Some 375 people registered for Friday’s virtual version of Raab Associates’ 165th New England Electricity Restructuring Roundtable, held exclusively online in response to the COVID-19 coronavirus pandemic.
Three of seven panelists appeared in person at the Boston law offices of Foley Hoag with moderator Jonathan Raab, while the others joined via video link.
Robert Ethier, ISO-NE vice president for system planning, stayed away from the venue under a new policy from the RTO, effective the previous day, for staff not to appear in person at any conference or stakeholder meeting through the end of April.
Later that day, Massachusetts Gov. Charlie Baker prohibited gatherings of more than 250 people in the state, which was already operating under a state of emergency.
The webinar focused on the evolution of the transmission system in a decarbonizing New England. Electrification of the transportation and building sectors will increase power consumption, and transmission will serve as the linchpin to the region’s transition to a low-carbon and carbon-free future, Raab said.
“As New England states are pursuing their economy-wide greenhouse gas-reduction goals and mandates, our transmission grid will need to grow substantially to facilitate the development of renewable energy resources as we decarbonize our electricity supply,” Raab said.
Following is some of what we heard.
Choice of Focus
Higher load, lower clean energy capacity factors and renewable curtailments mean New England will need more than 200 GW of capacity by midcentury, said Jürgen Weiss, a principal with The Brattle Group.
“We concluded that if you decarbonize the energy economy in the New England states, you can count on roughly doubling electric load by 2050,” Weiss said during his presentation.
Brattle’s analysis found that growth in electricity demand by midcentury will range from about 77% when policy is focused on energy efficiency, to 103% when it’s focused on electrification, to 136% when it’s focused on electrification and renewable fuels.
“If we use electricity to make renewable fuels, to make some carbon-neutral substitute for natural gas, those processes are actually more energy-intensive; they use more electricity per unit of energy delivered to the end use than direct electrification, so in that case, you might actually see significantly more than a doubling of electricity demand,” Weiss said.
Any resource scenario has important implications for the transmission and distribution system, he said. Brattle estimated a rough doubling of incremental annual national transmission investment, largely related to connecting renewable energy resources to the grid.
“Relative to the annual transmission investments that have been occurring over the last few years, which are somewhere between $10 billion and $15 billion a year [in the U.S.], we probably need to add about twice that amount over the coming decades. So $25 billion of incremental transmission investments to do several things,” Weiss said.
“First, the new transmission will interconnect a lot of resources that are not going to be sitting next to load like the current generation is,” he said. “Here in New England, that’s obviously a lot of offshore wind.”
New distribution infrastructure also will address “very different load profiles, and ultimately much higher peaks,” Weiss said.
Big Wind Overflow
Ethier agreed with Weiss’s analysis and said that changing use patterns are “probably going to require an entirely new way of looking at the transmission system.”
“The integration of renewables and storage may significantly change the transmission flows, and we’re already seeing that with lots of resources added to the distribution system, which will cause some of our distribution feeders to actually flow in the opposite direction,” Ethier said.
He outlined ISO-NE’s transmission planning process and noted its first-ever solicitation in December for competitive transmission solutions for reliability needs in the Boston area, which drew 36 proposals — both AC and HVDC — ranging from $49 million to $745 million. The RTO is evaluating proposals and will review results with the Planning Advisory Committee. (See ISO-NE Issues First Competitive Tx RFP.)
“There are two issues with the transmission system: There’s paying for it, and then there’s getting it built,” Ethier said. “Both of those are time-consuming, and both of those are things that, if the past is any guide, we’re going to have a hard time keeping up with the states’ goals [and] meeting their carbon-reduction targets.”
In addition, developers are proposing about 15 elective transmission upgrades (ETUs) to help deliver about 11,000 MW of clean energy to load centers in New England, he said.
“We’re seeing lines that are seeking to connect northern Maine; we see lines seeking to connect offshore wind to load centers in New England, and also lines for hydropower from Canada,” Ethier said. “In most cases, we see multiple versions of these things that would accomplish the same goals.”
The ETU proposals “are queued up now and waiting for an opportunity to sell their services and sell their project as part of some sort of clean energy procurement at the state level, and until then, they’ll just bide their time in our queue,” he said.
The largest public policy effect in the region these days is offshore wind, and studies have shown that the rate of spillage increases as the buildout increases, Ethier said.
The RTO last month presented its latest study results on integrating up to 8,000 MW of offshore wind into the regional grid, analysis requested by the New England States Committee on Electricity (NESCOE). (See “OSW Study: More the Better,” ISO-NE Planning Advisory Committee Briefs: Feb. 20, 2020.)
“Spillage is where we have excess generation in New England and we actually have to back down renewable resources,” he said. “At 8,000 MW we hit spillage in every month of the year, so we have to back down various economic resources to accommodate these renewables. To avoid that you either need to increase load in the region, shift load around, or add significant amounts of storage.”
Offshore Planning
Robert Kump, deputy CEO and president of Avangrid, said his company is working on both the Canadian hydropower side and offshore.
Avangrid subsidiary Central Maine Power is nearing completion of permitting for its $950 million New England Clean Energy Connect (NECEC) project to carry 1,200 MW of power from Hydro-Québec to Massachusetts, he said.
“The latest approval was from the Maine Land Use Planning Commission, received in January,” Kump said. “We expect any day now to get a draft approval from the Maine [Department of Environmental Protection],” which in fact came later that day.
“The goal would be to have all of our permits completed by the summer, and to start construction in the third quarter with a year-end 2022 completion date,” Kump said. Four gigawatts of additional transmission is needed to balance variable resources, he said, citing a Massachusetts Institute of Technology study this year on the role of Canadian hydropower in decarbonizing the Northeast.
Kump also presented data from Vineyard Wind, his company’s offshore wind joint venture with Copenhagen Infrastructure Partners, and called for increased state and federal coordination to reduce permitting and siting risks.
“The starting point for thinking about how we connect this brand new and significant resource to the grid is looking at where we can bring it ashore,” said Peter Shattuck, chief information officer of Anbaric Development Partners. “Overall, independent transmission can minimize interconnection costs, reduce marine cabling and enable offshore wind to scale.”
Shattuck presented an argument for networked HVDC offshore transmission that compared scenarios of planned and unplanned development, with the latter seeing energy losses of 8%, while a planned network had only 3% losses, with comparable reductions in environmental and fisheries impacts because of 49% fewer miles of cables needed.
Wholesale Market Design
The second panel focused on what wholesale market design should look like in a fully decarbonized regional grid.
MIT economist Paul Joskow discussed how wholesale markets will support the investment costs of new generation and storage technologies.
“The systems in place have worked least well in stressed conditions in terms of providing efficient price formation,” Joskow said. “There’s been a lot of discussion about resource adequacy and capacity compensation focused on adapting capacity markets in various ways to provide additional net revenues. I don’t think that the conventional capacity markets framework used in most RTOs is well-adapted to a system dominated by intermittent generation.”
Joskow’s observation that New England “is way behind the other states and regions in the smart meter or smart grid technology” prompted a question from Manuel Esquivel of the Boston Planning and Development Agency as to what municipalities could do to encourage the adoption of smart meters.
“Mandating real-time meters and other smart equipment, controllable sensing equipment, inverters that can do more; these are state public utility commission decisions,” Joskow said. “This is not some way-out thing. Philadelphia has 100% penetration of smart meters; Baltimore has 100% penetration.”
The most important thing is to get the real-time design correct, said professor William Hogan, of Harvard University’s John F. Kennedy School of Government.
“If not, you’ll create many new problems,” Hogan said.
He highlighted that under scarcity pricing in ERCOT, high prices of $9,000/MWh last summer occurred at the right time and were not socialized through capacity market charges spread over all load. (See “Scarcity Pricing Likely Again in 2020,” Overheard at Infocast’s ERCOT Market Summit.)
Sue Coakley, executive director of Northeast Energy Efficiency Partnerships, asked what the market design would need in order to include carbon-free demand-side resources, especially energy efficiency.
“I have a long record of not being a big fan of capacity markets, so if you’re worried about this problem, the worst place to start would be the capacity markets,” Hogan said. “I would go much more towards the retail rate design side.”
Boreas Renewables President Abigail Krich agreed with Hogan, saying that ISO-NE’s current capacity market design “absolutely would not be sufficient” to decarbonize New England’s grid.
“Some other mechanism is needed to secure a new way of financing, whether it’s in the centrally run market by ISO-NE, or whether it’s some mechanism by the states, or hedging,” Krich said. “I think this is going to be an iterative process … and there is a lot of investment needed.”
Robert Stoddard of Berkeley Research Group asked if the states’ roles needed to fundamentally change: For example, does New England need to adopt mandatory retail choice, as in Texas?
“I actually think the Massachusetts attorney general has it right in pushing to eliminate retail choice at the residential customer level,” Krich said. “I think that experiment has not worked in Massachusetts so far. At a larger scale, there are customers who are able to make informed decisions.”
— Michael Kuser