WATERFORD – The future of energy — and energy costs — in New England hinge on the continued operation of Millstone Nuclear Power Station if Connecticut remains committed to the administration’s goal of a carbon-free electrical grid by 2040.
But keeping Millstone running may require difficult choices in just a few years, as lawmakers and energy officials across look to ensure one of New England’s two remaining power plants stays open – debating options including carbon taxes, cost-sharing and a new energy market specific to funding renewable projects.
In a region heavily reliant on natural gas, the 2-gigawatt nuclear plant produces about 15 percent of the electricity in New England and is crucial to the region’s supply of reliable energy.
And as a recent report compiled by the Department of Energy and Environmental Protection makes clear, nuclear power is crucial to meeting what state officials describe as a carbon-free electrical grid by 2040 – the alternatives would cost billions more without Millstone according to the report.
But the future of Millstone isn’t guaranteed.
Millstone’s owner Dominion Energy likely would have shuttered the plant in 2019 if Connecticut hadn’t stepped in and agreed to buy half the station’s output at a favorable rate until 2029 – and the company warns that it will close the plant if Connecticut or the region as a whole fails to fund the plant after 2029.
In contrast to the general consensus among lawmakers and state energy officials regarding the importance of the continued operation of Millstone for the region, the state’s actual role in keeping the plant open has been the subject of intense debate since Dominion first threatened to close the plant in 2016.
A number of state lawmakers have questioned why the burden of supporting a power plant so crucial to the entire New England region should fall entirely on Connecticut. But without a mechanism for the regional grid operator ISO New England to fund the plant regionally, Connecticut officials say they have no choice but to shoulder the burden of keeping Millstone open.
That disconnect has been a key point of contention for Connecticut DEEP Director Katie Dykes and the administration of Gov. Ned Lamont as they have pushed for changes at the ISO.
Whether ongoing discussions result in a regional solution to funding Millstone could determine whether the plant stays open beyond 2029 — and Dominion officials warn that they’ll need to have a viable plan in hand for keeping the plant open by 2025.
The high price of the alternative
According to the recent report, if Millstone had closed in 2019, replacing that electricity would have cost Connecticut electric customers an additional $1.8 billion. And carbon emissions across New England would have increased by 25 percent as the nuclear plant’s production is replaced mainly by gas-fired plants, said Dykes.
“At a time when most states in New England have decarbonization goals that we need to move rapidly forward on, [allowing Millstone to close] would have been digging a huge hole in terms of carbon emissions.”
Keeping Millstone running avoids the need to use more natural-gas plants, which makes it crucial to a state with ambitious goals for carbon-free electricity. According to modeling in DEEP’s Integrated Resource Plan, if Millstone closes in 2029, building out enough renewable energy to offset the loss of the plant’s 2 gigawatts of zero-carbon baseload would cost Connecticut electric customers $5 billion by 2040 than if Millstone continues to run.
The closure would mean that Connecticut would need to procure 8.5 gigawatts of zero-carbon electricity by 2040 to meet the administration’s carbon goals – even more if home heating and vehicle electrification pick up pace. The state will need to procure 4.8 gigawatts of zero-carbon energy if Millstone remains open.
And securing that offsetting power might be more challenging than the model suggests, given that it assumes much of the new power would come from a proposed transmission line that would import hydroelectric power from Quebec. That project might not be built at all. It has met fierce opposition in Maine, where voters in November rejected the $1 billion plan to import 1.2 gigawatts of hydro-power through Maine’s northern forests and into New England.
“It’s hard to build anything in New England, even clean energy infrastructure like the [connection to Quebec], so you cannot overstate the importance of an existing clean energy resource,” Weezie Nuara, Dominion’s New England policy director, said. “We have always said it’s going to take each and every carbon-free megawatt hour from new and existing resources to meet the state’s decarbonization goals.”
State Sen. Paul Formica, R-East Lyme, told CT Examiner that he wasn’t sure whether a zero-carbon grid is achievable by 2040, and urged a steady and moderate approach to procuring electricity to avoid unaffordable spikes in the already high cost of electricity in Connecticut. Millstone, Formica said, is crucial to that transition.
“Without Millstone, there’s a very bleak energy picture,” warned Formica, whose district includes Waterford and the Millstone plant. “I know we want to get [away from oil and natural gas] eventually, but there’s not an adequate substitution for that in renewable energy.”
The fact that Millstone is already built is a major part of its appeal, according to State Sen. Norm Needleman, D-Essex, one of the co-chairs of the legislature’s Energy and Technology Committee.
The biggest expense in nuclear energy is building the plant, so once it’s built the electricity it produces is relatively cheap, Needleman said. That’s especially true now as the global spike in the price of natural gas has caused prices on New England’s energy market to rise above the $49.99 per megawatt-hour in Millstone’s contract.
Spot market prices in New England averaged $55.93 in October – more than double the price from October 2020.
Needleman said he doesn’t expect that Connecticut will always be on the plus side with the Millstone contract, but the deal to keep the plan open is one of the cheaper contracts in Connecticut for zero-carbon energy.
Guaranteeing a return on investment
In 2021, nuclear plants generating a combined 5.1 GW of capacity will be taken offline.
That’s the most nuclear capacity ever taken offline in a single year, according to the U.S. Energy Information Administration, and it’s a situation the EIA projects will continue as long as gas prices remain low.
Running a 40-year-old nuclear plant is expensive, Nuara explained to CT Examiner, and involves long-term planning to ensure equipment is maintained and replaced to keep the plant running safely. When natural gas prices aren’t unusually high, it’s difficult for nuclear energy to compete with cheap gas-fired electricity in an open market.
“It’s a capital-intensive resource,” Nuara said. “It’s not a resource that sits idly for most of the year and then is fired up on the coldest winter day or hottest summer day. It is running every single day and requires extensive investments to make sure it can continue operating reliably.”
For the most part, Connecticut’s contract with Dominion is expected to subsidize Millstone with a price higher than the wholesale price of electricity in gas-heavy New England. It’s clear now amid unusually high natural gas prices that isn’t always the case, and Dominion says it isn’t the main benefit of the contract.
Since 2018, Dominion has invested about $450 million in capital projects for the two Millstone reactors – most significantly spending $109 million to replace the original generator in Unit 3, which was built in 1986.
The company also spent tens of millions of dollars on safety measures, including $31 million to replace a radiation monitor in unit 3, $18 million to upgrade the reactor protection system in unit 2, and $40 million for systems to detect issues in the electrical connections between the reactors and the electric grid.
“That kind of investment wouldn’t be made unless you had some certainty that you were going to see some return on that investment,” Dominion spokesman Ken Holt said. “Knowing what we’re going to get for approximately half of Millstone’s output gives us that stability, that means of planning so that we can make the plant more efficient and safer to operate as well.”
Without some certainty in how much revenue the plant would bring in, those investments aren’t possible, Holt said. And without those investments, keeping the plant open wouldn’t have been possible.
Those financial constraints will still exist in 2030, said Holt, especially as Dominion decides whether it should apply for extensions to the permits for unit 2, set to expire in 2035, and unit 3, which expires in 2045. Keeping the plants open for another 20 years beyond their current permits – or another 40 if a proposal to allow 100-year permits for nuclear plants is approved by federal regulators – will come with more major capital expenses, and even applying for the extension is costly, he said.
Dominion’s other nuclear plants in Virginia and South Carolina operate in regulated markets, so they simply apply to the utility regulator – the states’ equivalent of PURA in Connecticut – to have any capital expenses approved as “prudent cost.”
In New England’s deregulated market, Millstone operates as a merchant plant, meaning it has to sell its power on the market, and lacks a built-in mechanism to ensure that Dominion will earn an adequate return on any investments it makes in the plants, Holt explained. A power purchase agreement like the one the company currently has with Connecticut, or another regional funding mechanism, would provide that assurance, he said.
“We’re making these investments at risk,” Holt said. “Knowing that we have something like a contract gives us that assurance that the money is there that can support that kind of licensing effort.”
What are the options?
Leaders of the legislature’s Energy & Technology Committee agree on the importance of keeping Millstone operating – but not on how much of that burden should fall on Connecticut.
“There has to be a regional solution,” said Rep. David Arconti, D-Danbury, co-chair of the Energy and Technology Committee, who opposed the contract with Dominion in 2017. “Millstone provides benefits to the whole region, and Connecticut has some of the highest electric rates in the country to begin with. I don’t see how our ratepayers can afford to continue a Connecticut-only PPA.”
The Millstone contract has emerged as a significant point of contention between Lamont’s administration and ISO-New England. Dykes has consistently criticized ISO as an obstacle to the states’ clean energy goals, forcing the state to pay for reliability in the form of natural gas plants, without accounting for renewable energy sources states under contract in arrangements similar to Millstone.
A coalition of five New England states, including Connecticut, is evaluating what changes can be made to the regional markets to make them better fit the states’ energy goals, and the Millstone contract, Dykes said, is one of the major reasons she and Lamont have been calling for change.
“[ISO-New England] had nothing to offer to try to prevent the retirement [of Millstone], even though they were the ones saying the loudest that the grid couldn’t operate without it,” Dykes said. “That’s why we’ve been prioritizing calls to reform the ISO market, to ensure that resources like Millstone can be paid for in the market and continue to operate.”
ISO has hired a consulting firm to evaluate possible opportunities to fund Millstone regionally. That report is expected in early 2022, but two options have been raised already.
The first option is a carbon tax, forcing power plants to pay for the carbon they emit by burning fossil fuels. Dykes said there have been discussions about a carbon tax set at a “relatively modest” level that could generate revenue for the ISO to ensure that the region’s baseload nuclear reactors – Millstone and the Seabrook Power Station in New Hampshire.
Dykes said the ISO has “latched on” to the idea of a carbon tax as a silver bullet that would help the states reach their decarbonization goals. But Dykes said that for a carbon tax to be effective in both retaining existing resources and supporting new ones like offshore wind and solar, the price would have to be set very high – which could cause a sharp increase in electric rates for customers.
Another idea being considered is a regional forward clean energy market, which would be similar to the forward capacity market that ISO currently uses to fund projects three years in advance to make sure there is enough electricity to supply the grid.
While the capacity market has been criticized by renewable energy proponents for putting renewable projects at a disadvantage, a forward clean energy market – a concept Arconti said would be a good road to go down – would ensure renewable projects are funded by the regional market.
But the desire to shift the cost of Millstone to the rest of New England isn’t universal.
While both Arconti and Needleman said they want to see a regional solution to funding Millstone, Formica said he’s confident the power purchase agreement will prove itself to be the right choice.
“The movement to regionalize Millstone to absorb some of, according to DEEP, the costs to the ratepayers – I’m wondering if we’re measuring that absorption of cost with the absorption of [credit for zero-carbon energy] which would get spread around the region,” Formica said.