New England Markets in Fundamental Shift
BOSTON — FERC Commissioner Cheryl LaFleur kicked off her farewell tour with reflections on electricity markets in New England and around the country, NERC CEO Jim Robb shared concerns about fuel security, and a panel of experts discussed the challenges confronting the industry.
Attendees heard that and more at the 161st New England Electricity Restructuring Roundtable hosted by Raab Associates on Friday. Following is some of what we learned during the event.
Attributes over Volume
LaFleur, who announced in January that she will leave the commission between the end of her term June 30 and the end of the year, offered her insights into the changes on the horizon. (See LaFleur Announces Departure from FERC.)
“I am seeing lots of evidence from all over the country, in organized markets and outside organized markets, that a fundamental shift is underway in how we procure and pay for electricity,” she said.
“Back in the vertically integrated days … we took it for granted, and many times we still do, that energy is priced on volume,” LaFleur said. “Aside from a few ancillary services that were co-optimized at a lower price, everything was volumetric, and it worked as long as the cost curves were that way. Well, there’s a lot of evidence that the cost curves are not going to look that way in the future.”
With persistently low gas prices, even in New England, zero-marginal-cost renewables coming online, and distributed energy and demand-side resources changing the load curves, the industry can’t assume that resources are going to make money on volume, and that peaks are going to set the prices at which resources make money, she said.
“Across all the markets and regions, what we’re seeing is people … paying for attributes rather than volume in the energy markets, in the capacity markets and in the ancillary services markets,” LaFleur said.
“The trouble is, an attribute is a slippery thing” and can encompass anything from stockpiling coal to pricing carbon; from flexible ramping to scarcity pricing, storage or fuel security, she said.
“And it’s in the capacity markets too, where we have Pay-for-Performance; Capacity Performance; seasonal capacity,” LaFleur said. “I’m starting to think if we’re not going to pay on volume, how are we going to pay? And this is fundamental. … Most of the money is in the energy market. How we pay for energy is going to determine what we get and how we pay to keep the lights on.”
The “cut-across issue” for LaFleur is jurisdictional, where the federal government does some things and the states do others.
“We understand what’s interstate, and we have jurisdiction over the ISO rates, and then the states have their jurisdiction, but then here are resources connecting behind the meter at the distribution level that operate like wholesale resources,” she said in response to a question about DERs.
“It’s really easy to say, ‘Oh, we should have more cooperation with the states,’ but it’s really hard to figure out how to do that in this space because our system was set up as if we knew the difference between central station wholesale and distributed [resources],” LaFleur said. “So, [there is] a lot to work through, but … I think it’s way more an opportunity than a challenge. It could be, to use an overused word, transformative.”
‘A Lot to Celebrate,’ but…
New England has benefited from ISO-NE’s creativity in dealing with fuel security, said Robb, who has been at the helm of NERC for nearly a year after leaving the chief role at the Western Electricity Coordinating Council.
“There are really three hotbeds of issues in reliability around the country,” Robb said. “The first one is California … the epicenter of the issues around an integration of large-scale solar into the system. … Whoever thought we’d have too much generation on peak?”
Until the Aliso Canyon gas storage facility came in service, it was not clear what a growing balancing role the natural gas system was playing in response to the surge in solar capacity, and how that system was being stressed by fast-ramping gas-fired plants pulling gas off the network faster than it could be replaced, Robb said.
“The other area is Texas, which is really testing all of our patience on the question of capacity adequacy and reserve margin,” Robb said. “They’re operating at about a 7 to 8% reserve margin going into the summer. They put great faith in the market signals that they’re sending to the operators and to the plants online. They made it through a very hot summer last year, so there’s something in the soup that we’re starting to understand about what kind of reserve margins are really necessary.”
The third area is New England, and “from an environmental perspective there’s a lot to celebrate,” Robb said. “You have substantially repositioned your fleet to a much lower carbon footprint than it was 20 or 30 years ago to meet environmental objectives and have managed to keep the lights on.
“The shift away from on-site fuel — large coal, nuclear and petroleum — to resources that are dependent on weather and just-in-time delivery of fuel really changes the risk profile,” he said. “The issue up here is not one of capacity adequacy; it’s one of energy adequacy and, importantly, fuel adequacy to serve load.”
Robb looked at the dramatic oil consumption during last winter’s sever cold snap — when generators burned as much oil in two weeks as they normally do in a year — and asked what would have happened if the cold snap had lasted another day.
Oil supplies at plants around New England declined rapidly over the two-week cold spell as gas prices spiked and dual-fuel plants switched to oil, but the RTO avoided serious reliability issues thanks to LNG shipments. (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)
“You guys are a day away from a load-shedding event,” Robb said.
Where the NERC CEO sees the region’s glass as being half-empty, Dan Dolan, president of the New England Power Generators Association, said he “would argue that we passed the stress test [and] came through the most severe cold snap in 100 years with gas in the system at the end.”
“The open market has been extraordinarily successful at dispatch of least-cost resources,” Dolan said.
However, he pointed to the increasing trend of states procuring energy contracts and estimated that state-sponsored resources will compose more than half of the region’s energy production by 2027.
Dolan cited research by Joe Cavicchi of Compass Lexecon, commissioned by NEPGA, that says New England’s much-needed fast-ramping resources require capital investment — and that generators believe the market signals get mixed in a half free, half state-controlled market.
Jonathan Raab of Raab Associates, who conducted the roundtable, asked if the wholesale markets are at a tipping point, and if so, how New England can prepare for the world 10 years from now.
“It’s later than you think,” said Katie Dykes, commissioner of the Connecticut Department of Energy and Environmental Protection.
“We hear from those who have been in this market for quite some time that there’s a lot of volatility, uncertainty, marginal earnings and even from the [perspective of the] status quo, it’s not a market that a lot of people are feeling comfortable continuing to invest in,” Dykes said.
“Our failure to plan proactively [for natural gas supply constraints] … has exposed our ratepayers to the exercise of market power by those generators who do have the ability to provide fuel-secure resources,” she said. (See Exelon to Push for Laws, Rules to Boost Profitability.)
The retreat at the federal level on the need to address climate change has injected further uncertainty for those who would like to move forward with market-based approaches to valuing carbon reduction, she said.
Connecticut has long-term contracts approved or pending for 52% of the state’s energy demand, including 13% for non-nuclear resources needed to meet its renewable portfolio standard, Dykes said.
“If we’re paying a capacity payment to resources for availability for an entire year, for resources that we know don’t have access to pipeline gas to be able to run year-round, I think some further refinement on what that market is designed to procure is important,” Dykes said.
To the extent that states are seeking to meet their planning objectives for environmental policy around carbon, the more that those products can have resource adequacy and fuel security benefits will also be helpful, she said.
“We are with our capacity markets nearing an inflection point where we need to figure out exactly what our resource adequacy construct needs to be going forward,” said Mark Karl, ISO-NE vice president for market development.
As he did in December, Karl said the RTO’s long-term solution for energy security has three components: multiday-ahead markets, a new ancillary service integrated into that market and a new, voluntary forward seasonal auction. (See Fuel Security the Focus at ISO-NE Consumer Liaison Meeting.)
“I should be clear it’s not just about fuel; it is about energy security,” Karl said.
The RTO’s enhanced storage participation rules go into effect April 1, with a second phase coming in the second half of this year, and staff are working on a third phase, he said. (See FERC Accepts ISO-NE Storage Tariff Revisions.)
In addition, the RTO prepared an interim proposal for compensating generators for fuel security, which it plans to file this month with FERC, with or without stakeholder endorsement. (See ISO-NE Steady on Fuel Plan Despite NEPOOL Rebuff.)
The Analysis Group’s Paul Hibbard, former chairman of the Massachusetts Department of Public Utilities, said the desire to reduce energy sector carbon emissions is the biggest market factor of all.
With various state policies being enacted, “how do the markets provide the resources needed to maintain reliability, particularly during winter months?” Hibbard asked. “That’s what makes this so incredibly difficult.
“There’s really very little opportunity for resources to earn sufficient revenues through energy markets when you look five or 10 years out, but we still have to maintain reliability during those winter months,” he said.
When the Pilgrim nuclear plant and the remaining oil and coal units retire, the system will become “a lot more peaky” from a gas supply perspective, he said. “What really changes here is that the consumption of natural gas power plants for electricity spikes in the winter … so it really increases our reliance, particularly for power sector reliability, on LNG over the course of the 25 or 50 coldest days of the year.”
Add electrification and “things get really scary, because now pipelines can’t even meet total demand for gas for over 100 days in the year,” Hibbard said. “It’s this combination of what the states are trying to do to meet carbon-reduction goals, and the feedback that has on the electric system, that makes the challenges so incredibly important when thinking about this transition over the next 10 years.”
– Michael Kuser