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."