The Shifting Floor Energy, decisions, and the forty years ahead

From January 23 through February 10, 2026, New England experienced a prolonged outbreak of Arctic air. ISO New England reported that regional temperatures averaged about 15 degrees Fahrenheit during the period — approximately 11 degrees below normal. Electricity consumption during the cold spell totaled roughly 7,669 gigawatt-hours. Winter demand peaked on January 25 at 20,182 megawatts, slightly above the grid operator's pre-winter forecast for normal conditions.^[1]

The system remained reliable, but doing so required extraordinary use of stored fuel. ISO New England reported that power plants burned approximately 139 million gallons of oil during the full winter, including about 111 million gallons during the nineteen-day cold period. Snow cover also reduced the performance of behind-the-meter solar installations during the event.^[1]

On January 25, at ISO New England's request, the U.S. Department of Energy issued an emergency order under Section 202(c) of the Federal Power Act. The order allowed specified generating resources to operate as needed notwithstanding certain permit or emissions limits. DOE extended the order on January 30, and it remained effective through February 14. Fifty-seven resources representing approximately 11,215 megawatts of winter capacity received specified-resource treatment; twenty-six later reported exceeding a limit identified in the order.^[1][2]

The financial number associated with the winter also requires precision. ISO New England reported more than $6 billion in energy-market value over the entire December-through-February winter: approximately $1.8 billion in December, $2.7 billion in January, and $1.5 billion in February. That was not the cost of the nineteen-day cold spell alone, and market value is not the same thing as generator profit. It is a measure of transactions in the regional wholesale energy market.^[1]

The record supports two conclusions. First, the regional system performed its essential job: customers were served through a difficult period. Second, that performance depended heavily on oil, natural gas, fuel logistics, and temporary regulatory flexibility. Calling the winter either an uncomplicated success or a narrowly avoided collapse would overstate the evidence. It was a demanding real-world test of the system New England has today.

Connecticut released a new Zero Carbon Request for Proposals on January 30, 2026. The solicitation sought bids from existing or new nuclear generation, hydropower, solar, onshore wind, related transmission, and certain storage resources. Most bids were due March 17. Connecticut designed the procurement to allow participation by other New England states, and state law requires at least two other states to share the costs of any new Connecticut procurement of existing nuclear generation.^[3]

The current Millstone and Seabrook contracts expire in 2029. In announcing the new solicitation, the Department of Energy and Environmental Protection said those contracts had saved Connecticut ratepayers an estimated $153 million as of 2025 through the resale of energy and environmental attributes into the market. DEEP also said that the risk of existing nuclear plants retiring had receded as wholesale market conditions improved. The new procurement is therefore best understood as a competitive search for affordability, reliability, and price stability — not as proof that Millstone has announced an imminent closure.^[3]

Proposals submitted to a competitive procurement may contain confidential commercial information. Until DEEP publishes selections or releasable bid documents, the price, volume, duration, and conditions of individual proposals should not be treated as settled public facts. The decision process will involve DEEP review and, for any resulting utility contract, review by the Public Utilities Regulatory Authority.

Millstone remains central to Connecticut's electricity system and to southeastern Connecticut's economy. Its two operating units provide carbon-free, around-the-clock generation and connect to transmission infrastructure built for a major power station. Those characteristics make the Waterford site relevant to any discussion of the state's existing nuclear fleet. They do not, by themselves, determine the terms of a future contract or establish that a new reactor will be built there.

Federal law ended the Residential Clean Energy Credit under Section 25D for expenditures made after December 31, 2025. For an eligible homeowner-owned system completed in time, the credit had generally equaled 30 percent of qualified expenditures. For later residential expenditures, that homeowner credit is no longer available.^[7]

The change does not create a single "typical Connecticut loss." The former credit's dollar value depended on the project's qualified cost and the taxpayer's circumstances. A $30,000 eligible project, for example, could have generated a credit of up to $9,000, but that example should not be presented as the universal Connecticut installation.

Third-party-owned systems require different language. A homeowner who signs a lease or power-purchase agreement does not personally claim the business investment credit under Section 48E. The third-party owner may be eligible, depending on the facility and compliance with federal requirements. For affected wind and solar facilities, July 4, 2026 is generally a beginning-of-construction deadline associated with continued eligibility; other requirements, including placed-in-service rules, also apply. It is not simply a last day for a homeowner to sign a lease.^[8]

State-level programs remain important. Connecticut's Residential Renewable Energy Solutions program compensates participating residential systems under long-term tariff structures. The Energy Storage Solutions program provides incentives for qualifying batteries and grid-support performance. State tax provisions and financing through Connecticut Green Bank programs may also affect project economics. Homeowners should evaluate the complete contract, including ownership, escalation clauses, maintenance obligations, production assumptions, roof condition, and the treatment of renewable-energy attributes — not only the advertised monthly payment.

On May 6, the General Assembly passed House Bill 5340. As of this edition's May 14 reporting cutoff, the bill awaited final gubernatorial action. Its provisions addressed successor programs and additional policy and consumer-protection questions for solar and distributed energy; it did not recreate the former 30-percent federal homeowner credit.^[9]

The federal change makes many new residential projects less attractive than they would have been with a 30-percent homeowner credit. How much Connecticut's installation market contracts cannot yet be stated as an observed 2026 fact. It will depend on system prices, financing costs, state programs, utility rates, customer preferences, and the availability of third-party ownership.

Revolution Wind is a 704-megawatt offshore-wind project located approximately fifteen nautical miles southeast of Point Judith. Connecticut contracted for 304 megawatts of its output and Rhode Island for 400. The project is designed around sixty-five turbines.^[11]

On August 22, 2025, the Bureau of Ocean Energy Management issued a stop-work order when the project was approximately 80 percent complete. Revolution Wind challenged the order, and on September 22 the U.S. District Court for the District of Columbia granted preliminary relief allowing construction to resume. A preliminary injunction preserves the parties' positions while litigation continues; it is not a final judgment on every disputed question.^[12]

On December 22, 2025, the Department of the Interior paused construction on five offshore-wind projects then under development or construction: Revolution Wind, Vineyard Wind 1, Sunrise Wind, Empire Wind 1, and Coastal Virginia Offshore Wind. Revolution Wind again sought judicial relief. On January 12, 2026, the district court granted another preliminary injunction, and construction continued.^[13]

Revolution Wind delivered electricity to the New England grid for the first time on March 13. First power is a commissioning milestone, not the same as full commercial operation. As of the reporting cutoff, construction and commissioning work remained underway.^[14]

After courts allowed the five paused projects to proceed, the federal government began reaching agreements under which companies relinquished undeveloped offshore-wind leases. TotalEnergies announced on March 23 that it would relinquish two leases in exchange for approximately $928 million in reimbursement and make an equivalent investment in U.S. gas and power projects. On April 27, the Interior Department announced agreements involving Bluepoint Wind and Golden State Wind totaling another $885 million.^[16][17]

Together, those announced reimbursements were approximately $1.8 billion as of May 14. They concerned undeveloped leases, not the cancellation of Revolution Wind. The broader federal pause on new offshore-wind leasing and permitting nevertheless makes the post-construction pipeline substantially less certain. In March, the Clean Energy States Alliance described the national project pipeline as having "virtually disappear[ed]" during the preceding year.^[18]

New London's State Pier has supported the regional offshore-wind supply chain, including work associated with South Fork Wind and Revolution Wind, with Sunrise Wind also part of the planned project sequence. The facility's future workload will depend on completion schedules, remaining approved projects, litigation, procurement decisions, and federal policy. That uncertainty is real; declaring the entire industry either secure or finished would go beyond the record.

Natural gas produced approximately 55 percent of the electricity generated within New England in 2025. Nearly half of the region's generating capacity — about 14,000 megawatts in 2026 — uses natural gas as its primary fuel. More than 7,000 megawatts of mostly coal, oil, and nuclear generation has retired since 2013 or announced plans to retire in the coming years.^[19]

The regional constraint is not simply a shortage of gas-fired power plants. It is the interaction between the electric system and the natural-gas delivery system. During cold weather, pipeline capacity is heavily committed to local gas utilities serving residential, commercial, and industrial heating customers. Many electric generators rely on interruptible gas arrangements and must obtain fuel that remains available after firm obligations are served.

Liquefied natural gas delivered by ship can supplement pipeline supply, and dual-fuel generators may switch from gas to stored oil. Both were important during the 2026 cold period. ISO New England reported 45.6 billion cubic feet of natural gas consumed by power plants during the winter and record oil use, including the 111 million gallons burned during the nineteen-day cold spell.^[1]

Behind-the-meter solar reduces the amount of electricity that must be supplied by the bulk system during daylight hours. Its winter contribution is limited by shorter days, snow, clouds, and the timing of evening demand. Batteries can shift electricity across hours, but their contribution depends on charge level and duration. Offshore wind tends to have stronger seasonal production in winter, although individual hours remain weather-dependent. Nuclear plants provide large quantities of energy from fuel stored on site.

The practical lesson is not that one resource can replace every other resource. It is that New England's reliability depends on the performance of a portfolio — and on the physical fuel, transmission, storage, and operating arrangements behind that portfolio.

In January 2026, the U.S. Energy Information Administration projected that national electricity use would rise for four consecutive years for the first time since 2007, producing the strongest four-year growth period since 2000. EIA identified large computing centers as the principal driver of the acceleration.^[20]

The International Energy Agency projects that U.S. data-center electricity consumption will increase by approximately 240 terawatt-hours between 2024 and 2030 — an increase of about 130 percent. That is more than a doubling, not merely a 30-percent rise. The forecast is not a guarantee, and the geographic distribution of the load remains uncertain.^[21]

Virginia demonstrates both the scale and the importance of definitions. Dominion Energy reported a contracted data-center pipeline of nearly 51 gigawatts as of March 2026, an increase of approximately 2.5 gigawatts from the end of 2025. That figure includes projects at different stages of development and should not be confused with 51 gigawatts of data centers already operating. Virginia's existing data-center load is much smaller, although it remains the country's largest concentration.^[22]

Dominion advises that data centers expecting less than 50 megawatts may sometimes connect through existing distribution infrastructure, while projects above 50 megawatts will probably require transmission extensions and a new substation. Actual requirements depend on the site and the customer's requested service.^[23]

The policy question remains broader than either bill. Large loads can require generation, substations, transmission, distribution upgrades, water, land, and long lead times. Municipal land-use decisions and state utility regulation therefore intersect, but they are not interchangeable. Before Connecticut attracts development at Virginia's scale, policymakers will need to decide how project-specific infrastructure costs, long-term commitments, reliability risks, tax benefits, and community effects are allocated.

Military action involving the United States, Israel, and Iran began on February 28, 2026. A ceasefire took effect on April 8, although President Trump described it on May 11 as being on "life support." As of May 12, the Energy Information Administration expected the Strait of Hormuz to remain effectively closed through late May, with traffic gradually resuming afterward.^[26][27]

The volume figure also needs a definition. Total petroleum liquids moving through the strait averaged approximately 20 million barrels per day in 2024. Narrower measures limited to crude oil and condensate produce smaller figures. A publication should state which measure it is using rather than present a single number without a category.^[28]

The disruption reduced Middle Eastern production and shipping, raised global oil prices, and affected liquefied-natural-gas markets. By late April, the United States had released 17.5 million barrels from the Strategic Petroleum Reserve. EIA also reported that U.S. LNG export capacity increased by about 0.9 billion cubic feet per day in April, though that capacity increase should not be attributed solely to the conflict.^[27][29]

For New England, the connection is economic rather than geographic. The region's wholesale electricity prices are strongly influenced by the cost and availability of natural gas and oil. International disruptions can therefore affect a Connecticut electricity bill without any direct interruption at a Connecticut power plant.

Commissioner Katie Dykes connected the harsh winter and the Iran conflict to the value of a diverse supply portfolio in a March written release:

Southeastern Connecticut's submarine industrial base is part of the nation's broader defense posture, but assigning a specific deterrent effect in the Hormuz conflict to submarines built or based here would require evidence not available in the public record. The region's naval importance and the region's electricity costs are both real; they should not be joined by an unsupported causal claim.

The energy decisions facing southeastern Connecticut are consequential, but they are not exclusively local — or exclusively federal.

The Nuclear Regulatory Commission licenses commercial reactors. Federal agencies control offshore-energy leasing and permitting. ISO New England operates the regional bulk power system and wholesale markets. Connecticut determines state procurement policy, utility regulation, consumer programs, and many cost-allocation rules. Municipalities make land-use decisions and, under Public Act 25-173, may choose whether to pursue eligibility for advanced-nuclear site-readiness assistance.

Millstone's existing contracts expire in 2029, and Connecticut's 2026 procurement will help determine whether a new agreement provides sufficient value to ratepayers and participating states. Revolution Wind is moving from construction and commissioning toward full commercial operation, while the pipeline of later offshore projects faces serious federal uncertainty. Residential solar continues under a changed federal tax environment. Natural gas remains the principal source of New England generation and the fuel most exposed to winter delivery constraints. Data centers could add substantial new demand, but forecasts do not establish that the load will locate in Connecticut.

The lower Thames region enters this discussion with significant assets: an operating nuclear station in Waterford, the Naval Submarine Base, Electric Boat and its regional supply chain, maritime and logistics capacity in New London, and a workforce experienced in demanding technical and industrial work. Those strengths create opportunities. They do not eliminate the need for transparent costs, credible schedules, community consent, federal licensing, environmental review, and protection of residential ratepayers.

The Thames Club has always included members drawn from communities that shaped New London's civic and maritime life. The Club does not need to produce a single institutional position on nuclear power, wind, solar, gas, or data centers. It can do something more consistent with its history: provide a room in which claims are tested, uncertainties are acknowledged, and disagreement begins from an accurate record.

The grid is changing in front of us. The first responsibility is to describe that change truthfully.