US renewable output exceeded coal in 2022

The U.S. generated more electricity from renewable sources than from coal last year, for the first time in history. The nation's portfolio of electric generation resources continues to shift away from coal and oil and towards renewable resources and natural gas.

The U.S. Energy Information Administration (EIA) tracks statistics on a variety of energy sources and their related infrastructure. According to EIA, the domestic electric power sector generated 4,090 million megawatthours (MWh) of electricity in 2022. The greatest share of this power (39%) came from natural gas in 2022, whose contribution has generally continued to increase over time. 

Renewable energy sources contributed the second-largest share of U.S. electricity in 2022, surpassing nuclear output (for the second time) as well as coal output (for the first time). Within the renewables sector, the wind sector grew from 133 gigawatts (GW) of installed capacity in 2021 to 141 GW in 2022, and the solar sector grew from 61 GW to 71 GW. Contributions from hydro, biomass, and geothermal remained steady.

EIA notes that the closure of the Palisades nuclear power plant in 2022 reduced national nuclear output, and cites closure of multiple coal plants as well as decreased utilization of existing coal plants.

EIA projects continued growth in the shares of the U.S. generation mix provided by wind and solar; steady levels of natural gas generation; and continued decreases in coal use for electricity.

Maine "Solar for All" program proposed for EPA funding

The Maine Governor's Energy Office has applied to the U.S. Environmental Protection Agency for $99.5 million to establish statewide "Solar for All" programs for Maine. If selected for funding by EPA, the programs could create new incentives for residential solar development in Maine with a focus on low-income and disadvantaged communities.

The Inflation Reduction Act allocated $7 billion to the EPA, to fund a system of competitive grants to states and other entities to establish or expand "Solar for All" programs that support deployment of solar and energy storage to benefit low-income and disadvantaged communities. Implemented as part of the Inflation Reduction Act’s Greenhouse Gas Reduction Fund (GGRF), the EPA program will award up to 60 grants to states, territories, Tribal governments, municipalities, and eligible nonprofits to create and expand low-income solar programs that provide financing and technical assistance, such as workforce development, to enable low-income and disadvantaged communities to deploy and benefit from residential solar.

According to EPA, the Solar for All program advances President Biden’s Justice40 Initiative, a program seeking to allocate 40% of the overall benefits of certain Federal investments to disadvantaged communities that are marginalized, underserved, and overburdened by pollution. EPA also cites the program as supporting the administration's goal of achieving a carbon pollution-free power sector by 2035 and net zero emissions economy by no later than 2050.

In Maine's proposal, the state energy office proposed three new programs:  

• New incentives for residential rooftop solar and energy storage serving affordable multifamily housing and single-family homes of low-income households and those located in Federally-defined disadvantaged communities in Maine, to minimize financial barriers to rooftop solar benefits; 
• New technical and financial assistance to support cooperatively-owned community solar enabling households, resident-owned communities, Tribal communities, and community-based organizations, to participate in solar energy ownership without barriers of homeownership or rooftop suitability; and 
• A new community solar and energy storage program focused on serving low-income and disadvantaged households, utilizing competitive bidding and aligning with existing energy assistance programs to minimize costs and maximize benefits delivered directly to households through lower electricity bills while building energy resilience.

According to the energy office, full funding by EPA of Maine’s Solar for All proposal "will enable an estimated 38,000 low-income and disadvantaged households to access solar by supporting rooftop projects on owner-occupied and rental residences across the state, as well as cost-effective community solar to enable energy savings for low-income households." 

Applications by states and others were due to EPA this past fall. Announcements of awards could be made as early as March 2024, with EPA anticipating beginning to make awards in July 2024. The Inflation Reduction Act requires EPA to award all Solar for All funds by September 30, 2024.

Feds predict winter oil heating cost increase; Maine pursues heat pumps

U.S. households that rely primarily on heating oil for heating will spend more this winter on heating compared to last winter, according to a federal projection.

The U.S. Energy Information Administration's 2023 Winter Fuels Outlook supplement to its October 2023 Short-Term Energy Outlook includes heating data, projections, and analysis. Based on NOAA data and a 30-year weather trend, EIA projects that this winter will be colder than last winter, driving an increase in demand for heating fuels and energy. 

For households that heat primarily with heating oil, most of which are located in the Northeast, EIA projects a 40-gallon increase in oil consumption per household relative to last winter. Even accounting for a small projected decrease in oil pricing, EIA expects expenditures for these households to increase by 8 percent year-over-year.

Notably, only 4 percent of U.S. households heat primarily with oil. By contrast, in 2022 over 60 percent of Maine households relied primarily on oil for heating, according to the Governor's Energy Office. 

To reduce Maine's reliance on oil, the state legislature, Governor Janet Mills, and various agencies have adopted policies favoring the deployment of heat pumps powered by electricity. Earlier this year, Maine surpassed the state's targeted level of 100,000 heat pump installations, and established increased goals for beneficial electrification of the state's heating systems. Incentives available depend on the circumstances of each deployment, but generally can include rebates and grants as well as tax credits.

Solar, wind, and natural gas power plant construction costs declined in 2021

Construction costs decreased for several types of new power plants on average in 2021, according to federal data. The Energy Information Administration reports that compared to 2020, average construction costs for natural gas-fired generators fell by 18% in 2021, with average construction costs for solar and wind systems declining by 6% and 5% respectively.

Source: U.S. EIA

Average U.S. solar project construction costs in 2021 were $1,561 per kilowatt. Crystalline silicon tracking systems, which accounted for 56% of the nation's utility-scale solar capacity installed in 2021, had a slightly lower per-unit cost, at $1,423 per kilowatt.

Average onshore wind turbine construction costs were slightly lower, at $1,428 per kilowatt. In general, larger projects tended to have smaller per-unit construction costs, implying efficiency due to economies of scale.

Natural gas provided the lowest average construction cost per unit of installed capacity, at $920 per kW. Within natural gas units, combustion turbines had the lowest average cost per unit of capacity, at $512 per kW.

According to EIA, solar, wind, and natural gas collectively account for over 91% of the electric generating capacity added to the U.S. grid in 2021. 

Over 2 million light-duty EVs registered in the US in 2021

The number of light-duty electric vehicles registered in the U.S. reached 2.13 million in 2021, according to federal data. The Energy Information Administration reports a "sharp increase from the less than 100,000 EVs on the roads in 2012". The lagging nature of this data set and continued growth in EV adoption mean that an even greater number of EVs are now registered in the U.S.

EIA's annual EV registration data is segmented into two categories: battery-electric vehicles (without any internal combustion engine) and plug-in hybrid electric vehicles (with both batteries and a traditional engine). Both categories show strong growth since 2012, with BEV adoption growing even faster in 2021.

Consistent with the recent growth of EVs, the average EV registered in the U.S. was 3.6 years old in 2021, considerably younger than the 11.1-year-old age of the average non-EV. 

To explain the rise of EVs, EIA cites factors including changing consumer preferences and an increasing number of EV models, particularly in the "luxury" sector. EIA also notes the effect of government policies supporting beneficial electrification of the carbon-emission-intense transportation sector. Policies designed to increase EV uptake include purchase incentives like tax credits and rebates, zero-emission vehicle sales mandates, and fuel economy standards.

US added record amounts of small solar power in 2022

A recordbreaking amount of small-scale solar electric generating capacity was added to the U.S. grid in 2022, as the nation added more distributed solar than in any prior year according to federal energy data. 

The U.S. Energy Information Administration tracks the nation's portfolio of electric generation resources. EIA considers solar-power systems with one megawatt (MW) of capacity or less to be "small-scale solar", also called distributed solar or rooftop solar.

According to EIA, U.S. small-scale solar capacity has grown consistently year-over-year since the agency started tracking it in 2014. In the ensuing eight years, U.S. small-scale solar capacity grew from 7.3 gigawatts (GW) to reach 39.5 GW in 2022. 

About one-third of the total solar capacity in the U.S. now comes from small-scale systems. EIA reports that rooftop solar panels installed on homes make up the majority of the nation's small-scale solar capacity. Additional small-scale solar power systems are installed in commercial and industrial contexts.

EIA attributes growth in small-scale solar capacity over the past decade to tax credits and incentives, public policy, and higher retail electricity prices, as well as falling solar panel costs. The federal tax code includes tax credits for investments in small-scale solar power and other forms of clean energy. The scope and value of these credits was enhanced by the enactment of the Inflation Reduction Act. 

In addition, many states offer state-level incentives for solar power production. Diversity among state levels of solar adoption isn't just about how sunny a place might be, as EIA posits that the levels of state incentives affect the degree to which solar projects are developed in each state. 

EIA also notes that while many states with the most small-scale solar capacity also have large populations (like California and New York), some smaller states like Hawaii, Rhode Island, Maine, and Vermont have high levels of market penetration on a watts-per-capita basis.

Natural gas pricing drives New England's electricity costs

Two factors are the main drivers of wholesale electricity prices in New England, according to the region's grid operator: the cost of natural gas and other fuels used to generate electricity, and the level of consumer demand for power.

Fuel costs are a key component of the cost of electricity, and natural gas is the "predominant fuel in New England", used to generate 52% of the power produced in 2022 by New England’s power plants. According to ISO New England Inc., the regional transmission organization, natural gas-fired power plants usually set the price of wholesale electricity in New England.

As a result, the grid operator says that "average wholesale electricity prices are closely linked to natural gas prices." The chart below, prepared by ISO-NE, shows the close correlation between wholesale electricity and natural gas prices between for the past two decades:

ISO-NE reports that demand for electricity is the second main driver of the region's wholesale electricity prices, and that demand "is driven primarily by weather, as well as economic factors." The extent to which consumers rely on electricity-powered heating and air conditioning equipment means that peak demand is driven by weather. 

While New England's original electric system reached peak demand in winter, the region shifted to summer-peaking in the early 1990s due to increased air conditioner use and decreased reliance electric heating. The grid operator's records as of mid-2023 show that the all-time high winter peak of 22,818 MW occurred during a cold snap in January 2004, and the all-time peak demand of 28,130 MW occurred during an August 2006 heat wave. 

ISO-NE projects future growth in consumer demand for electricity and a shift back to a winter-peaking system by 2035, as beneficial electrification of the region's heating and transportation sectors add heat pumps and electric vehicles to the grid.

U.S.-Canada energy trade reached record-high value in 2022

Energy trade between the United States and Canada reached record high levels of value in 2022, according to the U.S. Energy Information Administration.

EIA tracks and reports statistics concerning energy matters, including volumes and values of international trade. According to EIA, high energy prices contributed to a total of $190 billion in energy trade between the U.S. and Canada in 2022, when adjusted for inflation.

EIA tracks four main types of energy commodity transacted between the U.S. and Canada: crude oil, other petroleum products, natural gas, and electricity. In recent years, crude oil has represented the largest fraction of these countries' energy trade on a value basis, followed in turn by the other commodities listed above.

The value of energy trade is driven by a combination of factors, including the volumes of energy imported and exported, as well as the prices for those transactions. EIA reports that volumes of energy trade between these two countries were nearly unchanged between 2021 and 2022. 

Meanwhile, the value of energy trade increased by 41% in 2022. According to EIA:

• The U.S. imported a greater value of trade from Canada ($156.3 billion, inflation-adjusted) than it exported to its neighbor ($33.8 billion, inflation-adjusted). 
• U.S. crude oil imports in 2022 averaged 3.7 million barrels per day by volume, while U.S. crude exports to Canada averaged 305,000 barrels per day. 
• Natural gas imports from Canada averaged 7.6 billion cubic feet per day (Bcf/d), while exports to Canada averaged 2.5 Bcf/d. 
• Petroleum product trade was closer to even, with 580,000 barrels per day imported and 524,000 barrels per day exported. 

Maine considers distributed generation interconnection reforms

The Maine legislature has enacted a law designed to reform the state's procedures for interconnecting solar projects and other forms of distributed generation resources to the electric grid. The law, An Act to Provide Maine Ratepayers with Equitable Access to Interconnection of Distributed Generation Resources, requires the Public Utilities Commission to appoint an "interconnection ombudsman". The law also requires the PUC to align its interconnection rules with best practices and to prioritize interconnection of solar resources and energy storage systems used to serve on-site load.

Interconnection is an essential component of distributed generation project development and operation. Policies enacted since 2019 have led to a flood of interconnection requests by project developers, seeking access to the grid. Each request must be studied, sequentially, to identify what grid upgrades and interconnection facilities must be built for safe and reliable operation. Large projects and those connected to the interstate transmission grid generally interconnect under federally jurisdictional procedures, like the interconnection procedures adopted by regional grid operator ISO New England. 

Smaller distributed generation projects in Maine generally use the state-jurisdictional interconnection process, which operates under the PUC's Chapter 324 rule. The rule specifies rights and responsibilities of both the project developer as interconnection customer and the utility. The recent flood of interconnection requests has caused project developers to complain about lengthy timelines, inflexible procedures, and missed deadlines by utilities.

To address these concerns, the Maine legislature recently enacted the distributed generation interconnection reform act, Public Laws of 2023 chapter 307. Introduced as LD 327, the law as enacted requires the PUC to appoint an interconnection ombudsman to assist people seeking state-jurisdictional interconnection of solar resources and energy storage systems. The interconnection ombudsman's duties include tracking interconnection disputes, facilitating their efficient and fair resolution, reviewing utility policies to assess opportunities to reduce disputes, convening stakeholder groups, and reporting. The position must be funded by interconnection fees or sources other than general ratepayer funds, and the PUC must make a good faith effort to appoint the ombudsman within 12 months of the law's effective date.

The law also requires the PUC to adopt interconnection rules that prioritize interconnection of solar resources and energy storage systems owned by customers of investor-owned transmission and distribution utilities and used to serve an on-site load. It also requires the PUC to convene an interconnection working group. 

Maine enacts law to develop clean energy on PFAS-contaminated lands

The Maine legislature has taken a significant step to promote the economic reuse of agricultural land contaminated by perfluoroalkyl and polyfluoroalkyl substances (PFAS) through the development of renewable energy projects. A newly enacted law will require state regulators to solicit proposals for renewable energy projects, with a primary preference given to projects located on PFAS-contaminated agricultural land. The law could help Maine address challenges arising from farmland contamination with PFAS, while promoting renewable energy development. 

Importantly, the law represents a new wave of Maine energy contracting policy, because it requires the procurement of both energy and renewable energy credits (RECs), rather than one or the other. By mandating the acquisition of both energy and RECs, the law has potential to enable Maine consumers to truly say they consumed renewable power specifically from these projects, as a result of these contracts.

An Act to Promote Economic Reuse of Contaminated Land Through Clean Energy Development was introduced as LD 1591, a bipartisan bill sponsored by Senator Stacy Brenner with co-sponsors including Representative Zeigler, Senators Bennett, Black, Carney, LaFountain, and Pouliot, and Representatives Boyle, Campbell, and Hall. In a statement, Senator Brenner noted that PFAS chemicals have been found on at least 56 Maine farms in high amounts, limiting or effectively ending their agricultural production. 

In response, the sponsors proposed a bill that called for the Maine Public Utilities Commission to solicit proposals to sell power from renewable projects on contaminated agricultural lands. Following amendment by the Joint Standing Committee on Energy, Utilities and Technology, the law was enacted by the Maine legislature as Public Laws of 2023 chapter 321, and signed by Governor Mills on June 26, 2023. 

In its final form, the law requires the PUC to conduct one or more competitive solicitations for contracts for energy and renewable energy credits from new renewable energy projects. The law requires the PUC to direct Maine's investor-owned transmission and distribution utilities to enter into contracts to purchase power and RECs from selected projects. The law prescribes procurement of amounts equal to at least 5% of Maine's retail electricity sales in 2021, plus additional amounts to cover any unused contracting capacity under a previously enacted procurement law. 

The law requires the PUC to select only projects that will benefit ratepayers, to give primary preference to projects located on contaminated land, with secondary preference for projects that minimize use of forested land and uncontaminated farmland. Contracts can be for up to 20 years, or longer if the PUC finds this prudent. Projects combined with grid-connected energy storage systems are also eligible but must promise that the storage system will remain stationary and under the same ownership throughout the contract term. Combined projects must also submit a separate generation-only bid.

A critical distinction of this law is its explicit requirement that proposals and contracts include both "energy and renewable energy credits", rather than offering either/or options. RECs represent the environmental attributes associated with a given megawatt-hour of electric energy and are crucial for tracking renewable energy under Maine's renewable portfolio standard. The holder of a REC generally may make claims about their use of renewable electricity, which effectively uses up the REC. The same claims can't be made if the REC is sold separately to someone else. 

Other recent Maine contracting programs generally have not required the sale of both energy and RECs. Nearly all contracts awarded under these programs have been for energy and not for RECs. Project developers selling their energy under these Maine programs typically sell their RECs separately to buyers in southern New England states who will use the RECs for compliance with their own state's renewable energy laws. As a result, these other Maine contracting programs don't generally directly result in renewable energy supply to Maine consumers. 

By contrast, the recently enacted clean energy development on contaminated land act requires contracts to be for both energy and RECs. It requires the PUC to adopt a process to assign the procured RECs to a standard-offer service provider to satisfy its own renewable portfolio standard requirements. While the details of that process will be specified by rule, the law contemplates that the procured RECs will enable Maine consumers to claim they consumed renewable energy as a result of contracts awarded under this program, unlike some of Maine's other recent energy contracting programs.

Maine enacts Beneficial Electrification Policy Act

The Maine legislature has enacted a law promoting beneficial electrification. The Beneficial Electrification Policy Act, chapter 328 of the Public Laws of 2023, gives Maine new tools to reduce carbon emissions from the state's heating, transportation, and other sectors, by promoting electrification through heat pumps, electric vehicles, and other measures.

Maine law requires the state to achieve specified reductions in its statewide net and gross annual greenhouse gas emissions over time. Gross annual emissions must drop to at least 45% below the 1990 gross level by 2030, falling to at least 80% below the 1990 level by 2050. Net annual greenhouse gas emissions may not exceed zero from 2045 on.

Separately, Maine's renewable portfolio standard law includes both goals and mandates that increasing portions of retail sales electricity must come from renewable resources over time. Statutory goals include that 80% of retail sales electricity in the State will come from renewable resources by 2030, and 100% by 2050. Enforceable mandates already require retail suppliers to cover increasing percentages of their retail sales with renewable energy certificates (RECs) from various classes of resource; for 2023, the total RPS mandate percentage exceeds 50%, rising to 84% by 2030.

Maine has already largely decarbonized its electric power sector. According to the Maine Department of Environmental Protection, "Annual CO2 emissions from fossil fuel combustion in the electric power sector have decreased by 91 percent since they peaked in 2002 largely by replacing high carbon fuels with lower carbon energy sources, primarily natural gas and renewable sources."

Even though the electric sector has largely cleaned up its act, heating and transportation continue to account for the bulk of fossil fuel use in Maine and associated carbon emissions. Transportation alone accounted for 49 percent of Maine's CO2 emissions from fossil fuel combustion in 2019. Technologies like heat pumps and electric vehicles have potential to displace these fossil fuel uses, in ways that can reduce both carbon emissions and consumer costs -- a concept termed beneficial electrification.

Building on Maine's original beneficial electrification law enacted in 2019, the Beneficial Electrification Policy Act defines "beneficial electrification" as:

electrification of a technology or process that results in reduction in the use of a fossil fuel, including electrification of a technology or process that would otherwise require energy from a fossil fuel, and that provides a benefit to a utility, a ratepayer or the environment, without causing harm to utilities, ratepayers or the environment, by improving the efficiency of the electricity grid or reducing consumer costs or emissions, including carbon emissions.

Sponsored by Senator Nicole Grohoski, and co-sponsored by Representatives Steven Foster and Chris Kessler, the bipartisan An Act to Enact the Beneficial Electrification Policy Act was introduced in the 131st Maine Legislature as LD 1724. Following legislative debate, the bill was enacted into law and signed by Governor Janet Mills on June 26, 2023.

The new law includes several measures supporting beneficial electrification. It requires the Public Utilities Commission to advance beneficial electrification in order to achieve the emission reduction and renewable energy goals of the State, reduce energy costs to consumers and provide economic and climate benefits for all ratepayers. It also authorizes the Governor's Energy Office to petition the Public Utilities Commission to procure energy from renewable resources to achieve Maine's emission reduction and renewable energy goals and to meet reasonably expected growth in electric demand. According to the regional grid operator ISO New England, demand for power will increase by 23% over the next decade to account for increasing electrification of heating and transportation.

The law also requires the Efficiency Maine Trust to include a 3-year beneficial electrification plan for end uses of energy as part of the Trust's triennial planning process, including all beneficial electrification measures that are cost-effective and reliably reduce electricity rates over the life of the measures.

In addition to requiring the Public Utilities Commission to report annually on its activities under the new law, the Beneficial Electrification Policy Act also directs the Commission to conduct a study on how to cost-effectively provide consumer financing of beneficial electrification products, including products for energy efficiency, home or business energy storage, electric vehicle charging equipment and other distributed energy products. The law requires the study to include consideration of methods including, but not limited to, on-bill financing by standard-offer service providers or competitive electricity providers. It requires the Commission to report back to the legislative energy committee by January 5, 2024.

New England power plant air emissions increased in 2021

New England's power plants collectively emitted greater amounts of key air emissions in 2021 than in the year before, according to a report by the region's electric grid operator. Factors included the weather, decreases in power imported from outside the region, and increased reliance on coal and oil-fired generation.

The 2021 ISO New England Electric Generator Air Emissions Report provides "a comprehensive analysis of New England’s native electric generator air emissions (nitrogen oxides [NOX], sulfur dioxide [SO2], and carbon dioxide [CO2]), along with CO2 emissions associated with imported energy, and a review of relevant system conditions."

New England has significantly reduced the air emissions associated with its electric power sector over the past decades. According to the report, total average air emissions from "native generation" (in-region) have decreased overall during the 10-year span from 2012 through 2021: NOx by 39%, SO2 by 87%, and CO2 by 20%. The report credits the decline in emissions over this period to "shifts in the regional generation mix, with imports and wind generation offsetting decreases in coal-fired generation." 

Looking farther back to cover the 20-year span from 2001 through 2021, NOx emissions fell by 80%, SO2 emissions fell by 99%, and CO2 emissions fell by 41%. Summarizing these two decades of change, ISO-NE says, "The increased use of highly efficient natural-gas-fired generators, mandated use of lower-sulfur fuels, retirements of coal- and oil-fired generation, increasing amounts of wind and solar generation, and higher net energy imports have all contributed to the trend."

But on a year-over-year basis, emissions increased in 2021 relative to 2020 according to the grid operator. For native generation, NOx emissions grew by 2.9%, SO2 emissions grew by 12.2%, and CO2 grew by 7.8%. 

ISO-NE attributes the region's recent backsliding on emissions to several factors, including increased demand for native generation (due to a 20% reduction in imports), weather (warm summer, cold winter), and "the resource mix":

Coal- and oil-fired generation had year-over-year increases of 281% and 53%, respectively. Resources fueled by coal or oil produced more power than usual during colder weather in January and February 2021, and production by oil-fired resources also increased during hot weather in June and August. These resources, which have higher emission rates than plants fueled by natural gas, often contribute generation during peak energy demand periods in the summer, or when winter heating demand limits the availability of natural gas or drives up its price.

The grid operator expects continued growth in demand for electricity, as transportation and heating increasingly become powered by electricity.

New England electric demand projected to grow by electrifying heating and transportation

The operator of New England's electricity grid projects that demand for power will increase by 23% over the next 10 years "due to accelerating electrification of the heating and transportation sectors." State and federal policymakers are promoting "beneficial electrification", the replacement of carbon-emitting fossil fuel uses with lower-carbon-intensity electricity as a power source. The trend has potential to significantly decarbonize the region's transportation and heating sectors, which collectively emit many times more greenhouse gases than the region's electric power sector.

ISO New England's 2023–2032 Forecast Report of Capacity, Energy, Loads, and Transmission (CELT Report) presents the grid operator's perspective on the region's power system, including a long-term forecast for energy consumption and peak demand. To prepare the forecast, ISO-NE first develops a gross long-term forecast for electricity demand, based on factors including economic forecasts and weather data -- and increasingly on projections for the electricity needed to power electric vehicles and air-source heat pumps that are being added to the grid. ISO-NE then backs out its projection of energy efficiency and behind-the-meter solar photovoltaic production, to yield a net forecast.

According to the latest CELT report, gross annual electricity use is expected to grow by 2.4% annually over the 10-year period, while net annual use is expected to grow by 2.3% annually. EVs are expected to account for 13,961 GWh of grid demand in 2032, while heating electrification is expected to account for 7,334 GWh of demand that year. 

In terms of peak demand, ISO-NE expects significant growth in EV use, with transportation electrification is forecast to contribute 3,420 MW to the winter peak in 2032-2033. Heating electrification is forecast to contribute another 2,965 MW to the winter peak under average weather in 2032-2033, or 4,033 MW under colder-than-average weather. 

For comparison, in 2021 Maine's total net summer generating capacity was 5,026 MW, according to U.S. Energy Information Administration data. In other words, electrifying transportation and heating is projected to add more load to the region's grid than all of Maine currently consumes.

Quack: the New England solar duck curve

The New England wholesale electricity grid set a new record for low demand on Sunday, April 9, 2023, according to grid operator ISO New England. Moderate temperatures and the Easter holiday contributed to setting a record low demand of 6,814 megawatts, as did significant electrical production from behind-the-meter solar resources on the sunny afternoon. The result is the "duck curve" familiar from California and other regions with increasing amounts of behind-the-meter solar, a phenomenon now increasing in both depth and frequency in New England, with important implications for electric system engineering and planning.

According to ISO-NE, New England now increasingly experiences the "solar duck curve", as growing amounts of solar generation depress demand for grid power on sunny days, driving the need for other fast-ramping resources to come online to meet consumer demand as the sun sets. The "duck curve" name comes from traditional graphs depicting how behind-the-meter solar affects demand for grid electricity, such as this one prepared by ISO-NE for the Easter 2023 record low: 

Historically, demand for electricity peaked during the midday and evening, and was lowest at night. While underlying consumer demand for power is changing somewhat, change is occurring even faster for the wholesale power system, as growing amounts of behind-the-meter solar photovoltaic (PV) generation reduce the need for other power plants to operate while it's sunny. ISO-NE reported first seeing the "duck curve" indicating grid demand was lower in the afternoon than overnight on April 21, 2018. At the time, solar power exceeded 2,300 megawatts for the first time. 

In 2018, the grid operator could see what was coming next:

ISO New England’s system operators will remember April 21 as a milestone for electricity demand in New England, with these dramatic midday dips expected to crop up more often as more solar comes on line. Mike Knowland, ISO Forecast and Scheduling Supervisor, notes, “We were expecting this to happen at some point as more behind-the-meter solar gets installed in New England and the weather conditions were just right. While this kind of dip in demand is new for New England, it’s a common occurrence in California.”

More behind-the-meter solar continued to be added to the system. By April 2021, ISO-NE reported that solar power had reduced grid demand enough to produce the duck curve 26 additional times, like this example from March 27, 2021. 

Prior to April 2023, the region's previous record low occurred on May 1, 2022, when mild temperatures, sunny skies, and a Sunday combined to yield a grid demand of 7,580 megawatts, which was then the lowest demand for grid electricity on record in New England since ISO-NE began operating the system in 1997. For the 2022 record low, ISO-NE estimated that behind-the-meter solar resources produced over 4,000 megawatts of electricity, while grid demand dropped below 7,600 megawatts. On May 5, 2012, the grid operator said that New England had already seen nearly as many “duck curve” days, during which demand from the bulk power system is at its lowest in the afternoon hours and not overnight, in 2022 as in all previous years combined. 

By the end of 2022, ISO-NE had tallied 45 duck-curve days for the year, more than the previous four years' combined total. The grid operator has said that this "points to the growing contribution of BTM PV to New England's energy mix -- particularly in the spring, when solar production is at its strongest."

Behind-the-meter solar continues to be installed across New England. For the April 2023 low, ISO-NE estimates even greater production from behind-the-meter solar generation, exceeding 4,500 megawatts throughout much of the afternoon. This changes the shape of the duck curve. Comparing duck curves over time, the depth of the "belly" of the duck is trending upward, as larger amounts of behind-the-meter solar resources come online (and come offline). In addition to deepening the duck's belly, the frequency of duck-curve days is expected to continue to increase; according to the grid operator, the region is on pace to set another new record for the number of duck-curve days in 2023.

Coal declined, gas and renewables grew in 2022

U.S. electricity generation resource portfolios continued to shift in 2022, with natural gas and renewables increasing their shares of total electric power generation, as coal's share continued to decline, according to data released by federal energy regulators.

The U.S. Energy Information Administration tracks national electric power generation, among other energy metrics. According to EIA, in 2022 the U.S. electric power sector produced 4,090 million megawatt-hours (MWh) of electric power. The greatest fraction of this power came from natural gas, whose contribution increased from 37% of U.S. generation in 2021 to 39% last year.

Renewables continued to grow, led by gains from wind and solar whose combined share of total generation increased from 12% in 2021 to 14% last year. EIA notes that utility-scale solar capacity grew from 61 gigawatts (GW) in 2021 to 71 GW in 2022, while wind grew from 133 GW to 144 GW. Hydropower (6%), and biomass and geothermal (each less than 1%) resource contributions remained stable year-over-year.

Meanwhile, coal-fired power generation continued to decline, decreasing from 23% in 2021 to 20% in 2022. This continues a general trend of declining U.S. electricity generation from coal, which historically fueled most electric power generation, but which was displaced by natural gas in the last decade. Natural-gas-fired power plants typically emit less than half as much carbon dioxide per unit of electricity generation as compared to coal-fired plants. Many coal-fired plants have retired or are facing increased economic pressures to retire, while other coal plants have seen less use. Nuclear power's contributions also decreased slightly last year, falling from 20% in 2021 to 19% in 2022. The Palisades nuclear power plant retired in May 2022.

US retail electric choice holds steady, per EIA

Over a quarter of eligible residential electricity consumers participated in their state’s retail choice program in 2021, according to the U.S. Energy Information Administration. At the national level, participation in state retail choice programs has remained stable from 2019 to 2021, at about 26% of eligible U.S. customers participated in their state’s retail choice program, or 13.2 million U.S. residential electric customers.

How consumers buy electricity at retail is generally a matter of state law. Under the traditional system of vertically integrated utilities, a customer is served by a utility that provides both electricity supply and delivery service, and customers have no choice as to who serves their load. Most consumers nationwide are served by traditional utilities that both generate or purchase power and deliver it to their customers.

But some jurisdictions have restructured their electricity sectors, to give customers retail choice, meaning the customer can choose which provider they want to have supply their energy for delivery by the local utility acting as a "wires company". According to EIA, today 13 states and the District of Columbia have active statewide or districtwide retail choice programs for residential customers. The states include California, Connecticut, Delaware, Illinois, Massachusetts, Maryland, Maine, New Hampshire, New Jersey, New York, Ohio, Pennsylvania, and Rhode Island. In addition, Texas has a mandatory retail choice program; and Michigan, Nevada, Oregon, and Virginia have limited forms of retail choice programs (mostly for non-residential electric customers).

According to EIA, participation by residential retail customers in retail choice programs grew from 2015 through 2019, and has remained stable at 26% through 2021.

Retail choice is generally a matter of state law. Laws vary by state, and can change over time, as can the degree to which customers choose to participate in retail choice programs where they are offered. For example, participation among Ohio residential customers increased from 45% in 2015 to 50% in 2021, while participation by Massachusetts residential consumers increased from 22% to 49%. 

California launched its first Community Choice Aggregator (CCA) program in 2010, allowing local governments to buy power from retail suppliers on behalf of community residents, who have an option to opt-out if they don't want to participate in the program. Under the CCA system, participation in California grew from 2% in 2015 to 30% in 2021.

On the other hand, other states like Illinois and Connecticut have seen declines in residential retail choice participation rates, with Illinois dropping from 57% in 2014 to 31% in 2021, and Connecticut falling from 42% in 2013 to 24% in 2021.

New England EV growth predicted by electric grid operator

New England is poised for significant growth in electric vehicle (EV) use through 2030, according to a draft forecast by the region's electric grid operator. 

According to the draft ISO New England Inc. Load Forecast Committee 2023 CELT Transportation Electrification Adoption Forecast released in February 2023, various federal and state policies incentives promote EV adoption, as do economic and environmental concerns, though their impacts on EV adoption in New England remain uncertain. For example:

• The federal Inflation Reduction Act creates tiered incentives for consumers to buy new personal light-duty EVs, which must meet increasingly strict vehicle assembly and domestic-material sourcing requirements, as well as incentives to buy used EVs or commercial light, medium, and heavy-duty EVs.
• U.S. Environmental Protection Agency’s (EPA) Clean School Bus Program has $5 billion available over the next five years (FY 2022-2026) through the Bipartisan Infrastructure Law, to replace existing school buses with zero-emission and low-emission models. This money is available to school entities through EPA and state programs like the Maine Department of Education's Maine Clean School Bus Program.

As part of its mission to forecast regional energy demands, ISO-NE prepares a transportation electrification forecast to forecast the energy and demand impacts associated with the uptake of electric vehicles (EVs) within selected categories of vehicles: light-duty personal vehicles, light-duty fleet vehicles, medium-duty delivery vehicles, school buses, and transit buses.

ISO-NE's latest draft transportation electrification adoption forecast includes two adoption scenarios that reflect different assumptions about the pace and extent of transportation electrification within each state: a theoretical “Full Electrification” adoption scenario (intended to represent an upper bound based on state emissions goals and associated EV adoption targets) and a projected "Draft CELT 2023" adoption scenario (intended to reflect the likely pace and level of EV adoption over the next 10 years given the current understanding of individual state goals, policies, and programs, as well as uncertainty in the timing of goal achievement and extent to which electric vehicles will be utilized to accomplish goals).

For personal light-duty EV adoption, the draft forecast projects an increasing pace of EV adoption over the ten-year period through 2032. For example, it projects that 2023 will see 85,901 of these EVs added, while 2032 will see an incremental 468,679 EVs added to the stock, for a 10-year total of 2,724,923 personal light-duty EVs added from 2023 through 2032. This is a significant increase from ISO-NE's prior 10-year forecast, which projected that 1,521,796 of these EVs would be added between 2022 and 2031.

ISO-NE's latest forecast shows similar growth in other categories of EVs, including flight light-duty (projecting that a cumulative total of 240,713 will be added regionwide by 2032), medium duty-delivery (3,352), school bus (6,505), and transit bus (833). Within each category of EV, ISO-NE's model provides state-specific annual data. For example, ISO-NE's forecast projects that Massachusetts will hew close to the "Full Electrification" scenario, contributing more than half the total number of personal EVs, while New Hampshire will lag relative to "Full Electrification" in the forecast.

By 2032, ISO-NE now projects about 3,000 MW of winter transportation electrification demand, with nearly 1,600 gigawatt-hours of transportation electrification energy per month by 2033, and accounting for up to about 9% of monthly regional gross electric energy consumption from the grid.

FERC sets New England gas-electric forum for June 2023

U.S. utility regulators have scheduled a second New England Winter Gas-Electric Forum, to be held this June in Portland, Maine, to continue discussions from a forum held last fall regarding the electricity and natural gas challenges facing the New England region. According to the Federal Energy Regulatory Commission, the objective of the June 20, 2023 forum is "to shift from defining electric and natural gas system challenges in the New England Region to discussing potential solutions, including both infrastructure and market-based solutions."

New England's wholesale electricity price is strongly influenced by the price of natural gas. The federal government, New England's regional electricity grid operator, and states like Maine have all found that recently increased energy costs in New England are a result of higher natural gas prices. Beyond price impacts, electric system reliability can depend on ensuring that natural gas-fired power plants can access adequate amounts of fuel. 

On September 8, 2022, FERC convened a forum in South Burlington, Vermont, to discuss the electricity and natural gas challenges facing the New England region. According to FERC's public notice for the September 2022 forum, its purpose was "to bring together stakeholders in New England to discuss the challenges faced historically during New England winters and discuss the stakeholders’ differing expectations of challenges for future winters. The objectives of the forum are to achieve greater consensus or agreement among stakeholders in defining the electric and natural gas system challenges in New England and identify what, if any, steps are needed to better understand those challenges before identifying solutions." 

At the September 2022 event, lead-off speaker Charles Dickerson, President and CEO of reliability organization Northeast Power Coordinating Council (NPCC) described the regional context for New England's gas-electric relationship:

The problem in New England is in the wintertime there are only so many gas pipes feeding natural gas into the New England area, and those gas pipes can be constrained. They're going to be constrained for two reasons.

One, they're going to be constrained because of the physics. There's nothing we can do. The pipe is only so big no matter how big we make it, and we're not going to be changing the price of the existing price any time soon I don't believe. So, there's a physical limit to how much gas can flow through those pipes.

The other constraint that's on the operators is a policy constraint which made sense, that basically says in periods of very low temperatures, commercial and industrial users of gas needs are going to be supporting it into residential people who need fuel for heating, which makes sense. So if we have a generator that's using natural gas, and we have a pipe constraint, and even if we didn't have the constraint, we would have to curtail the usage of generating facilities that use gas from those pipes, so that residential customers can use them.

It begs the question what must be done? I would submit through our review that liquefied natural gas is probably a good path for that until we get through the transition. ...

The next speaker, a director of Operational Performance and Training for regional electricity grid operator ISO New England Inc., continued the discussion:

So in terms of close calls we've had a number of close calls over the past couple of decades, primarily as a result of the region's constrained natural gas system, its reliance on imported fuels, and vulnerability to correlated contingencies. So nearly 20 years ago, back in January of 2004, the events first shed light on New England's constrained pipeline and the risk associated with that.

Only 10 years later during the polar vortex we saw similar events: constrained pipelines, operational challenges, and in this case reserve deficiencies. Moving forward a little bit closer to today, we've seen more recent issues particularly during the winter of 17-18 where we were only days away from running out of useable fuel in the region.

Anybody that was in New England at that time, or had interests in the region, probably remembers this winter.

Another speaker, Commissioner Patrick Woodcock of the Massachusetts Department of Energy Resources, described reliability concerns arising under the status quo including these constraints:

I do think however, what is in my mind is on ISO's description of the 2017-2018 cold snap. And I remember that very well. I remember the frostbite that I got as I was talking to ISO about the depletion of our energy reserves. That was a one in 100 year event and I really do not see market arrangements really being adequate to ensure that generators will make arrangements for that event. 

And we were really on the cusp if there was another N minus 1 event lost to nuclear power plant. We were at the point where we were going to have to really start talking about contingencies and rolling blackouts in New England. That's what we need to prepare for.

In a follow-up request for public comments, FERC summarized the September 2022 forum's scope as including "the historical context of New England winter gas-electric challenges, concerns and considerations for upcoming winters such as reliability of gas and electric systems and fuel procurement issues, and whether additional information or modeling exercises are needed to inform the development of solutions to these challenges." 

To continue the discussions, FERC has now scheduled a second forum to be held this June. According to Commission chair Willie Phillips, the June 2023 event will focus on what he calls "the Commission’s primary job: ensuring reliability of the grid to continue safe and secure delivery of energy services to consumers." 

Reliability is Job No. 1. Each winter, natural gas supply constraints during extreme weather places the New England electric grid and its nearly 15 million residents at risk for rolling blackouts ... I believe addressing this risk is urgent and I am hopeful that we can continue the productive discussions from the last forum as we shift our focus to having stakeholders propose potential solutions to address the winter reliability challenges in the region.

The Commission has also described the objective of the upcoming June 2023 forum as "to shift from defining electric and natural gas system challenges in the New England Region to discussing potential solutions, including both infrastructure and market-based solutions." 

US added record-low amount of interstate gas pipeline capacity in 2022

The least U.S. interstate natural gas pipeline capacity on record was added in 2022, according to the U.S. Energy Information Administration, and nearly all the new capacity was from compressor upgrades, not new pipeline.

EIA is a division of the federal Department of Energy, whose work includes collecting, analyzing, and disseminating independent and impartial energy information to promote sound policymaking, efficient markets, and public understanding of energy and its interaction with the economy and the environment. EIA's data and analysis includes electricity, natural gas, oil, and other forms of energy commodities and related infrastructure.

Since 1995, EIA has tracked interstate natural gas pipeline capacity additions. According to EIA's most recent report, in 2022, 897 million cubic feet per day (MMcf/d) of interstate natural gas pipeline capacity was added in the U.S, but this was the smallest amount of new interstate pipeline capacity for any prior year:

According to EIA's State-to-State Capacity Tracker, which contains information on the capacity of natural gas pipelines that cross state and international borders, only five new interstate natural gas projects came online in 2022, and these focused primarily on upgrading compressor stations, "with only one project adding a relatively small amount of new pipe."

EIA says interstate capacity additions were low in 2022 for two primary reasons: more growth in intrastate capacity (not captured in its interstate data), and less overall capital expenditures by oil and natural gas companies.

EIA notes that in prior years, interstate pipeline capacity was added from looping and compressor station projects designed to accommodate growing production in Appalachia. While these types of projects were the most common for developing new interstate pipelines, all of the planned projects are  now mostly completed. 

Since 2017, about 70% of the growth in natural gas production has come from wells in the Permian and Haynesville regions which are near liquefied natural gas (LNG) export terminals sited on the Gulf Coast. EIA also notes growth in intrastate projects, including in Texas and Louisiana where intrastate projects, rather than interstate projects, have increased takeaway capacity and connected natural gas production to LNG export terminals. According to EIA:

Building large-scale, commercial natural gas pipelines that cross state boundaries involves a number of contractual, engineering, regulatory, and financial requirements. These requirements may involve more coordination and can take longer to complete compared with intrastate pipeline projects.

EIA has previously noted decreased capital expenditures by oil and gas companies since 2019.

State utility regulators as well as the regional grid operator ISO New England have found that constraints on interstate natural gas pipeline infrastructure drive up the price of electricity for New England consumers.

Maine electricity cost increases driven by natural gas pricing

Maine's increased electricity costs in the past year were yet again driven by increases in the cost of natural gas, according to the most recent annual report from Maine utility regulators.

The Maine Public Utilities Commission regulates electric, gas, telephone, and water utilities, as part of a regulatory system intended by statute to achieve multiple purposes, including to ensure safe, reasonable and adequate service, to assist in minimizing the cost of energy available to the State’s consumers, to ensure that the rates of public utilities subject to rate regulation are just and reasonable to customers and public utilities and to reduce greenhouse gas emissions to meet the greenhouse gas emissions reduction levels.

The Commission issues various reports, including an annual report to the Legislature presenting an overview of the Commission's work in the prior calendar year. The Commission's most recent annual report, released in February 2023, covers the 2022 calendar year.

According to the 2022 report, wholesale electric energy costs nearly doubled year-over-year, driven by increased natural gas pricing:

Wholesale electricity market costs to Maine consumers for the period December 2021 to November 2022 were $1,067,263,891. This is approximately a 77% increase from the $603,233,815 market costs the year prior. Between the two periods, wholesale energy costs increased 86% and capacity costs increased by 29%. The increased electricity costs were driven by the highest natural gas costs the region has experienced since 2014.

These recent gas-driven price increases continue a trend established in prior years, as the 2021 report shows:

Regional wholesale energy prices in the ISO-NE Real-Time market during the 12-month period ending October 31, 2021 averaged $40.7/MWh, about 71% higher than prices during the prior 12-month period. From December 2020 – February 2021, prices averaged $52/MWh, which is about 73% lower than the prior winter period.

According to the 2021 report, with respect to supply rates, "The increases reflect prevailing energy market conditions, including those in the regional electric power market in which prices are strongly influenced by natural gas." The report documents increases in other energy products: between October 2020 and October 2021, natural gas prices increased by 94.8%, and heating oil prices increased by 121.7%; by comparison, between November 2020 and November 2021, wholesale electricity prices increased by 126.3%.

The Maine PUC's findings align with recent reports from regional grid operator ISO New England Inc., which concluded that increased energy costs in New England throughout 2021 and 2022 were driven by high natural gas prices.

New England electric prices increase due to natural gas pricing, again

Increased energy costs in New England in fall 2022 were a result of higher natural gas prices, according to a report by the regional wholesale electricity market monitor. The finding continues a trend documented throughout 2021, through which high natural gas prices drive higher prices in electric energy markets.

ISO New England Inc. is the regional transmission organization responsible for operating New England's wholesale electricity markets. The ISO's Internal Market Monitor (IMM) department regularly evaluates the markets and issues reports, including quarterly and annual assessments.

Each of the market monitor's four most recent quarterly reports has noted year-over-year increases in the cost of wholesale electricity in New England -- and says the cost of natural gas explains the electricity price hikes:

Winter 2022: High natural gas prices drove an 85% year-over-year increase in the region’s wholesale market cost of electricity for the winter of 2022 ...

Spring 2022: Rising natural gas prices continued to drive up the region’s wholesale market cost of electricity in the spring of 2022, resulting in a 78% increase over the spring of 2021 ...

Summer 2022: The cost of electricity on New England’s wholesale markets in the summer of 2022 was 79% higher than in the summer of 2021 ...

Fall 2022: High natural gas prices continued to drive increases in the cost of wholesale electricity in New England in the fall of 2022 ...

The market monitor's reports show that natural gas pricing is responsible for wholesale electricity price increases, providing explanations like this one for fall 2022, "Energy market costs totaled $1.85 billion, up 13% from $1.64 billion last fall. Driving the increase was the cost of natural gas, which rose 18% compared to the fall of 2021."

The IMM's fall 2022 report documents natural gas pricing as a key driver of electricity prices:

Natural gas prices, which saw record lows in 2020 and record highs in 2021 and 2022, continued to be a key driver of energy prices. The Fall 2020 natural gas price ($1.93/MMBtu) was the lowest fall price since 2001, while the Fall 2022 natural gas price ($6.00/MMbtu) was the highest fall price since Fall 2008.

2022's year-over-year price increases follow a 2021 in which New England’s average wholesale energy prices rose to their highest levels in seven years in 2021. According to the 2021 annual report by ISO-NE's IMM, 2021's high prices too were caused by natural gas pricing:

High natural gas prices drove higher prices in the energy markets, leading to a 38% year-over-year increase in the total wholesale market cost of electricity, which rose from $8.1 billion in 2020 to $11.2 billion last year. The increase followed record-low energy prices recorded during the first months of the COVID-19 pandemic.

In addition to playing a significant role in setting the price of electricity in the regional energy market, natural gas also plays a major roles in regional electric reliability, according to ISO-NE:

During the last few years, inadequate infrastructure to transport natural gas has at times affected the ability of natural-gas-fired plants to get the fuel they need to perform. This energy-security risk has become a pressing concern in New England, considering the major role natural-gas-fired generation plays in keeping the lights on and setting prices for wholesale electricity.

According to ISO-NE's resource mix documentation, in 2022 natural gas provided 52% of wholesale electric generation in New England, and supplied the energy serving 45% of New England load.

Heat pumps in Maine give lowest-cost heat, per state energy office

Heat pumps in Maine heated homes and other buildings at a lower per-unit cost compared to furnaces fueled by natural gas, oil, or propane, or electric baseboard heating, according to statewide average data recently reported by the state energy office. 

Maine's state energy office describes the state as having "long been a national outlier for reliance on oil". According to the U.S. Energy Information Administration, "Three-fifths of Maine's households use fuel oil as their primary energy source for home heating, a larger share than any other state." EIA data for 2020 shows that Maine consumed 31 million barrels of petroleum for all uses, with residential heating accounting for 7,155,000 of these barrels at a cost of over $652 million.

Heat pumps provide energy efficient heating and cooling to Maine’s homes and businesses and reduce the state’s high reliance on fossil fuels for heating. State law and Maine's Climate Action Plan establish a goal for the installation of 100,000 new heat pumps by 2025, with 15,000 new heat pumps being provided to income-eligible households. 

Efficiency Maine Trust, the state's quasi-governmental energy efficiency organization, offers rebates for heat pump installations for residential, low-income, and commercial customers. According to Efficiency Maine Trust, "Tens of thousands of heat pumps have been installed in homes and businesses across Maine. They are the most popular heating system across all of Efficiency Maine’s rebates because they offer highly efficient heating, air conditioning, and dehumidification."

A legislative resolve enacted in 2022 directed the Governor's Energy Office to monitor, in coordination with the Office of the Public Advocate and the Public Utilities Commission, factors that directly affect energy supply and costs in the service territory of the northern Maine independent system administrator and in other rural or geographically isolated communities in the State, including, but not limited to, electric grid reliability, availability and costs of electric generation resources, electricity rates and heating fuel supplies and costs.

The Governor's Energy Office released a report in February 2023 addressing the resolve. Regarding heat pumps, the report notes:

Heat pumps provide energy efficient heating and cooling to Maine’s homes and businesses in addition to decreasing the state’s high reliance on fossil fuels for heating. The benefits of heat pump adoption and weatherization not only include lower prices as compared to other common heating systems (which in Maine are predominately delivered fuel), but also climate benefits including reduced greenhouse gas emissions and increased resilience to fossil fuel price swings. 

The report includes a graph presenting a price comparison of common heating systems in Maine, from 2019 through 2021, using statewide average data. The graph shows that heat pumps were the lowest-cost source of heat over the time period, relative to other typical heating systems such as furnaces fueled by natural gas, oil, or propane, or electric baseboard heating:

In addition, Maine utility Central Maine Power Company has offered a "Seasonal Heat Pump Rate" pilot program limited to the first 5,000 participants. The pilot rate differs from the utility's standard tariffed rates, but has potential to provide significant savings to heat pump users whose usage characteristics align with the rate's incentives.

Maine PUC RFP for Wood-fired CHP

Maine utility regulators are soliciting proposals from qualifying combined heat and power projects that use wood fuel to generate electric heat and power for industrial or space heating purposes to sell energy, capacity or renewable energy credits (RECs) to Maine's investor-owned transmission and distribution utilities. 

Cogeneration, or combined heat and power (CHP), involves the generation of electricity in ways that also enable the productive use of heat from the generation process. Cogeneration can provide significant efficiency advantages compared to standalone electric power generation using thermal fuels, because typical standalone electric power plants cannot capture as much of their fuels' energy content as can CHP plants.

A law enacted by the Maine legislature in 2022 requires the state's Public Utilities Commission to establish a wood-fired CHP program. The law, An Act To Establish a Wood-fired Combined Heat and Power Program. P.L. 2021, Chapter 604, creates opportunities for qualifying combined heat and power projects to seek Commission-ordered long-term contracts to sell electricity or RECs to Maine's investor-owned transmission and distribution utilities.

To implement the Act, the Commission has issued a Request for Proposals in Docket No. 2022-00342. To be a qualifying combined heat and power project for this RFP, a generation facility must meet the requirements of Section 3 of last year’s new law, including the following:

To participate in this RFP, a project must meet the eligibility requirements specified in the Act. Specifically, a project must be a combined heat and power project, which is defined as a facility that uses wood fuel to generate electric heat and power that is used for industrial or space heating purposes. Wood fuel is defined as biomass derived from: (1) forest products manufacturing residuals, including, but not limited to, mill chips, sawdust, bark, shavings and fines; (2) harvest residues, including trees or portions of harvested trees that are too small or of too poor quality to be used for wood products; or (3) downed trees from weather events and natural disasters, nonhazardous landscape or right-of-way trimmings, and plant material removed for purposes of invasive species control.

The Act and the RFP impose additional requirements, including that qualifying projects must be connected to the Maine electric grid; have an in-service date after November 1, 2022; satisfy the limits on net generating capacity of no less than 3 MW and no more than 10 MW in any hour; be highly efficient, as determined by the Commission; and not be a participant in net energy billing under Maine law. 

Under the RFP, bidders selected by the Commission will enter into contract(s), with one or both of Maine's investor-owned utilities, for a term of up to 20 years. The RFP prescribes that the Commission will evaluate proposals based upon the requirements and objectives stated in the Act and the RFP, which include 30% for efficiency and heat utilization, 40% for total cost, and 30% for certain other policy-based factors (like alignment with waste diversion and renewable policies, economic impact including jobs, net greenhouse gas emissions, location and local electric demand, and alignment with load patterns expected from beneficial electrification).

According to the RFP, responsive proposals must be submitted to the Commission by 11:59 PM on March 3, 2023.

Where did New England's electricity come from in 2022?

Natural gas was the source of about 45 percent of the electricity consumed on the New England grid in 2022, according to regional wholesale market operator ISO New England, Inc., and nuclear power provided another 23 percent. Imported electricity accounted for about 14 percent. 

ISO-NE is the federally designated regional transmission organization responsible for the electric transmission system and wholesale electricity market covering nearly all of the New England region. It describes itself as "the independent, not-for-profit corporation responsible for keeping electricity flowing across the six New England states and ensuring that the region has reliable, competitively priced wholesale electricity today and into the future."

The grid operator periodically releases data on the portfolio of generating resources providing power to the wholesale market. Its most recent summary covers the 2022 calendar year. According to that summary of preliminary data, total production for the year (net energy for load, or NEL), amounted to 118,878 gigawatt-hours (GWh).

Of this total amount of electricity consumed from the New England electric grid in 2022, in-region electric generation accounted for 103,877 GWh in 2022, or about 87 percent. Imports from neighboring control areas like Quebec, New Brunswick, and New York accounted for about 14 percent. ISO-NE's analysis then deducts about 1 percent of NEL to account for electricity consumed in pumping water uphill for use in pumped storage generation facilities.

Focusing on in-region generation in 2022, ISO-NE's data shows the following resource contributions to net energy load:

In commentary, ISO-NE noted that solar power production increased by about a third from 2021 to 2022, reaching 3 percent of net energy for load, and nearly tying wind power; meanwhile, the grid operator noted that oil's contribution increased year over year, "reflecting rising prices for the region’s main energy fuel, natural gas, that made oil more economical at certain times of the year."

Federal funds expected for tribal clean energy projects

The U.S. Department of Energy's Office of Indian Energy Policy and Programs has announced its intent to make $50 million available this spring for clean energy technology deployment on tribal lands. 

The Energy Policy Act of 2005 authorized the Department of Energy to establish the Office of Indian Energy, which is directed and authorized to provide, direct, foster, coordinate, and implement energy planning, education, management, development, and efficiency. Its mission is to maximize the development and deployment of energy solutions for the benefit of American Indians and Alaska Natives.

On January 26, 2023, the Office of Indian Energy issued a Notice of Intent (NOI) to release a $50 million Funding Opportunity Announcement (FOA) later this year, to support clean energy technology deployment on tribal lands. Through the anticipated FOA, the Office of Indian Energy plans to solicit applications from Indian Tribes, which include Alaska Native Regional Corporations and Village Corporations, Intertribal Organizations, and Tribal Energy Development Organizations to: 

• Install clean energy generating system(s) and/or energy efficiency measure(s) for Tribal Building(s) (Area of Interest 1);
• Deploy community-scale clean energy generating system(s) or energy storage on Tribal Lands (Area of Interest 2);
• Install integrated energy system(s) for autonomous operation (independent of the traditional centralized electric power grid) to power a single or multiple essential tribal buildings during emergency situations or for tribal community resilience (Area of Interest 3); or
• Power unelectrified Tribal Buildings (Area of Interest Area 4).

Except for Area of Interest 4, the NOI indicates that awards are intended for Tribal Buildings that are either (1) grid-connected (connected to the traditional centralized electric power grid), or (2) connected to an integrated energy system(s) that operates autonomously from the grid (not connected to the traditional centralized electric power grid). Area of Interest 4 is intended to deploy integrated energy system(s) or energy infrastructure to provide electricity to Tribal Buildings which otherwise would be unelectrified, where “unelectrified” means Tribal Buildings that are not connected to (1) the traditional centralized electric power grid, or not connected to (2) an integrated energy system(s) operating independent of the traditional centralized electric power grid. 

According to the announcement, awards are anticipated to range from $100,000 to as much as $5 million, depending on its Area of Interest.

The NOI, formally named Clean Energy Technology Deployment on Tribal Lands – 2023 (DE-FOA-0002974), is available on the Office of Indian Energy's funding opportunities website. 

131st Maine Legislature EUT Energy, Utilities and Technology Committee

 As 2023 advances, the 131st Maine Legislature has convened in Augusta to pursue its lawmaking agenda. Under the Legislature's rules, the Joint Standing Committee on Energy, Utilities and Technology (EUT) plays important roles.

The EUT Committee is one of the 17 joint standing committees of the Maine Legislature, charged with responsibilities pursuant to the Legislature's Joint Rules including considering and reporting to both chambers on legislation; reviewing and making recommendations on budgeting and fiscal policy issues concerning state government; conducting oversight and review of the actions of departments and agencies of state government; reviewing and making recommendations on gubernatorial appointments that require legislative confirmation; and performing other tasks assigned to them, like reviewing specific provisions of law, conducting studies on assigned topics, issuing reports on policy and legal issues of interest to the Legislature, and reporting out specific legislation pursuant to joint order. The EUT Committee exercises jurisdiction in the areas of energy, utilities and technology. Other committees exercise jurisdiction over other areas, such as environment and natural resources.

By rule, each of the joint standing committee consists of 13 members, 3 from the Senate and 10 from the House of Representatives. For the 131st Legislature, the following legislators have been assigned or appointed to the EUT Committee:

• Senator Mark Lawrence of York- Chair D - Senate District 35
• Senator Nicole Grohoski of Hancock D - Senate District 7
• Senator Matthew Harrington of York R - Senate District 33
• Representative Stanley Zeigler of Montville- Chair D - House District 40 
• Representative Mark Babin of Fort Fairfield R - House District 3 
• Representative James Boyle of Gorham D - House District 109 
• Representative Larry Dunphy of Embden U - House District 72 
• Representative Steven Foster of Dexter R - House District 32 
• Representative Valli Geiger of Rockland D - House District 42 
• Representative Christopher Kessler of South Portland D - House District 121 
• Representative Reagan Paul of Winterport R - House District 37 
• Representative Walter Runte of York D - House District 146 
• Representative Sophia Warren of Scarborough D - House District 124

The Committee's page on the legislative website provides information including contact information for Committee members and staff, and scheduling information, among other materials.