Concerns over the reliability of New England's electricity grid this coming winter have led the regional grid operator to develop a new program designed to ensure sufficient energy is available. While natural gas remains the dominant cost-effective fuel for electric generation in New England, grid operator ISO New England expressed concern over its ability to ensure a reliable supply of electricity in the event of a natural gas shortage or supply disruption. As a result, the grid operator launched a so-called Winter Reliability Program to compensate oil-fired generators, dual-fuel generators, and demand response resources for their promise to stand ready to serve if needed. Is the program necessary? If so, will it prove sufficient to protect consumers against power outages and high prices?
ISO New England's Winter Reliability Program plan was
designed to address the reliability risks
arising from constraints on the interstate pipeline system's ability to meet demands for natural gas deliveries into New England, increased reliance on natural gas-fired generation, and generating resource performance
during periods of stressed system conditions. While regional stakeholders are developing a longer-term fix for these risks, last winter highlighted the urgency of the problem, as natural gas pipelines supplying fuel to New England reached full capacity through the winter season, leaving natural gas more expensive and less available than it should be.
As a short-term solution, through its Winter
Reliability Program, ISO New England will procure up to 2.4 million megawatt-hours of energy for the coming winter, from a combination of oil-fired generators, dual-fuel generators, and demand
response assets.
In exchange for their commitment to provide power when called upon, the selected generators and demand response assets will receive payments regardless of whether they are actually needed this winter.
This program was conditionally accepted by the Federal Energy Regulatory Commission last month, after which the grid operator held its competitive bidding process. When the bidding settled, ISO New England had failed to procure commitments to provide as much energy as it had sought. According to a FERC order accepting the bid results, market participants
submitted bids totaling 2.29 million MWh, or 96 percent of the target, at a total offer
price of $114.3 million. ISO New England proposed to trim the offered supply farther, accepting bids from 20 participants for just 1.995 million MWh, or 83.1 percent
of the target, for a total price of $78.8 million.
How did ISO New England reach this result? According to the grid operator's filing to the FERC, the selected bids are all less than $31 per MWh-month. ISO New England says that beyond this point, the supply curve became steeper, and the grid operator wanted to balance
fuel security for the region against the costs to consumers. But as the FERC found, ISO New England did not adequately explain its selection process, nor did it sufficiently describe why it cut off supply bids at $31 per MWh-month. As a result, the FERC directed the grid operator to submit a compliance filing within 15 days describing its process in more detail.
Once ISO New England submits its compliance filing, we will have better insight into the selection process. Further questions, such as whether the program will prove necessary or effective, cannot be answered until the winter season hits New England. Will ISO New England's Winter Reliability Program yield consumers value in excess of its $78.8 million cost?
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Showing posts with label ISO New England. Show all posts
Showing posts with label ISO New England. Show all posts
End in sight for New England's largest coal plant
Wednesday, October 9, 2013
New England's largest coal-fired power plant will close by May 2017, according to its owner. The Brayton Point Power Station in Somerset, Massachusetts, consists of three coal-fired units and a unit capable of burning natural gas and oil, with a net generating capacity of 1,537.6 megawatts. Within 4 years, it will follow other large New England coal-fired power plants like Salem Harbor Power Station into history.
The forces leading to Brayton Point's closure have been gathering for years. The U.S. energy industry is in the midst of a revolution led by affordable and abundant natural gas supplies. Meanwhile, tighter environmental regulations on air emissions from coal-fired power plants have made these traditionally cheap generators more and more expensive to run. This past March, Brayton Point's previous owner Dominion Resources Inc. announced plans to sell the plant and two other fossil-fired plants to a subsidiary of Energy Capital Partners LLC. That deal was consummated in August.
In an effort to keep the plant economic, Energy Capital Partners reportedly worked with regional electricity grid operator ISO New England Inc. on an agreement under which Brayton Point would have been paid for its ability to be called upon to provide electric generating capacity when needed. But when Brayton Point demanded a higher price for this capacity than ISO New England was willing to offer, the generator submitted papers indicating that it would not provide capacity for the 2017-2018 forward capacity year.
Without those capacity market revenues, Brayton Point's owners have said it will close by May 2017, according to AP reports. If it does, it will follow Salem Harbor and other coal-fired power plants around the country which have either closed or been converted to natural gas. What will the future hold for Brayton Point's site in Somerset? With transmission lines already in place, will it be redeveloped with other energy infrastructure? What environmental issues will closure or repowering entail?
 |
| The Salem Harbor Power Station in Salem, Massachusetts, scheduled to close in May 2014. |
The forces leading to Brayton Point's closure have been gathering for years. The U.S. energy industry is in the midst of a revolution led by affordable and abundant natural gas supplies. Meanwhile, tighter environmental regulations on air emissions from coal-fired power plants have made these traditionally cheap generators more and more expensive to run. This past March, Brayton Point's previous owner Dominion Resources Inc. announced plans to sell the plant and two other fossil-fired plants to a subsidiary of Energy Capital Partners LLC. That deal was consummated in August.
In an effort to keep the plant economic, Energy Capital Partners reportedly worked with regional electricity grid operator ISO New England Inc. on an agreement under which Brayton Point would have been paid for its ability to be called upon to provide electric generating capacity when needed. But when Brayton Point demanded a higher price for this capacity than ISO New England was willing to offer, the generator submitted papers indicating that it would not provide capacity for the 2017-2018 forward capacity year.
Without those capacity market revenues, Brayton Point's owners have said it will close by May 2017, according to AP reports. If it does, it will follow Salem Harbor and other coal-fired power plants around the country which have either closed or been converted to natural gas. What will the future hold for Brayton Point's site in Somerset? With transmission lines already in place, will it be redeveloped with other energy infrastructure? What environmental issues will closure or repowering entail?
FERC OKs sale of Dominion merchant power plants to Energy Capital Partners
Wednesday, August 21, 2013
Federal regulators approved yesterday the sale of three fossil fuel-fired power plants from energy company Dominion Resources Inc. to Energy Capital Partners LLC for $650 million. The order by the Federal Energy Regulatory Commission moves the deal closer to fruition. Is the transaction part of a trend in the U.S. energy industry?
Dominion is a major player in the U.S. energy business, serving customers in 15 states with its holdings in both the electricity and natural gas sectors. Dominion owns a portfolio of about 27,000 megawatts of electric generation and 6,400 miles of electric transmission lines, as well as vertically-integrated electric utilities like Dominion Virginia Power. Dominion also owns a large natural gas storage system as well as about 11,000 miles of natural gas transmission, gathering and storage pipelines.
Buyer Energy Capital Partners is a private equity firm focused on investing in North America's energy infrastructure. The firm has recently acquired other electric generation plants, including the 830-megawatt combined-cycle natural gas-fired Red Oak power plant in Sayreville, New Jersey, and the 847-megawatt Broad River simple cycle, natural gas-fired power plant in South Carolina.
Over the past several decades, Dominion added merchant power plants designed not to serve the load of its affiliated utilities. These plants produced electricity from coal, oil and other fossil fuels, and sold the power into regional wholesale markets such as those managed by ISO New England and mid-Atlantic grid operator PJM. But with tighter environmental regulations, and more competitive electricity markets thanks to low-cost natural gas, many New England coal and oil-fired power plants have a hard time succeding in the current markets. As an apparent result, in 2012 said it would sell or close its merchant coal-fired plants to realign its portfolio and improve return on invested capital and shareholder value, and sold the coal- and oil-fired Salem Harbor Power Station in Massachusetts.
In March 2013, Dominion announced a deal to sell its interests in three power plants to Energy Capital Partners. 1,528-megawatt Brayton Point Power Station, in Somerset, Massachusetts, is the largest remaining coal-fired power plant in New England. It has three coal-fired units and one unit capable of being firing oil or natural gas, as well as the coal-fired 1,158-megawatt Kincaid Power Station in Illinois.. Dominion also offered its stake in 1,424 megawatts of capacity at the Elwood Power Station outside Chicago, which is powered by nine 158-MW natural gas-fired combustion turbines.
The deal price announced was $650 million. At least one analyst has noted that after removing tax benefits, the deal implied an underlying price paid per kilowatt of capacity of just over $100, a price 30 times lower than the the cost of building a new coal-fired plant according to the U.S. Department of Energy.
The Federal Trade Commission approved the deal from an antitrust perspective under the Hart-Scott-Rodino Act in March 2013, so the Federal Energy Regulatory Commission approval today was among the final approvals needed.
Fossil fuel and electricity markets are experiencing changes, from tighter air emissions to the prospect of federal carbon regulation. Assuming the Dominion deal actually happens, does it signal a trend of utility divestiture of merchant fossil fuel-fired power plants? Will other utilities exit the merchant electricity generation business? Will we see increased transactional activity, as utilities sell their fossil fuel-fired plants? For how much longer will the buyers run these plants? In the case of the Salem station Dominion sold last year, buyer Footprint Power LLC is demolishing the old plant and redeveloping the site as a natural gas-fired power plant. Will Energy Capital Partners choose to keep Brayton Point operating in a market where margins are often tight? Or is this just the rationalization of Dominion's asset base, with no similar ripples throughout the sector?
Dominion is a major player in the U.S. energy business, serving customers in 15 states with its holdings in both the electricity and natural gas sectors. Dominion owns a portfolio of about 27,000 megawatts of electric generation and 6,400 miles of electric transmission lines, as well as vertically-integrated electric utilities like Dominion Virginia Power. Dominion also owns a large natural gas storage system as well as about 11,000 miles of natural gas transmission, gathering and storage pipelines.
Buyer Energy Capital Partners is a private equity firm focused on investing in North America's energy infrastructure. The firm has recently acquired other electric generation plants, including the 830-megawatt combined-cycle natural gas-fired Red Oak power plant in Sayreville, New Jersey, and the 847-megawatt Broad River simple cycle, natural gas-fired power plant in South Carolina.
Over the past several decades, Dominion added merchant power plants designed not to serve the load of its affiliated utilities. These plants produced electricity from coal, oil and other fossil fuels, and sold the power into regional wholesale markets such as those managed by ISO New England and mid-Atlantic grid operator PJM. But with tighter environmental regulations, and more competitive electricity markets thanks to low-cost natural gas, many New England coal and oil-fired power plants have a hard time succeding in the current markets. As an apparent result, in 2012 said it would sell or close its merchant coal-fired plants to realign its portfolio and improve return on invested capital and shareholder value, and sold the coal- and oil-fired Salem Harbor Power Station in Massachusetts.
In March 2013, Dominion announced a deal to sell its interests in three power plants to Energy Capital Partners. 1,528-megawatt Brayton Point Power Station, in Somerset, Massachusetts, is the largest remaining coal-fired power plant in New England. It has three coal-fired units and one unit capable of being firing oil or natural gas, as well as the coal-fired 1,158-megawatt Kincaid Power Station in Illinois.. Dominion also offered its stake in 1,424 megawatts of capacity at the Elwood Power Station outside Chicago, which is powered by nine 158-MW natural gas-fired combustion turbines.
The deal price announced was $650 million. At least one analyst has noted that after removing tax benefits, the deal implied an underlying price paid per kilowatt of capacity of just over $100, a price 30 times lower than the the cost of building a new coal-fired plant according to the U.S. Department of Energy.
The Federal Trade Commission approved the deal from an antitrust perspective under the Hart-Scott-Rodino Act in March 2013, so the Federal Energy Regulatory Commission approval today was among the final approvals needed.
Fossil fuel and electricity markets are experiencing changes, from tighter air emissions to the prospect of federal carbon regulation. Assuming the Dominion deal actually happens, does it signal a trend of utility divestiture of merchant fossil fuel-fired power plants? Will other utilities exit the merchant electricity generation business? Will we see increased transactional activity, as utilities sell their fossil fuel-fired plants? For how much longer will the buyers run these plants? In the case of the Salem station Dominion sold last year, buyer Footprint Power LLC is demolishing the old plant and redeveloping the site as a natural gas-fired power plant. Will Energy Capital Partners choose to keep Brayton Point operating in a market where margins are often tight? Or is this just the rationalization of Dominion's asset base, with no similar ripples throughout the sector?
Grid operator expects sufficient electricity this summer
Wednesday, May 1, 2013
Regional electricity grid operator ISO New England, Inc. issued its 2013 summer outlook on April 29. In that report, New England regional transmission organization found that regional electricity supplies during the upcoming summer are expected to be sufficient to meet consumer demand under normal weather conditions. But if any number of contingencies occur, such as a heat wave, the grid could be seriously strained.
ISO New England noted that under normal conditions, there should be enough electricity this summer. But it identified a series of risk factors could tip the balance of supply and demand for electricity, including extreme summer weather conditions or unexpected resource outages. These factors could create "operational challenges", meaning a hard time finding enough electricity to meet peak demand. New England may be forced to resort to importing emergency power from neighboring regions, and asking businesses and people to voluntarily conserve energy.
The report's base assumption is for "normal" summer weather conditions of about 90 degrees in key southern New England cities. Under these conditions, ISO New England forecasts electricity demand could reach 26,690 megawatts (MW). If an extended heat wave pushes temperatures to 95, demand could rise to 28,985 MW. Last summer’s load peaked July 17 at 25,880 MW, about 3% smaller than the base amount forecast for summer 2013. New England set its record for peak demand on August 2, 2006, when demand reached 28,130 MW.
On the supply side, ISO New England identified several risks that could lead to unexpected shortages of electricity. First, most natural gas pipeline maintenance in the region is scheduled for the summer months. Maintenance activities could affect natural gas supplies to some power plants. On this point, the grid operator said it was coordinating with the pipeline companies to ensure that the supply is adequate for power generation during the maintenance season.
Second, liquefied natural gas (LNG) is in high global demand. Current LNG prices are roughly three times higher in Europe and Japan than in the United States. This mean LNG deliveries into New England might be reduced this summer. At times, New England electric generation relies on LNG, which could also affect power plant operations.
Overall, ISO New England reported that it expects electricity supplies to be sufficient to meet consumer demand under normal weather conditions this summer. If shortages occur, they will likely affect both the reliability of the grid and the wholesale price of power. The winter season is likely to be worse, as regional demand for natural gas for heating increases during the winter, placing a tighter squeeze on the amount and price of gas available for electric generation. The grid operator's prediction will be put to the test in the coming months.
ISO New England noted that under normal conditions, there should be enough electricity this summer. But it identified a series of risk factors could tip the balance of supply and demand for electricity, including extreme summer weather conditions or unexpected resource outages. These factors could create "operational challenges", meaning a hard time finding enough electricity to meet peak demand. New England may be forced to resort to importing emergency power from neighboring regions, and asking businesses and people to voluntarily conserve energy.
The report's base assumption is for "normal" summer weather conditions of about 90 degrees in key southern New England cities. Under these conditions, ISO New England forecasts electricity demand could reach 26,690 megawatts (MW). If an extended heat wave pushes temperatures to 95, demand could rise to 28,985 MW. Last summer’s load peaked July 17 at 25,880 MW, about 3% smaller than the base amount forecast for summer 2013. New England set its record for peak demand on August 2, 2006, when demand reached 28,130 MW.
On the supply side, ISO New England identified several risks that could lead to unexpected shortages of electricity. First, most natural gas pipeline maintenance in the region is scheduled for the summer months. Maintenance activities could affect natural gas supplies to some power plants. On this point, the grid operator said it was coordinating with the pipeline companies to ensure that the supply is adequate for power generation during the maintenance season.
Second, liquefied natural gas (LNG) is in high global demand. Current LNG prices are roughly three times higher in Europe and Japan than in the United States. This mean LNG deliveries into New England might be reduced this summer. At times, New England electric generation relies on LNG, which could also affect power plant operations.
Overall, ISO New England reported that it expects electricity supplies to be sufficient to meet consumer demand under normal weather conditions this summer. If shortages occur, they will likely affect both the reliability of the grid and the wholesale price of power. The winter season is likely to be worse, as regional demand for natural gas for heating increases during the winter, placing a tighter squeeze on the amount and price of gas available for electric generation. The grid operator's prediction will be put to the test in the coming months.
2013: a look ahead
Thursday, January 3, 2013
With the new year upon us, here is a preview of several energy-related issues and events we will likely see this year:
Expansion of natural gas production, transmission and distribution. The spread of hydraulic fracturing or fracking as a technique to produce natural gas from previously-uneconomic sources appears to be the largest revolution in the U.S. energy landscape in decades. Natural gas will continue to displace coal and oil as an energy source in 2013, particularly for the generation of electricity. The availability of cheap natural gas will also lead to the development of more local distribution company pipelines, enabling more businesses and homes to connect to natural gas supplies. 2013 will likely also bring proposed new natural gas transmission pipelines, connecting gas sources like the Marcellus and Utica shale fields to consumers across the country.
Offshore wind in U.S. waters. 2013 may see the construction of the first offshore wind projects in United States waters. Cape Wind's project off Massachusetts may start cable work or other construction this year, as may Deepwater Wind's Block Island project off Rhode Island and Fishermen’s Energy's project off Atlantic City, New Jersey. Congress's last-minute extension of the Investment Tax Credit or ITC gives a significant boost to offshore wind projects capable of beginning construction in 2013. Not only was the tax credit's deadline extended by one year, but Congress also changed the trigger from being "placed in service" to commencing construction by December 31, 2013. No offshore wind projects are currently operating or under construction in U.S. waters, so 2013 could be the year the first projects enter the water. The federal Bureau of Ocean Energy Management is expected to continue its leasing program, making more ocean sites available for future offshore wind projects.
Keystone XL pipeline. The Keystone XL pipeline, a $7 billion proposed extension of an existing crude oil pipeline, is slated to connect Alberta, Canada to Texas. In 2011 and 2012, the project faced public scrutiny and failed to secure necessary federal and state approvals. Among other permits, the project faces State Department review because it would enable imports or exports of oil across the national border with Canada. Meanwhile, project lead TransCanada is moving ahead with the construction of some of the domestic legs of the project, and the full project is likely to come back up for review this year.
Energy efficiency continues to grow. Investments in energy efficiency are likely to continue to grow in 2013. Using fuels and energy sources more efficiently saves money for businesses and homeowners capable of making the investment. It can also lower market prices for electricity and fuels by reducing demand, spreading the savings across all consumers. New England regional electric grid operator ISO New England recently revised its load forecast to predict no increases in the demand for electricity through 2021 as a result of increased investment in energy efficiency. This trend is likely to continue nationwide.
With 362 days left in the year, these issues and events are likely to be discussed for some time to come. Will these predictions come true in 2013?
Expansion of natural gas production, transmission and distribution. The spread of hydraulic fracturing or fracking as a technique to produce natural gas from previously-uneconomic sources appears to be the largest revolution in the U.S. energy landscape in decades. Natural gas will continue to displace coal and oil as an energy source in 2013, particularly for the generation of electricity. The availability of cheap natural gas will also lead to the development of more local distribution company pipelines, enabling more businesses and homes to connect to natural gas supplies. 2013 will likely also bring proposed new natural gas transmission pipelines, connecting gas sources like the Marcellus and Utica shale fields to consumers across the country.
Offshore wind in U.S. waters. 2013 may see the construction of the first offshore wind projects in United States waters. Cape Wind's project off Massachusetts may start cable work or other construction this year, as may Deepwater Wind's Block Island project off Rhode Island and Fishermen’s Energy's project off Atlantic City, New Jersey. Congress's last-minute extension of the Investment Tax Credit or ITC gives a significant boost to offshore wind projects capable of beginning construction in 2013. Not only was the tax credit's deadline extended by one year, but Congress also changed the trigger from being "placed in service" to commencing construction by December 31, 2013. No offshore wind projects are currently operating or under construction in U.S. waters, so 2013 could be the year the first projects enter the water. The federal Bureau of Ocean Energy Management is expected to continue its leasing program, making more ocean sites available for future offshore wind projects.
Keystone XL pipeline. The Keystone XL pipeline, a $7 billion proposed extension of an existing crude oil pipeline, is slated to connect Alberta, Canada to Texas. In 2011 and 2012, the project faced public scrutiny and failed to secure necessary federal and state approvals. Among other permits, the project faces State Department review because it would enable imports or exports of oil across the national border with Canada. Meanwhile, project lead TransCanada is moving ahead with the construction of some of the domestic legs of the project, and the full project is likely to come back up for review this year.
Energy efficiency continues to grow. Investments in energy efficiency are likely to continue to grow in 2013. Using fuels and energy sources more efficiently saves money for businesses and homeowners capable of making the investment. It can also lower market prices for electricity and fuels by reducing demand, spreading the savings across all consumers. New England regional electric grid operator ISO New England recently revised its load forecast to predict no increases in the demand for electricity through 2021 as a result of increased investment in energy efficiency. This trend is likely to continue nationwide.
With 362 days left in the year, these issues and events are likely to be discussed for some time to come. Will these predictions come true in 2013?
New England energy efficiency grows, saves
Thursday, December 13, 2012
Energy efficiency in New England has
saved consumers significant money in recent years, and is changing the
energy landscape in the northeastern U.S. At a briefing yesterday, the
region's electric grid operator announced that continued investment in
electric energy efficiency has changed its load projections from modest
growth to a flat forecast
through 2021.
ISO New England manages the energy markets and transmission grid in the six New England states. ISO New England plans for future electricity needs, and develops forecasts for electricity consumption for the next decade. In recent years, the adoption of energy efficiency measures has reduced society's demand for electricity. From 2008 to 2011 New England spent $1.2 billion on energy efficiency through programs like Efficiency Maine and Mass Save. ISO New England said that it expects spending on energy efficiency is expected to increase to $5.7 billion from 2015 to 2021. As a result, electricity use previously projected to rise by 0.9 percent annually between 2012 and 2021 will instead be flat.
Customers win through energy efficiency in several ways. Direct savings include the money they would have spent on electricity but for their efficiency increases. The overall wholesale price of energy and capacity can also be reduced through greater adoption of energy efficiency. Efficiency can also eliminate the need for some transmission upgrades; according to ISO New England, 10 transmission upgrades that earlier studies showed were needed to ensure reliability can be deferred until after 2020, saving consumers an estimated $260 million more.
ISO New England manages the energy markets and transmission grid in the six New England states. ISO New England plans for future electricity needs, and develops forecasts for electricity consumption for the next decade. In recent years, the adoption of energy efficiency measures has reduced society's demand for electricity. From 2008 to 2011 New England spent $1.2 billion on energy efficiency through programs like Efficiency Maine and Mass Save. ISO New England said that it expects spending on energy efficiency is expected to increase to $5.7 billion from 2015 to 2021. As a result, electricity use previously projected to rise by 0.9 percent annually between 2012 and 2021 will instead be flat.
Customers win through energy efficiency in several ways. Direct savings include the money they would have spent on electricity but for their efficiency increases. The overall wholesale price of energy and capacity can also be reduced through greater adoption of energy efficiency. Efficiency can also eliminate the need for some transmission upgrades; according to ISO New England, 10 transmission upgrades that earlier studies showed were needed to ensure reliability can be deferred until after 2020, saving consumers an estimated $260 million more.
Vermont transmission line vandalism
Friday, November 9, 2012
Vermont's electric transmission authority has reported vandalism to a section of high-voltage line connecting Hydro-Quebec's grid to southern New England markets. According to the Caledonian Record, 167 insulating discs were shot out from a transmission line in the town of Concord, Vermont.
Vermont Electric Power Company (VELCO) manages Vermont's electric transmission system, which includes, 738 miles of transmission lines, 13,000 acres of rights-of-way, 55 substations, switching stations and terminal facilities, interconnection facilities with Hydro-Quebec, as well as fiber optic communication networks that both control the electric system and provide the backbone for high-speed data internet access. VELCO was formed by the state's utilities in 1956 as the nation's first statewide, "transmission only" public utility.
Vandals reportedly used a shotgun to shoot the glass insulating discs which are spaced along the transmission lines and are designed to keep the lines safe from shorting out. In all, 167 out of over 400 insulating discs were destroyed. As a result, VELCO depowered the line until the discs could be replaced, which took from last Friday until last Sunday. The repair itself cost about $250,000, but the biggest cost arose when regional grid operator ISO New England was forced to turn to the spot market to replace the electricity normally imported over the line from Quebec while the line was down. The cost of that replacement power was reportedly over $1 million per day.
The incident is now the subject of a federal investigation. Laws enacted after the widespread eastern blackout in 2003 and the September 11 terrorist attacks have increased the penalties for disrupting electric transmission and other infrastructure. The insulating disc shooting may be treated as a "terrorist act" under federal law.
Transmission lines provide value to society, but are typically expensive and are often located in remote areas. Hunting often occurs along or near transmission lines; just this year, VELCO won the National Wild Turkey Federation's Energy for Wildlife award for the company’s ongoing commitment to develop and improve wildlife habitat along its rights-of-way. The extent of the damage to the insulating discs makes the shooting appear to be intentional, and thus more than a "hunting accident". How will the incident affect transmission line owners' policies about public access to areas near lines? How can transmission lines be better protected against vandalism?
Vermont Electric Power Company (VELCO) manages Vermont's electric transmission system, which includes, 738 miles of transmission lines, 13,000 acres of rights-of-way, 55 substations, switching stations and terminal facilities, interconnection facilities with Hydro-Quebec, as well as fiber optic communication networks that both control the electric system and provide the backbone for high-speed data internet access. VELCO was formed by the state's utilities in 1956 as the nation's first statewide, "transmission only" public utility.
Vandals reportedly used a shotgun to shoot the glass insulating discs which are spaced along the transmission lines and are designed to keep the lines safe from shorting out. In all, 167 out of over 400 insulating discs were destroyed. As a result, VELCO depowered the line until the discs could be replaced, which took from last Friday until last Sunday. The repair itself cost about $250,000, but the biggest cost arose when regional grid operator ISO New England was forced to turn to the spot market to replace the electricity normally imported over the line from Quebec while the line was down. The cost of that replacement power was reportedly over $1 million per day.
The incident is now the subject of a federal investigation. Laws enacted after the widespread eastern blackout in 2003 and the September 11 terrorist attacks have increased the penalties for disrupting electric transmission and other infrastructure. The insulating disc shooting may be treated as a "terrorist act" under federal law.
Transmission lines provide value to society, but are typically expensive and are often located in remote areas. Hunting often occurs along or near transmission lines; just this year, VELCO won the National Wild Turkey Federation's Energy for Wildlife award for the company’s ongoing commitment to develop and improve wildlife habitat along its rights-of-way. The extent of the damage to the insulating discs makes the shooting appear to be intentional, and thus more than a "hunting accident". How will the incident affect transmission line owners' policies about public access to areas near lines? How can transmission lines be better protected against vandalism?
Report on 2011 New England electricity market
Friday, June 29, 2012
New England electricity markets operated competitively and relatively efficiently in 2011, according to a report filed with federal regulators earlier this week. The 2011 Assessment of the ISO New England Electricity Markets (184-page PDF), prepared by New England's external market monitor, reports on how the market performed last year, with a focus on evaluating efficiency and competitiveness.
ISO New England Inc. is the regional transmission organization covering most of New England. In this role, ISO New England performs three major functions: overseeing operation of New England's bulk power generation and transmission system, administering the region's wholesale electricity markets, and managing regional planning processes. ISO New England is regulated by the Federal Energy Regulatory Commission, and has both internal and external market monitors who review its performance. The internal market monitor is a unit within ISO New England Inc., while the external market monitor is an independent outside consultant. Potomac Economics currently serves as the external market monitor.
Potomac's report found that "the markets performed competitively in 2011". One piece of evidence Potomac used to support this finding is that average energy prices fell 7 percent from 2010 to 2011 (from approximately $53 per MWh in 2010 to $49 in 2011). According to the report, this is due in large part to a decrease in the average price of natural gas. In Potomac's view, lower fuel costs translate to lower prices in a well-functioning, competitive market because fuel costs constitute the vast majority of the marginal costs of most generation. Natural gas pricing decreases were not the only contributor to lower energy prices, according to the report; Potomac also noted that prices fell due to a weather-driven decrease in demand for electricity, stating that, "Average load decreased 1 percent from 2010 to 2011 and 2.5 percent from the summer of 2010 to the summer of 2011, primarily due to milder weather."
Potomac also found that "both the day-ahead and real-time markets operated relatively efficiently in 2011 as prices appropriately reflected the effects of lower fuel prices and load levels." However, the external market monitor found that "real-time prices often do not fully reflect the cost of satisfying demand and maintaining reliability during tight market conditions, particularly when fast-start resources or demand response resources are deployed in the real-time market." As a result, the report recommended a series of changes to the New England markets, including developing pricing changes to allow the actual costs of demand response and fast-start resources to be reflected in prices.
The report was filed with the Federal Energy Regulatory Commission on June 25. It complements the 2011 Annual Markets Report (121-page PDF), released this May by ISO New England's internal market monitor. The internal market monitor's report similarly found that the markets operated competitively in 2011.
ISO New England Inc. is the regional transmission organization covering most of New England. In this role, ISO New England performs three major functions: overseeing operation of New England's bulk power generation and transmission system, administering the region's wholesale electricity markets, and managing regional planning processes. ISO New England is regulated by the Federal Energy Regulatory Commission, and has both internal and external market monitors who review its performance. The internal market monitor is a unit within ISO New England Inc., while the external market monitor is an independent outside consultant. Potomac Economics currently serves as the external market monitor.
Potomac's report found that "the markets performed competitively in 2011". One piece of evidence Potomac used to support this finding is that average energy prices fell 7 percent from 2010 to 2011 (from approximately $53 per MWh in 2010 to $49 in 2011). According to the report, this is due in large part to a decrease in the average price of natural gas. In Potomac's view, lower fuel costs translate to lower prices in a well-functioning, competitive market because fuel costs constitute the vast majority of the marginal costs of most generation. Natural gas pricing decreases were not the only contributor to lower energy prices, according to the report; Potomac also noted that prices fell due to a weather-driven decrease in demand for electricity, stating that, "Average load decreased 1 percent from 2010 to 2011 and 2.5 percent from the summer of 2010 to the summer of 2011, primarily due to milder weather."
Potomac also found that "both the day-ahead and real-time markets operated relatively efficiently in 2011 as prices appropriately reflected the effects of lower fuel prices and load levels." However, the external market monitor found that "real-time prices often do not fully reflect the cost of satisfying demand and maintaining reliability during tight market conditions, particularly when fast-start resources or demand response resources are deployed in the real-time market." As a result, the report recommended a series of changes to the New England markets, including developing pricing changes to allow the actual costs of demand response and fast-start resources to be reflected in prices.
The report was filed with the Federal Energy Regulatory Commission on June 25. It complements the 2011 Annual Markets Report (121-page PDF), released this May by ISO New England's internal market monitor. The internal market monitor's report similarly found that the markets operated competitively in 2011.
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