As federal regulators of U.S. energy markets update their systems to track electricity sales, the Federal Energy Regulatory Commission has temporarily extended the deadline for utilities to file Electric Quarterly Reports (known as EQRs).
Under Section 205(c) of the Federal Power Act, "public utilities" must file their rates with the FERC and make them availble for public inspection. These utilities include traditional vertically-integrated electric companies owning transmission systems as well as independent generators, and even industrial manufacturers with on-site electricity generating facilities and other entities authorized to sell electricity into wholesale markets.
To implement this requirement, the FERC requires utilities to file information about they electricity they sell at negotiated or market-based rates. To accomplish this, utilities make quarterly filings using FERC's EQR system, which has been in place since 2002. Most recently, utilities have been required to use free software developed by the FERC to submit EQRs.
While the FERC has updated this proprietary software from time to time, it has been left behind in capability and convenience by more modern technologies and interfaces. Following the recent FERC Order No. 768, which broadenied EQR filing responsibilites to cover certain non-public utilities, the FERC announced in Order No. 770 that it would transition to a new web-based interface effective with the filings for the third quarter of 2013. In explaining this shift, the FERC noted that technology changes will render the current filing process "outmoded, ineffective, and unsustainable." These filings would normally be due on October 31, 2013.
When filing requirements change, as they have several times in the last decade, filers experience a learning curve as they seek to understand the new system. At the same time, the FERC's development of the new system remains a work in progress. In an order issued on October 16, the FERC announced that the new web-based approach is not yet available, and extended the deadline to file Q3 2013 EQRs from October 31, 2013 to "a date to be determined." Once the new web-based approach is available, the FERC will notify all filers and provide the new deadline for filing Q3 2013 EQRs.
For now, filers have some time to prepare for the new system.
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How New England plans to keep the lights on this winter
Thursday, October 10, 2013
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?
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?
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?
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| 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?
Predictions for renewable energy in 2013
Tuesday, October 8, 2013
With under three months left in 2013, we will soon learn whether this year's projections for the energy industry prove accurate. The U.S. Energy Information Administration publishes a series of short-term energy outlook reports covering crude oil and liquid fuels, natural gas, coal, and electricity. What has EIA forecast for the year in renewable energy?
EIA projects a continued increase in the consumption of renewable energy in the forms of electricity and heat generation. Overall, in 2013 EIA expects 4.5% growth over 2012's renewable energy consumption, with further growth of 2.3% in 2014.
EIA also predicts shifts in the resource mix providing this renewable energy. In 2013, EIA expects a 1.5% decline in hydropower production, offset by 8.3% average growth of nonhydropower renewables used for electricity and heat generation. In particular, EIA expects 2.5% growth in wind capacity this year, reaching a total installed capacity of about 61 gigawatts from wind. This capacity is predicted to enable generation from wind to increase 19% in 2013 and another 2.4% in 2014, at which point it is expected to reach over 4% of all electricity generated in the U.S.
Solar energy is expected to grow more sharply, but will remain a relatively small segment of the nation's overall energy portfolio. EIA expects solar generation by the electric power sector to increase a staggering 79% in 2013 and 80% in 2014. In recent years, customer-sited distributed generation projects have led the charge in new capacity additions, but EIA expects utility-scale projects to more than double in total installed capacity between 2012 and 2014. Most of this new utility-scale solar capacity will continue to come from photovoltaics, but several large solar thermal generation projects may come online the next two years. Despite this relative growth, the small absolute size of the U.S. solar market means that solar energy will only account for about 0.3% of energy consumed in 2014.
When 2013 has ended, will EIA's predictions come true? We will learn in several months.
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| Fall foliage and solar photovoltaic panels at Cider Hill Farm in Amesbury, Massachusetts. |
EIA projects a continued increase in the consumption of renewable energy in the forms of electricity and heat generation. Overall, in 2013 EIA expects 4.5% growth over 2012's renewable energy consumption, with further growth of 2.3% in 2014.
EIA also predicts shifts in the resource mix providing this renewable energy. In 2013, EIA expects a 1.5% decline in hydropower production, offset by 8.3% average growth of nonhydropower renewables used for electricity and heat generation. In particular, EIA expects 2.5% growth in wind capacity this year, reaching a total installed capacity of about 61 gigawatts from wind. This capacity is predicted to enable generation from wind to increase 19% in 2013 and another 2.4% in 2014, at which point it is expected to reach over 4% of all electricity generated in the U.S.
Solar energy is expected to grow more sharply, but will remain a relatively small segment of the nation's overall energy portfolio. EIA expects solar generation by the electric power sector to increase a staggering 79% in 2013 and 80% in 2014. In recent years, customer-sited distributed generation projects have led the charge in new capacity additions, but EIA expects utility-scale projects to more than double in total installed capacity between 2012 and 2014. Most of this new utility-scale solar capacity will continue to come from photovoltaics, but several large solar thermal generation projects may come online the next two years. Despite this relative growth, the small absolute size of the U.S. solar market means that solar energy will only account for about 0.3% of energy consumed in 2014.
When 2013 has ended, will EIA's predictions come true? We will learn in several months.
NJ offshore wind project faces dilemma
Monday, October 7, 2013
Fishermen's Energy's proposed offshore wind project off the New Jersey coast has essentially all its permits in place to start construction -- but the project's future is in doubt over a question of financial support from electricity ratepayers.
Fishermen's Energy has proposed building a 25-megawatt wind project about 2.8 miles off the coast of Atlantic City. The $200 million project would be connected to the mainland electricity grid, enabling the power it produces to be sold to New Jersey electric customers. The project has already received key permits, such as approval by the Army Corps of Engineers to begin construction.
Building what could be the nation's first commercial offshore wind project will be expensive. While future offshore wind projects could be cost-competitive against more traditional electric generation resources, the New Jersey pilot project's finances rely on a portfolio of federal and state financial incentives. These include federal tax credits, a grant from the U.S. Department of Energy, and a state commitment that utility ratepayers will shoulder above-market costs.
A 2010 New Jersey law established an offshore wind renewable energy certificate program known as OREC that was designed to provide that ratepayer commitment. For over a year, Fishermen's Energy has been waiting for the New Jersey Board of Public Utilities to decide whether to require mainland utilities to purchase the project’s renewable energy output. But that case remains pending, with no clear state-law timeline for its resolution. Issues in play include the project's cost to ratepayers, particularly if the project fails to win further competitive grants from the federal Department of Energy.
In the meantime, Fishermen’s Energy needs to spend at least $10 million on the project this year to remain eligible for the federal investment tax credit. Yet the developer is presumably reluctant to commit those funds before learning whether it will also win ratepayer support. As December 31 draws nearer, this dilemma makes it more challenging for Fishermen's Energy to sustain project development efforts.
Fishermen's Energy has proposed building a 25-megawatt wind project about 2.8 miles off the coast of Atlantic City. The $200 million project would be connected to the mainland electricity grid, enabling the power it produces to be sold to New Jersey electric customers. The project has already received key permits, such as approval by the Army Corps of Engineers to begin construction.
Building what could be the nation's first commercial offshore wind project will be expensive. While future offshore wind projects could be cost-competitive against more traditional electric generation resources, the New Jersey pilot project's finances rely on a portfolio of federal and state financial incentives. These include federal tax credits, a grant from the U.S. Department of Energy, and a state commitment that utility ratepayers will shoulder above-market costs.
A 2010 New Jersey law established an offshore wind renewable energy certificate program known as OREC that was designed to provide that ratepayer commitment. For over a year, Fishermen's Energy has been waiting for the New Jersey Board of Public Utilities to decide whether to require mainland utilities to purchase the project’s renewable energy output. But that case remains pending, with no clear state-law timeline for its resolution. Issues in play include the project's cost to ratepayers, particularly if the project fails to win further competitive grants from the federal Department of Energy.
In the meantime, Fishermen’s Energy needs to spend at least $10 million on the project this year to remain eligible for the federal investment tax credit. Yet the developer is presumably reluctant to commit those funds before learning whether it will also win ratepayer support. As December 31 draws nearer, this dilemma makes it more challenging for Fishermen's Energy to sustain project development efforts.
What federal shutdown means for energy
Tuesday, October 1, 2013
With Congress's failure to pass a budget, today the U.S. federal government entered shutdown mode. For 800,000 federal workers, shutdown means being furloughed until Congress resolves the budget. What does the shutdown mean for the energy sector?
Each federal agency is reacting differently to the shutdown. For the Federal Energy Regulatory Commission, it means continued normal business operations - as long as it still has funds on hand. What happens after that? According to a contingency plan issued last week, when those funds run out, FERC will continue "only those excepted activities authorized by law" to the extent that they protect life and property. These activities include the work of the Commissioners themselves, hydroelectric and liquefied natural gas inspections, managing the reliability of the nation's electric and gas systems, and monitoring market operations.
The U.S. Department of Energy faces similar impacts from the shutdown. It has some funds remaining on hand, but when those funds run out, according to its "lapse in appropriations plan", of its 13,814 employees, only 1,113 excepted personnel and 11 Presidentially-appointed and Senate-confirmed employees will remain on the job.
The Bureau of Ocean Energy Management will continue some operations. According to its contingency plan, between 35 – 40% of Bureau employees will continue to report for full time duty, and BOEM will continue to work on current offshore wind projects and other renewable energy plans.
Each federal agency is reacting differently to the shutdown. For the Federal Energy Regulatory Commission, it means continued normal business operations - as long as it still has funds on hand. What happens after that? According to a contingency plan issued last week, when those funds run out, FERC will continue "only those excepted activities authorized by law" to the extent that they protect life and property. These activities include the work of the Commissioners themselves, hydroelectric and liquefied natural gas inspections, managing the reliability of the nation's electric and gas systems, and monitoring market operations.
The U.S. Department of Energy faces similar impacts from the shutdown. It has some funds remaining on hand, but when those funds run out, according to its "lapse in appropriations plan", of its 13,814 employees, only 1,113 excepted personnel and 11 Presidentially-appointed and Senate-confirmed employees will remain on the job.
The Bureau of Ocean Energy Management will continue some operations. According to its contingency plan, between 35 – 40% of Bureau employees will continue to report for full time duty, and BOEM will continue to work on current offshore wind projects and other renewable energy plans.
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