Energy Musings - April 10, 2025

ISO-NE is struggling to figure out how to power its grid to meet the region's future electricity demand without offshore wind. We explore the challenge it faces.

Best Laid Plans In New England Go Awry

The six states of New England, as a region, had the highest electricity price of any contiguous area of the country in January 2025. The region’s average price of $0.2500 per kilowatt-hour (kWh) was nearly 12 cents higher than the U.S. average of $0.1311/kWh. Hawaii and California had more expensive electricity than New England, at $0.3655 and $0.2561/kWh, respectively. Rhode Island had New England’s most expensive electricity, second to Hawaii, at $0.2721/kWh.

Residential electricity rates were higher across the board. Interestingly, New England’s residential electricity price was $0.0369/kWh above the region’s average price. That spread was wider than seen nationwide, which was only $0.0284/kWh higher. Because the data is for a month in the dead of winter, New England’s fuel supply issues likely explain most of the wider spread. And that is the issue the region’s electric grid operator is concerned about.

During the winter, limited natural gas supplies in the region are diverted for home heating, resulting in a reduced supply of gas available for electricity generation. Therefore, New England imports liquefied natural gas (LNG) from abroad due to the Jones Act shipping restrictions on moving domestic gas to the region. The region also often has to reactivate old coal- and oil-fired generators to meet power demand, which is both expensive and less environmentally friendly.

To overcome these traditional fuel supply patterns, New England is counting on using the immense power output of planned offshore wind farms. That potential is in question, given President Donald Trump’s opposition to offshore wind and the actions his administration has taken to pause its development. His action has disrupted the electricity grid’s planning for a future grid fuel mix powered exclusively by renewable energy, creating significant angst among grid and utility officials.

That angst was evident in the March testimony of Gordon van Welie, the president and chief executive officer of the Independent System Operator New England (ISO-NE), before the House Energy & Commerce Committee’s Subcommittee on Energy. His testimony focused on “New England’s current energy situation and the outlook for the changing resource mix, the growth of electricity demand, and the impacts for reliability and the wholesale markets.”

New England’s electricity fuel mix has changed significantly over the past 24 years. As the chart shows, natural gas has gone from a 25% share in 2000 to 51% last year. At the same time, coal and oil have almost disappeared (23% to less than 2%), while the region’s nuclear share is down by four percentage points. Renewable energy has been a beneficiary of the fuel shift, with its share increasing from 7% to 12%, primarily driven by clean energy policies of the various states.

How New England’s fuel mix has changed since 2000.

For the past few years, ISO-NE has been developing long-range plans to meet the electricity needs of its six member states. The task is challenging because the states have very aggressive plans for decarbonizing their electricity industries. Rhode Island has the most aggressive strategy, mandating that 100% of the state’s electricity demand be met by renewable energy by 2033 – eight years away. What many people do not know is that utilities can meet this requirement by purchasing Renewable Energy Certificates (RECs), which indicate that a generating plant in the region produced clean energy and earned a REC that can be sold to others. That is a way renewable energy developers can supplement their income.

In van Welie’s testimony, he described the fuel mix shift that ISO-NE has experienced since 2000. He highlighted the problem the region’s limited natural gas delivery network presents for generating electricity during winter months. This capacity problem forces the grid to rely on imported liquefied natural gas (LNG) due to restrictions under the Jones Act, which requires U.S.-flag LNG carriers to deliver domestic supplies. Since no LNG carriers are meeting Jones Act requirements, New England utilities are forced to burn much more expensive imported LNG.

He highlighted how well the region has progressed in reducing grid demand by investing in energy efficiency and behind-the-meter solar resources. He further noted that New England is fortunate that the area is not a target of technology companies wanting to build large, power-hungry data centers to exploit AI technology. According to ISO-NE, the result of these trends is that electricity demand is projected to grow at a rate of 1.7% per year, or 17% over the next decade. Over the six years from 2024 to 2030, S&P Global projects that U.S. electricity demand will increase by 25%, underscoring the significant impact of data centers and AI usage on national power demand.

As ISO-NE plans for the future of its grid and wholesale electricity market, it should consider itself fortunate that the region is unlikely to experience significant growth in data center and AI power demand. However, due to the states’ plans to electrify the region’s transportation and heating demand, ISO-NE will experience significant changes and demand increases.

In the 1990s, the region experienced a shift in its seasonal peak demand from winter to summer. The growth in air conditioning drove the change. However, with the planned increase in the region’s electric vehicle fleet and electric home heating, ISO-NE expects its winter peak to surpass the summer peak by 2040. This trend is illustrated by the organization’s forecast, which predicts that summer electricity demand will grow at a rate of 1.1% per year over the next decade, while winter demand is expected to increase at a rate of 3.1% per year.

Twice a day, winter power peak will be a problem.

The chart shows the additional challenge ISO-NE will face. Electrifying transportation and home heating will result in the winter peak exceeding the summer peak. Additionally, the winter peak occurs twice a day – when people wake up and start their day and then again when they return home for dinner, although the late afternoon peak is lower than the early morning peak.

Another chart from the ISO-NE report shows that winter electricity demand skyrockets. It approaches the summer peak by 2033. The projections are based on a normal seasonal demand. Between 2023 and 2033, the gap between the summer and winter demand shrinks from 4,336 megawatts (MW) to 779 MW. The trend lines will continue to grow because only a fraction of the transportation and heating shifts will be completed in the decade.

How ISO-NE will change.

The dilemma confronting ISO-NE officials is how best to meet the demand growth. With shorter days and more days of dismal weather during winter months, solar power plays a smaller role in meeting electricity demand. On the other hand, offshore wind tends to be stronger and more consistent during the winter, which is one reason why politicians and utility executives are counting on this resource to play a significant role in the grid of the future. January 20 and Trump’s executive order pausing offshore wind upended ISO-NE’s fuel mix planning.

The fuel mix path ISO-NE has been traveling since the 1990s has involved shutting down six of the region’s eight nuclear power plants. Over the past 12 years, two nuclear plants – Vermont Yankee and Pilgrim – were permanently shut down. That leaves only Millstone in Connecticut and Seabrook in New Hampshire in operation. The cost of maintaining Millstone became a bargaining chip for Connecticut when it declined to participate with Massachusetts and Rhode Island in purchasing the power from a proposed offshore wind farm due to the price. Selling more power to other states would ease the nuclear power plant’s subsidy burden on Connecticut ratepayers, but neither state agreed.

As part of ISO-NE’s long-term planning, it has modified its capacity market, shifting it from procuring an annual fuel supply on a three-year forward basis to buying it on a seasonal basis and closer to the timeframe when it will be needed. This allows purchases to capitalize on lower near-term prices that are usually offset by long-term purchases. The grid organization has also “initiated a resource capacity accreditation project to reflect better each resource’s contribution to system reliability during stress grid conditions.” It aims to ensure that each fuel’s operating characteristics and seasonal capabilities are accurately accounted for when planning its use.

Two charts from ISO-NE’s Economic Planning for the Clean Energy Transition (EPCET) study show the timeline for the evolution of the clean energy grid. It also highlights problems the grid will confront. These problems will lead to escalating power prices.

Opportunities and challenges of making the ISO-NE grid green.

For example, in the 2030s, the grid is expected to experience more significant demand variability, with the potential for minimum loads at certain times. During that time frame, the grid peak demand shifts from summer to winter. This variability can lead to renewable resources being built in 2035 and operating under existing power purchase agreements becoming unprofitable within five years. What renewable project developer will take such a risk? They will look to change the pricing structure and shift the risk of non-use onto ratepayers.

As the system evolves in the late 2040s, renewable energy resources may operate only 10% of the year or possibly only 1% of the time. Again, this presents a serious challenge for developers needing to generate sufficient revenue to cover the costs of their plants.

ISO-NE has already been dealing with the need for significant grid expansion due to the shift to renewable energy sources. The following chart shows the projected annual additions by specific renewable energy resources required to meet the region’s 2050 clean energy mandates. Note that more than a third of the annual growth is projected to come from offshore wind, highlighting the importance of this renewable energy resource in ISO-NE's current planning.

New England’s challenge is to transition to 100% renewable energy.

Offshore wind has become increasingly controversial. The surge in whale deaths and bureaucrat dismissal of any possible linkage to offshore wind construction have become explosive political controversies. Many people view the rush to approve and keep offshore wind farms on schedule as part of a government agenda that overlooks the costs to ratepayers. Moreover, the push has exposed the incompetence and potentially criminal behavior of a wind turbine manufacturer, the government’s waiver of standard safety and financial standards demanded of the offshore oil and gas industry, and the allowance of harassment of marine mammals.

Surveys of the public in New Jersey, where offshore wind has faced significant pushback, show a deterioration in support. In 2019, a Stockton University poll of respondents living in locales “bordering an ocean or bay” showed 77% supported offshore wind. That support cratered to only 33% favoring offshore wind in the 2023 poll. A similar survey from Monmouth University of Garden Staters showed opposition to offshore wind had increased from 15% in 2019 to 40% in 2023. Respondents indicated that they felt offshore wind contributed to the increased deaths of whales, would harm tourism in the state, and would not produce the promised job growth. We wonder what support would be today, given the wind turbine blade accident last summer off Nantucket and the discovery of a cover-up of faulty testing results. At the same time, the regulators worked around rules to keep the offshore wind construction project on schedule.

Publicly traded offshore wind developers and equipment suppliers have been forced to write off billions in shareholder value due to the altered U.S. offshore wind economic environment. Assuming the Trump administration adheres to its distaste for offshore wind projects, we question what the market outlook might be in four years. Four years is a long time for an industry that was in its infancy.

Without offshore wind, ISO-NE must find another energy source to power the future grid. Importing power from Canada is a possibility, but that option, at the moment, has been dashed by Trump’s reciprocal tariffs. Moreover, New England already has plans for more hydroelectric power from Canada. That source may be ready to supply New England, but there are questions about how long it can be counted upon. That is because the power is to come from Newfoundland’s hydropower resources, but there is no long-term agreement with Ontario. Therefore, when the initial years of the ISO-NE contract pass, there is no assurance that Ontario will have the necessary power supply, as Newfoundland has indicated it will require that power for its own needs.

Given the prospect of no additional offshore wind resources beyond those under construction for the next four years, ISO-NE needs more fuel. Coal and oil are only winter stopgap sources. That means the region will need more natural gas, but how will it be delivered? Increasing the amount of imported LNG is not realistic due to the physical limitations of gas-receiving terminals in the area. Building additional import capacity will take years, and the volumes will be small. Additionally, imported LNG is much more expensive than domestic natural gas, which will raise ratepayer bills.

Expanding existing natural gas pipelines or building new ones are better options, although such projects would also take time. Last month, President Trump discussed with New York Governor Kathy Hochul the possibility of resurrecting the long-discussed Constitution Pipeline, which would deliver up to 650 million cubic feet of gas per day (MMcf/d). The gas would come from the Marcellus formation in Northeast Pennsylvania. The gas would be delivered to upstate New York. Energy Secretary Chris Wright has said the permitting process for the 124-mile pipeline should be expedited. Hochul’s predecessor blocked all new pipelines and expansion projects for existing gas pipelines, which has strangled New England.

Another option is to revive the three billion cubic feet per day (Bcf/d) expansion of the Algonquin Gas Transmission (AGT) pipeline system owned by Canadian-based Enbridge, which was proposed in September 2023. The project would expand the pipeline systems by replacing existing smaller-diameter pipe with larger-diameter pipe, extending pipeline loops in parallel to existing pipeline facilities, and adding compression at existing compressor stations. Importantly, Enbridge stated that the proposed expansion was “scalable,” and its final scope depended on the level of market support. As initially proposed, the expansion could deliver 500 MMcf/d to AGT’s Ramapo receipt point in New Jersey. It could result in up to 250 MMcf/d of additional capacity at the company’s Salem receipt point near Boston.

During the recent winter months of January and February, natural gas consumption in New England totaled approximately 4 Bcf/d. Home heating demand accounted for roughly 2.5 Bcf/d of the total. The potential for an additional 250 MMcf/d of supply to Boston would represent an extra 17% of the existing gas supply for generating electricity.

ISO-NE’s problem in securing this additional gas supply is that less than 10% of gas generators needed in the region to support the grid’s peak demand are under firm-service contracts. The vast majority of gas generators operate under interruptible service agreements. This is how the region can meet winter home heating needs by stopping the flow of gas to generators that produce electricity.

Until New England regulators alter this market dynamic, it isn't easy to see how Enbridge would proceed with the AGT expansion. During Enbridge’s recent investor day presentation, CEO Greg Ebel said that Project Maple is “a once-burnt, twice-shy kind of thing.” He reminded the audience that Enbridge had previously absorbed project development costs when New England pipeline projects stalled. “I’m willing to share risk. I’m not willing to take on all the risks.”

A potential supply of additional natural gas for New England.

If ISO-NE officials are seeking an easy answer to their grid fuel future, there is none. The rush to decarbonize New England's state economies had set grid planners on a course that was tenuous to begin with and is now in danger of collapsing. A major tenant of the future grid rested on offshore wind, a power source whose economics have been destroyed by the return to a typical interest rate environment. Higher rates have forced developers to reduce their financial leverage just as project costs have increased. Developers need substantially higher prices for their power and greater government subsidies to support their projects. Neither solution is popular with the public.

For the immediate future, grid officials will be forced to “muddle through” by continuing their current approach to meeting the grid’s fuel needs, which includes imported LNG, coal, and oil. The officials must begin developing a grid-fueling strategy that does not rely on offshore wind. They must also recognize that it will be impossible to offer ratepayers relief from escalating power bills in the near term. Therefore, it is time for utility executives, grid officials, and regulators to begin a massive educational program – Electricity 101. An educated public should decide what it is willing to pay for its electricity, considering three key qualities: clean, affordable, and reliable. When the public chooses the appropriate weight it wishes to assign to those qualities, it will be forced to accept the price outcome of that decision. Thus, there should be less resistance to electricity rate increases. An educated public means grid officials would have an easier time planning the future with them on board.