Maine utility regulators have amended rules governing net energy billing for electricity customers, in the wake of recently enacted laws requiring the rules to be restored to how they read prior to changes adopted in 2017 that cut the value of net metering for customers with solar panels or other distributed generation. The Maine Public Utilities Commission's July 31, 2019 order amending its Chapter 313 net energy billing rules describes the amendments as intended to make the rules "substantively equivalent to the rules in effect on January 1, 2017." Further reforms will follow, as a new law taking effect on September 19, 2019 requires further changes to net metering that significant expand customers' opportunities to participate in distributed generation projects.
Since the 1980s, Maine has allowed electricity customers who install their own small generating facilities to "net meter" or offset their electricity bills with electricity they inject into the grid. In 2017, the Commission approved amendments to its rule that reduced the amount of energy that could be used to offset a customer's transmission and distribution bill.
But those amendments were controversial for a variety of reasons, including their requirement that net energy billing customers install a costly second meter, their imposition of transmission and distribution charges for electricity that a customer both produces and consumes in real-time within its own facilities, and for their overall reduction of the value to customers of operating distributed generation.
In 2019, the Maine State Legislature enacted a law directing the Commission to amend its net energy billing rules to be substantively equivalent to the rules in effect on January 1, 2017, and, further, that the amended rules must apply to all customers that entered into a net energy billing arrangement between March 29, 2017 and the effective date of the new rules. On July 31, the Commission took that step. It amended Chapter 313 to define net energy as the difference between the energy produced by the generating facility and the energy used by the customer or shared ownership customers, required that customers be billed on this basis, and made a handful of other changes the Commission described in its statement of factual and policy basis as "non-substantive."
Separately, the 2019 Maine legislature enacted a law significantly expanding net energy billing. This
law expands the maximum size of a generating facility eligible for net energy
metering, from 660 kilowatts to 5 megawatts. It also eliminates any limit on
the number of customers in the territories served by investor-owned utility who
may “share ownership” and net meter against a given project’s output. The new law allows a customer with a power purchase agreement to be considered a "shared owner", in addition to those who own or lease a facility. A new variation on net energy billing provides additional
value specifically for nonresidential customers
of an investor-owned utility: a voluntary
tariff rate providing a monetary bill credit for any electricity delivered to
the electric grid from a distributed generation resource, equal to the
applicable standard offer service rate for that customer receiving the credit
plus 75% of the effective transmission and distribution rate for the rate class
that includes the smallest commercial customers of the investor-owned
transmission and distribution utility. The law requires the Commission to develop tariffs and rules implementing these additional reforms, which the Commission is expected to do in the coming months.
Energy powers society; society's choices shape energy policy. A blog about our energy resources and the choices they present for society.
Heat pumps efficient, getting even better
Tuesday, July 30, 2019
As society looks to use less petroleum for heating, heat pumps represent an alternative that can use electricity to provide space heating and cooling. U.S. efficiency standards for heat pumps are set to tighten in 2023 -- but in many cases, the heat pumps sold today already meet those future standards.
Heat pumps can provide heat while avoiding direct combustion and carbon emissions, and can be powered by electricity from renewable resources. Heat pumps can also be cost-effective and efficient. According to the Maine Department of Environmental Protection, Maine's residential sector is responsible for 18% of the state's total greenhouse gas emissions, primarily resulting from space heating. Heat pumps offer a significant opportunity for "beneficial electrification" -- using electricity generated by lower-carbon resources to displace the direct combustion of higher-carbon fossil fuels. Nationally, according to federal data, about 13 million homes (11% of the total) use heat pumps for heating or cooling, and many states are increasing incentives for heat pump installation.
Heat pumps sold in the U.S. are subject to federal efficiency standards. Under the Energy Policy and Conservation Act of 1975, the U.S. Department of Energy has the authority to develop and implement minimum energy conservation standards for appliances and equipment , and to revise the standards if the amendments are energy-saving, technologically feasible, and economically justifiable. The subsequent National Appliance Energy Conservation Act of 1987 set minimum efficiency requirements for central air-conditioning and heat pump equipment sold in the United States. The first round of efficiency standards under that law took effect in 1992, with amendments in 2006 and 2015.
Heat pump efficiency can be measured by a metric called heating seasonal performance factor or HSPF. HSPF represents the ratio of heat output over the heating season to watt-hours of electricity used; higher numbers mean the consumer got more heat for less electricity. Under the currently effective standards set in 2015, air-source heat pumps sold in the U.S. must have a HSPF of at least 8.2. But under a 2017 Department of Energy rulemaking, beginning in 2023, the minimum HSPF will increase to 8.8.
While the tightened standard may affect some models with marginal efficiency, many heat pumps sold today already outperform the 2023 standard, as do most incentivized by state and utility programs. For example, Efficiency Maine Trust's rebate program for ductless heat pumps provides incentives for installations with a minimum HSPF of 12.0 for systems with one indoor unit or 10.0 for systems with more than one indoor unit. Because these incentivized units all exceed the future federal standard, their sales should not be affected by the 2023 standard. If nothing else, the tightening performance standards suggest that heat pumps will continue to play an increasing role in space heating and cooling over the coming years.
Heat pumps can provide heat while avoiding direct combustion and carbon emissions, and can be powered by electricity from renewable resources. Heat pumps can also be cost-effective and efficient. According to the Maine Department of Environmental Protection, Maine's residential sector is responsible for 18% of the state's total greenhouse gas emissions, primarily resulting from space heating. Heat pumps offer a significant opportunity for "beneficial electrification" -- using electricity generated by lower-carbon resources to displace the direct combustion of higher-carbon fossil fuels. Nationally, according to federal data, about 13 million homes (11% of the total) use heat pumps for heating or cooling, and many states are increasing incentives for heat pump installation.
Heat pumps sold in the U.S. are subject to federal efficiency standards. Under the Energy Policy and Conservation Act of 1975, the U.S. Department of Energy has the authority to develop and implement minimum energy conservation standards for appliances and equipment , and to revise the standards if the amendments are energy-saving, technologically feasible, and economically justifiable. The subsequent National Appliance Energy Conservation Act of 1987 set minimum efficiency requirements for central air-conditioning and heat pump equipment sold in the United States. The first round of efficiency standards under that law took effect in 1992, with amendments in 2006 and 2015.
Heat pump efficiency can be measured by a metric called heating seasonal performance factor or HSPF. HSPF represents the ratio of heat output over the heating season to watt-hours of electricity used; higher numbers mean the consumer got more heat for less electricity. Under the currently effective standards set in 2015, air-source heat pumps sold in the U.S. must have a HSPF of at least 8.2. But under a 2017 Department of Energy rulemaking, beginning in 2023, the minimum HSPF will increase to 8.8.
While the tightened standard may affect some models with marginal efficiency, many heat pumps sold today already outperform the 2023 standard, as do most incentivized by state and utility programs. For example, Efficiency Maine Trust's rebate program for ductless heat pumps provides incentives for installations with a minimum HSPF of 12.0 for systems with one indoor unit or 10.0 for systems with more than one indoor unit. Because these incentivized units all exceed the future federal standard, their sales should not be affected by the 2023 standard. If nothing else, the tightening performance standards suggest that heat pumps will continue to play an increasing role in space heating and cooling over the coming years.
US energy regulators create LNG division
Wednesday, July 24, 2019
The Federal Energy Regulatory Commission has reorganized its structure to create a new Division of LNG Facility Review & Inspection (DLNG), to accommodate the growing number and complexity of applications to
site, build and operate liquefied natural gas export terminals.
The Commission is responsible for authorizing the siting and construction of onshore and near-shore LNG import or export facilities under Section 3 of the Natural Gas Act. The first exports from the Lower 48 came in February 2016, when the first cargo shipped from the Sabine Pass terminal in Louisiana, but exports have since grown significantly. Since 2017, the U.S. has exported more natural gas than it imports. U.S. LNG export capacity is on track to double from 5 billion cubic feet per day to 10 Bcf/d by the end of 2020, with significantly more export capacity approved or pending.
The Commission has said that since April 2018, it has grown from 13 to 20 staff dedicated to working on LNG engineering and review issues. In addition, it has announced plans to hire eight more LNG experts to staff a new Houston Regional Office.
According to the Commission, its creation of DLNG and establishment of a new Houston office will help prepare the agency "for the additional work necessary once LNG project applicants make final investment decisions and move toward construction."
The Commission is responsible for authorizing the siting and construction of onshore and near-shore LNG import or export facilities under Section 3 of the Natural Gas Act. The first exports from the Lower 48 came in February 2016, when the first cargo shipped from the Sabine Pass terminal in Louisiana, but exports have since grown significantly. Since 2017, the U.S. has exported more natural gas than it imports. U.S. LNG export capacity is on track to double from 5 billion cubic feet per day to 10 Bcf/d by the end of 2020, with significantly more export capacity approved or pending.
The Commission has said that since April 2018, it has grown from 13 to 20 staff dedicated to working on LNG engineering and review issues. In addition, it has announced plans to hire eight more LNG experts to staff a new Houston Regional Office.
According to the Commission, its creation of DLNG and establishment of a new Houston office will help prepare the agency "for the additional work necessary once LNG project applicants make final investment decisions and move toward construction."
Electric utility rate cases on the rise
Monday, July 22, 2019
Federal data shows an increase in the number of U.S. electric utility rate cases filed in 2018, to the largest number since 1983. Of the 89 utilities filing rate cases in 2018, 10 proposed to decrease rates, one proposed a rate freeze until next year, and the remaining 78 utilities proposed to increase their rates.
Under typical state law, public electric utility companies must obtain regulatory approvals before changing the rates they charge their customers. According to the U.S. Energy Information Administration, 89 electric utilities sought to change their rates by filing rate cases with state regulatory commissions in 2018. This represents a significant increase relative to two decades ago.
According to EIA, the frequency or number of electric utility rate cases "typically reflects changes in the costs of generating and delivering electricity." For 2018, EIA pointed to increases in spending for electric transmission and delivery (as opposed to generation) as driving most of the rate increases that were ultimately approved.
EIA notes that the last time electric utility rate case filings were this active was the early 1980s, an era of significant rate increases: electricity rates increased at an average annual rate of 12% in the decade following the 1973 oil embargo. To explain that historic period of numerous rate cases, EIA points to factors including investments in coal and nuclear plants following the oil crisis; the enactment of the federal Public Utility Regulatory Policies Act of 1978 (PURPA), which required utilities to purchase electricity from generation from small, independently-owned renewable facilities, and the 1979 Three Mile Island nuclear plant accident which placed increased focus (and expense) on the safety of nuclear plants. By contrast, during a period of time when the Federal Energy Regulatory Commission was restructuring most electric markets (between 1995 and 2000), fewer than 20 rate cases were filed in most years.
Utilities typically ask for approval of significantly higher rate increases than are ultimately approved by regulators. According to EIA, in 2018, utilities asked for an aggregate rate increase $6.8 billion, but regulators approved a total increase of just $2.8 billion.
Under typical state law, public electric utility companies must obtain regulatory approvals before changing the rates they charge their customers. According to the U.S. Energy Information Administration, 89 electric utilities sought to change their rates by filing rate cases with state regulatory commissions in 2018. This represents a significant increase relative to two decades ago.
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| Source: U.S. Energy Information Administration |
According to EIA, the frequency or number of electric utility rate cases "typically reflects changes in the costs of generating and delivering electricity." For 2018, EIA pointed to increases in spending for electric transmission and delivery (as opposed to generation) as driving most of the rate increases that were ultimately approved.
EIA notes that the last time electric utility rate case filings were this active was the early 1980s, an era of significant rate increases: electricity rates increased at an average annual rate of 12% in the decade following the 1973 oil embargo. To explain that historic period of numerous rate cases, EIA points to factors including investments in coal and nuclear plants following the oil crisis; the enactment of the federal Public Utility Regulatory Policies Act of 1978 (PURPA), which required utilities to purchase electricity from generation from small, independently-owned renewable facilities, and the 1979 Three Mile Island nuclear plant accident which placed increased focus (and expense) on the safety of nuclear plants. By contrast, during a period of time when the Federal Energy Regulatory Commission was restructuring most electric markets (between 1995 and 2000), fewer than 20 rate cases were filed in most years.
Utilities typically ask for approval of significantly higher rate increases than are ultimately approved by regulators. According to EIA, in 2018, utilities asked for an aggregate rate increase $6.8 billion, but regulators approved a total increase of just $2.8 billion.
Maine regulators approve long-term contract
Friday, July 19, 2019
Maine utility regulators have approved a long-term contract to purchase the output of a 72.6-megawatt wind power project under development by Weaver Wind, LLC in Hancock County, Maine. The 20-year contract bears a price of 3.5 cents per kilowatt-hour, escalating at 2.5 percent per year.
A Maine statute enacted in 2006 authorizes the Public Utilities Commission to direct investor-owned transmission and distribution utilities to enter into long-term contracts, to the degree necessary to ensure reliability, meet energy efficiency program requirements, or reduce customer costs. In 2008, the Commission used this law to order a contract with the Rollins Wind project. After three subsequent procurement rounds, in 2017 the Commission approved a contract to buy 75 megawatts from Dirigo Solar, LLC, at a price of 3.4 cents/kWh escalating at 2.5% annually for 20 years.
In response to its most recent solicitation, earlier this year the Commission approved a term sheet for a contract to buy 100 megawatts from Three Rivers Solar Power, LLC’s solar project, with a price of 3.5 cents/kWh escalating at 2.5% annually for 10 years. Most recently, on July 12, 2019, the Commission approved a contract to buy the output of the Weaver Wind project, also at a price of 3.5 cents/kWh escalating at 2.5% annually for 10 years.
In addition to this existing law, in 2019 the Maine state legislature enacted several additional long-term contracting programs. One new law creates a new "Class IA" renewable portfolio standard, and requires the procurement by December 31, 2020 of energy or renewable energy credits from Class IA resources sufficient to cover between 7 and 10 percent of Maine's retail electricity sales, with a second round bringing the total procurement to 14 percent of Maine's retail electricity sales. Another new law requires the procurement of 375 megawatts from distributed generation resources between 2020 and 2024, with each project sized at less than 5 megawatts, and specific requirements for participation by non-residential and "community" or shared-ownership projects.
Collectively, these laws create a variety of opportunities for electric power generation projects to compete for and win long-term contracts to sell their output to Maine utilities.
A Maine statute enacted in 2006 authorizes the Public Utilities Commission to direct investor-owned transmission and distribution utilities to enter into long-term contracts, to the degree necessary to ensure reliability, meet energy efficiency program requirements, or reduce customer costs. In 2008, the Commission used this law to order a contract with the Rollins Wind project. After three subsequent procurement rounds, in 2017 the Commission approved a contract to buy 75 megawatts from Dirigo Solar, LLC, at a price of 3.4 cents/kWh escalating at 2.5% annually for 20 years.
In response to its most recent solicitation, earlier this year the Commission approved a term sheet for a contract to buy 100 megawatts from Three Rivers Solar Power, LLC’s solar project, with a price of 3.5 cents/kWh escalating at 2.5% annually for 10 years. Most recently, on July 12, 2019, the Commission approved a contract to buy the output of the Weaver Wind project, also at a price of 3.5 cents/kWh escalating at 2.5% annually for 10 years.
In addition to this existing law, in 2019 the Maine state legislature enacted several additional long-term contracting programs. One new law creates a new "Class IA" renewable portfolio standard, and requires the procurement by December 31, 2020 of energy or renewable energy credits from Class IA resources sufficient to cover between 7 and 10 percent of Maine's retail electricity sales, with a second round bringing the total procurement to 14 percent of Maine's retail electricity sales. Another new law requires the procurement of 375 megawatts from distributed generation resources between 2020 and 2024, with each project sized at less than 5 megawatts, and specific requirements for participation by non-residential and "community" or shared-ownership projects.
Collectively, these laws create a variety of opportunities for electric power generation projects to compete for and win long-term contracts to sell their output to Maine utilities.
2019 Maine energy legislation
The First Regular Session of the 129th Maine State Legislature adjourned on June 20, 2019, after having enacted 530 new public laws. Here's a look at some of the significant energy legislation enacted this year:
- An Act to Promote Clean Energy Jobs and To Establish the Maine Climate Council, P.L. 2019, c. 476: This bill establishes the Maine Climate Council to advise the Governor and state Legislature on ways to mitigate the causes of, prepare for and adapt to the consequences of climate change, and calls for the Department of Environmental Protection to adopt regulations requiring significant reductions in the state's overall greenhouse gas emissions.
- An Act To Reform Maine's Renewable Portfolio Standard, P.L. 2019, c. 477: This bill adds two new renewable portfolio standards, along with a procurement program. In addition to Maine's preexisting Class I and Class II RPS requirements, the new law adds a new Class IA requirement which increases from 2.5% of retail sales in 2020 to 40% in 2030. Class IA resources are basically the same resources that could qualify as Class I under existing law – “new” renewables installed or refurbished after September 1, 2005 – except Class IA excludes resources that satisfy the “newness” requirement by restarting after 2 years of downtime, even though these can qualify for Class I. Large customers may elect to opt out; retail sales to a customer who opts out are not subject to the Class IA mandate, in exchange for which the customer may not generate Class IA RECs. The bill also requires each competitive electricity provider to demonstrate to the Commission that it accounted for a defined percentage of its retail electricity sales in Maine with thermal renewable energy certificates or RECs, representing useful heat or thermal energy produced by certain technologies and delivered to an end-use customer for use. The thermal REC mandate increases from 0.4% in 2021 to 4% in 2030. Large customers may elect to opt out; retail sales to a customer who opts out are not subject to the thermal REC mandate, in exchange for which the customer may not generate thermal RECs. Finally, the law requires the Commission to conduct a series of solicitations to procure long-term contracts for an annual amount of energy or RECs from Class IA resources equal to 14% of Maine’s annual retail electricity sales. A first procurement round, for between 7% and 10% of Maine’s 2018 retail sales, must be concluded with contracts approved by December 31, 2020. A second round for the remaining amount needed to cover 14% of sales must be completed by December 31, 2020. 75% of the energy or RECs contracted must come from Class IA resources that began commercial operations after to June 30, 2019, and 25% from Class IA resources that started up on or prior to that date. In evaluating bids, benefits to ratepayers gets 70% weighting, and economic benefits get 30% weighting. Bids may include energy storage systems.
- <An Act To Promote Solar Energy Projects and Distributed Generation Resources in Maine, P.L. 2019, c. 478: This law expands the maximum size of a generating facility eligible for net energy metering, from 660 kilowatts to 5 megawatts. It also eliminates any limit on the number of customers in the territories served by investor-owned utility who may “share ownership” and net meter against a given project’s output. “Shared ownership” forms include facility ownership, a lease agreement or a power purchase agreement. A new variation on net energy billing provides additional value specifically for commercial and institutional (nonresidential) customers of an investor-owned utility, for whom demand charges may constitute a relatively high portion of the total electricity bill. For these customers, LD 1711 requires the Public Utilities Commission to establish by rule a voluntary tariff rate, which will provide a bill credit for any electricity delivered to the electric grid from a distributed generation resource, equal to the applicable standard offer service rate for that customer receiving the credit plus 75% of the effective transmission and distribution rate for the rate class that includes the smallest commercial customers of the investor-owned transmission and distribution utility. The credit is monetary and can be applied to any portion of the bill, including demand charges. A customer who enrolls may receive service under the tariff rate for at least 20 years. By allowing monetary crediting of facilities up to 5 megawatts against a customer’s total bill, including demand and customer charges, the newly enacted law encourages the development of larger solar or other net metered facilities, capable of generating sufficient bill credits at the specified tariff rate to offset some or all of the customer’s bill on a monetary basis. The law also requires the investor-owned utilities to serve as counterparties for long-term power purchase agreements with distributed generation resources.
- An Act to Establish a Green New Deal for Maine, P.L. 2019, c. 347: This law requires construction employers constructing a generation facility of 2 megawatts or more, other than a facility located on the customer side of an electric meter, to use a workforce that includes a defined percentage of apprentices. The law also requires that when a new school is constructed, Efficiency Maine Trust shall solicit bids for solar power purchase agreements, and award a power purchase agreement to the qualified bidder that offers the lowest price for the school to purchase the solar installation at the end of the term of the power purchase agreement. In such a case, the Commission shall direct the transmission and distribution utility serving the school to administer the power purchase agreement on behalf of the school in a manner, so far as possible, consistent with section 3210-C.
US energy-related CO2 emissions projected to decline
Wednesday, July 17, 2019
Energy-related carbon dioxide emissions in the U.S. are projected to decrease by 2.2 percent in 2019 relative to the previous year, according to the latest forecast by the U.S. Energy Information Administration.
EIA tracks energy-related carbon dioxide emissions from petroleum, natural gas, and coal. Petroleum made up nearly half of energy-related CO2 emissions in 2018, at 45 percent of all energy-related carbon dioxide emissions. Transportation, heating, and electric power generation sectors consume significant amounts of petroleum. EIA projects petroleum CO2 emissions will remain relatively flat in 2019, relative to 2018.
According to EIA, nearly all of its forecast decrease for 2019 is due to reduced emissions from coal consumption. EIA forecasts that coal-derived CO2 emissions will decrease by 169 million metric tons (MMmt) in 2019. This represents the largest year-over-year decrease in coal-derived CO2 emissions since 2015. Nearly all the coal used in the U.S. -- 92 percent -- is consumed by the electric power sector; EIA attributes the decline to forecast changes in the electricity generation mix, with coal plants retiring and relatively milder summer weather expected to lead to overall lower electricity demand.
While coal-related emissions are projected to decline, EIA projects that forecast natural gas CO2 emissions will increase by 53 MMmt, largely due to increased use of natural gas to displace coal for electric power generation. According to EIA, the decrease in coal emissions will more than outweigh the increase in natural gas emissions, because natural gas-fired electricity generation is less carbon-intensive than coal-fired electricity generation.
EIA tracks energy-related carbon dioxide emissions from petroleum, natural gas, and coal. Petroleum made up nearly half of energy-related CO2 emissions in 2018, at 45 percent of all energy-related carbon dioxide emissions. Transportation, heating, and electric power generation sectors consume significant amounts of petroleum. EIA projects petroleum CO2 emissions will remain relatively flat in 2019, relative to 2018.
According to EIA, nearly all of its forecast decrease for 2019 is due to reduced emissions from coal consumption. EIA forecasts that coal-derived CO2 emissions will decrease by 169 million metric tons (MMmt) in 2019. This represents the largest year-over-year decrease in coal-derived CO2 emissions since 2015. Nearly all the coal used in the U.S. -- 92 percent -- is consumed by the electric power sector; EIA attributes the decline to forecast changes in the electricity generation mix, with coal plants retiring and relatively milder summer weather expected to lead to overall lower electricity demand.
While coal-related emissions are projected to decline, EIA projects that forecast natural gas CO2 emissions will increase by 53 MMmt, largely due to increased use of natural gas to displace coal for electric power generation. According to EIA, the decrease in coal emissions will more than outweigh the increase in natural gas emissions, because natural gas-fired electricity generation is less carbon-intensive than coal-fired electricity generation.
Maine Climate Council legislation enacted
Monday, July 15, 2019
Newly enacted Maine legislation establishes the Maine Climate Council to advise the Governor and state Legislature on ways to mitigate the causes of, prepare for and adapt to the consequences of climate change, and calls for significant reductions in the state's overall greenhouse gas emissions.
On June 26, 2019, Maine Governor Janet Mills signed into law An Act to Promote Clean Energy Jobs and To Establish the Maine Climate Council. One set of provisions in the new law establishes a requirement that Maine reduce gross annual greenhouse gas emissions -- to at least 45% below the 1990 gross annual greenhouse gas emissions level by 2030, at least 80% below the 1990 gross annual greenhouse gas emissions level by 2050, and on track to meet the 2050 target by 2040. The law requires the Department of Environmental Protection to adopt rules to ensure compliance with these levels, and authorizes the Department of Transportation to adopt similar rules.
Crucially, the rules must prioritize greenhouse gas emissions reductions by sectors that are the most significant sources of greenhouse gas emissions, as identified by the United States Energy Information Administration and in the department's biennial reports, taking into account gross greenhouse gas emissions reductions achieved by each sector since 1990 and the cost-effectiveness of future gross greenhouse gas emissions reductions by each sector. While the electricity sector has largely been decarbonized, transportation and heating lag significantly. Maine's transportation sector was responsible for 53 percent of the state's greenhouse gas emissions in 2017, with heating taking the next greatest share. Meanwhile, electricity generation in Maine accounted for just 9 percent of the state's greenhouse gas emissions.
The law also creates a 39-member Maine Climate Council, with a subcommittee for scientific and technical matters and various working groups. The Council must meet at least every three months, report annually to a legislative committee, and prepare an updated climate action plan by December 1, 2020 and every four years thereafter. The climate action plan must include a clean energy economy transition plan.
On June 26, 2019, Maine Governor Janet Mills signed into law An Act to Promote Clean Energy Jobs and To Establish the Maine Climate Council. One set of provisions in the new law establishes a requirement that Maine reduce gross annual greenhouse gas emissions -- to at least 45% below the 1990 gross annual greenhouse gas emissions level by 2030, at least 80% below the 1990 gross annual greenhouse gas emissions level by 2050, and on track to meet the 2050 target by 2040. The law requires the Department of Environmental Protection to adopt rules to ensure compliance with these levels, and authorizes the Department of Transportation to adopt similar rules.
Crucially, the rules must prioritize greenhouse gas emissions reductions by sectors that are the most significant sources of greenhouse gas emissions, as identified by the United States Energy Information Administration and in the department's biennial reports, taking into account gross greenhouse gas emissions reductions achieved by each sector since 1990 and the cost-effectiveness of future gross greenhouse gas emissions reductions by each sector. While the electricity sector has largely been decarbonized, transportation and heating lag significantly. Maine's transportation sector was responsible for 53 percent of the state's greenhouse gas emissions in 2017, with heating taking the next greatest share. Meanwhile, electricity generation in Maine accounted for just 9 percent of the state's greenhouse gas emissions.
The law also creates a 39-member Maine Climate Council, with a subcommittee for scientific and technical matters and various working groups. The Council must meet at least every three months, report annually to a legislative committee, and prepare an updated climate action plan by December 1, 2020 and every four years thereafter. The climate action plan must include a clean energy economy transition plan.
ISO-NE expects competitive Boston transmission solicitation
Thursday, July 11, 2019
The operator of New England's electricity system has announced an upcoming competitive solicitation for transmission proposals to address the expected retirement of a large power plant outside Boston. The solicitation would be significant, as the region's first competitive transmission procurement since a 2011 order by federal regulators created a competitive selection process for certain transmission upgrades.
In 2011, the Federal Energy Regulatory Commission issued its landmark Order No. 1000, reforming how public utilities plan and pay for transmission upgrades. In issuing the order, the Commission noted that changes in the generation mix were driving significant expansions of the transmission system -- but that "the narrow focus of current planning requirements and shortcomings of current cost allocation practices create an environment that fails to promote the more efficient and cost-effective development of new transmission facilities." Order No. 1000 aimed to address these problems by providing a framework for fair and open evaluation of regional transmission needs, and for fair allocation of the costs of transmission solutions to their beneficiaries.
Each regional transmission organization revised its tariff to conform to Order No. 1000. Since the order took effect, several other regional transmission organizations have engaged in competitive solicitations for transmission solutions. But to date, ISO New England Inc. has not. That may soon change, as according to ISO-NE, the grid operator expects to issue a request for proposals in the coming months. In a statement, ISO-NE notes that Exelon has sought to retire the Mystic Generating Station outside Boston -- one of the largest power plants in New England, located adjacent to the region's most concentrated demand -- in June 2022. While ISO-NE chose to retain two of the Mystic units until June 1 2024 for fuel-security reasons, a Boston 2028 Needs Assessment and other studies by the grid operator led it to announce plans to issue its first request for proposals for a competitively-selected regulated transmission solution, pursuant to Oder No. 1000.
ISO-NE has released the draft RFP templates that will be used in competitive transmission solicitations. The grid operator says it expects to issue a final request for proposals in late 2019 or early 2020.
In 2011, the Federal Energy Regulatory Commission issued its landmark Order No. 1000, reforming how public utilities plan and pay for transmission upgrades. In issuing the order, the Commission noted that changes in the generation mix were driving significant expansions of the transmission system -- but that "the narrow focus of current planning requirements and shortcomings of current cost allocation practices create an environment that fails to promote the more efficient and cost-effective development of new transmission facilities." Order No. 1000 aimed to address these problems by providing a framework for fair and open evaluation of regional transmission needs, and for fair allocation of the costs of transmission solutions to their beneficiaries.
Each regional transmission organization revised its tariff to conform to Order No. 1000. Since the order took effect, several other regional transmission organizations have engaged in competitive solicitations for transmission solutions. But to date, ISO New England Inc. has not. That may soon change, as according to ISO-NE, the grid operator expects to issue a request for proposals in the coming months. In a statement, ISO-NE notes that Exelon has sought to retire the Mystic Generating Station outside Boston -- one of the largest power plants in New England, located adjacent to the region's most concentrated demand -- in June 2022. While ISO-NE chose to retain two of the Mystic units until June 1 2024 for fuel-security reasons, a Boston 2028 Needs Assessment and other studies by the grid operator led it to announce plans to issue its first request for proposals for a competitively-selected regulated transmission solution, pursuant to Oder No. 1000.
ISO-NE has released the draft RFP templates that will be used in competitive transmission solicitations. The grid operator says it expects to issue a final request for proposals in late 2019 or early 2020.
Vermont PUC report on electric vehicles
Monday, July 8, 2019
Vermont utility regulators have recommended steps Vermont could take to accelerate the use of electric vehicles (EVs) in the state, including creating state incentives for EV purchases as well as encouraging electric utilities to adopt new rate structures.
Like most other states, Vermont's transportation sector contributes more greenhouse gas emissions than any other sector of the state's economy. Due in large part to emissions from cars and trucks powered by fossil fuels, the transportation sector is responsible for about 47% of Vermont's total greenhouse gas emissions; by contrast, Vermont's electricity generating sector is relatively small but nearly entirely renewable, and has the lowest carbon dioxide emissions of any state according to federal data. Other New England states are similar -- for example, Maine's transportation sector contributed 53% of the state's total greenhouse gas emissions in 2017, while electric power generation in Maine accounted for just 9 percent of the state’s total carbon emissions.
Indeed, the New England electricity grid has experienced significant decarbonized in recent decades, and renewable energy can now be consumed in the transportation sector through the use of EVs. In 2016, Vermont adopted a Comprehensive Energy Plan aiming to power 10% of transportation with renewable energy by 2025, and 80% by 2050, while reducing the sector's emissions by 30% by 2025. Vermont estimates that reaching these goals would require adding about 50,000 to 60,000 EVs to replace vehicles with internal combustion engines by 2025, for a compound annual growth rate of about 54%.
On June 27, 2019, the Vermont Public Utilities Commission released its report to various state legislative committees, "Promoting the Ownership and Use of Electric Vehicles in the State of Vermont." The report recommends that Vermont create incentives for EV purchases or leases, whether in the form of time-of-sale rebates or tax credits. It also recommends that Vermont buy EVs for the state vehicle fleet, and encourage the development of EV charging infrastructure through zoning or building code modifications.
The report also suggests that the Commission encourage electric utilities to take additional actions to promote EV adoption, such as funding EV purchase incentives through Vermont's Renewable Energy Standard program, or developing time-of-use retail rates to encourage car charging at off-peak times. It also noted that utility rate structures which impose demand charges on most commercial accounts but not on residential accounts make public direct-current fast-charging more expensive than at-home charging.
The report also notes that increased education and outreach efforts -- by utilities as well as by car dealers and other third parties -- could encourage consumer adoption of EVs.
Like most other states, Vermont's transportation sector contributes more greenhouse gas emissions than any other sector of the state's economy. Due in large part to emissions from cars and trucks powered by fossil fuels, the transportation sector is responsible for about 47% of Vermont's total greenhouse gas emissions; by contrast, Vermont's electricity generating sector is relatively small but nearly entirely renewable, and has the lowest carbon dioxide emissions of any state according to federal data. Other New England states are similar -- for example, Maine's transportation sector contributed 53% of the state's total greenhouse gas emissions in 2017, while electric power generation in Maine accounted for just 9 percent of the state’s total carbon emissions.
Indeed, the New England electricity grid has experienced significant decarbonized in recent decades, and renewable energy can now be consumed in the transportation sector through the use of EVs. In 2016, Vermont adopted a Comprehensive Energy Plan aiming to power 10% of transportation with renewable energy by 2025, and 80% by 2050, while reducing the sector's emissions by 30% by 2025. Vermont estimates that reaching these goals would require adding about 50,000 to 60,000 EVs to replace vehicles with internal combustion engines by 2025, for a compound annual growth rate of about 54%.
On June 27, 2019, the Vermont Public Utilities Commission released its report to various state legislative committees, "Promoting the Ownership and Use of Electric Vehicles in the State of Vermont." The report recommends that Vermont create incentives for EV purchases or leases, whether in the form of time-of-sale rebates or tax credits. It also recommends that Vermont buy EVs for the state vehicle fleet, and encourage the development of EV charging infrastructure through zoning or building code modifications.
The report also suggests that the Commission encourage electric utilities to take additional actions to promote EV adoption, such as funding EV purchase incentives through Vermont's Renewable Energy Standard program, or developing time-of-use retail rates to encourage car charging at off-peak times. It also noted that utility rate structures which impose demand charges on most commercial accounts but not on residential accounts make public direct-current fast-charging more expensive than at-home charging.
The report also notes that increased education and outreach efforts -- by utilities as well as by car dealers and other third parties -- could encourage consumer adoption of EVs.
US ocean energy regulators consider NY-NJ offshore transmission line
Wednesday, July 3, 2019
After receiving a request from a developer of offshore electricity transmission lines for a right-of-way in ocean waters offshore New York and New Jersey, U.S. ocean energy regulators have asked whether any other developers are interested in the same area.
On April 30, 2018, Anbaric Development Partners, LLC (ADP) applied to the federal Bureau of Ocean Energy Management (BOEM) for a right-of-way grant for a proposed project called the New York/New Jersey Ocean Grid. As envisioned by ADP, the project would include a submarine system approximately 185 nautical miles in length. It would also include up to 9 offshore collector platforms which would collect and distribute power generated from existing offshore wind leases, each capable of handling 800 to 1,200 megawatts of offshore wind energy, as well as up to 6 onshore landings at locations from Long Island, New York to Cardiff, New Jersey. On June 22, 2018, BOEM approved ADP's legal, technical, and financial qualifications to acquire and hold a Right of Way Grant on the Outer Continental Shelf.
Under BOEM's regulations, different procedures apply depending on whether the agency is following a competitive lease process or a noncompetitive lease award process. ADP's application was "unsolicited," meaning it was not submitted in response to a BOEM solicitation, Request for Interest, or Call for Information and Nominations. Under BOEM's case-by-case process for considering unsolicited requests, the agency will issue a public notice and solicit comments to determine whether competitive interest exists, before considering the application itself. If BOEM determines that competitive interest exists in the requested lease area, BOEM will proceed with its competitive process; otherwise, BOEM will publish a notice of Determination of No Competitive Interest, and may proceed to review the unsolicited lease request.
On June 17, 2019, BOEM announced that it would publish a Request for Competitive Interest for project; the Notice of Proposed Grant Area and Request for Competitive Interest was published in the Federal Register on June 19, 2019. Indications of interest in acquiring a right-of-way grant for the area ADP requested must be sent by mail, postmarked no later than July 19, 2019, to be considered. Comments or other information may be sent by mail, postmarked by the same date, or may be submitted through the Federal Rulemaking Portal at http://www.regulations.gov.
If BOEM receives indications of competitive interest from qualified entities, the bureau may decide to move forward with the right-of-way grant issuance process using competitive procedures. BOEM will continue to consult with the state task force and partners regarding the proposed transmission project.
As an increasing number of states and utilities are procuring offshore wind, functions that must be provided include collecting the power produced, transmitting it to shore, and integrating it into the onshore grid. Depending on their design and configuration, offshore transmission grids could play these roles, and could also help wheel power along the coastline from one region to another. Questions of cost recovery -- who pays for these systems -- will continue to arise, at the intersection between state policies calling for offshore wind and regional markets rooted in economics.
On April 30, 2018, Anbaric Development Partners, LLC (ADP) applied to the federal Bureau of Ocean Energy Management (BOEM) for a right-of-way grant for a proposed project called the New York/New Jersey Ocean Grid. As envisioned by ADP, the project would include a submarine system approximately 185 nautical miles in length. It would also include up to 9 offshore collector platforms which would collect and distribute power generated from existing offshore wind leases, each capable of handling 800 to 1,200 megawatts of offshore wind energy, as well as up to 6 onshore landings at locations from Long Island, New York to Cardiff, New Jersey. On June 22, 2018, BOEM approved ADP's legal, technical, and financial qualifications to acquire and hold a Right of Way Grant on the Outer Continental Shelf.
Under BOEM's regulations, different procedures apply depending on whether the agency is following a competitive lease process or a noncompetitive lease award process. ADP's application was "unsolicited," meaning it was not submitted in response to a BOEM solicitation, Request for Interest, or Call for Information and Nominations. Under BOEM's case-by-case process for considering unsolicited requests, the agency will issue a public notice and solicit comments to determine whether competitive interest exists, before considering the application itself. If BOEM determines that competitive interest exists in the requested lease area, BOEM will proceed with its competitive process; otherwise, BOEM will publish a notice of Determination of No Competitive Interest, and may proceed to review the unsolicited lease request.
On June 17, 2019, BOEM announced that it would publish a Request for Competitive Interest for project; the Notice of Proposed Grant Area and Request for Competitive Interest was published in the Federal Register on June 19, 2019. Indications of interest in acquiring a right-of-way grant for the area ADP requested must be sent by mail, postmarked no later than July 19, 2019, to be considered. Comments or other information may be sent by mail, postmarked by the same date, or may be submitted through the Federal Rulemaking Portal at http://www.regulations.gov.
If BOEM receives indications of competitive interest from qualified entities, the bureau may decide to move forward with the right-of-way grant issuance process using competitive procedures. BOEM will continue to consult with the state task force and partners regarding the proposed transmission project.
As an increasing number of states and utilities are procuring offshore wind, functions that must be provided include collecting the power produced, transmitting it to shore, and integrating it into the onshore grid. Depending on their design and configuration, offshore transmission grids could play these roles, and could also help wheel power along the coastline from one region to another. Questions of cost recovery -- who pays for these systems -- will continue to arise, at the intersection between state policies calling for offshore wind and regional markets rooted in economics.
U.S. consumes more petroleum than any other energy source
Monday, July 1, 2019
Petroleum was the largest source of energy consumed in the United States in 2018, as it has been every year since it surpassed coal in 1950.
According to data maintained by the U.S. Energy Information Administration, in 2018 the U.S. used 101 quadrillion British thermal units (Btu) of overall energy -- for transportation, heating, electric power generation, and all other uses. This was a record high level of overall energy consumption.
Of this amount, about 81 quadrillion Btu (about 80% of the total) came from fossil fuels -- petroleum, natural gas, and coal. This is fossil fuels' second-lowest share of the total since 1902, after setting a record low share in 2017.
Petroleum provides the largest share of energy consumed in the U.S., at about one-third of the total. Petroleum consumption increased year-over-year, to about 37 quadrillion Btu in 2018. At the same time, U.S. petroleum consumption remains lower than its peak level (about 40 quadrillion Btu), which occurred in 2005.
Natural gas consumption also increased in 2018, reaching a new record level of 82.1 billion cubic feet per day (or about 31 quadrillion Btu for the year).
Meanwhile, coal consumption fell by 4.3% in 2018. U.S. coal consumption peaked in 2005, and has declined about 42% since then, to the lowest level of coal consumption since the 1970s.
At the same time, renewable energy has continued to grow. In 2018, hydroelectricity, biomass, wind, solar, and other renewables provided about 11.4% of the total energy consumed in the U.S., with significant growth in solar and wind energy generation. In the electric power sector, renewable resources generated more electricity than coal did in the U.S. in April 2019 for the first month.
However, despite the substantial decarbonization of the power grid in New England and other regions, for now transportation and heating remain dominated by petroleum, with associated economic, environmental, and climate implications. Efforts to reduce the carbon intensity of these sectors, such as through electric vehicles and electricity-powered heat pumps, could do much to reduce the associated greenhouse gas emissions.
According to data maintained by the U.S. Energy Information Administration, in 2018 the U.S. used 101 quadrillion British thermal units (Btu) of overall energy -- for transportation, heating, electric power generation, and all other uses. This was a record high level of overall energy consumption.
Of this amount, about 81 quadrillion Btu (about 80% of the total) came from fossil fuels -- petroleum, natural gas, and coal. This is fossil fuels' second-lowest share of the total since 1902, after setting a record low share in 2017.
Petroleum provides the largest share of energy consumed in the U.S., at about one-third of the total. Petroleum consumption increased year-over-year, to about 37 quadrillion Btu in 2018. At the same time, U.S. petroleum consumption remains lower than its peak level (about 40 quadrillion Btu), which occurred in 2005.
Natural gas consumption also increased in 2018, reaching a new record level of 82.1 billion cubic feet per day (or about 31 quadrillion Btu for the year).
Meanwhile, coal consumption fell by 4.3% in 2018. U.S. coal consumption peaked in 2005, and has declined about 42% since then, to the lowest level of coal consumption since the 1970s.
At the same time, renewable energy has continued to grow. In 2018, hydroelectricity, biomass, wind, solar, and other renewables provided about 11.4% of the total energy consumed in the U.S., with significant growth in solar and wind energy generation. In the electric power sector, renewable resources generated more electricity than coal did in the U.S. in April 2019 for the first month.
However, despite the substantial decarbonization of the power grid in New England and other regions, for now transportation and heating remain dominated by petroleum, with associated economic, environmental, and climate implications. Efforts to reduce the carbon intensity of these sectors, such as through electric vehicles and electricity-powered heat pumps, could do much to reduce the associated greenhouse gas emissions.
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