequency regulation. Unless this balance is maintained in real-time, problems can arise ranging from poor power quality to blackouts and safety hazards. Historically, grid operators controlled the output of electric generators to maintain this balance, but flywheels and other energy storage technologies may be able to smooth out disturbances on the grid more , more cost-effectively, and with fewer environmental impacts.
Beacon Power's business model has involved building, owning, and operating flywheel-based frequency regulation plants on a merchant basis. Indeed, Beacon Power describes itself as "a global leader in the development and commercialization of flywheel-based energy storage solutions for grid-scale frequency regulation services and other utility-scale and unitary energy storage applications."
In August 2010, Beacon Power received a $43 million loan guarantee through the U.S. Department of Energy's loan program office. That financing helped Beacon Power develop its 20 MW flywheel project in Stephentown, NY. But in October 21, Beacon Power filed for Chapter 11 in federal bankruptcy court.
At about the same time, federal regulators changed the way grid operators pay for frequency regulation. FERC Order No. 755 required grid operators to pay more for fast-responding frequency regulation -- just the kind of service that flywheel operators like Beacon Power may be able to provide best.
Now, Rockland Power proposes to pick up where Beacon left off, buying Beacon's assets for $5.5 million cash and a $25 million promissory note to the DOE. Rockland says that it intends to continue operating the Stephentown plant and developing a second facility in Hazle Township, Pennsylvania. Order 755 has given the energy storage industry a needed boost, which may be enough to let Rockland succeed with flywheel energy storage.
Beacon Power patented a composite flywheel technology for use in balancing supply and demand on the nation's electric grid, an application known as frequency regulation. Unless this balance is maintained in real-time, problems can arise ranging from poor power quality to blackouts and safety hazards. Historically, grid operators controlled the output of electric generators to maintain this balance, but flywheels and other energy storage technologies may be able to smooth out disturbances on the grid more , more cost-effectively, and with fewer environmental impacts.
Beacon Power's business model has involved building, owning, and operating flywheel-based frequency regulation plants on a merchant basis. Indeed, Beacon Power describes itself as "a global leader in the development and commercialization of flywheel-based energy storage solutions for grid-scale frequency regulation services and other utility-scale and unitary energy storage applications."
In August 2010, Beacon Power received a $43 million loan guarantee through the U.S. Department of Energy's loan program office. That financing helped Beacon Power develop its 20 MW flywheel project in Stephentown, NY. But in October 21, Beacon Power filed for Chapter 11 in federal bankruptcy court.
At about the same time, federal regulators changed the way grid operators pay for frequency regulation. FERC Order No. 755 required grid operators to pay more for fast-responding frequency regulation -- just the kind of service that flywheel operators like Beacon Power may be able to provide best.
Now, Rockland Power proposes to pick up where Beacon left off, buying Beacon's assets for $5.5 million cash and a $25 million promissory note to the DOE. Rockland says that it intends to continue operating the Stephentown plant and developing a second facility in Hazle Township, Pennsylvania. Order 755 has given the energy storage industry a needed boost, which may be enough to let Rockland succeed with flywheel energy storage.
Klamath basin dam removal
Tuesday, February 7, 2012
The US Department of the Interior recently released a draft report analyzing the economic and environmental impacts of removing four dams in the Klamath River Basin. The report frames a public debate over water rights, natural resource management, and dam removal.
Long home to prodigious salmon runs and a vibrant ecosystem, several of the rivers in the Klamath system were dammed in the 1900s. Today, four of these dams - J.C. Boyle, Copco 1, Copco 2, and Iron Gate - are owned by utility PacifiCorp. Over time, fish numbers in the Klamath River declined precipitously; according to the report, numbers of many species like salmon are reduced over 90% from historical levels. In 2006, after a 50-year term, the FERC license for the four dams expired.
Activism by environmental groups and others frustrated PacifiCorp's plans to relicense the dams, and ultimately led stakeholders to sign two key agreements governing the basin: the Klamath Hydroelectric Settlement Agreement (KHSA) and the Klamath Basin Restoration Agreement in 2010. Under the terms of those agreements, the four named dams would be removed.
The Draft Klamath Dam Removal Overview Report for the Secretary of the Interior (333 page PDF) bills itself as an assessment of scientific and technical information about the proposal. The report found that dam removal would cost between $238 million and $493 million, with $292 million as the most likely cost. Notably, these estimates are well below the amount previously projected for dam removal. Dam removal would release sediment that could kill salmon in the short term, but the agency found that dam removal would create more habitat and could increase adult chinook salmon production by about 83 percent.
If the dams are to be removed, Congress will have to authorize their removal. Together, the dams can produce up to 163 megawatts of power, and produce about 716,800 megawatt-hours per year. While this is relatively small compared to national demand for electricity, existing hydroelectric generation is relatively low-cost compared to alternative sources of power. Existing hydro also is generally viewed as emissions-free and relatively benign from an environmental perspective, especially compared to fossil fuel resources like coal and oil. Nevertheless, the draft report suggests that the benefits of removal will exceed retaining the dams in place by a factor of between 9 and 48.
Will this be enough to justify their removal?
Long home to prodigious salmon runs and a vibrant ecosystem, several of the rivers in the Klamath system were dammed in the 1900s. Today, four of these dams - J.C. Boyle, Copco 1, Copco 2, and Iron Gate - are owned by utility PacifiCorp. Over time, fish numbers in the Klamath River declined precipitously; according to the report, numbers of many species like salmon are reduced over 90% from historical levels. In 2006, after a 50-year term, the FERC license for the four dams expired.
Activism by environmental groups and others frustrated PacifiCorp's plans to relicense the dams, and ultimately led stakeholders to sign two key agreements governing the basin: the Klamath Hydroelectric Settlement Agreement (KHSA) and the Klamath Basin Restoration Agreement in 2010. Under the terms of those agreements, the four named dams would be removed.
The Draft Klamath Dam Removal Overview Report for the Secretary of the Interior (333 page PDF) bills itself as an assessment of scientific and technical information about the proposal. The report found that dam removal would cost between $238 million and $493 million, with $292 million as the most likely cost. Notably, these estimates are well below the amount previously projected for dam removal. Dam removal would release sediment that could kill salmon in the short term, but the agency found that dam removal would create more habitat and could increase adult chinook salmon production by about 83 percent.
If the dams are to be removed, Congress will have to authorize their removal. Together, the dams can produce up to 163 megawatts of power, and produce about 716,800 megawatt-hours per year. While this is relatively small compared to national demand for electricity, existing hydroelectric generation is relatively low-cost compared to alternative sources of power. Existing hydro also is generally viewed as emissions-free and relatively benign from an environmental perspective, especially compared to fossil fuel resources like coal and oil. Nevertheless, the draft report suggests that the benefits of removal will exceed retaining the dams in place by a factor of between 9 and 48.
Will this be enough to justify their removal?
Cape Cod canal tidal energy project
Monday, February 6, 2012
A tidal energy project proposed for the Cape Cod Canal appears not to be moving forward, as ocean energy developer Free Flow Power's affiliate FFP Mass 1, LLC has surrendered its preliminary permit to investigate the site and its priority to seek a license for the project.
The project was proposed for the Cape Cod Canal and part of the Hog Island Channel, between Cape Cod Bay and Buzzards Bay. The strong tidal currents and coastal geography combine to make the area near the south end of the canal attractive for energy projects.
As early as 2007, tidal energy developer Natural Currents Energy Services, LLC secured a preliminary permit to investigate stake a claim to the waters around the canal. NCES's preliminary permit was canceled in May 2010 after it missed key deadlines for filing a draft license application and formal notice of intent documents. At that point, the site went back up for grabs.
Three months later, another developer stepped forward, as FFP Mass 1 filed its application for a preliminary permit for the Cape Cod Tidal Energy Project. As described in the application, FFP's project would consist of up to 2,000 hydrokinetic generation units configured in a series of turbine arrays and turbine fields. These turbines would be installed from the end of the Cape Cod Canal out southward into Buzzard's Bay, between Taylor Point (home to Mass Maritime Academy) and Hog Neck in Wareham. FERC granted a preliminary permit later that year.
One year later, in October 2011, Free Flow Power asked FERC to accept its surrender of the preliminary permit for the Cape Cod Tidal Project. FFP stated that it had completed initial diligence on the project, and that based on the results of that diligence, "FFP has decided not to pursue the licensing of this project".
FERC has now issued an order accepting the surrender of the permit. FFP Mass 1's preliminary permit will remain in effect until the close of business on March 4, 2012. Only after that permit expires will the Commission consider new applications for this site, at which point the rights to the site will again be up for grabs. Given the site's potential, another developer may materialize, or either previous permittee could seek to claim the site in the future.
Who will be next to try the Cape Cod Tidal Energy Project?
The project was proposed for the Cape Cod Canal and part of the Hog Island Channel, between Cape Cod Bay and Buzzards Bay. The strong tidal currents and coastal geography combine to make the area near the south end of the canal attractive for energy projects.
As early as 2007, tidal energy developer Natural Currents Energy Services, LLC secured a preliminary permit to investigate stake a claim to the waters around the canal. NCES's preliminary permit was canceled in May 2010 after it missed key deadlines for filing a draft license application and formal notice of intent documents. At that point, the site went back up for grabs.
Three months later, another developer stepped forward, as FFP Mass 1 filed its application for a preliminary permit for the Cape Cod Tidal Energy Project. As described in the application, FFP's project would consist of up to 2,000 hydrokinetic generation units configured in a series of turbine arrays and turbine fields. These turbines would be installed from the end of the Cape Cod Canal out southward into Buzzard's Bay, between Taylor Point (home to Mass Maritime Academy) and Hog Neck in Wareham. FERC granted a preliminary permit later that year.
One year later, in October 2011, Free Flow Power asked FERC to accept its surrender of the preliminary permit for the Cape Cod Tidal Project. FFP stated that it had completed initial diligence on the project, and that based on the results of that diligence, "FFP has decided not to pursue the licensing of this project".
FERC has now issued an order accepting the surrender of the permit. FFP Mass 1's preliminary permit will remain in effect until the close of business on March 4, 2012. Only after that permit expires will the Commission consider new applications for this site, at which point the rights to the site will again be up for grabs. Given the site's potential, another developer may materialize, or either previous permittee could seek to claim the site in the future.
Who will be next to try the Cape Cod Tidal Energy Project?
Transmission lines on national park land provoke challenge
Friday, February 3, 2012
A 145-mile high voltage transmission line upgrade connecting Pennsylvania and New Jersey is on a fast-track review process at the federal level, but a proposed route through the popular and scenic Delaware Water Gap National Recreation Area and other lands managed by the National Park Service is drawing opposition.
Last fall, nine federal agencies formed the Interagency Rapid Response Team for Transmission. This group announced a coordinated federal policy decision to expedite the review process for 7 electric transmission lines across 12 states. These pilot projects were selected based on the premise that, when built, they will help increase electric reliability, integrate new renewable energy into the grid, and save consumers money.
Of these fast-tracked projects, the one farthest along in development is a 500-kilovolt line proposed by PPL Electric Utilities and Public Service Electric and Gas Co. 's running from PPL's Susquehanna substation near Berwick, Pennsylvania to Roseland, New Jersey. While the exact route of the line is not yet final, the utilities have requested a construction and right-of-way permit from the National Park Service for the expansion of an existing electric transmission line that crosses NPS lands within Pennsylvania and New Jersey. Three units of National Park Service lands would be affected by the project: the Delaware Water Gap National Recreation Area; the Middle Delaware National Scenic and Recreational River and National Recreation Water Trail; and the Appalachian National Scenic Trail.
Environmental and conservation activists have challenged any plan to route the line through national park lands. The utilities propose to expand upon an existing right-of-way across these units which contains a single 230kV electric transmission line. Existing towers would be replaced by new, taller tower structures. The 230 kV line would be upgraded to carry 500 kV, and an additional 500 kV line would be added. This work would also entail widening the existing right-of-way and constructing new access roads. The utilities have offered a mitigation package that includes the conservation of thousands of acres of high-priority lands. In addition, proponents say the line would save consumers more than $200 million each year in electric bills and create 2,000 jobs through construction.
The Park Service has released its draft environmental impact statement analyzing the project's impacts, and a final route is expected to be selected in March 2012.
Feds ok enviro impacts of offshore wind site leasing
Thursday, February 2, 2012
Offshore wind development off the mid-Atlantic coast took a step forward today with the release of a federal assessment of the environmental impacts of leasing ocean sites for wind projects. US Secretary of the Interior Ken Salazar and Maryland Governor Martin O'Malley held a press conference in Baltimore this morning at which the document was unveiled. The Bureau of Ocean Energy Management's final environmental assessment for mid-Atlantic site leasing (366 page PDF) will allow it to move forward with granting commercial wind leases and allowing site characterization activities on the mid-Atlantic outer continental shelf. Notably, the document found that leasing sites and allowing developers to study them would not have a significant impact on the human environment.
Under the National Environmental Policy Act, federal agencies must analyze and document the environmental effects of proposed federal actions such as issuing leases for offshore wind sites. A final environmental assessment was needed before BOEM could issue more leases, whether for offshore wind generation sites or for offshore transmission facilities.
At the same time, Governor O'Malley is intent on passing legislation that he believes will make Maryland the hub of the mid-Atlantic offshore wind industry. From the Atlantic Wind Connection offshore transmission network to generation projects in federal waters off Maryland (and Maryland state waters), any offshore wind development will need site leases, and issuing an environmental assessment is needed before issuing site leases. Thus for Governor O'Malley's plan to come to fruition, he needs to show that he (and developers) will have the cooperation of the federal BOEM. Today's event may have been designed to demonstrate that federal regulators will be cooperative with mid-Atlantic offshore wind projects. This would help the industry by reducing regulatory uncertainty, and would also help Governor O'Malley promote his offshore wind program.
The draft environmental assessment released last summer was generally favorable, if not groundbreaking. Notably, it did not explicitly make a finding of no significant impact from leasing. Comments on the draft environmental assessment were due in August 2011; these public comments are available through a federal document website. Today's final environmental assessment was developed partly in response to these public comments.
A final environmental assessment is a key step in developing the offshore wind resource, but it's still one of many steps needed. The environmental assessment in question does not cover any specific projects, nor would it permit the actual construction or operation of any projects. Rather it serves as a blanket assessment to document BOEM's review of the impacts of issuing site leases generally, and of allowing developers to study sites.
Today's finding of no significant impact, or FONSI, allows BOEM to move forward with leasing without preparing a more intensive (and time-consuming) environmental impact statement. This leasing program is part of BOEM's Smart from the Start initiative. The final assessment will now allow BOEM to award of a non-competitive lease for the wind energy area off Delaware, as well as a competitive process to select developers for sites off Maryland.
Under the National Environmental Policy Act, federal agencies must analyze and document the environmental effects of proposed federal actions such as issuing leases for offshore wind sites. A final environmental assessment was needed before BOEM could issue more leases, whether for offshore wind generation sites or for offshore transmission facilities.
At the same time, Governor O'Malley is intent on passing legislation that he believes will make Maryland the hub of the mid-Atlantic offshore wind industry. From the Atlantic Wind Connection offshore transmission network to generation projects in federal waters off Maryland (and Maryland state waters), any offshore wind development will need site leases, and issuing an environmental assessment is needed before issuing site leases. Thus for Governor O'Malley's plan to come to fruition, he needs to show that he (and developers) will have the cooperation of the federal BOEM. Today's event may have been designed to demonstrate that federal regulators will be cooperative with mid-Atlantic offshore wind projects. This would help the industry by reducing regulatory uncertainty, and would also help Governor O'Malley promote his offshore wind program.
The draft environmental assessment released last summer was generally favorable, if not groundbreaking. Notably, it did not explicitly make a finding of no significant impact from leasing. Comments on the draft environmental assessment were due in August 2011; these public comments are available through a federal document website. Today's final environmental assessment was developed partly in response to these public comments.
A final environmental assessment is a key step in developing the offshore wind resource, but it's still one of many steps needed. The environmental assessment in question does not cover any specific projects, nor would it permit the actual construction or operation of any projects. Rather it serves as a blanket assessment to document BOEM's review of the impacts of issuing site leases generally, and of allowing developers to study sites.
Today's finding of no significant impact, or FONSI, allows BOEM to move forward with leasing without preparing a more intensive (and time-consuming) environmental impact statement. This leasing program is part of BOEM's Smart from the Start initiative. The final assessment will now allow BOEM to award of a non-competitive lease for the wind energy area off Delaware, as well as a competitive process to select developers for sites off Maryland.
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