NESCOE requests first ISO-NE LTTP RFP

In a move that could unlock significant new energy supplies for New England, a committee representing the six states has asked the region's electric grid operator to use a new process to solicit transmission capable of accommodating large amounts of new generation plants interconnected to the Maine grid.

The New England States Committee on Electricity (NESCOE) is a not-for-profit entity recognized by the Federal Energy Regulatory Commission (FERC) as a regional state committee. NESCOE represents the collective perspective of the six New England states in regional electricity matters. The organization typically focuses on two areas: resource adequacy and system planning and expansion.

For several years, NESCOE has been engaged with regional grid operator ISO New England to reform the region's longer-term transmission planning (LTTP) process. In an initial phase, in 2022 FERC approved a new process through which NESCOE may ask ISO-NE to perform system planning analyses that may extend beyond its usual 10-year planning horizon and that identify, at a high-level, transmission infrastructure necessary to meet a New England state’s energy policy, mandate, or legal requirement.

Meanwhile ISO and stakeholders continued to develop a second phase of reforms, which FERC accepted in July 2024. The second phase's reforms included a new "scenario-based" LTTP process. The second phase of LTTP reforms also creates a process to advance identified transmission upgrades into developable projects. It also includes a cost-allocation mechanism for those transmission improvements

On December 13, 2024, NESCOE submitted a request to ISO-NE, asking the grid operator to issue its first regional solution under this new LTTP process. NESCOE identified the following minimum scope for the first LTTP RFP:

 (1) a requirement to increase the Maine-New Hampshire interface capacity to at least 3,000 MW by 2035 and increase the Surowiec-South interface capacity to at least 3,200 MW by 2035; and

(2) a requirement to develop new infrastructure (e.g., substation) at Pittsfield, Maine that can accommodate the interconnection of at least 1,200 MW (nameplate) of onshore wind. Pittsfield should be used as the presumed location based on previous analysis, however, bidders may propose alternate locations which, based on their own expertise, bidders conclude would be more efficient and cost-effective.

(3) The required in-service date for both scope components is by 2035 unless a bidder can demonstrate supply chain issues that warrant a later in-service date. A strong preference should be given to bids with an in-service date by 2035, or as close as possible thereto recognizing supply chain constraint information bidders provide.

According to NESCOE, this scope includes "two equally important requirements that, when taken together, should result in improvements to the transmission system that will benefit consumers." 

Record-low inflation-adjusted natural gas prices, says EIA

For the tenth time this year, natural gas at the U.S. benchmark "Henry Hub" pricing point has reached an all-time low in inflation-adjusted dollars, according to the federal Energy Information Administration.

Image source: U.S. Energy Information Administration

According to U.S. EIA, natural gas at the Henry Hub has recently reached all-time low pricing on an inflation-adjusted basis. EIA says gas at Henry Hub was priced at $1.21 per million British thermal units (MMBtu) twice last month, on November 8 and November 11, 2024. EIA called this pricing "an all-time low in inflation-adjusted dollars." 

These record low prices were just the latest in a series, as two earlier days in November had already seen record low inflation-adjusted prices for gas at the Henry Hub. Six more record-low inflation-adjusted prices occurred earlier in 2024, according to the energy agency.

EIA attributes the record-low prices to factors including robust supply and constraints on demand. EIA also notes that natural gas prices can be volatile, as "Henry Hub spot prices spiked to over $13/MMBtu in January due to well-below-normal temperatures across most of the United States."

Corporate nuclear power offers solicited

Tech company Meta Platforms Inc. has issued a request for proposals "to identify nuclear energy developers to help us meet our AI innovation and sustainability objectives — targeting 1-4 gigawatts (GW) of new nuclear generation capacity in the U.S."

In a statement on its sustainability blog, Meta expressed its views that nuclear power would help the company meet its objectives relating to both artificial intelligence and sustainability:

... we believe that nuclear energy can help provide firm, baseload power to support the growth needs of the electric grids that power both our data centers (the physical infrastructure on which Meta’s platforms operate) as well as the communities around them. ... At Meta, we believe nuclear energy will play a pivotal role in the transition to a cleaner, more reliable, and diversified electric grid.

Citing its experience helping the renewable energy industry develop, Meta says it is taking a similar approach to nuclear power: 

When we began engaging with the renewable energy industry more than a decade ago, the industry was scaling. Our early engagement with developers of renewable energy allowed Meta to design contracts that enable both Meta and our developer partners to achieve our respective goals. We want to work creatively with developers to structure an agreement that will similarly enable development of nuclear technology.

At the same time, Meta notes that nuclear power's needs are somewhat different from those of renewable projects, due to key technological, economic, and regulatory differences: 

Compared to renewable energy projects that we continue to invest in, such as solar and wind, nuclear energy projects are more capital intensive, take longer to develop, are subject to more regulatory requirements, and have a longer expected operational life. These differences mean we need to engage nuclear energy projects earlier in their development lifecycle and consider their operational requirements when designing a contract. And, as scaling deployments of nuclear technology offers the best chance of rapidly reducing cost, engaging with a partner across projects and locations will allow us to ensure that we can deploy strategically. An RFP process will allow us to approach these projects thoroughly and thoughtfully with these considerations in mind.

Meta's RFP is not directly available to the public. Instead, Meta's blog directs interested parties to complete a qualification intake form by January 3, 2025, with initial RFP proposals due on February 7. Meta says it will screen interested parties for their qualifications, including "developers with strong community engagement, development, and permitting, and execution expertise that have development opportunities for new nuclear energy resources – either Small Modular Reactors (SMR) or larger nuclear reactors." Meta says it will also require interested parties to execute a non-disclosure agreement before receiving Meta's Nuclear RFP.

Other tech companies are similarly pursuing nuclear energy projects to power datacenters, as are some utilities. Nuclear power is drawing renewed interest from other sectors too, like the military and even industrial manufacturers.

New England passes its 100th duck curve day of 2024

For the 100th time this year, demand for electricity from New England's power grid was lower at midday than overnight, a sign of significant growth in behind-the-meter solar photovoltaic power in recent years. Until 2018, this phenomenon -- called the "duck curve" due to the shape of graphs of demand -- had never occurred. But according to the region's grid operator, duck curve days will likely continue to recur.

ISO New England says that April 21, 2018 was the first day when "New Englanders used less grid electricity midday than while they were sleeping". Nearly two years later, by the spring of 2020, the duck curve phenomenon had appeared on seven days. By the end of 2021, it had occurred a total of 35 times.

The duck curve phenomenon has since gone from rare to common. The grid operator says there were "45 times in 2022 when demand for grid electricity was lowest during the day instead of at night." In 2023, New England experienced 73 duck curve days. Last year the region also set a new low for midday demand, thanks to mild temperatures, a holiday, and continued growth of behind-the-meter solar.

The duck curve trend has continued to spread. According to ISO-NE, "the region recorded its 100th 'duck curve' day of 2024 on Monday, November 25."

Graph from ISO-NE. Available at 100th ‘duck curve’ day marks New England solar power milestone - ISO Newswire

So far this year, the New England grid has also set a new record low for midday demand. 

The grid operator notes:

Duck curve days are becoming more frequent as more New England homeowners and businesses install solar power systems. But duck curves are not disruptive from a grid operations perspective. Staff in the ISO’s control room keep the entire system in balance by instructing the region’s other energy resources to decrease production when BTM PV output is high, and to increase production when BTM PV output is low. 

At the same time, this level of solar penetration requires flexibility from "the region's other energy resources", which must be technically capable of ramping up and down to follow load, as well as economically capable of sustaining commercial operations.

Small modular reactors and Maine's nuclear referendum law

Tech companies, datacenters, and industrial consumers are pursuing the development of small modular nuclear reactors (SMR), capable of producing stable amounts of carbon-free power at a distributed scale. 

Much smaller than a typical commercial or utility-scale nuclear power plant, SMRs are typically envisioned as varying in size from tens of megawatts up to hundreds of megawatts, with potential uses including power generation, process heat, desalination, or other industrial uses.

Utilities, tech companies and some other corporate energy consumers have signed deals or announced plans to pursue SMR development. In 2023, GE Hitachi Nuclear Energy announced that it had signed a contract with Ontario Power Generation and others to deploy a BWRX-300 SMR at the Darlington New Nuclear Project site. GE's press release called the Darlington deal "the first commercial contract for a grid-scale SMR in North America." 

That same year, materials science manufacturer Dow announced a joint development agreement with X-Energy Reactor Company, LLC "to demonstrate the first grid-scale advanced nuclear reactor for an industrial site in North America." The Dow project involves the installation of an Xe-100 SMR at one of Dow’s U.S. Gulf Coast sites, using funding from sources including the Department of Energy's Advanced Reactor Demonstration Program. 

Federal support for SMR development is both longstanding and bipartisan. The Department of Energy cites an unbroken heritage of support for SMRs since the late 1990s. Both President Obama and President Trump issued executive orders promoting the design and development of small modular nuclear reactors. Under the Biden administration, the U.S. Department of Energy has described advanced SMRs as "a key part of the Department’s goal to develop safe, clean, and affordable nuclear power options." Last month, the Energy Department offered up to $900 million in funding to support the initial domestic deployment of Generation III+ (Gen III+) SMR technologies.

Corporate interest in SMRs has continued, and maybe even grown. In October 2024, Dominion Energy Virginia announced that it had entered into a memorandum of understanding with Amazon "to explore innovative new development structures that would help advance potential Small Modular Reactor (SMR) nuclear development in Virginia." With federal energy regulators recently rejecting a separate plan to co-locate an Amazon data center behind-the-meter at the utility-scale Susquehanna nuclear plant, corporate buyer pressure may soon place an increased emphasis on developing new SMRs at datacenter sites, rather than siting datacenters at existing nuclear plants.

Might small modular reactors come to Maine? Maine's history with nuclear energy involves the now-decommissioned Maine Yankee plant, the continued storage of its spent nuclear fuel and radioactive reactor components, and public perceptions of nuclear power. As a result of this history, any Maine SMR project faces challenges including a law which requires approval by the state's voters through a statewide referendum before any nuclear reactor may be constructed. 

A law enacted in 1987 provides for "citizen participation in any decision to construct a nuclear power plant within the State." Now codified as Chapter 43 of Title 35-A of the Maine Revised Statutes, this law requires a statewide referendum asking voters to accept or reject construction of any proposed plant, through balloting on the following question: "Do you approve construction of the nuclear power plant proposed for (insert locations)?"

As interest in SMRs continues to grow, expect Maine to consider its 1987 nuclear referendum law, and whether change is appropriate to enable small modular nuclear reactor development in Maine.

New England natural gas market dynamics affected by constraints and changing supply mix

Natural gas market dynamics vary across the U.S., according to the U.S. Energy Information Administration, with a key pricing hub in the Northeast showing both high prices and high price volatility due to constrained infrastructure and a changing supply mix.

According to EIA, natural gas is traded at about 200 pricing hubs across North America, with prices varying widely based on factors including location, weather conditions, proximity to supply, pipeline constraints and bottlenecks.

EIA produced the graphic below, showing the range of natural gas spot prices at seven key pricing hubs for the first nine months of 2024. It shows that the Algonquin Citygate pricing hub experienced the highest average price over this time period, as well as the highest spot price and the largest price volatility (or range of prices).

Chart source: U.S. Energy Information Administration

According to EIA: 

Algonquin Citygate is an important pricing hub in the northeastern United States, and prices at this hub reflect natural gas market dynamics in Boston, Massachusetts, and elsewhere in New England. New England relies heavily on natural gas for heating in the winter months, but supplies are constrained by the region’s limited natural gas pipeline capacity and changing fuel mix. Price volatility at Algonquin Citygate is typically related to these periods of peak demand.

As EIA notes, natural gas pipeline constraints contribute to high prices and price volatility in New England, particularly during the winter heating season.

Maine PUC awards biomass power contract

Maine utility regulators have voted to award a long-term contract to a biomass-fueled power plant proposed for development in northern Maine.

In 2022, the Maine legislature enacted a law directing the Public Utilities Commission to establish a wood-fired combined heat and power program. The law creates an opportunity for qualifying projects to compete for long-term contracts to sell electricity or renewable energy certificates to Maine's investor-owned transmission and distribution utilities. In 2023, the PUC solicited proposals, but the PUC ultimately found that none of the proposals submitted were eligible for contracting under the 2022 law.

In 2023, the legislature amended the procurement law to broaden program eligibility including with respect to size, net generating capacity, and location. The PUC issued a revised request for proposals under the amended law. 

Now, the PUC has selected a proposal by Ashland CHP LLC to sell the electricity generated by a new biomass-fueled facility to the local utility. According to the PUC, the facility would include about 17.75 megawatts of biomass power, with 15 megawatts of electricity offered into the program, and the remaining power used for heating.

In deliberations, Maine PUC commissioners encouraged the purchasing utility to "secure offtake for the project" and to "maximize the value of the energy from this project". Maine restructured its investor-owned utilities 25 years ago, to separate wires-owning utilities from deregulated generation and competitive retail supply. The restructured utility environment means that the utility has no natural need for power, so the utility typically resells its entitlements under power purchase agreements to other buyers. 

Gulf of Maine offshore wind lease auction scheduled

U.S. ocean energy managers will soon auction the right to lease about 850,000 acres offshore Maine, New Hampshire, and Massachusetts, according to a recent federal announcement. 

On September 16, 2024, the Department of the Interior announced an offshore wind energy lease sale to be held on October 29, 2024. Through an auction process, the Bureau of Ocean Energy Management will sell leasehold interests in eight designated areas in the Gulf of Maine.

According to BOEM's Final Sale Notice for offshore wind leasing on the Outer Continental Shelf (OCS) in the U.S. Gulf of Maine, the government will auction rights to eight separate lease areas within the Gulf of Maine. Each lease area varies in total acreage as well as "developable acres", with the average size being just over 100,000 acres per area. 

If fully developed, BOEM says these "these areas have a potential capacity of approximately 13 gigawatts of clean offshore wind energy, which could power more than 4.5 million homes."

BOEM notes that these lease areas exclude about 120,000 acres that BOEM had initially proposed for leasing; these areas were removed following public comment, engagement meetings, and concern over impacts to fishing grounds, navigation, and habitats. The Final Sale Notice also follows BOEM's recent issuance of its final Environmental Assessment of leasing in the Gulf of Maine Wind Energy Area (WEA).

Separate from this commercial leasing process, earlier this year BOEM entered into the nation’s first floating offshore wind energy research lease, covering about 15,000 acres elsewhere in the Gulf of Maine.

BOEM releases Gulf of Maine offshore wind environmental assessment

U.S. federal ocean energy managers have issued a final assessment of the environmental impacts of issuing leases for offshore wind development in the Gulf of Maine. The Bureau of Ocean Energy Management's final Environmental Assessment (EA) of the Gulf of Maine Wind Energy Area (WEA) sets the stage for future leasing.

Earlier this year, the U.S. Department of Energy designated the Gulf of Maine WEA and announced that BOEM would prepare an EA on potential impacts from offshore wind energy leasing in the Gulf of Maine. BOEM also proposed an offshore wind energy lease sale in the Gulf of Maine featuring eight potential leasing areas offshore Maine, Massachusetts, and New Hampshire.

Furthering these processes, on September 6, 2024, BOEM announced the availability of its final EA for offshore wind site leasing in the Gulf of Maine. The final EA evaluated the potential issuance of commercial wind energy leases off the coasts of Maine, New Hampshire, and Massachusetts. 

BOEM's September 2024 environmental review considered potential environmental impacts from pre-development activities like conducting surveys and installing meteorological buoys. BOEM found that leasing and these site assessment and characterization activities will not have a significant impact on the environment.  

Notably, this EA did not cover the installation of offshore turbines in the Gulf of Maine. Any specific project development of that nature would need to be assessed in a separate environmental review, following lease issuance and a project proposal by a leaseholder.

Separately, in August 2024, the Department of Interior issued a research lease for a floating offshore wind project in the Gulf of Maine. BOEM has called that agreement "the nation's first floating offshore wind energy research lease." 

ISO-NE EPCET report projects future power supply and demand

New England's electric grid must overcome operational, engineering, and economic challenges to support state decarbonization commitments, according to a recently released draft report by grid operator ISO New England. ISO-NE's Economic Planning for the Clean Energy Transition (EPCET) study report concludes that a "vast renewable build-out may be required" to support wide swings in demand for electricity across days and seasons.

Today, peak demand for electricity occurs during the summer for reasons including air conditioning demand. But ISO-NE projects that peak demand for electricity will shift from summer to winter by the mid-2030s, as heat pumps are increasingly used to decarbonize building heating. 

As this new form of heating load becomes dominant, the weather will increasingly affect the level of peak demand, with a severe winter calling for up to 20 gigawatts more power than a mild winter. Increased variability in power system demand will require "vastly different supply levels from year to year", according to ISO-NE. The grid operator expects that this variability will mean that some dispatchable capacity is needed for reliability but might operate infrequently: "Some resources needed to maintain reliability during the harshest conditions may only run for a few days once every few years."

Another consequence of this variability is that emissions reductions will vary seasonally. Relatively high power production by wind and solar resources in spring and fall could combine with relatively lower levels of electricity demand in those seasons to yield substantial decarbonization in spring and fall, many years before summer or winter achieve that level of decarbonization. "Modeling shows spring will be mostly decarbonized by 2040, but a small portion of winter days will still produce significant emissions in 2050."

To meet these projected levels of demand solely with renewable resources, ISO-NE projects that the scale of development needed is vast. "If the future resource build-out is almost entirely wind, solar, and batteries, the region will need to add roughly 18 times its current combined capacity of these resources to achieve state emissions goals and maintain reliability." Revenue structures for generators might also need to change, to accommodate expected surplus generation from wind and solar resources in spring and fall. 

ISO-NE thinks that long-duration storage can help during shorter cold snaps but not over more extended periods of severe winter weather. To ensure reliability during prolonged severe winter conditions, ISO-NE suggests firm, dispatchable, zero-carbon generation, such as the use of synthetic natural gas (SNG) and small modular nuclear reactors (SMRs) as possible resources. The EPCET report concludes that SNG and SMRs may reduce overall system costs, by reducing the need for new renewable capacity.

BOEM issues Maine a floating offshore wind energy research lease

U.S. federal ocean regulators have announced the execution of a lease with the State of Maine for almost 15,000 acres located on the outer continental shelf offshore Maine. The Bureau of Ocean Energy Management calls the agreement "the nation's first floating offshore wind energy research lease." 

According to BOEM, the lease area includes approximately 14,945 acres, an area of sea sufficient to host up to 12 floating offshore wind turbines collectively capable of generating up to 144 megawatts of renewable energy. BOEM says the research lease will let Maine and stakeholders "conduct in-depth studies and thoroughly evaluate floating offshore wind as a renewable energy source" and "evaluate its compatibility with existing ocean uses and assess its potential effects on the environment, supply chains, and job creation."

BOEM issued the Maine lease through a process that began with the State's October 2021 application for a lease. In 2023, BOEM issued a Determination of No Competitive Interest for the area, enabling BOEM to issue Maine the lease. Maine has described the floating offshore wind research array as "a key priority for the State that will help fulfill the objectives of the Maine Offshore Wind Roadmap by advancing critical research and innovation to develop offshore wind responsibly."

As a research lease, the State of Maine or its designated operator Pine Tree Offshore Wind, LLC will engage in research regarding environmental and engineering aspects of the proposed project, to be made public and for use in informing future commercial-scale floating offshore wind projects in the region. According to BOEM, construction activity on the research array is not likely to occur for several years and will require additional permitting.

Maine PUC inquires into storm costs and grid resilience

Citing "increasing storm frequency and severity, and escalating storm restoration costs", Maine utility regulators have opened an inquiry to obtain information about the problem and how it could be addressed.

On July 25, 2024, the Maine Public Utilities Commission (PUC) issued a Notice of Inquiry in docket 2024-00191. According to that notice:

Maine is experiencing increasing storm frequency and severity, and escalating storm restoration costs. While utilities are developing their grid plans and doing the vulnerability assessments and preparing resiliency/mitigation plans, the Commission opens this inquiry to look for some shorter-term efforts to reduce the impact of storm damage to the system and study ways in which Maine’s electric utilities may more proactively address escalating storm costs.

The PUC's notice includes a list of questions and prompts for comment by September 4, 2024. Some questions ask how other states are addressing storm- and resilience-related costs. Others seek information on how Maine utilities might behave differently -- for example, leveraging data systems to prioritize resilience upgrades, shifting away from wood poles, or changing tree trimming protocols and other vegetation management programs. The questions also ask about what "resilience" means and how it can be quantified.

Under PUC practice, an inquiry is a relatively informal proceeding initiated by the PUC to gather information. After the PUC collects information through an inquiry, it can use what it learned to inform a subsequent adjudicatory proceeding (like an investigation) or a rulemaking. 

Outside this inquiry, a recently enacted law requires each of Maine's investor-owned transmission and distribution utilities to develop "a 10-year integrated grid plan designed to improve system reliability and resiliency and enable the cost-effective achievement of the State’s greenhouse gas reduction obligations and climate policies." The utilities must file their proposed grid plans by January 12, 2026.

A separate statute requires each utility to file a 10-year climate change protection plan that includes specific actions for addressing the expected effects of climate change on the utility's assets needed to transmit and distribute electricity to its customers. The first climate change protection plans were due on December 31, 2023, and must be updated every three years.

FERC Order 1920 reforms electric transmission planning

US electricity regulators have issued a major order addressing the nation's policy on regional planning of the electric transmission grid. The Federal Energy Regulatory Commission describes its Order No. 1920 as "the first time in more than a decade that FERC has addressed regional transmission policy – and the first time the Commission has ever squarely addressed the need for long-term transmission planning."

FERC adopted Order No. 1920 at its May 13, 2024 Open Meeting, by a vote of 2-1. Captioned "Building for the Future Through Electric Regional Transmission Planning and Cost Allocation", Order No. 1920 spans 1,364 pages. 

Issued in Docket No. RM21-17-000, the order adopts a final rule revising the Commission's pro forma Open Access Transmission Tariff (OATT) "to remedy deficiencies in the Commission's existing regional and local transmission planning and cost allocation requirements." As described by FERC, the order "finds that sufficiently long-term, forward-looking, and comprehensive regional transmission planning and cost allocation to meet long-term transmission needs is not occurring on a consistent and sufficient basis". According to FERC, this results in "piecemeal transmission expansion that addresses relatively near-term transmission needs" and "transmission providers investing in relatively inefficient or less cost-effective transmission infrastructure", causing customers to incur costs and miss benefits. This, according to the Commission, "in turn renders Commission-jurisdictional regional transmission planning and cost allocation processes unjust and unreasonable."

To remedy this problem, the order prescribes specific requirements that regional grid operators and transmission providers must follow in conducting long-term planning for regional transmission facilities and in allocating their costs. Among other reforms, it requires transmission operators to engage in long-term planning, with a 20-year time horizon, and a process for updates at least once every five years. It requires planners to consider seven specific categories of benefit, to determine whether a regional proposal will efficiently and cost-effectively address long-term transmission needs. These benefits are:

1. avoided or deferred reliability transmission facilities and aging infrastructure replacement;
2. either reduced loss of load probability or reduced planning reserve margin;
3. production cost savings;
4. reduced transmission energy losses;
5. reduced congestion due to transmission outages;
6. mitigation of extreme weather events and unexpected system conditions; and
7. capacity cost benefits from reduced peak energy losses. 

The order includes provisions designed to "right-size" transmission facilities, by which FERC means considering cost-effective expansion to increase transfer capability, whenever replacement is needed. Incumbent transmission owners will have a right of first refusal to develop these "right-sized" transmission facilities.

Order 1920 also gives states key responsibilities in planning, selecting, and determining the cost allocation for transmission lines, while continuing to require that customers pay only for projects from which they benefit. It also creates a process giving states and interconnection customers the opportunity to fund some or all of the cost of a long-term regional transmission facilities that otherwise would not meet the transmission provider’s selection criteria. 

Commissioner Christie dissented, asserting that the order exceeds FERC's legal authority and fails to protect consumers. The order is set to take effect 60 days after its publication in the Federal Register. Order No. 1920 requires one set of compliance filings within 10 months of its effective date, with another round concerning interregional coordination due within 12 months of the effective date.

New England electric load to grow, grid operator says

Electricity consumption in New England will increase by about 17 percent over the next ten years, according to the regional grid operator, mostly due to the electrification of heating and transportation.

ISO New England tracks and projects power generation as well as consumer demand. Its 2024-2033 Forecast Report of Capacity, Energy, Loads, and Transmission (CELT Report) provides a ten-year look at projected power system characteristics. 

According to the grid operator, 2024 represents an inflection point in New England's electricity use, as the regional trend shifts from declining power consumption, back to significant growth. 

From 1995 to 2005, net annual energy use in New England grew steadily. ISO-NE attributes the growth primarily to "increased economic growth and the use of air conditioning". Since peaking in 2005 at 136,425 gigawatt-hours, net annual energy use in the region has generally decreased. ISO-NE attributes the reduction primarily to "an increase in energy efficiency from advanced cooling and heating technologies, energy-efficient appliances and lighting, and the increased prevalence of BTM solar generation."

Now, ISO-NE projects another reversal of this trend, as it forecasts "steady growth in net annual energy use as state policy goals for carbon emissions reductions drive the increased electrification of heating systems and transportation in the region." The grid operator projects that electric vehicles (EVs) "will account for 15,182 GWh of energy use in 2033, while heating electrification is expected to account for 7,996 GWh that year." After considering growth in behind-the-meter solar and efficiency measures, these projections represent an increase of about 17% in regional net annual energy use; meeting these needs will likely require significant new generating plants and transmission facilities.

ISO-NE also projects that the region will shift from summer-peaking to winter-peaking soon after 2033, due to heating electrification. Specifically, the grid operator expects winter demand to grow faster (3% annually under typical weather conditions) than summer demand (1%). 

ISO-NE notes that behind-the-meter solar power "does not reduce winter peak demand, because the peak typically occurs after sunset."

US proposes Gulf of Maine offshore wind site auction

The U.S. Department of the Interior has proposed the first offshore wind energy auction in the Gulf of Maine. The process has potential to advance the development of large-scale offshore wind projects in New England.

BOEM's Proposed Sale Notice for ATLW-11 appeared in the Federal Register on May 1, 2024. According to the Bureau of Ocean Energy Management, the proposed "Atlantic Wind Lease Sale 11 (ATLW-11)" would cover about one million acres of the Outer Continental Shelf offshore Maine, Massachusetts, and New Hampshire. BOEM plans to divide this zone into eight lease areas, which it says could collectively support about 15 gigawatts of offshore wind generation. 

BOEM selected these areas for leasing through a process that included a 2022 Request for Information (considering public comments and impacts to resources regarding a broader 13.7-million-acre area),  a 2023 Call for Information and Nominations, the 2024 identification of a Wind Energy Area (WEA) in the Gulf of Maine, and environmental reviews. 

BOEM says that in identifying the ATLW-11 areas for leasing, it "prioritized avoidance of offshore fishing grounds and identification of vessel transit routes, while retaining sufficient acreage to support the region’s offshore wind energy goals (13-18 GW based on information from Massachusetts, Maine, and ISO-New England)." For example, in response to requests from members of the fishing community, BOEM created three corridors between leases in the southern region of the Final WEA to facilitate existing and future transit through proposed lease areas.

According to BOEM, it has notified the following entities that their qualification is pending or that they are qualified to participate in any Gulf of Maine auction:

• Avangrid Renewables, LLC
• Equinor Wind US LLC
• US Mainstream Renewable Power Inc
• Diamond Wind North America, LLC
• Hexicon USA, LLC
• TotalEnergies SBE US, LLC
• Pine Tree Offshore Wind, LLC
• OW Gulf of Maine LLC
• Repsol Renewables North America, Inc
• Maine Offshore Wind Development LLC
• Corio USA Projectco LLC

Any other entity wishing to participate in any Gulf of Maine auction must submit the required qualification materials to BOEM by July 1, 2024.

US announces offshore wind leasing schedule through 2028, finalizes Gulf of Maine area

The U.S. Department of the Interior has announced a schedule for up to 12 potential offshore wind energy lease sales through 2028, in Atlantic, Gulf of Mexico, Pacific, and territorial waters.

According to Interior, the new offshore wind leasing plan features the following schedule:

2024 Central Atlantic, Gulf of Maine, Gulf of Mexico, and Oregon 

2025 Gulf of Mexico 

2026 Central Atlantic 

2027 Gulf of Mexico and New York Bight 

2028 California, a U.S. Territory, Gulf of Maine, and Hawaii 

The Bureau of Ocean Energy Management, within the Interior Department, produced a visual-format schedule showing more detail on the estimated time range for each round of leasing.

To date, BOEM has held 12 offshore wind competitive lease sales resulting in the issuance of at least 26 leases. 

In support of planned leasing activity, BOEM recently finalized its designation of a Wind Energy Area (WEA) in the Gulf of Maine, capable of supporting 32 gigawatts of generation. The Gulf of Maine WEA covers about two million acres offshore Maine, Massachusetts, and New Hampshire, ranging from approximately 23 to 92 miles off the coast.

BOEM plans to hold a lease auction for sites within the Gulf of Maine WEA later this year.

Bourne tidal hydrokinetic project obtains FERC pilot project license

U.S. hydropower regulators have issued a pilot project license to the Marine Renewable Energy Collaborative of New England (MRECo) for its proposed Bourne tidal hydrokinetic energy project to be located on the Cape Cod Canal in Massachusetts.

MRECo describes itself as a nonprofit corporation that educates and involves all stakeholders (Academic, industry, governmental/regulatory, and public interest groups) to promote the sustainable development of renewable energy in New England ocean waters.

In 2023, MRECo applied to the Federal Energy Regulatory Commision for an 8-year pilot project license for the proposed Bourne Tidal Hydrokinetic Test Site Project. The 50-kilowatt project would include an existing steel platform (installed in 2017), an existing mounting pole, and a new tidal turbine-generator. According to the FERC order, MRECo plans to test various turbine-generator units at the project, including axial, cross flow, oscillating, conveyor, and Archimedes Screw turbine-generator units, but only one turbine-generator unit will be tested at a time. MRECo estimates that testing for any turbine-generator unit will occur for one to two months at a time, with three to four tests per calendar year.  

Photo from MRECo "Current Projects" website

The facilities will be located within the Army Corps-managed canal, less than a mile north of its southern entrance from Buzzards Bay. According to FERC, about 15,000 commercial vessels up to 825 feet in length use the canal each year. 

FERC issued the license under its hydrokinetic pilot project licensing process, a special procedure FERC uses "to meet the needs of entities, such as MRECo, who are interested in testing new hydropower technologies while minimizing the risk of adverse environmental impacts." FERC has described the goal of this process as "to allow developers to test new hydrokinetic technologies, to determine appropriate sites for these technologies, and to confirm the technology’s environmental and other effects without compromising the Commission’s oversight of the projects or limiting agency and stakeholder input."

As outlined in FERC staff’s 2008 white paper presenting the pilot project licensing process, a pilot project should be (1) small, (2) installed for a short term, (3) located in non-sensitive areas based on the Commission’s review of the record, (4) removable and able to be shut down on short notice, (5) removed, with the site restored, before the end of the license term (unless a new license is granted), and (6) initiated by a draft application in a form sufficient to support environmental analysis.

FERC found that these factors applied to the Bourne tidal project, and granted MRECo a pilot license for "an 8-year license term to allow it sufficient time to validate the efficiency of the project prior to applying for a longer-term license for the platform."

Solar power and the Great American Eclipse of 2024

A total solar eclipse traversed North America on April 8, 2024, on a path from Mexico, across the U.S. from Dallas to northern New England, and into Canada. No total eclipse has covered such a large extent of the U.S. in recent years (a 2017 eclipse was the first in the U.S. in 26 years); meanwhile, an increasing amount of solar photovoltaic power plants have been built. The "Great North American Eclipse" of 2024 thus provided an opportunity to examine how a total solar eclipse affects solar power and the broader grid, using New England as an example.

According to New England's regional grid operator ISO New England, "the April 8 solar eclipse led to a steep and significant decrease in solar energy production, but due to extensive planning by ISO New England operators, the event caused no disruptions to the power system." All of New England experienced at least a partial eclipse where the moon blocked at least 80% of the sun. Parts of Vermont, New Hampshire, and Maine experienced totality.

During the two hours around the eclipse's peak, ISO-NE reports that regional solar production dropped by as much as 4,000 megawatts. 

Chart from ISO-NE (source)

Most of the drop-off -- about 3,300 to 3,500 MW -- came from small-scale, distributed photovoltaic panels connected directly to distribution systems which ISO-NE says "make up the vast majority of solar resources in New England", while grid-connected solar system production dropped by about 650 MW. The timing of the eclipse, relatively late in the afternoon, meant that only about 1,350 MW of solar production returned to the system after the eclipse passed.

ISO reports that its market yielded negative real-time prices as the eclipse approached, followed by a price spike over $100 as the eclipse passed overhead, and then price moderation toward the day's average value.

ISO-NE reports no power system or reliability disruptions from the eclipse, thanks to the system operator's planning for the eclipse, and operations which dispatched natural gas and hydroelectric generators to make up the solar power blocked by the moon. 

New England must balance multiple objectives, says grid operator

New England must balance multiple objectives as it navigates the clean energy transition, according to the operator of the region's electric grid and wholesale electricity markets.

ISO New England, Inc. is the regional transmission organization serving all of New England except northern Maine. ISO-NE administers the regional electric transmission system and wholesale markets for electricity. 

The region must increasingly balance multiple objectives in light of state policies promoting renewable energy and decarbonization, according to recent remarks by ISO-NE President and Chief Executive Officer Gordon van Welie. 

Historically, the grid and markets were designed to maintain the reliability of the regional bulk electric system, while minimizing costs by selecting the lowest-price resources: what ISO-NE calls the "least-cost security-constrained economic energy-dispatch model". But according to a presentation by Gordon van Welie at the March 22 meeting of the New England Electricity Restructuring Roundtable, "there is not an adequate regional mechanism to sufficiently value clean energy attributes or price carbon – which are public policy decisions."

Additionally, each of the six New England states has adopted various policies regarding renewable energy and decarbonization or beneficial electrification of the whole economy or of specific sectors like transportation and heating. ISO-NE projects a significant increase in electricity consumption as a result of these state policies, with the potential to triple existing peak demand by the early 2030s. This will require a large scale of carbon-free generating resources. According to van Welie, "Existing carbon-free energy resources are an important part of achieving these policies."

The ISO-NE leader noted the consequence of these dynamics: "Greater dependency on the capacity market for all resources, and a need for supplementary, out-of-market revenues for carbon-free resources that are uneconomic in the wholesale market".

ISO-NE 2024 Regional Electricity Outlook

ISO New England Inc., the operator of New England's wholesale electricity markets and transmission system, has published its 2024 Regional Electricity Outlook. The report examines trends affecting supply and demand for electricity, through the ongoing clean energy transition.

Specifically, ISO-NE notes the dawn of "a new era in our energy history", as broad decarbonization in the name of climate change becomes public policy. According to the grid operator, "This era will be marked by rapid and significant change. Over the next 20 years, we expect that renewable resources will displace natural gas as the main source of electricity generation in the region—just as natural gas displaced coal and oil generation beginning 20 years ago."

As in its most recent prior Regional Electricity Outlook report (issued in 2022), ISO-NE's 2024 report identifies "four pillars for a reliable transition to a greener grid: clean energy, balancing resources, energy adequacy, and robust transmission."

• Pillar One: Clean Energy. "In the coming years, construction of unprecedented amounts of clean energy resources will be needed to meet state decarbonization goals while serving significantly increased demand."
• Pillar Two: Balancing Resources. "Dispatchable generators, energy storage, demand response, and a range of services will be crucial to ensure equilibrium as intermittent resources see swings in energy production."
• Pillar Three: Energy Adequacy. "Risks to energy adequacy could increase if expected renewable resources don’t materialize, needed transmission isn’t built, or fuel supply chains are disrupted."
• Pillar Four: Robust Transmission. "Significant investment in new and existing infrastructure will be critical to enabling the clean energy transition."

In its 2024 report, ISO-NE rated each pillar as green, yellow, or red, based on its relative health and readiness to meet the needs ahead. For example, ISO-NE assigned the first three pillars a rating of "yellow trending green", but ranked transmission development as yellow.

The report concludes that collaboration is essential:

All four pillars must be robust—there is no path to a reliable, clean energy future without all four elements working in concert. That same balance is required from the partnership among the region’s energy stakeholders, with each—the ISO, policymakers, and market participants—doing their part to bring a shared vision for a greener future to fruition.

ISO-NE also notes the importance of education for "all stakeholders—including consumers—to understand how our electric power system operates, and the roles we each can play in ensuring it is clean, cost-effective, and reliable for generations to come."

Court suspends EIA-862 survey of crypto mining energy use

The U.S. Energy Information Administration's efforts to require cryptocurrency miners to report on their electricity use have been suspended by the U.S. District Court for the Western District of Texas, following a complaint by Texas crypto miners alleging that EIA exceeded its regulatory authority in requiring the report. 

Earlier this year, EIA announced a new, mandatory survey of crypto miners. The Form EIA-862 report would cover topics like the nature and scale of equipment installed, electricity consumption, and sources of power. EIA developed the survey and announced it as a new requirement, after requesting and receiving approval from the U.S. Office of Management and Budget for an "emergency data collection request". Emergency requests generally skip procedural steps including publication of a 60-day notice in the Federal Register and public comment. 

But a trade group and a crypto miner sued to block EIA from implementing the EIA-862 survey requirement. They argued that EIA and OMB committed procedural violations in approving the survey, including that EIA failed to establish a bona fide emergency, and that OMB authorized the emergency data collection for 189 days (longer than the 180-day maximum under the Paperwork Reduction Act). 

On February 23, a judge from the federal District Court issued a 14-day temporary restraining order enjoining EIA from implementing the survey requirement, based on a finding that the plaintiffs were "likely to succeed on the merits". The order scheduled a preliminary injunction hearing for February 27.

Regardless of the outcome of the judicial challenge to EIA's Form EIA-862 survey requirement, policymakers will likely continue to be interested in understanding energy consumption requirements for blockchain, crypto, hyper-scaling facilities, and even other data center activities.

Will ISO-NE capacity market shift from forward to prompt/seasonal?

The operator of New England's transmission grid and wholesale electricity markets has proposed major reforms to its market for capacity. For 18 years, ISO New England has administered a "Forward Capacity Market", featuring annual auctions to procure commitments from energy resources, for a capacity commitment period three years in the future. ISO-NE has now proposed to shift to a "prompt/seasonal" model. If adopted, the reforms will change important elements of New England's electric market systems.

According to ISO-NE, its Forward Capacity Market "ensures that the New England power system will have sufficient resources to meet the future demand for electricity." The grid operator adopted a capacity market 18 years ago, to provide a revenue stream to support the development and sustained availability of enough power plants (and eventually other resources like storage and demand response). Under the present construct, ISO-NE holds annual Forward Capacity Auctions (FCA), in which resources compete to obtain a capacity supply obligation (a commitment to supply capacity) in exchange for a capacity payment determined by the auction price.

But now the grid operator has proposed to shift away from a forward market design, to a "prompt/seasonal" design:

“Prompt” means the capacity auction would take place much closer to the delivery period. As a result, the auctions would be based on more accurate information about the expected demand for electricity and resources’ ability to meet that demand during the most stressed system conditions. A prompt auction would better accommodate the development timelines of diverse resources, and reduce risk of resources securing capacity supply obligations but being unable to deliver.

The “seasonal” element involves procuring capacity in a way that better addresses the distinct reliability challenges of winter and summer, as well as variations in resource performance from season to season. Winter risks are expected to increase as weather becomes more extreme and unpredictable, and as public policies guide the region toward wider adoption of weather-dependent clean energy resources and the electrification of heating and transportation.

According to ISO-NE's proposal, the reforms would take effect beginning with the 2028/2029 capacity commitment period. Absent reform, that period would be the subject of the 19th Forward Capacity Auction (FCA 19). FCA 19 was originally scheduled for 2025, but the auction timeline was extended by the Federal Energy Regulatory Commission at ISO-NE's request to allow time for a separate, lesser reform to how it accredits capacity to resources. The grid operator says it will pursue a further FERC approval to delay the auction until 2028, so it can develop rules for the prompt/seasonal market, and hold the first prompt capacity auction in early 2028.

EIA Form EIA-862 cryptocurrency mining electricity use survey

A federal agency will start requiring commercial cryptocurrency miners to report on their electricity consumption. The U.S. Energy Information Administration has obtained an emergency clearance allowing it to begin collecting data on a monthly basis from February through July 2024. EIA's new Form EIA-862, the "Cryptocurrency Mining Facilities Report", is mandatory for all commercial cryptocurrency mining facilities in the U.S. Failure to file could result in criminal and civil fines and penalties that could exceed $10,000 per violation per day.

According to EIA, electricity demand from cryptocurrency mining operations in the United States has grown rapidly in recent years. While EIA doesn't have the full data it would need to evaluate crypto's share of domestic power use, EIA's "preliminary estimates suggest that annual electricity use from cryptocurrency mining probably represents from 0.6% to 2.3% of U.S. electricity consumption." 

EIA says the growth of crypto load "has drawn the attention of policymakers and grid planners concerned about its effects on cost, reliability, and emissions." EIA continues, "As cryptocurrency mining has increased in the United States, concerns have grown about the energy-intensive nature of the business and its effects on the U.S. electric power industry. Concerns expressed to EIA include strains to the electricity grid during periods of peak demand, the potential for higher electricity prices, as well as effects on energy-related carbon dioxide (CO2) emissions." For example, several U.S. Senators and Representatives sent letters to U.S. Environmental Protection Agency Administrator Michael Regan and Secretary of Energy Jennifer Granholm in July 2022 and February 2023, asking the EPA and Energy Department to "require reporting of energy use and emissions from cryptominers."

To model crypto mining's effects on the grid, EIA performed two kinds of analysis: a "top-down approach" based on the Cambridge Bitcoin Electricity Consumption Index (CBECI), and a "bottom-up approach" based on identifying specific U.S. cryptocurrency mining operations and estimating their existing electric demands. Under the top-down approach, EIA estimates electricity usage from Bitcoin mining based in the United States to range from 25 TWh to 91 TWh, amounting to 0.6% to 2.3% of the nation's 2023 electricity demand in 2023 -- comparable to three million to six million homes, or at least as much annual electricity usage as entire states like Utah or West Virginia. 

Under the bottom-up approach, EIA tried to "identify as many U.S. cryptocurrency mining facilities as possible". EIA ultimately identified a total of 137 facilities, of which EIA has location and capacity data for 52 facilities. These sites are located in 21 states, with most in Texas, Georgia, and New York. "Of the 137 facilities identified, we have identified maximum electricity use at 101 of those facilities, which we estimate to be 10,275 MW. This amount compares with an average annual power demand of about 450,000 MW in the United States, representing a share of 2.3%."

EIA notes that its surveys of power plants have revealed that some have been used for cryptocurrency mining. Considering "a group of five small U.S. power plants in Montana, New York, and Pennsylvania where cryptocurrency mining has occurred", EIA notes that these plants' generation "rose sharply beginning in 2021 when cryptocurrency miners established operations. ...  Prior to the installation of the cryptocurrency mining equipment, output from the five plants had been much lower. The previous underutilization of these power plants has attracted cryptocurrency miners to these facilities given prospects of dedicated electricity at low rates."

Going forward, EIA "will be conducting a mandatory survey focused on systematically evaluating the electricity consumption associated with cryptocurrency mining activity, which is required to better inform planning decisions and educate the public." The survey instrument is Form EIA-862, which collects data on the energy usage, and related characteristics, of commercial cryptocurrency mining facilities in the U.S. 

Form EIA-862 asks questions about cryptocurrency validation using a proof-of-stake consensus mechanism as well as cryptocurrency mining using a proof-of-work consensus mechanism. For each reportable facility, Form EIA-862 solicits information including total electricity consumption, the percentage of electricity used for cryptocurrency mining, details on the facility's cryptocurrency mining equipment, and copies of the facility's electricity bills. EIA says it will use data gathered during the survey to inform its approach going forward.

EIA has published its forms of several letters associated with the EIA-862 survey, including a Welcome letter informing entities of the need to respond and a Reminder letter. EIA also released a form of Escalation letter, which reminds respondents that the report is mandatory under federal law, that failure to comply may result in criminal fines, civil penalties, and other sanctions, that making false, fictitious or fraudulent statements is a criminal offense, and that any failure to report "may result in a civil penalty of not more than $10,633 each day for each violation".

2022 Maine power outages quantified

Maine electricity customers experienced more frequent and longer power outages on average in 2022, compared to the national average, according to recently released federal data.

According to the U.S. Energy Information Administration, U.S. electricity consumers in 2022 experienced one or two outages, averaging about 5.5 total hours of power outage. According to EIA, major incidents like storms are most likely to cause outages with extended durations, while heavily forested states are most likely to experience a higher frequency of outages.

EIA tracks reliability and outages through two key metrics: SAIFI (which measures the frequency of service interruptions) and SAIDI (which measures duration). Some states are outliers with respect to both these metrics of electric grid reliability. The chart below, prepared by EIA, shows how various states' utilities performed in 2022 with respect to SAIDI and SAIFI. 

The average customer in Maine experienced three outages totaling over 15 hours without power in 2022. Only Alaska and Tennessee experienced more frequent outages than Maine, and only Florida and West Virginia experienced greater total durations of outages than Maine. Maine's outage duration in 2022 was roughly the same as in 2021; both were down compared to 2017, when the average Maine customer went without power for about 42 hours. According to EIA, "Power interruptions resulting from falling tree branches are common, especially because of winter ice and snowstorms that weigh down tree limbs and power lines."

Meanwhile, the District of Columbia had both the lowest frequency of service interruption and the lowest total outage duration, with an average of just 34 minutes without power in 2022. Delaware, Rhode Island, Nebraska, and Iowa also had top rankings for low outage duration.

ISO-NE 2022 generation portfolio emissions report

New England's electric power generation fleet emitting slightly less carbon dioxide in 2022 relative to 2021, according to the grid operator's 2022 ISO New England Electric Generator Air Emissions Report.

ISO New England operates the regional transmission grid and the wholesale market for electricity. In support of this role, ISO-NE tracks the portfolio of generation resources used in the region, as well as the resources' emission characteristics.

According to ISO-NE, New England generation emitted 33,382 kilotons of carbon dioxide in 2022, a decline of two-tenths of a percent relative to 2021. The grid operator reports an average 2022 emission rate of 643 pounds of CO2 per megawatt-hour of New England generation. 

Over longer time scales, air emissions from New England's power plants have decreased significantly. "From 2001 through 2022, CO2 emissions fell by 37%, NOx emissions fell by 79%, and SO2 emissions fell by 98%."

While carbon dioxide emissions decreased slightly again this year, sulfur dioxide (SO2) emissions increased to 3.38 kilotons, climbing over 60 percent relative to 2021. The grid operator attributes the sulfur emissions to increased reliance on fuel oil for electric generation:

More electricity came from oil-fired generators in 2022 than in the previous four years combined. At 1,845 GWh, production from these resources in 2022 was eight times higher than in 2021. Oil has a high sulfur content, so SO2 emissions rise when these resources produce more power.

The chart below shows the region's generation portfolio on a monthly basis for 2022; the red and black bars at the top of each month's column represent oil and coal use. The largest blue bars represent natural gas, while the largest orange bars represent nuclear power.

ISO-NE attributes increased use of oil for power generation to "record high natural gas prices associated with the Russia-Ukraine conflict, and thus an increase in regional reliance on oil versus natural gas." The grid operator also says that decreases in coal generation largely offset the increased oil use for purposes of CO2 and NOX emissions.