CARMEL, Ind. — MISO is preparing to make two resource adequacy filings with FERC aimed at making its capacity resources more readily available.
The RTO last week promised two filings in late April that would ensure that resources procure transmission deliverability to their full installed capacity levels before receiving full capacity credits and shave the capacity credits of some load-modifying resources (LMRs). If approved, both will impact the 2021/22 Planning Resource Auction.
LMR Accreditation
MISO said it will file a proposal to establish an LMR’s capacity accreditation as the smaller of either an average of its actual availability over a three-year period or its tested availability. LMRs that can respond more often and with shorter lead times will receive a larger capacity credit, while those that can respond to 10 or more calls in a year will receive full capacity credit. (See MISO Pursues Leaner LMR Accreditation.)
The RTO will also no longer qualify LMRs with lead times greater than six hours as emergency-only resources because they don’t help mitigate emergency events. However, those long-lead LMRs will still be eligible to qualify as capacity resources.
Speaking at the Resource Adequacy Subcommittee’s meeting Wednesday, MISO planning adviser Davey Lopez pointed out that other RTOs require much shorter lead times for their LMRs. PJM requires its emergency resources have anywhere from a 30-minute to two-hour requirement, while NYISO’s LMRs have a two-hour requirement once called upon. CAISO’s reliability demand response resources have an obligation to reach their maximum curtailment within 40 minutes of dispatch instructions.
The RTO also announced this week it would not use the MISO Communications System to evaluate data for accreditations. Stakeholders often criticize the nonpublic site as outdated and difficult to use to update LMR availability.
Nevertheless, stakeholders have said the proposal seems designed to punish LMRs.
Customized Energy Solutions’ Ted Kuhn said he anticipated that the new LMR accreditation could cut capacity supply by as much as 6 GW.
“This is a ‘yank the rug out, blow out the back door, and then cover the back with a tarp and hope everything is OK’ kind of approach,” Kuhn said.
Capacity Deliverability
MISO is also working on a proposal to allocate capacity credits to resources based on their deliverability relative to ICAP levels.
The RTO said it won’t require that planning resources procure full transmission service up to their ICAP levels; however, resources that that are only partially deliverable won’t receive full capacity credits. The RTO said it’s fine if conventional generators opt not to purchase additional transmission service and settle for fewer zonal resource credits.
MISO also plans to file the new condition for full capacity accreditation with FERC in late April.
By December, MISO will work up unforced capacity values for the 2021/22 PRA. By April 2021, it will run the PRA using its new deliverable ICAP policy.
MISO has already said it plans to model intermittent resources using actual historical market injection values, which will reduce some units’ UCAP values and stand to reduce capacity credits. The RTO first developed a possible solution only for its intermittent resources, citing increasing wind curtailments in the footprint. (See “MISO Pushes Back Deliverability Requirements,” MISO RASC Briefs: Oct. 9, 2019.)
MISO Manager of Capacity Market Administration Eric Thoms said Iowa stands to be the most affected by the new deliverability requirement simply because the state contains a lot of wind generation.
The Independent Market Monitor has said that the RTO doesn’t properly account for capacity deliverability because its loss-of-load expectation study assumes all capacity resources are fully deliverable on an ICAP basis. However, the RTO allows resources to demonstrate deliverability only up to UCAP levels, which tend to be about 5 to 10% below full ICAP levels. The Monitor has said MISO should ensure all capacity resources are fully deliverable based on their ICAP.
MISO Preps 2020/21 PRA
At the same RASC meeting, MISO reported that estimated values for the 2020/21 PRA have remained consistent, sticking with an almost 122-GW coincident peak forecast and a nearly 136-GW planning reserve margin requirement. (See Little Change in MISO 2020/21 PRA Assumptions.)
MISO will update preliminary PRA data a final time March 19. The PRA will be conducted April 1 to 14, with the RTO posting prices April 14 and conducting a stakeholder conference call April 15.
WASHINGTON — The need for gas peakers and electric transmission and the increasing popularity of hybrid storage projects were recurrent topics at the American Council on Renewable Energy’s (ACORE) Policy Forum on Wednesday. And of course, no energy conference would be complete without a discussion of FERC’s controversial order on PJM’s minimum offer price rule (MOPR).
Speakers from Dominion Energy and NextEra Energy had a very different take on the viability of natural gas-fired peaking generation.
Emil Avram, vice president for business development for Dominion, said the company sees a continuing role for natural gas even as it ramps up its renewable generation. (On Friday, Virginia lawmakers approved legislation requiring Dominion and other utilities to go to 100% renewable sources by 2045.)
“While some may not want to hear this … in order to maintain reliability for the gigawatts that will be added to our system over the next decade, we have to build peaking plants. And that means bringing more natural gas into our system,” he said.
Moderator Renee Eastman, of Salt River Project, asked whether energy storage could replace the need for natural gas peaker plants.
Yes, said Rob Gramlich, founder of consulting firm Grid Strategies and executive director of Americans for a Clean Energy Grid and the WATT Coalition. “My firm is testifying ‘yes’ in a number of states’ integrated resource plan proceedings, and that’s kind of where the rubber meets the road,” he said. “So yes, it can. Not all cases, but yes.”
“Maybe yes,” said Eric Vandenberg, deputy director of FERC’s Office of Energy Policy and Innovation.
Former FERC Chair Joseph T. Kelliher, now NextEra’s executive vice president for federal regulatory affairs, wasn’t hedging. “I think there’s no reason to … build peakers going forward,” he said. “And I think storage is going to start leading to the retirement of existing peakers.”
The Hybrids are Coming
Vandenberg said hybrid generation-plus-storage projects have grown “faster than I think a lot of us expected.”
“The business case for pairing storage with renewable resources just keeps getting better. … That starts to create some questions about how do you handle those at both the energy markets — because they’re not fully dispatchable, but they’re much more dispatchable than a regular renewable resource. And then, how do you handle those for interconnection purposes? Obviously, again, it’s like a renewable resource, but not exactly like a renewable resource, not exactly like a standalone battery storage facility. So that’s something we’re keeping our eye on. I think all of the RTOs at this point, except for maybe one, have stakeholder processes underway because they understand that that’s coming down the pipe, and we need to deal with it. So that’s something that we’re going to be paying really close attention to here in the next 12 to 18 months.”
Kelliher said NextEra, the largest renewable company in the world with 15,000 MW of wind and 2,000 MW of solar, is bullish on the potential for hybrids. “We find it very exciting because it firms up renewables, and at some point, it makes renewable energy projects a functional substitute and effective substitute for thermal generation.”
Gramlich said he has become convinced of hybrids’ potential despite earlier skepticism.
“I will eat some crow on that. I always thought that, well, it doesn’t matter if the battery is 300 miles away from the renewable. It’s all a big power pool; it all mixes together,” he said.
But he said the capabilities of inverters and the efficiencies of combining storage and generation in a single interconnection have become compelling. “NextEra and others are doing incredibly innovative work in how to optimize and autonomously operate these units. You can make them do almost anything because they’re inverter-based. You can do everything in millisecond time frames as fast up or down as you as you want.”
Gramlich noted that hybrids were not mentioned in FERC Order 841, which opened RTO markets to storage, or Order 845, which sought to increase the transparency and speed of the interconnection process. But he said he sees no need to ask FERC to take further action — for now.
“I think the message that the commission sent by doing [Order] 841 has gotten all these RTOs off the dime and they have their own processes and they’re moving forward pretty well,” he said. “I mean, obviously, if [RTOs] slow down and we’re stuck, we’ll be walking back over to 888 First St. [FERC headquarters]. But for now, there’s a lot of progress.”
Is Transmission Essential for All Renewables?
FERC Commissioner Richard Glick told ACORE the biggest hurdle to integrating renewable generation is electric transmission.
Glick said FERC is unlikely to win siting authority over transmission, given the controversies over its regulation of interstate gas pipelines. But he said FERC’s pending Notices of Inquiry on transmission incentives and return on equity may provide some improvements.
And he said the commission could improve Order 1000, noting that although it required RTOs to consider public policies in regional transmission planning, “very little public policy transmission is getting built.” Instead of spurring the long-distance transmission needed to deliver renewables, Glick said, Order 1000 encouraged utilities and RTOs to focus on small reliability projects by exempting them from competition.
“I’m a big believer in distributed energy resources, solar panels and so on,” he said. “But I think we’re all fooling ourselves if we think we’re going to get there with just those particular types of technology, the microgrids and things like that. We’re going to have to access areas with substantial wind [including] offshore [and] areas of substantial solar, Southwest and elsewhere.”
Gramlich said Order 1000’s requirement for interregional planning has not produced the HVDC lines or other types of a “macro grid” that is needed. “There is still a ton of renewable resources in the central region that want to go … towards PJM or the Southeast,” he said.
“I think transmission is the linchpin for some renewables, but not all renewables,” Kelliher said. “It’s the linchpin for the best wind resource. And ironically, it’s also the linchpin for the worst wind resource. It’s of less importance for the mediocre wind resource, and it’s actually not that important for solar.
“Look at Southeast renewable development,” he continued. “For a while, people thought we needed a monster transmission project to bring low-cost wind from SPP. But at some point, the economics of solar got so low that it just … made more sense to build solar locally. And then you avoid the brain damage of trying to figure out how do you get transmission siting across four or six states, in the absence of any effective federal siting authority.”
Avram said the incentive to build long-distance transmission from one RTO to another has diminished because of low power prices.
“Ten years ago, you had an incentive to bring, $30 to $40 wind to an RTO that was selling power at $60 to $70/MWh. That gap created some potential opportunities to build transmission and … renewable energy zones and so forth. I think that that has flattened out now, with all the natural gas and solar and wind that’s suppressed wholesale market prices across all the RTOs. So, I think it’s a challenge now to build a business case to build transmission across RTOs.”
A Maryland Capacity Auction? Dominion Going FRR?
Speakers from Dominion and Maryland’s Department of the Environment talked about their response to FERC’s December order extending the MOPR to new state-subsidized resources.
Devon Dodson, an aide to Maryland Environment Secretary Ben Grumbles, said the state is “ridiculously concerned” about the MOPR order. “The singling out of the PJM market really pisses us off — no sense in sugarcoating it,” he said.
The legislature has created a working group on the issue, and the governor’s office directed the Public Service Commission to work with Grumbles’ office and the state Energy Administration to plan a response. “Is it running [our] own capacity auction? I mean, that’s the elephant in the room when we have these discussions. No one wants to say it, but does the state take on the task of running its own capacity auction?”
Avram said vertically integrated utilities that are growing, like Dominion, will likely have to leave PJM’s capacity market because FERC interpreted its state-regulated cost recovery as a subsidy.
The company expects continued load growth driven by the construction of large data centers in the D.C. suburbs.
“I think any utility that’s vertically integrated, that has a growth plan to build renewables or really any new generation … is going to be subject to MOPR. And really the only alternative they have is to elect a fixed resource requirement [FRR] alternative in order to maintain the same economics of those assets in the future,” he said.
In the past, Dominion justified generation additions to state regulators by showing the economics of the asset compared to forecasted prices for energy, capacity and renewable energy credits. Under the MOPR, a new resource will be unlikely to clear the capacity market, reducing its value.
“By electing FRR … you’re now pooling your entire resource [mix] and managing your capacity reserve in its entirety,” he said. “What we’re going to be proposing to the [Virginia State Corporation Commission] is avoided capacity cost from the load side. … That’s the reason why I think, personally, vertically integrated utilities are going to have to exit the capacity market if they’re growing.”
Gramlich was rendered speechless.
“I don’t know what else I can say. Half a minute ago, we heard one of the largest utilities in the country say we’re seeing the end of peakers. Now we’ve got one of the other largest utilities in the country saying this is the end of vertically integrated utility participation in capacity markets. You got your news,” he said to a reporter. “There’s nothing else I can add.”
WASHINGTON — Renewable industry advocates, environmental activists and congressional Democrats said Wednesday that 2021 may provide the best opportunity in a decade for legislative action to address climate change.
But speakers at the American Council on Renewable Energy (ACORE) Policy Forum said their messaging should emphasize the economic benefits of clean energy industries to win support from organized labor, minority communities, farmers and Republican lawmakers.
Sen. Ron Wyden (D-Ore.) led off the forum with a speech — part political science lecture, part pep rally — on the strategy and coalition building he said is needed to reduce greenhouse gas emissions.
Wyden said Republicans can be brought into a climate change coalition because many of them “have skin in the game on renewable technologies.” He named Sens. Jodi Ernst (Iowa), Martha McSally (Ariz.), John Cornyn (Texas), Cory Gardner (Colo.), Thom Tillis (N.C.) and Susan Collins (Maine).
“I can make the list go on and on,” he said. “Why do I single out those folks? Because they come from places where the wind blows, where the sun shines [and] where they make batteries for energy storage.”
Wyden said renewable vendors and investors need to be in regular contact with their members of Congress to make them aware of the clean energy workers in their constituencies.
“They have to hear from you all the time. … Only those kinds of direct contacts [will] really change people’s mind to the point where they’ll show up and vote … for a package rather than give you a speech.”
Senate Majority Leader “Mitch McConnell [R-Ky.] hears a whole lot more from the oil and gas lobby than he’s hearing from our network as it exists today. If senators go home and they are met by a coalition of 50 businesspeople who say, ‘I want these renewable provisions on storage or wind or wave or solar,’ they come back to Washington. And they say to Mitch McConnell: ‘I gotta have this. I was stunned, Mitch, to see all this support at home for it. I have to have it.’ And then Mitch McConnell finds a vehicle for doing it.”
Aruna Kalyanam, staff director of the House Ways and Means Committee’s Subcommittee on Select Revenue Measures, agreed. “The members of the United States Senate are so entirely parochial. They don’t have to give a damn about the overall issue, so long as they care about the people that are employed that work in that issue,” she said. Senators may not want to speak out on climate, she said. “But my God, are they there to defend the linear generator manufacturers in their state.”
Rep. Paul Tonko (D-N.Y.) said prospects for climate legislation have improved in the 10 years since the failure of the Waxman-Markey cap-and-trade bill, because of falling renewable prices, an improved economy and increasing evidence of climate change.
“I think the big factor is the general public. They now see climate change from a different lens. It’s no longer about protecting the polar bears … no longer just about coastal erosion. It’s about backyard situations. Just this week: the tragedy of a tornado in Nashville, Tenn.; the wildfires in the Southwest; the record rising of the Mississippi; the flooding in Nebraska. It is a backyard issue.”
Jobs and Wages
Neera Tanden, CEO of the Center for American Progress (CAP), said, “The issue around climate is much more salient than ever, not just with Democratic voters, but really with independent voters and in important states like Florida.
“All the remaining candidates on the Democratic side have bolder proposals around climate than any previous nominees or candidates on the Democratic side. And I think the really critical issue going forward in the climate space is going to be around how to make climate a win-win on the economy,” she continued. “We see around the world that when climate has become an issue, conservatives have often [described] it as a job-killer idea that will actually hurt economic growth. … And we expect to see that in the general election, no matter who the Democratic nominee is.”
Tanden said the renewable industry should not be so focused on costs that it fails to deliver on promises of “high-wage, high-benefit jobs that are often, or could be, unionized.”
“I appreciate the difficulty because we’re all in a place where we’re trying to make the cost as cheap as possible. But in a political environment, when jobs that are being lost, to have high-benefits jobs [is essential]. These issues are going to get demagogued unless the jobs that replace them are higher-wage jobs. … To get a large-scale investment, or even think of a mandate, the way to do that isn’t through the climate sphere. It’s obviously through the jobs sphere.”
Tom Kiernan, CEO of the American Wind Energy Association (AWEA), concurred.
“I don’t think politically we will move major carbon or climate legislation without the labor community being — not just OK — but enthusiastic and part of the solution,” he said. “Communities of color need to see themselves in this effort. So … don’t think we’re just going up there and let’s get a $40/ton on carbon and we’re done. … We’ve got to come together there — and that may be new for the industry.”
Ken Kimmell, president of the Union of Concerned Scientists, said labor and minority communities are “open minded” but skeptical of climate policy.
“Organized labor is not yet seeing those high-wage jobs coming. They know there’s some anecdotal evidence of it, but they’re not yet seeing it,” Kimmell said. “And the environmental justice community is just starting to see that it’s possible to have climate policy and policies that simultaneously lower local sources of pollution. So, they’re open to it, but they need to be shown that it’s real.”
Abigail Ross Hopper, CEO of the Solar Energy Industries Association (SEIA), said her organization conducted polling about a year ago to find the message that was most likely to increase support for solar power.
“Is it that we’re competing against another country? Is it that we’re innovative? Is it that we’re low price? Is it that it’s [reducing] carbon?” she asked. “The message that had the most resonance amongst voters was the clean air message, which makes sense when I saw [it], but it’s certainly not what we lead with.”
Kiernan said Republican senators have recently become more receptive to discussing climate issues. “One of them brought up the [importance of] getting the [agricultural] community on board and in sync with us. Yes, they’re well aware of the weather extremes. But if a carbon regime — whether it’s a carbon fee or carbon sequestration — [if] farmers could perhaps get credit for their role in carbon sequestration, [it could] make a big difference.
“The wind industry does that often vis-a-vis wind farms and in the land lease payments,” he continued. “But if we can think [of] a broader regime, that may be a significant tipping point for a fair number of Republican senators.”
Kiernan said the renewable industry also must increase its presence in RTO stakeholder processes, noting that AWEA and SEIA agreed about a year ago to join forces on that front. “We need to redesign a market. That is mostly accomplished at RTOs. And the stakeholders there are not appropriately representative of the future of the grid. We’ve got to be there,” he said.
Carbon Fee? Clean Energy Standard? Cap and Trade?
In addition to plotting strategy, speakers at the daylong forum also discussed individual legislative proposals.
Tonko said he is pursuing a “two-track” approach of preparing major climate legislation that could be passed under a Democratic Congress and administration, while supporting more modest bills in the current term. Tonko said he is encouraged by the bipartisan American Energy Innovation Act (S. 2657), which he said includes important measures on research and development, energy efficiency, workforce development and energy storage. (See Murkowski, Manchin Offer Bipartisan Energy Bill.)
In January, Tonko and other Democrats on the Energy and Commerce Committee released the discussion draft of the Clean Future Act, which seeks to get the economy to net-zero greenhouse gas emissions by 2050. Tomko said a “full comprehensive climate bill … needs to be part energy bill, part infrastructure bill, part environmental protection statute and part workforce development program.” (See Draft Climate Bill Would Make RTO Membership Mandatory.)
Sen. Wyden is hoping to see extensions of clean energy tax incentives in the current Congress. If Democrats take the Senate and he is chair of the Finance Committee in 2021, he said, he will seek to eliminate 45 current energy tax breaks and replace them with three: one each for clean energy, clean transportation fuel and energy efficiency.
The pros and cons of a carbon fee were discussed at a conference earlier last week sponsored by the New York University School of Law Institute for Policy Integrity and Duke University’s Nicholas Institute for Environmental Policy Solutions. (See related story, Carbon Pricing Gains Popularity —and Doubts.)
Kiernan said AWEA supports the “broad brushes” of the Climate Leadership Council’s carbon dividends plan, which claims it will cut U.S. CO2 emissions in half by 2035 with a gradually rising carbon fee, and rebates of $2,000 a year for a family of four.
But, he added, AWEA could support several approaches. “We’ve not ruled out cap and trade or a CES [clean energy standard].
“There are a number of Republicans — unfortunately, more behind closed doors — that are talking about the fee-and-dividend approach and are open to it, if not enthusiastic about it,” Kiernan continued. “They’re not public about it. Obviously, the fee or, quote, ‘tax’ is a challenge politically. But I’ve also talked to some leading Republicans in the Senate that are seeing the opening to potentially moving some type of fee and dividend or at least having a serious discussion about it post-election.”
CAP’s Tanden said beginning with a low carbon fee may be the key to winning congressional approval.
“We all acknowledge that the science requires a relatively large and impactful carbon tax. One way to think about the next 30 years is to have a low carbon tax enacted, which … shows it does not have the dire impact [feared], and they can ratchet up based on targets. … If we’re not meeting targets, it will automatically increase over time so that you are automatically having the impact that you need to have. That’s just one thing to think about because the most important thing is to actually get the carbon tax in law at a time where it’s still going to be heavily demagogued as a middle class tax increase no matter how we structure it.”
Pete Wyckoff, energy and environment policy adviser to Sen. Tina Smith (D-Minn.), touted the Clean Energy Standard Act of 2019, introduced by Smith and Rep. Ben Ray Luján (D-N.M.) last May, which would require electric retailers to sell increasing percentages of carbon-free energy (51% of retail sales in 2021, 77% in 2035 and 96% in 2050).
Resources for the Future said its modeling of the bill indicates that by 2035, it would reduce greenhouse gas emissions by 61%, prevent the retirement of 43 GW of nuclear capacity and increase renewable generation from 30% to 56% of total generation.
Wyckoff said Smith and Luján have had “fruitful” talks with Republicans, although they have no GOP cosponsors yet. “But we have built a coalition,” he said, citing endorsements by Utility Workers Union of America, the United Steelworkers, Xcel Energy, Exelon, UCS, the Clean Air Task Force and former Energy Secretary Ernest Moniz.
Wyckoff said Smith is backing the bill in part because similar bills have received Republican backing. “Our bill is also something she’s interested in because it’s what the states are doing. … No one is passing carbon taxes. But a clean energy standard, if well designed, can give you a lot of the same market benefits of a carbon tax and is much more politically palatable.”
NextEra Energy subsidiaries last week appealed a federal court ruling that upheld a Texas law giving incumbent transmission companies the right of first refusal to build new power lines.
The companies asked for expedited treatment to prevent “irreparable harm.”
NextEra Energy Capital Holdings and four other NextEra transmission owner/developer entities took their case to the 5th U.S. Circuit Court of Appeals in New Orleans (20-50160) after the U.S. District Court for the Western District of Texas last month refused to overturn Texas Senate Bill 1938. (See District Court Dismisses Texas ROFR Repeal.)
The law essentially allows only incumbent transmission companies to build new power lines in Texas by granting regulatory certificates of convenience and necessity to the owners of the endpoints of a new transmission line.
The NextEra units said the Feb. 26 ruling means NextEra Energy Transmission (NEET) Midwest could lose its “lawfully won right” to build the $115 million Hartburg-Sabine transmission project in MISO’s East Texas footprint. NEET Midwest won the project’s rights in 2018 through a competitive bidding process. (See NextEra Wins Bid to Build MISO’s 2nd Competitive Project.)
The 5th U.S. Circuit Court of Appeals grounds in New Orleans | 5th U.S. Circuit Court of Appeals
“Accordingly, without expedited decision on the merits from this court, NextEra will be imminently and irreversibly deprived of its lawfully won right to build and operate a major transmission project,” NextEra said in its appeal.
NextEra’s filing on Friday said the company recently learned that MISO is using its established variance analysis process to study the project and developments around it. The RTO uses the analysis to study projects already approved under its Transmission Expansion Plan that are later disrupted by circumstances that affect the project’s cost, schedule or “the ability of selected developers and transmission owners to complete.”
NextEra said MISO indicated it anticipates a decision reassigning or canceling the project by March 31. MISO would then seek FERC approval of the change, with the commission ruling by June, NextEra said.
MISO told RTO Insider that it continues to plan for the project but wouldn’t say under which developer it will proceed. Should the project revert to the incumbent, it would become Entergy’s responsibility.
Spokesperson Allison Bermudez said in an email that MISO is aware of the recent court action, but confidentiality restrictions limit its ability to talk publicly about the project. Bermudez said MISO will make a further statement once the RTO completes the variance analysis.
NextEra did not respond to a request for comment.
The legislation also affects NEET Southwest’s application with the Public Utility Commission of Texas to transfer ownership of 30 miles of 138-kV facilities from Rayburn Country Electric Cooperative in SPP’s region of East Texas.
NextEra said SB 1938 violates the U.S. Constitution’s dormant Commerce Clause because it allows only the incumbent Texas owners of the end points to build, own and operate new lines. Should the incumbent decline to build the line, it can assign the right only to another Texas entity, NextEra said.
“In effect, Texas has closed its borders to new out-of-state companies from doing this type of business in the state,” NextEra said.
The company also asserted that the law violates the Constitution’s Contracts Clause “because it abridges the ‘existing contractual relationship’” for the Hartburg-Sabine project. It cited the Department of Justice’s “statement of interest” filed last year in NextEra’s appeal of SB 1938 that said the law placed Texas’ deregulated retail electric market “at risk.” (See DOJ Weighs in on Texas ROFR Lawsuit.)
The NextEra companies on March 2 also filed an injunction with the district court asking that its proposed transmission projects be shielded from the new law while they appeal to the 5th Circuit.
“In opposing the preliminary injunction, Texas identified only an amorphous threat to its sovereignty that might result from an injunction,” NextEra said. “An injunction pending appeal will temporarily prevent the imminent, irreversible loss of a $100 million-plus project for NextEra while the 5th Circuit considers the substantial constitutional issues presented here.”
ISO-NE and New England Power Pool stakeholders are collaborating to study market and reliability issues the region will face as it seeks to decarbonize power, transportation and heating over the next three decades.
NEPOOL members discussed the outlines of the study — which was prompted by requests last year from the New England States Committee on Electricity (NESCOE), New England Power Generators Association (NEPGA) and other stakeholders — at the Participants Committee meeting Thursday.
“People are generally very supportive of doing a study,” ISO-NE CEO Gordon van Welie said Friday at a news briefing on the RTO’s 2020 Regional Electricity Outlook, which noted states’ “goals to achieve up to 100% renewable resources” and asked “How do we get there from here?”
“I think the general consensus in the room … is it’s a good thing to go off and study the future power system because that’s going to give us a lot of information to then inform the other discussions that people want to have, which is the market design conversation, and ultimately transmission,” added van Welie, who said electrification will transition the region from a summer- to a winter-peaking electric system.
“There was less clarity around what the scope and objective of the study should be. The discussion yesterday was mostly about process and not scope. And that conversation [about scope] will be coming in due course in the next month or two.”
Projected changes in New England power resources and energy efficiency | ISO-NE 2020 Regional Electricity Outlook
The PC meeting materials included a graphic depicting the study as four bubbles: the objective (assessing the power system needed to meet state energy and environmental policies); study process (identify the resource mix and operational and reliability needs); a gap analysis (to determine whether the current markets plus ESI provide resources and ISO-NE what they need to continue reliable operations); and a discussion of potential market approaches to address any gaps.
Van Welie said that the study’s time frame will be the subject of future stakeholder discussions, but that he expects it to be longer than the next 10 years, when he said electric demand from decarbonization of transportation and heating is projected to increase only slightly.
“When I look at that and the long-term decarbonization goals in the region, I think there will be a hockey stick [rise in demand]. We’re going to have to accelerate — dramatically accelerate — decarbonization of the other sectors, so there will be a steep growth in electric demand over that period,” he said. “It’s important, if we’re going to study the future, that we study that hockey stick because there’s nothing really interesting to study in the next 10 years. The demand’s pretty flat.”
A Brattle Group study released in September predicted that meeting the states’ goals for reducing greenhouse gas emissions by 80% by 2050 will result in a doubling of electricity demand, even with substantial energy efficiency gains.
“I don’t know that we should lock onto specific numbers and multiples at this time,” van Welie said. More important, he said, is how the system will add renewable capacity: through the markets that have served the region for the last two decades, or through long-term power purchase agreements, which would put investment risk back on consumers.
ISO-NE sought to develop a market-based path for renewables to supplant carbon-emitting resources through the substitution auction in the Competitive Auctions for Sponsored Policy Resources (CASPR) program, which allows resources nearing retirement to trade their capacity supply obligations with new state-sponsored resources that did not clear in the primary auction.
The RTO has held two auctions under CASPR. Vineyard Wind, a planned 800-MW offshore wind farm, took over a 54-MW obligation from a retiring resource in Forward Capacity Auction 13 last year. There were no trades this year in FCA 14.
“As we said when we filed CASPR, it’s intended to work over time,” said Anne George, the RTO’s vice president of external affairs and corporate communications. “We still feel like with only two auctions of experience, we need a little more time to see how CASPR works.”
“I think it’s going to take time for those economic pressures to build up” to persuade incumbent generators to retire, van Welie added. “So, we have been very clear about this: We think carbon pricing is a much better solution … which is why you hear us advocating for it.” (See ISO-NE: States Must Lead on Carbon Pricing.)
State renewable portfolio standards in New England | ISO-NE 2020 Regional Electricity Outlook
At a conference in D.C. last week, speakers expressed some doubts about carbon pricing, saying it won’t solve the climate crisis by itself or persuade states to abandon their own clean energy policies. (See related story, Carbon Pricing Gains Popularity — and Doubts.)
“I think it’s going to take time for people to get comfortable with [carbon pricing]. It may take a long time for us to get comfortable with it,” van Welie acknowledged. “Developers are going to be very cautious about trusting the regulatory system around carbon pricing until they see that it’s stable and has longevity.”
The Regional Greenhouse Gas Initiative, which includes all six New England states, “never produced a material carbon price in terms of driving the clean energy transition,” van Welie said. RGGI’s most recent auction in December cleared at only $5.61/ton.
Van Welie contrasted RGGI with Europe, where carbon emissions were trading last week at about 25 Euros/ton ($28), high enough that Royal Dutch Shell, BP and others are willing to build offshore wind on their own balance sheets without long-term PPAs, he said.
Transmission RFP
On an unrelated issue, van Welie said the RTO was “very pleased” with the response to its first-ever competitive transmission solicitation, which resulted in 36 project proposals by the March 4 deadline. (See ISO-NE Issues First Competitive Tx RFP.)
ISO-NE issued the solicitation in December to prepare the transmission system in the Boston area for the retirement of the Mystic Generating Station in Everett, Mass. The proposals will seek to address transmission facility overloads under peak load conditions, as well as system restoration concerns with the underground cable system. ISO-NE hopes to select the finalists for the work by the end of the year.
“We’ve got a lot of work ahead of us,” said van Welie, adding that the RTO will be releasing more details on the responses shortly.
New Member
In addition to its discussion on the futures study, the PC voted Thursday to admit trade group Advanced Energy Economy as a NEPOOL member. AEE, whose members provide energy efficiency, demand response, energy storage and natural gas, renewable and nuclear generation, was admitted as a Fuels Industry Participant.
Operating, Planning Procedure Revisions Approved
Members also approved revisions to the following operating and planning procedures:
OP-18 (Metering and Telemetering Criteria): adds a requirement to telemeter station frequency; identifies equipment requirements; specifies which requirements apply to existing and new equipment; and revises Section I (Purpose) to reflect current practice.
OP-23, Appendix I (Resource Auditing): clarifies the asset ID entry for certain reactive resources without an RTO-assigned asset ID.
OP-3 (Transmission Outage Scheduling): extends the maximum duration for an “opportunity outage” from 96 hours to 108 hours. An opportunity outage is one that fails to satisfy the minimum advance notice time required for planned short-term transmission outage processing and is submitted for RTO approval as a result of an unexpected opportunity to accomplish work that would otherwise require another outage at a less opportune time.
PP-3 (Reliability Standards for the New England Area Pool Transmission Facilities): replaces the term “governance participant” with the terms “market participant” and/or “transmission owner.”
The Upper Midwest needs more transmission, more technology and preservation of some dispatchable generation for the sake of reliability, the CapX2050 study concluded last week.
The 10 Minnesota utilities behind the effort drew three major takeaways from the study:
More transmission infrastructure will be necessary in the Upper Midwest to accommodate resource transition.
Non-dispatchable resources alone can’t meet all energy requirements, so some traditional power plants will still be necessary.
Real-time operational demands will become trickier to manage and will require new procedures.
Building on the CapX2020 transmission effort focused on 2020 reliability needs, the CapX2050 study addresses how the grid can handle widescale reductions in carbon emissions by 2050. (See Minnesota Utilities Reunite for CapX2050 Study.) Like the 2020 effort, the 2050 study concentrated on the transmission system that serves Minnesota, eastern South Dakota and North Dakota, western Wisconsin and the surrounding areas.
The study’s report said grid support in the form of ancillary services will be needed in areas where large, dispatchable generation is retired. New transmission technology and storage resources will be required to deliver ancillary services.
The Brookings County-to-Hampton project, part of CapX2020 | CapX2020
“The variability of the output of non-dispatchable resources, even within a single day, could lead to several thousands of [megawatts] being transferred across the transmission system, with reversals in direction of flow occurring in an equal but opposite magnitude during the same day,” the report warned. “Operating techniques, transmission infrastructure and analysis tools will need to become more sophisticated to more accurately identify and adjust in real-time to deal with these changes.”
The utilities said that simply adding more non-dispatchable resources cannot solve the problem of sometimes deficient energy supply.
“Abrupt changes in weather, including prolonged extreme weather conditions, sudden changes in consumer demand, or disturbances on the transmission system (i.e., outages) will increasingly challenge the ability of the electric grid to provide a continuous supply of energy as more non-dispatchable resources are added,” the report said. It added that maintaining some dispatchable resources and adding energy storage can keep the transmission system reliable.
In what should be déjà vu for MISO planners, the CapX2050 report also called for a “long-term comprehensive regional transmission plan.” The Organization of MISO States has been pressing the RTO for two years to develop a long-term transmission package to accommodate growth of policy-driven generation resources. (See MISO Cracks Door on Long-term Tx Planning.) The report reminded MISO that “transmission expansion has been shown to be cost-effective when considered as part of a larger market.”
At this point, the CapX2050 utilities aren’t calling for any specific transmission projects. CapX2020 culminated in an 800-mile, grid expansion in the Upper Midwest, including four 345-kV transmission lines in Minnesota, North Dakota, South Dakota and Wisconsin and a 230-kV line in northern Minnesota.
Great River Energy spokesperson Jenny Mattson said that while future studies under CapX2050 aren’t being ruled out, none are planned so far.
“Though there is no time frame for additional studies, we’ll continue to evaluate the system in partnership with other utilities and stakeholders, including legislators, regulators, communities and MISO,” Mattson said in an email to RTO Insider.
The utilities also said they’re “ready to engage with public and stakeholders” on planning for new transmission.
CARMEL, Ind. — MISO expects to have enough reserves on hand throughout spring to meet expected demand.
The RTO predicts spring energy usage will peak at 100 GW in May, with about 134 GW of total projected capacity available to meet load. MISO’s spring peak record of 107 GW occurred May 29, 2018.
“The 2020 spring is projected to be a very typical spring,” Senior Manager of Resource Adequacy Coordination Lynn Hecker told the Market Subcommittee on Thursday.
The National Oceanic and Atmospheric Administration forecasts above-normal spring temperatures for areas within MISO South, with the rest of the footprint at normal levels.
As with most of MISO’s preseason assessments, Hecker said high load coupled with high generation outages could have the RTO calling up load-modifying resources and operating reserves.
Spring load and capacity projections | MISO
Following its usual practice, MISO is preparing for higher generation outages on peak during spring. Potential reliability risks are most pronounced in April — when outages can historically near 45 GW — even though load is roughly 10 to 16 GW lower than in March or May.
“We are expecting to maybe dip into load-modifying resources in the 90/10 forecast,” Hecker said. That forecast represents a scenario in which there is a 90% chance of actual load being lower than predicted and a 10% chance of load being higher.
In the most likely 50/50 load scenario with a normal capacity supply, MISO won’t have to call on reserves in either March, April or May. However, if load is unusually high, the RTO runs the risk of entering emergency operating procedures.
The spring supply picture gets more dire if high-load scenarios pair with higher-than-expected generation outages, especially in April, a favorite month for scheduled maintenance. MISO said that April contains the only risk of the RTO burning through all of its operating reserves and LMRs and still coming up about half a gigawatt short.
ATLANTA — NERC’s new Reliability and Security Technical Committee (RSTC) held its first meeting Wednesday with a focus on introducing the body’s membership and laying the groundwork for beginning operations in June.
NERC’s Board of Trustees approved the creation of the RSTC last year, merging the Planning, Operating and Critical Infrastructure Protection committees, which have more than 120 members combined. (See NERC Board of Trustees Briefs: Feb. 6, 2020.)
For the initial meeting, RSTC Chair Greg Ford of Georgia System Operations and Vice Chair David Zwergel of MISO left most of the committee’s ostensible business to the three retiring committees, which concluded their final full meetings the same day (though they will meet briefly in June to finish handing over their work to the RSTC). Instead, the gathering featured briefings from the heads of the old committees on their existing structures and their ongoing work, followed by a discussion on how to consolidate their functions in the new organization.
Answering a question posed by numerous participants at previous meetings, Ford and Zwergel confirmed that the retiring committees’ existing subgroups will continue their ongoing projects with their current membership in the short term, reporting to the RSTC. Over the longer term, the leaders shared their initial broad thoughts on how the committee’s project pipeline might work, with projects organized into three main workstreams — technical services and modeling, assessments and analysis, and security. However, they emphasized that final arrangements have not been worked out and that input from members and industry will shape the process going forward.
Members Step Forward
Committee members suggested a number of ideas, such as assigning an RSTC liaison for each subcommittee that would be responsible for communicating between it and the larger body. Another significant concern raised was the logistical challenges of shrinking down the existing structure. Brian Evans-Mongeon of Utility Services Inc., the outgoing CIPC chair and at-large member of the RSTC, suggested that the new committee consider extending its meetings to accommodate the workload — for instance, by adding a two-hour introductory session like the joint sessions currently held by the OC, PC and CIPC.
“Given the fact that we’re trying to fit the agenda of three groups into an eight-hour span, it seems to me that kind of pre-session could [still be] of value,” Evans-Mongeon said.
“A pre-session is always an option,” Ford agreed, adding that the executive committee will also consider holding online informational meetings each quarter prior to the full meeting, similar to NERC’s Member Representatives Committee. NERC Chief Engineer Mark Lauby said that this can also be a solution for those members whose organizations’ travel policies might not permit them to attend longer meetings.
Members of NERC leadership attending the meeting encouraged the new committee to build on the work of its predecessors, while looking for any areas for further streamlining.
“As I attended the meetings yesterday and this morning, it was a little melancholy, to a degree, to listen to the closing statements from the chairs of the OC, PC and CIPC,” board Vice Chair Kenneth DeFontes said. “But at the same time, I come into this room with a great deal of optimism. And as I sat through the meetings, I saw evidence … that suggested to me the concept … should be very successful, because we’re going to be able to accomplish the same work, but hopefully do it more efficiently and more effectively.”
CARMEL, Ind. — A new report from MISO concludes that stakeholders will need to quickly adjust the RTO’s capacity construct and offer new market products to accommodate a resource mix in which renewables represent a majority.
The second annual Forward Report was framed from the perspective of MISO’s rapidly evolving utilities and what they will need from a grid operator in the near future. The report includes five hypothetical utility profiles based on integrated resource plans, interviews with stakeholders and investor presentations. MISO used the profiles to conclude it needs to change its capacity auction and resource accreditation, while developing new market products to incentivize a flexible supply.
“Utilities need MISO to act now to develop transitional and transformational solutions,” CEO John Bear wrote in the report’s introduction. “As customers continue to push for decarbonization goals, utilities are adopting significantly more diverse business models. Supply and demand of availability, flexibility and visibility will vary by utility. MISO’s ecosystem for exchange must accommodate this significantly increased degree of diversity and facilitate members to leverage that value.”
Bear said MISO utilities must “redefine what is needed” to manage risk on the grid.
MISO’s actual 2018 resource mix, and a projected 2030 mix based solely on utilities’ announced plans | MISO
“We have an imperative to act quickly,” MISO Executive Vice President of Market and Grid Strategy Richard Doying told the Resource Adequacy Subcommittee on Wednesday. He added that the Organization of MISO States and state regulators have said their utilities are weighing millions of dollars in investments and are wondering if the MISO market can accommodate their new resource portfolios.
Doying pointed to MISO’s 77-GW interconnection queue, now dominated by nearly 46 GW in solar generation projects.
“Not a lot of traditional resources; they’re new resources with operational characteristics that we aren’t used to,” Doying said of the queue makeup.
MISO predicts that by 2030 its generation mix will contain 32% renewables, 28% natural gas, 27% coal and 9% nuclear. In 2018, MISO’s generation mix was fueled by 47% coal, 27% natural gas, 15% nuclear and 8% renewables. Doying said the 2030 mix isn’t a MISO forecast but based on utilities’ announced plans.
“This is what all of your companies have said they’re doing. … This is not based on a bunch of assumptions,” he told stakeholders.
Sunset on the Planning Horizon
MISO said its footprint will soon contain “very diverse utilities that will rely on each other as neighbors in a shared resource pool in new ways.”
Customized Energy Solutions’ Ted Kuhn asked what role MISO sees itself playing: planner, or facilitator to the rapid change.
Doying said MISO will concentrate more on making sure it gathers more detailed and accurate information to share with its members making investment decisions.
The new report reiterated MISO’s now familiar prediction that its annual loss of load expectation process for estimating reliability needs will eventually be broken down by season to assess risks in all hours of the planning year.
“We count megawatts based on one thing: peak load. … If we only count megawatts based on the requirement we established, does that account for all reliability risks?” Doying asked rhetorically, referring to MISO’s current process of establishing accreditation and reserve margin requirements to serve load on the hottest summer day.
“I think a simple, summer-based loss-of-load expectation study doesn’t account for all risks. … It does a very good job, but it’s incomplete,” Doying said. “Is annual the right time frame to conduct that assessment, or should it be done seasonally?”
Doying said MISO is advancing on developing some sort of “sub-annual component” for its Planning Resource Auction. The RTO last year said a seasonal capacity auction would be beneficial though some stakeholders have pushed back on the idea. (See MISO Gives Tentative Nod to Seasonal Capacity Design.)
Kuhn said he was worried MISO was focusing too much on seasonal or monthly divisions of the planning horizon when an influx of solar generation will require an hourly analysis of risk.
“You can break the horizon down as much as you like; the sun doesn’t shine at night,” Kuhn said.
Doying also said MISO may create new market products that reward flexibility.
“We don’t have a proposal, but we do know that’s been done in other regions,” Doying said. “There are a lot of ramping needs when you get a lot of wind and solar on the system.”
He said MISO will re-evaluate its scarcity and emergency pricing in the coming months. Both items appear on the RTO’s Integrated Roadmap list of market improvements to undertake in 2020. MISO staff have said emergency pricing has generally been inefficiently low.
ERCOT’s first assessment of the summer season foresees a repeat of 2019 — record electric usage and tight reserves — but with additional capacity to help meet demand.
The Texas grid operator’s seasonal assessment of resource adequacy (SARA) projects a peak demand of 76.7 GW, almost 2 GW over the current record of 74.8 GW set last August. However, ERCOT expects to have 82.4 GW of total resource capacity on hand, a 3.5-GW increase over last summer’s available capacity.
“We continue to expect the region to have adequate reserves to cover a range of system conditions,” Warren Lasher, ERCOT’s senior director of system planning, said during a media call Thursday.
ERCOT said that, as in 2019, conditions could warrant the need to declare an energy emergency, but it noted that it and its market participants are taking steps to ensure system reliability can be maintained during tight conditions.
ERCOT has added 513 MW of capacity for the summer. | ERCOT
It has added 513 MW of additional capacity since December alone, including 348 MW of wind capacity. Solar energy accounts for 77 MW of capacity, and an 88-MW gas plant provides the only new addition of fossil generation.
Pointing to the vast amount of renewable energy in ERCOT’s generator interconnection queue (104.6 GW), John Hall, director of regulatory and legislative affairs for the Environmental Defense Fund, said renewable energy plays a critical role in “ensuring Texans have the power they need during the hot summer months ahead.”
“Texas’ competitive electricity market continues to lead the nation in providing clean, affordable and reliable power,” he said in a statement.
ERCOT also on Tuesday released its final SARA report for the spring season (March-May). The grid operator expects sufficient generation to meet a spring peak of 64.2 GW.
It will release the final summer SARA report and a revised Capacity, Demand and Reserves report in early May.
