By Rich Heidorn Jr.

CAPE NEDDICK, Maine — New England state regulators agreed last week that their region faces a growing winter reliability challenge but expressed skepticism over ISO-NE’s proposed solutions.

Speaking at the New England Conference of Public Utilities Commissioners’ (NECPUC) 71st annual symposium May 21, a panel of regulators pressed ISO-NE CEO Gordon van Welie on the need for an out-of-market contract for Exelon’s Mystic Generating Station, asking why it can’t be replaced through the capacity market and its Pay-for-Performance program.

The proposed Mystic contract represents the first of ISO-NE’s “three-track” plan for addressing its winter fuel reliability concerns. Last week, dozens of intervenors filed comments in response to the RTO’s request for a Tariff waiver needed to authorize the procurement, most of them in opposition (ER18-1509). (See related story, Mystic Waiver Request Spurs Strong Opposition.)

‘A Point at Which We Can’t Hold Things Together’

Van Welie said that Pay-for-Performance — which was premised on gas plants adding oil-fired capability — has been hampered by its stop-loss provisions and states’ resistance to oil-fired generation.

The CEO also said there isn’t enough oil storage or allowable air permits to rely on the fuel as the region’s backstop. During the Dec. 26-Jan. 8 cold snap, oil prices fell below gas, making oil-fired generation effectively baseload for two weeks, he said. The region burned about 2 million barrels of oil during that period — more than it used in all of 2016 and 2017 — drawing down supplies from 68% of tank capacity on Dec. 1 to 19% by Jan. 9. “The ISO had to step into the market to slow down the burn rate,” he noted.

Fuel delivery logistics also are a concern. Heating customers get priority for oil as well as gas. Oil deliveries can be delayed by storms and drivers’ working hour limits.

Van Welie said the RTO must firm up fuel deliveries and ensure that the market “uniformly” values all resources with such service, including its Millstone and Seabrook nuclear plants, which produce one-quarter of the region’s power during winter.

In addition to the region’s precarious fuel infrastructure, ISO-NE is concerned that state-sponsored renewable resources will reduce energy market revenues, causing increases in capacity market costs and plant retirements.

“Our concern is there’s a point at which we can’t hold things together,” van Welie told the regulators.

ISO-NE is seeking to delay Mystic’s retirement because its analysis indicated the loss of Units 8 & 9’s 1,700 MW of combined cycle capacity that don’t rely on pipeline gas would leave the RTO depleting its 10-minute operating reserves “on numerous occasions” — a violation of NERC reliability rules. The analysis also predicts load shedding during the winters of 2022/23 and 2023/24.

The RTO has asked FERC to waive its Tariff to retain resources to address fuel security risks — an option currently allowed only for local transmission security issues (Track 1). It hopes to file a Tariff change by the end of the year to make fuel security a reason resources can be retained (Track 2). In addition, the RTO is seeking a long-term plan to ensure sufficient firm energy for winter that would compensate needed resources through the market rather than reliability contracts (Track 3).

A Menu, not a To-Do List

Despite the hand he’s been dealt by the region’s resistance to oil generation, additional gas pipelines and electric transmission, van Welie was careful to couch his comments not as a “To Do” list but as a series of questions and menu choices for the states.

“We are an energy-constrained region. Do we want to maintain that constraint going forward, or do we want to do something about that? And specifically, can the states shape their resource procurements … in a way that they get at the winter constraint? Because I think in doing that the states can help us as well as maintaining or meeting their other policy goals.”

‘A Very Expensive Future’

“The magnitude of that problem is in [question] but there is a problem,” said Bob Stein, vice chair of the New England Power Pool’s Reliability Committee, who joined regulators on the panel.

NEPOOL has “a range of positions [on the RTO’s plans], and they’re not fully formed,” said Stein, principal of Signal Hill Consulting Group. The range, he noted, is framed by the two types of NEPOOL members: “Those that are long and those that are short. And you can instantly tell what people are going to say by where they are.”

Maine Public Utilities Commission Chairman Mark Vannoy and other commissioners pressed the RTO for a “definition” of the problem, saying he is concerned that “New England is on a course to a very expensive future.”

“I’m not arguing that there is not a problem,” Vannoy said. “But we need to define what the problem is and then — if our intent is to use market mechanisms to solve that — we have to be precise … so that we can move to those market solutions.

“We have a very complex and dynamic market, and as price signals drive fuel procurement questions … [as fuels] substitute for other fuels … we need to understand how that dynamic market reacts before we move to the Markets Committee for a solution.”

Vannoy said New England helped create its dilemma by “separat[ing] itself from the rest of the country’s energy … potentially, to our economic peril.” He cited states using their EPA-delegated authority under the Clean Air Act to prevent access to Marcellus shale and other gas supplies.

As an example, Vannoy later cited the Atlantic Bridge pipeline project. In the face of local opposition, Massachusetts officials said in December that they would take up to a year to review the impact of a compressor station in Weymouth, Mass., that is part of the project.

Seeking an Honest Conversation

Angela O’Connor, chair of the Massachusetts Department of Public Utilities, called for an “honest” conversation.

“Whether you want to reduce greenhouse gases or simply reduce the rising outrageous cost of energy … burning 2 million barrels of oil in five days and killing baby seals to get to expensive Russian gas cannot and should not be part of any intelligent conversation about energy policy in this region,” she said. “It clearly does not meet any of our New England collective goals for the states. We need to have an intelligent and honest — emphasis on honest — conversation to develop the right solutions, and we need to do it all together.”

Is Pay-for-Performance Broken?

New Hampshire Public Utilities Commissioner Kathryn Bailey said her state is not convinced that the out-of-market contract with Mystic is the only possible solution to the region’s near-term concerns. She said the Operational Fuel-Security Analysis released by ISO-NE in January suffered from “problems with the assumptions and the lack of analysis on how likely scenarios are to play out.” (See Report: Fuel Security Key Risk for New England Grid.)

She said maintaining Mystic could create incentives for other non-gas generators to seek cost-of-service agreements.

“I have to ask: What happened to the market-based solution to fuel security? Just a few short years ago, ISO-NE reported to FERC that Pay-for-Performance was a long-term, market-based solution designed to address generator availability concerns and the region’s vulnerability to interruptions in gas supply. … What changed? Why does the ISO think it won’t work, even before the incentives take effect next month? Where’s the analysis that demonstrates it won’t work? When the ISO originally brought this plan to FERC, there was a lot of analysis.

“If Pay-for-Performance had worked as expected … and Mystic announced its retirement, prices in [Forward Capacity Auction] 13 would likely separate to provide incentive for new resources to take on the supply obligation in that zone. But apparently Pay-for-Performance can’t work.”

Bailey also noted “the irony that ISO-NE refused to allow a 200-MW renewable exemption backstop to integrate state public policies because of the impact it would have on the market. But now they want to waive the Tariff and allow a 1,700-MW out-of-market contract.”

‘Buck up, Little Soldiers’

In a period of low gas and renewable prices and flat load growth, Connecticut Public Utilities Regulatory Authority Chair Katie Dykes asked: “Why is everybody so unhappy?”

Her theory: “Legacy” deals, conflicting state policies, and overlapping jurisdictional authority between FERC, state legislators, state commissions, siting councils and the courts make it difficult for economic regulators to achieve the “fairness” they seek.

“We were one of a few states that got our legislature to give us fresh, brand new authority to procure not only gas pipelines but LNG storage. We got all of that authority. We opened a [request for proposals]. …

“We opened up the bids. We were ready to go. [Then] we looked at the costs and we realized that if we didn’t have all the states moving with us that Connecticut was going to pay 100% of the cost of these resources and only get 25% of the benefit because that’s our share of load. And so, the bids are still sitting in a desk drawer somewhere.

“The challenge of the multi-jurisdictional process is it is guaranteed to be unfair to some parties. … There’s a temptation to retreat within our own borders and pursue this sort of righteous unilateralism. … But that’s not really an acceptable tactic. If it comes to those outcomes, everyone in this room is going to be blamed for that occurring. No matter how hard you’ve been working on this issue, no matter how small your slice of the jurisdictional pie is, you’re all going to share responsibility for [reliability problems], which will hurt people and drive businesses out of New England,” she said, raising her arms like a cheerleader waving pom-poms. “So, what we really need to do is buck up, little soldiers. We can do this. This is New England.”

16,000 Terminations

Rhode Island Public Utilities Commissioner Abigail Anthony stressed affordability, saying customers are best served by investments that “prioritize highly cost-effective measures that improve the reliability resiliency of both the distribution system and the [transmission] system.”

“So, the resources that we invest in need to do double or even triple duty to improve the energy system on multiple levels,” she said. She added, “Some of the best solutions to maintaining and improving reliability resiliency and affordability may lie outside the power system.”

She noted that 16,000 of her state’s residential electric accounts were terminated for nonpayment in 2016. “Rhode Island’s experience, consistent with national data, shows that the vast majority of customer outages are the result of disruptions of the distribution system or due to affordability,” she said.

Vermont Public Utility Commissioner Sarah Hofmann said she would like more data on resilience risks, the costs of reducing them and residential customers’ willingness to accept outages.

“The tolerance of consumers for the bad thing happening, such as rolling blackouts, that’s a conversation that … I don’t think we have as much as maybe we should, in terms of what can a residential customer tolerate as opposed to … a commercial customer.”

Enough LNG? Rewrite Capacity Market?

Van Welie said the two top sensitivities for its fuel study was the timing of retirements of its non-gas fleet and the size of LNG injections.

Over the last five winters, ISO-NE says the region has received an average LNG injection of 0.2 Bcfd, only occasionally spiking to the 1-Bcfd level assumed in the baseline case. In its recent analysis, Synapse Energy Economics said import terminals could handle 1.5 Bcfd.

“We’re talking about unprecedented levels of LNG imports into this region,” van Welie said. “And the big question is: Is the market signal strong enough to incent that behavior?”

Of New England’s 17 GW of combined cycle capacity, only 5 GW have dual-fuel capability. “There are three with large tanks. The biggest one is 10 days’ [capacity]. The next one down is five or six days. The next one down from that is three days. The tanks that are being built, if they do get built today, are [only] two days.”

“So, the issue is, Pay-for-Performance was calibrated to the economics around dual fueling, [which] may not be a good assumption in the long term.”

Van Welie also questioned Pay-for-Performance’s annual and monthly stop-loss limits for generators that fail to perform, which he said has many of them rolling the dice that they won’t need firm fuel. “Is that the right incentive to send generators? That they could end up still collecting capacity payments without necessarily having to feel that they need to run for the winter?”

Van Welie also said the decisions the RTO made when it designed its capacity market 14 years ago need to be reconsidered. The market’s design is based on meeting the summer peak rather than the winter peak, which is now the bigger risk. A seasonal construct that acquires resources separately for the winter and summer would be preferable, he said.

“Do we throw out the capacity market — go back to blank sheet of paper and redesign the seasonal capacity market? Or do we … do something complimentary, really specifically targeting … the firmness of energy that we required during the winter period?

“We have not landed on … the specific solution to this problem. … But we recognize that … some of the things that we assumed as far back as 14 years ago may not be valid.”