The price that electric consumers in Maine and New England pay to make sure there’s enough power to meet future demand will more than double next June and more than triple in June 2018, before easing in 2019.
For a typical Central Maine Power home customer who uses 550 kilowatt-hours a month and has a bill of roughly $70, paying for adequate capacity adds roughly $4 to their current bill. That will rise to $10 or so in June 2017, and $14 in June 2018. It will fall back to roughly $10 a month in June 2019.
The increases are welcomed by power plant owners. They’ve seen income fall in an era when the wholesale price of natural gas, which is used to generate half of New England’s electricity, is at a 13-year low. The price hike could come as a shock to utility customers, who may wonder why their bills are suddenly rising next summer.
The changes are tied to developments in what energy planners call the forward capacity market, which functions like an insurance policy for the electric grid’s reliability.
Before New England’s electric industry was restructured in the late 1990s, utilities directly charged customers for the cost of new power plants. But with private developers responsible for power these days, a special market has been put in place that creates a financial incentive to build the next generation of resources.
Each year, New England power plant owners bid into an auction meant to assure that there’s enough generating capacity on the hottest and coldest days. The bidders compete with each other to satisfy a set capacity requirement three years out.
Prices fall during each auction round, as generators who are unwilling to provide power at that new price drop out. Winners who “clear” the auction once the capacity requirement is met are obliged to provide power when called on by ISO-New England, the independent agency that operates the electric grid and conducts the auction.
The cost of this forward capacity will total $3 billion in 2017-2018, and $4 billion in 2018-2019, according to ISO-New England. Payments then will fall to $3 billion in 2019-2020.
GENERATORS IN FLUX
The spike in forward capacity payments reflects the fact that several older coal and oil plants, as well as two nuclear plants, have shut down or are going off line. Taken together, 4,200 megawatts of capacity have announced plans to retire in recent years. That’s more than 10 percent of the region’s total output.
This trend erased what used to be a surplus of generating capacity in New England. It made ISO-New England worry about having enough resources to assure reliable power if a big generator, for instance, had problems and suddenly shut down.
The pending imbalance between supply and demand allowed owners to bid much higher prices at the auction that was conducted in 2014, for capacity needed in 2017-18. A similar thing happened in 2015, for power needed in 2018-2019.
Experts who follow energy markets took note of these high prices. But they didn’t register with the general public, according to Don Sipe, a lawyer who represents big power users in Maine at the Industrial Energy Consumer Group.
“I call it a capacity time bomb,” Sipe said. “We knew these prices were going up significantly, but they hadn’t been put in rates, because it was three years out. That’s a long news cycle. So three years later, that headline is relevant.”
Dan Dolan, president of the New England Power Generators Association, said the prices are linked to the higher costs of building new power plants, some of which can burn both natural gas and oil. That dual-fuel flexibility is important, because limited room in the region’s gas pipelines on the coldest winter days can make gas expensive or unavailable at some power plants.
“We now have to bring on new supply,” he said. “Once that happens, prices will drop and stabilize.”
Elevated prices, Dolan added, also are a reaction to a new rule at ISO-New England. The rule penalizes generators that clear the annual auction, but fail to perform as promised. The new penalties could add up to millions of dollars, so generators have embedded the cost of that risk in their bid prices, he said.
Capacity payments are made solely for promising to provide a certain amount of power when it’s needed by ISO New England. On top of capacity payments, plants are paid for any power they do generate.
But because wholesale energy prices are very low now, capacity payments have become essential to keeping existing plants running, according to John Flumerfelt, a spokesman for Calpine Corp.
Calpine’s gas-fired power plant in Westbrook is among Maine’s largest, rated at 550 megawatts and able to serve roughly 500,000 homes. But with low gas prices, the 15-year-old plant relies on capacity payments to cover its fixed costs, Flumerfelt said.
“We have to have capacity payments or we wouldn’t survive, no less attract more investment,” he said.
Figures obtained by the Portland Press Herald show that Calpine’s Westbrook plant is receiving roughly $17 million a year in capacity payments. They will rise to $44 million in June of 2017 and $60 million in 2018 before falling back to $44 million in 2019.
Other Maine generators also are benefiting from high capacity payments.
The largest unit at Wyman Station in Yarmouth, operated by NextEra Energy Resources, is rated at 620 megawatts. Wyman is an old plant fired by oil and it rarely runs. But it has become an essential back-up generator for ISO-New England on cold winter days. Wyman offered 508 megawatts at auction, and is being paid $16.7 million this year. That payment will rise to nearly $43 million in 2017, and peak at $58 million in 2018, figures show.
Rumford Power offered 244 megawatts at auction. Owned by Emera Corp., the gas-fired power plant will see payments go from $8 million today to a high of $28 million in 2018.
COSTS ASSOCIATED WITH CHANGE
Clean energy also is benefiting from the spike in capacity payments.
The Kibby Wind Power project in western Maine, owned by TransCanada Corp., offered between 12 and 14 megawatts. Payments will go from $672,000 to $1.6 million.
Payments for two dozen hydro dams owned by Brookfield Renewable Partners will increase from roughly $15 million to $49 million during the period.
The most recent capacity auction was held lastin February, and it marked a turning point.
The clearing price for 2019-2020 was 25 percent lower than the previous year. More capacity was bid than was needed. The accepted bids included three, large gas-and-oil plants in southern New England that will have a total capacity of 1,302 megawatts. Clean energy had a strong showing, with 135 megawatts of wind and 65 megawatts of solar power clearing the auction.
Another highlight was that 2,746 megawatts of “demand-side” resources – businesses that have agreed to curtail their energy consumption if requested – will be in place and available when energy demand peaks.
Dolan, who represents power plant owners, said the outcome shows that competition is working in New England’s energy market, as the region’s fleet makes a transition to natural gas, renewables and efficiency.
“That’s the way the auction is supposed to work,” he said.
Tim Schneider, Maine’s Public Advocate, said that consumers need to recognize that the entire country is making a transition from one fleet of power generators to another, and there’s a cost associated with that. He noted that nuclear power plants that can’t compete with natural gas are closing, and that capacity payments are keeping some of the remaining ones profitable.
For example: New Hampshire’s Seabrook nuclear plant, which is rated at 1,244 megawatts and can serve more than 1 million homes, will see capacity payments soar from $41 million today to $142 million in 2018.
Schneider urged policymakers to gain a better understanding of the capacity market, because it has become a key factor in driving Maine’s above-average electric rates.
Increasing efficiency, shifting demand to off-peak hours, incorporating battery storage and taking advantage of solar power are all ways that New England can reduce the need for new capacity, Schneider said.
“It can save consumers millions,” he said.