Region’s electricity market in trouble

GORDON VAN WELIE is sitting in a conference room in Holyoke. Behind him is a bank of windows that look down on a control room with a massive screen showing the second-by-second status of New England’s power grid. On this day in November, everything is running smoothly, with the supply of electricity easily keeping pace with demand. The operators in the control room, sitting or standing in front of their work stations, seem relaxed as they casually chat with one another.

Up in the conference room, the mood is different. Van Welie, talking with the clipped, precise accent one would expect from someone with an electrical engineering degree and an MBA from the University of Witwatersrand in Johannesburg, is saying the wholesale market for electricity in New England is going through its most challenging time since he took over as CEO of the region’s power grid operator 17 years ago.

Most New Englanders have never heard of the 57-year-old van Welie. Few ever think about the wholesale electricity market, if they even know it exists. But the market that has kept the lights on in New England for the last 20 years is going through a very tough stretch. Some say it may not survive, as states, led by Massachusetts, are pursuing long-term renewable energy contracts outside the market and a money-losing, gas-fired power plant in Everett is in line for a temporary ratepayer bailout that could cost hundreds of millions of dollars.

The stakes are high, as geeky policymakers debate whether a competitive market is the best way to produce power in New England or whether we should return to a system that fell out of favor 20 years ago – letting state regulators decide which power plants should get built and at what cost. For electricity ratepayers, the choice is between a system that puts all the financial risk on power generators or one that shifts some of the risk on to them.

Dan Dolan, the president of the New England Power Generators Association, says the wholesale electricity market is facing an existential crisis, failing to meet the needs of the six New England states and the region’s electricity generators, whom he represents. “The direction we’re moving in with out-of-market contracts for renewable energy and special contracts for reliability is putting the risk right back on ratepayers. On the 20^th anniversary of electricity deregulation, we’re going right back to it,” he says, of the circling back toward a regulated market.

Abigail Krich, the president of a Cambridge energy consulting firm called Boreas Renewables, says the existing wholesale electricity market is failing to deliver the renewable energy projects the region needs to meet its greenhouse gas emissions goals. She said the region can either do a radical redesign of the wholesale market to remove its bias in favor of fossil fuels or go back to regulating electricity production in the region again.

“There’s been resistance to going back to regulation, but there’s been a lot of discussion about whether the market can survive in the future,” she says.

Van Welie strongly believes that competition best serves electricity ratepayers in the long run. He and his team are working on a number of big and small tweaks and fixes to make the existing market work, but he admits big changes could be coming as states negotiate more and more out-of-market contracts for renewable energy under what industry players call cost-of-service contracts.

“There are really only two paths open,” says van Welie. “One path is for us to continue to evolve the market design and make sure we can reflect the true cost of providing reliability. Or the region decides we’re going back to cost of service. If you choose to go back to cost of service, it’s not going to be possible to put humpty dumpty back together the way it was 20 years ago.”

MARKETS CHANGE

Twenty years ago utilities were vertically integrated, both producing and distributing power to customers. Regulators approved the construction of new power plants and ratepayers paid the bills. But regulators didn’t always make the right choices. Big bets on nuclear power turned into financial nightmares when cost overruns mounted and electric bills began rising, so the Legislature decided to deregulate most of the industry. Utilities continued to be regulated, but they had to sell off their power plants and narrow their focus to distributing electricity. Power generation was left to competitive markets.

Van Welie and his team designed and today oversee those markets. They are like air traffic controllers, but instead of guiding planes from one destination to another they determine which power plants in the region come on line and when. They also run a stock exchange of sorts for electricity, where power is bought and sold. This marketplace for electricity makes the decisions about which power plants get built, and those decisions are based on cost alone.

The region’s wholesale electric market consists of two major sub-markets. One is a day-ahead energy market, which sets “clearing prices” for electricity delivered to the power grid the next day. The other is a forward capacity market, which sets prices for what are essentially options to purchase electricity three years out. In both markets, van Welie’s organization estimates how much power is needed and then hosts an auction to fill that need. Between the two markets, generators are expected to recover the cost of constructing and operating their facilities. (There is also a retail market for electricity, but most consumers still buy a “basic service” package purchased on their behalf by their local utility.)

Over the last 15 years, the wholesale electricity market has transformed power production in New England. In 2000, oil and coal plants accounted for 40 percent of the region’s electricity generation, with natural gas providing 15 percent. As relatively cheap natural gas began to flood the region, more expensive coal and oil plants found themselves crowded out of the market. Brayton Point in Somerset, the largest coal-fired power plant in New England, shut down permanently in June 2017. The plant had spent more than $1 billion on environmental mitigation measures in the years before closure; none of those expenditures had to be absorbed by ratepayers. By 2016, natural gas’s share of the market had risen to 49 percent and coal and oil were down to 3 percent. (Nuclear plants, hydro-electricity, and renewables provided the rest.) The shift to natural gas, with its lower pollutant profile, also helped reduce greenhouse gas emissions across the region.

Van Welie says the environmental gains were an unexpected benefit of the market transformation. “The existing market has one objective, which is to provide reliable electricity at the least possible cost,” van Welie says. “That’s all this market does. It doesn’t incorporate an environmental objective.”

But as climate change moved to the forefront in state capitols across the region, that absence of an environmental objective became a major problem. Krich, the Cambridge energy consultant, said renewable energy projects, which require a significant up-front capital investment but are cheap to operate, weren’t a good fit for the wholesale electricity market. The projects couldn’t recover enough resources in the markets to convince bankers to loan them enough money to begin construction, she said.

With laws mandating a steep reduction in greenhouse gas emissions, New England states began offering subsidies and tax breaks to make solar and wind power more affordable. This year Massachusetts went much further, signing 20-year contracts committing the state’s electricity customers to pay for large-scale offshore wind and hydroelectricity projects. The prices were so attractive that lawmakers on Beacon Hill shouted, “more, more, more!”

As van Welie was struggling to come up with a way to deal with these large, out-of-market clean energy procurements, he faced another challenge. Natural gas, plentiful and relatively cheap most of the year, became scarce during prolonged cold spells when a combination of strong demand for gas for heating and limited pipeline capacity made it difficult for power generators to get the gas they needed to operate their plants. Suddenly, the market’s reliance on natural gas became a big problem. Last winter, for example, the combination of a 15-day severe cold spell and the pipeline constraints on natural gas forced generators to burn 2 million barrels of oil, far more than they burned in all of 2016 and 2017 combined.

Earlier this year, the company that owns Mystic Generation Station in Everett announced it was losing money running its gas-fired power plants and planned to shut the facility down in mid-2022. The liquefied natural gas facility next door, which supplies gas to Mystic and serves as a hedge against pipeline constraints because its fuel comes in by ship, was also in danger of closing.

Van Welie’s team ran the numbers and concluded rolling blackouts would be likely under certain conditions if Mystic shut down, so he is seeking approval from federal regulators to spend hundreds of millions of ratepayer dollars to prop up the money-losing facility for at least a year or two. The man behind New England’s energy markets is sidestepping that market to make sure the lights stay on.

MARKET DISTORTION

Both the proposed Mystic bailout and the Massachusetts clean energy procurements are retreats from a competitive wholesale electricity market. They aren’t quite a return to the vertically integrated utilities of 20 years ago, but they are a significant step toward a world where regulators make decisions about what kind of power generation gets built and at what cost. Ratepayers face greater risk with this kind of approach because a 20-year contract is risky in a business where change is accelerating. What happens if a new technology comes along after eight years that can provide electricity at far less cost? There’s no way of walking away from the old contract.

Most analysts expect state freelancing outside the wholesale market will accelerate in coming years as states try to decarbonize electricity production and then use that electricity to power the heating and transportation sectors. A study done for the New England Power Generators Association estimates these out-of-market, state-subsidized contracts for power will become the largest single source of consumer electricity supply in New England by 2023 and exceed 50 percent by 2027. The study estimated the percentage could reach 58 percent by 2027 if Massachusetts follows through on a legislative authorization approved this year to double the size of existing clean energy procurements.

What’s emerging is a power market split in two – one, the traditional market, set up to help generators recoup their costs, and the other a state-directed clean energy procurement system that covers most, if not all, of the generator’s costs. The clean energy generators, with their costs covered, are likely to depress prices in the wholesale electricity market and possibly force many generators out of business.

Van Welie has come up with several complicated schemes to blend the two markets together, allowing them to coexist.  But David O’Connor, the senior vice president for energy and clean technology at the lobbying firm ML Strategies and a former Massachusetts commissioner of energy resources under five governors from 1995 through 2007, says a sharp uptick in clean energy procurements will make that balancing act difficult.

“As it gets bigger, the distortion grows to the point where the markets don’t work anymore,” he says.

The three southern New England states seem all on board with operating outside the wholesale competitive market, but New Hampshire and Maine are not so thrilled.

“We all have an interest in this,” says George McCluskey, a ratemaking analyst for the New Hampshire Public Utilities Commission. “It is very disruptive when things don’t happen through the market route.”

On the issue of bailing out Mystic Generation Station in Everett, New Hampshire and Maine both oppose van Welie’s proposal to have all New England electricity customers foot the bill. He argues the fuel security benefits of keeping the plant online will benefit the entire region, so the entire region should pay. But New Hampshire and Maine say Massachusetts environmental policies are creating the fuel security problem the Mystic bailout is meant to address so Massachusetts ratepayers should foot the entire bill.

In a filing with the Federal Energy Regulatory Commission, Maine notes how Massachusetts has blocked construction of a new natural gas pipeline into the region. Both states say new Massachusetts environmental regulations that took effect on January 1 require Bay State power plants to steadily ratchet down their greenhouse gas emissions, making it difficult for those facilities with dual-fuel capability to shift to oil when gas is scarce.

McCluskey estimates the gross cost of bailing out Mystic for two years is $600 million to $650 million, which could net out to $400 million to $450 million assuming the plant is able to sell the power it generates. “There’s potential significant risk that the cost could be much more than that. It’s a very, very nice deal” for Mystic’s owner, Exelon Generation, he says.

In general, McCluskey said New Hampshire’s philosophical position is that Massachusetts ratepayers should pay the cost of their state’s environmental policies. “New Hampshire’s position is we’re not opposed to Massachusetts having these policies, but we certainly don’t want to pay for the consequences of what’s happening,” he says. “I’m having debates with my counterpart in Massachusetts all the time on how this is going to impact New Hampshire ratepayers.”

NO EASY ANSWERS

One seemingly easy solution to all of these problems would be to put a price on carbon, which would reorient the pricing dynamics of the wholesale electricity market by making carbon-intensive fuels more expensive.

“It’s probably the most efficient way to integrate the environmental objective into the wholesale electricity market,” van Welie says. “There’s a pathway there that the states could pursue but have chosen not to pursue.”

Krich, the energy consultant, says a price on carbon could work, but only in the short term – maybe 15 to 20 years. After that, she says, the market will be dominated by clean power and the impact of a price on carbon will be minimal.

“In the end, she says, the choice for policymakers will come down to either attempting a redesign of the wholesale market, one that better reflects the need for clean energy, or going with more extensive regulation. “I do think there’s a possibility that we’ll come up with a way to make the wholesale market work, but we’re not there yet,” she says.

O’Connor, the ML Strategies lobbyist, says it’s time that policymakers stop looking for a single solution to the problems with the wholesale electricity market. He says the region may need a combination of carbon pricing and long-term contracts. He is hopeful clean energy technology will progress quickly, and costs will comes down allowing for shorter and shorter contracts.

Dolan, who represents existing power generators, says the whack-a-mole approach to problems with the wholesale electricity market isn’t working. “My concern is we, as a region, are missing the long-term picture,” he says. “We’re not looking at this holistically and instead we’re trying to deal with each situation on a triage basis. We need to look at where the puck is going rather than where it’s at now. “

Dolan would like to retain a market that promotes competition among generators. “To me it all comes down to costs and risks,” he says. “We will find a way to preserve reliability. My worry is that the path we’re on is going to be one of the most expensive ways to do it.”

Van Welie also favors a competitive market. He is coming up with all sorts of new initiatives to make the existing market co-exist with the emerging market of clean energy procurements, but he says other options are on the table. He says states could abandon the wholesale market all together and decide to sign contracts for all the power generation they need. Or the states could sign cost-of-service contracts for renewable energy and have the Federal Energy Regulatory Commission oversee similar agreements with other generators.

“You could have a bifurcated cost-of-service structure, with us in the middle saying this is how much power we need,” he says. “The problem with that model is you put all the risk on ratepayers again. Competitive wholesale markets are a more efficient outcome for consumers in the long run.”