ST. PAUL, Minn. — A special task team is suggesting that MISO revise its Board of Directors selection rules to give stakeholders a more consequential voice in board makeup.
The Board Qualification Task Team (BQTT), composed of MISO stakeholders, last week released a draft of recommendations, including that the RTO double the number of stakeholder representatives on the Nominating Committee that selects board candidates and rotate the sectors from which committee participants are drawn. (See Task Team Zeroes in on MISO Board Recommendations.)
The recommendation would establish four stakeholder seats on the Nominating Committee, outnumbering the three seats reserved for MISO directors. The BQTT also raised the possibility of reserving one of the stakeholder seats for a representative of the Organization of MISO States.
Task team lead David Bloom, of the Power Marketers and Brokers sector, put the recommendations before Advisory Committee members at their meeting Wednesday. The list is still open to suggestions from the committee, which also extended the life of the BQTT through the end of the year to allow it to tweak the recommendations. The AC will vote individually on them at either its Oct. 23 or Dec. 11 meeting.
Also on the list is a recommendation to require state and federal regulators to observe a yearlong “cooling-off” period before becoming eligible for nomination to the board, a policy that currently applies only to those coming out of the industry. However, the change wasn’t labeled a must-have, as the task team also said it would accept if AC members ultimately don’t see a need to extend the moratorium to regulators.
MISO originally required board members with financial ties to the RTO footprint to observe two-year pre- and post-service restrictions, but it reduced those requirements to a one-year pre-service restriction in 2016.
Finally, the task team also presented options for MISO to either designate one of the nine director seats for those with experience representing utility customer interests or create a new process where RTO sectors could describe what qualifications they’re seeking in new board members. The Nominating Committee selects board member candidates in closed deliberations, assisted by management firm Russell Reynolds.
Reaction to the recommendations was mixed, with some AC members asking why the BQTT preferred a stakeholder majority on the Nominating Committee and others asking why all MISO sectors couldn’t be represented on the Nominating Committee at the same time.
Environmental and Other Stakeholder Groups representative Beth Soholt wondered if MISO’s cooling-off period unnecessarily limits the slate of board candidates. In meetings, the BQTT had mulled eliminating the period altogether.
“We note that [former FERC Commissioner Cheryl] LaFleur was appointed to the ISO-NE board without any cooling-off period. In fact, she’s probably red hot,” Soholt joked. (See LaFleur Elected to ISO-NE Board.)
ST. PAUL, Minn. — MISO stakeholders last week signaled that they’re not yet ready to embrace creating an 11th sector in the RTO’s Advisory Committee to accommodate hard-to-pin-down members.
But discussion on the matter will continue as MISO fields a growing number of membership applications from entities that don’t have goals that clearly align with any of the RTO’s 10 existing sectors — the “others” current housed within the increasingly crowded Environmental and Other Stakeholder Groups sector.
By the end of the AC meeting Wednesday, MISO’s Power Marketers and Brokers sector had offered to absorb the “others” into its fold for a yearlong trial period.
Committee Chair Audrey Penner said MISO could use the time as a period of “discovery” to determine the need for a new sector. “This will be an exploratory year, and I’m very interested in who will line up to join our dysfunctional group,” she joked.
The committee last month considered creating a miscellaneous, 11th sector in order to give its Environmental sector a more singular voice. The committee was weighing whether to spin off the “other” contingent from the sector in response to member requests that entities with miscellaneous interests be separated from those with an environmental focus. (See Advisory Committee Considers 11th MISO Sector.)
The move came with many possible AC voting implications, chief among them how to mete out the Environmental sector’s existing two votes. AC leaders proposed several options, including splitting them; allowing the Environmental sector to retain its votes without giving the new sector a vote; or upping the number of committee votes to allow the new sector to participate in voting.
But a poll released last month revealed a majority of sectors preferred no change at all.
Eligible End-User Customers sector representative DeWayne Todd said he wasn’t convinced about the need for a new sector. He cautioned that, because any undefined entity could join, establishing a unified opinion for AC voting matters could prove “cumbersome.”
“We didn’t see a compelling reason to make a change at this point. We created the [Competitive Transmission Developer] sector when there was a need,” Todd said. The Environmental/Other sector housed some competitive transmission developers briefly before the creation of the CTD sector in 2014. The Sustainable FERC Project’s John Moore recalled conversations within the sector during that time as being stifled.
The Independent Power Producers and Exempt Wholesale Generators sector’s Adam Sokolski said he would have appreciated more conversation on exactly what entities would join a catch-all sector.
As a rule, MISO does not reveal the names of companies that approach it for membership until public approval by the Board of Directors. All members must belong to one of the 10 sectors.
However, it’s no secret that multiple “miscellaneous” companies are clamoring for membership.
“We know that there are companies that are approaching MISO that don’t have a home. What that number is, we don’t know,” Penner said. She reminded the sectors that it’s incumbent upon the stakeholder community to be as inclusive as possible. She also said removing hurdles to membership can further FERC’s goal of RTO transparency.
“I’m going to recharacterize this as an opportunity, not a problem, because more around the table is a good thing as far as I’m concerned,” Penner said. “We need a home for entities to join MISO, but it’s clear the Environmental sector is not a good fit.”
The Environmental sector itself voted to drop the “Other Stakeholder Groups” descriptor, retain its two votes and take no action to create a new sector.
“We would hope there would be a way to give someone a voice without creating a new sector,” Clean Grid Alliance’s Beth Soholt said.
David Bloom of the Power Marketers sector offered to draw up a plan to for “others” to join his sector in time for the committee’s Oct. 23 meeting. He said the switch is dependent on existing members’ agreement.
Director Barbara Krumsiek predicted there will be many more “others” in MISO’s future as the RTO’s energy landscape “remains so fluid.”
ST. PAUL, Minn. — The rate of MISO’s grid transformation is at once distressingly slow and unbelievably quick, RTO members said last week in a session directed at guiding future market decisions.
And no one yet knows how high prices could go when renewables have the lion’s share of the market.
Stakeholders selected a rather broad topic for MISO’s quarterly “Hot Topic” discussion, choosing to focus on the pace of change and new directions in the markets and grid strategy during an Advisory Committee meeting Wednesday.
“This isn’t Festivus. This isn’t the airing of grievances,” moderator Kevin Gunn, an energy attorney and former chairman of the Missouri Public Service Commission, joked as he opened the discussion.
Gunn instead urged the committee to advise MISO on big-picture ways it could transform markets.
John Moore, representing the Environmental and Other Stakeholder Groups sector, called for “more active” cooperation between MISO and its participating states, saying that while the RTO appears ready to roll out more market services and products to meet demand, resource adequacy is ultimately the proprietary role of states.
“When you have high levels of renewable energy on the grid, you’re going to want to make sure you can meet the need, and folks on the distribution side of the grid will play a big role in meeting that need,” Moore said.
Arkansas Public Service Commission attorney Christina Baker reminded MISO and members that public service commissions have jurisdiction over utilities but not the data collection companies that could provide visibility into distributed resource participation.
“It’s a wider range sitting at the table than has been before,” she said.
Municipals, Cooperatives, and Transmission Dependent Utilities sector representative Chris Norton agreed that it was going to take much more communication between MISO and distribution facilities to manage supply.
The Independent Power Producers and Exempt Wholesale Generators’ Travis Stewart pointed to the poor financial outlook for merchant suppliers in MISO. He said the harsh winter in the northern footprint reinforced the need for suppliers outside the usual regulated utilities.
“Consumers really needed those electrons on the system to maintain their quality of life and safety,” Stewart said.
“One of the themes … is how fast this needs to happen,” MISO Director Nancy Lange observed, asking for members’ opinions on the necessary rate of market change.
“We need the price signals that will encourage us to build. And we’d like to see those sooner rather than later, because we’re on a 15-year planning horizon for storage builds,” Advisory Committee Chair Audrey Penner said.
Multiple members said the resource mix is changing much faster than MISO’s current transmission planning can accommodate. The IPPs’ Adam Sokolski said more transmission development is needed now.
“Markets, pricing can adapt a lot faster than transmission planning,” Sokolski said “It’s that transmission side, where we’re going to have to speed up that transmission regulatory review and execution.”
Legacy Costs
But Baker pointed out that customers all over the footprint are still paying for coal plant construction, even though coal plants are now generally deemed obsolete.
“We have to be able to balance that rates are still in the past,” Baker said. “Shiny new things are great,” she said, but she urged utilities and MISO to be mindful of the cost of new builds.
Norton agreed that “shiny new toys” saddle customers with legacy costs over multiple decades. Multiple stakeholders also said that while market pricing is very low today, rates in comparison are high because transmission and generation assets are bundled in.
Several stakeholders asked for fair market prices and incentives across all resources.
The Union of Concerned Scientists’ Sam Gomberg said that he perceived tax credits as a means for renewable resources to play catch-up with other heavily subsidized traditional resources. However, he warned MISO that absolute recovery across all resources is unattainable.
“You can’t ask a nuclear plant to follow load; you can’t ask a wind farm to be available next July 15 at 3 p.m.,” he said.
‘Catch-up’ to Corporate America
Transmission Owners sector representative Jeff Dodd said MISO and transmission owners must find a way to accelerate the study of projects in the interconnection queue.
“Everybody sees these corporate renewable goals and these companies saying, ‘We’re going to get there with or without you,’” Dodd said.
“The biggest buyer of renewable energy is Corporate America, not utilities,” Eligible End-User Customers sector representative Kevin Murray pointed out. “So, the train has left the station — we’re playing catch-up.”
Murray also noted that, the very next day, MISO’s board would decide whether to admit Google as a member in the End-User sector, which it ultimately did. (See related story, “MISO, Meet Google,” MISO Board of Directors Briefs: Sept. 18, 2019.)
To the Disruptors, Goes the … Bill?
Baker said that if utilities pivot to catering to industrial customers with renewable appetites, then rates will have to shift so that companies shoulder more costs of sometimes expensive technologies.
“Why are 60% of costs being borne by residential customers?” she asked rhetorically.
Wisconsin Public Service Commissioner Mike Huebsch added a caveat to what he dubbed a “transformative shift on the side of the angels.” He said a transformation must be tempered so reliability doesn’t suffer. He wondered aloud if “Corporate America” is as ready to accept unintended consequences of 100% renewable energy as it is willing to drive the change.
“It’s not going to be an inner-city townhouse in Milwaukee that loses heat; it should be Google that shuts down for an hour,” he said.
“The pace of change is never going to be fast enough for the threat of climate change,” Gomberg added.
TDU sector representative Kevin Van Oirschot said the conversation reminded him of an oft-repeated line of a colleague at Consumers Energy: “The rate of change will never be this fast again, and it will never be this slow again,” he said to laughter. “I think that perfectly captures this moment.”
“‘With all deliberate speed.’ Got it,” Gunn summed up the members’ conversation, quoting the infamously vague phrase in the Supreme Court’s Brown v. Board of Education decision.
A day after the talk at the board meeting, Board of Directors Chair Phyllis Currie thanked members for at least the consensus that new measures are necessary.
“We all agree that change is coming. We’ve had some deniers in the past,” she said.
MINNEAPOLIS — A frequency response study that NERC engineers began more than two years ago to model the potential impact on the Eastern Interconnection of replacing old coal power plants with wind and solar resources has reached a tentative conclusion that may present market issues to the developers of renewable energy.
The study has concluded that wind and solar generators, which precisely synchronize their power flows into the transmission system with electronic inverters, can respond to frequency disruptions far more quickly than a traditional synchronous machine response, which is based on the speed of governor action on the steam turbines and generators in conventional power plants.
But the catch would be that wind and solar developers would have to set aside some percentage of a wind or solar farm’s generation potential. In other words, the current rules that require transmission organizations to take all of the output of wind and solar whenever it is available would have to be changed.
“It sounds sacrilegious,” explained Robert Cummings, NERC’s senior director of engineering and reliability, who designed the study with his colleague Olushola Lutalo, lead engineer of power system analysis.
“If you really want to make the [transmission] system perform, you can curtail, you can spill wind and spill sun, in order to get a non-carbon-based reserve margin that can outperform anything else you’ve got out there,” he told members of NERC’s Planning Committee.
“If I can curtail solar or wind by 5% instead of reserving very large amounts of head room with synchronous machines, I can outperform the synchronous machines. That is the bottom line,” Cummings said.
Having sufficient backup reserves is a question that electric utilities have had to deal with since the birth of the industry a century ago. For decades, the answer was “spinning reserves,” the practice of keeping certain boilers hot enough to quickly produce power to deal with the failure of other boilers operating to generate power continuously.
“You’ve pointed out very clearly that IBRs [inverter-based resources] can respond faster and perhaps eliminate the need for carbon-based spinning reserves,” consultant Gary Brownfield said. “That’s a huge game changer and paradigm shift for the industry.”
Cummings said he’s been asked, “Are you ever going to get to an all renewables” grid?
“Well, we might get to all renewables, but you’re not going to retire Grand Coulee or Hoover Dam. … And so, you’re still going to have synchronous machines. There might come a time when it makes sense to couple them electronically.”
John Moura, director of reliability assessment and technical committees, said the research has major implications for system planners. “In the future, your largest contingency might not be the huge nuclear units tripping offline. It might be a cloud cover [affecting a large solar farm] in South Carolina.”
Planning Committee members had a lot of questions and comments about the study’s findings. The immediate question was how the sun or wind could be curtailed without paying a solar or wind developer for what in effect would be spinning reserves.
“We are not trying to address the economics or the market issues here,” Cummings said in response to questions that zeroed in on the regulatory implications of such a change. “We are just talking about what you can do with these devices.
“It’s not the mechanics. It’s the politics,” he added when pressed for more detail. “Right now, we are in a mindset of ‘you are going to take all the sun, you are going to take all the wind and you are going to swallow it.’
“You can’t. California is a good example of that with the duck curve. This [situation] is the freshman class trying to drink all the beer in the Ohio State University stadium. You keep on filling the stadium and the class cannot drink that much.”
Cummings, who is a member of the Department of Energy’s Electricity Advisory Committee, added that he will present the modeling conclusions to the committee next month.
Cummings said NERC’s Inverter-Based Resource Performance Task Force (IRPTF) has been talking with inverter manufacturers to understand the capabilities of inverters as part of the IEEE P2800 project to develop a performance capability standard for IBRs connecting to the bulk power system.
“The [original equipment manufacturers], they’re listening,” Cummings said. “We’re asking them, ‘Can you do this?’ They say, ‘Yeah, we can do that.’ … So, we’re being effective without the standard even yet being in place, because we’re not going to ask them to do something they can’t do. … We’re working really hard to make this a real solution as opposed to an argument. That’s the beauty of the IRPTF.”
The judge overseeing PG&E Corp.’s bankruptcy case will probably get an earful Tuesday from lawyers advocating for two warring reorganization plans.
One was drafted by PG&E and its utility subsidiary Pacific Gas and Electric, the debtors in the case. It proposes using $14 billion in new equity financing to pay off wildfire claims and to emerge from bankruptcy by June, in time to take advantage of a new $21 billion wildfire recovery fund established by the California State Legislature. (See PG&E Offers $16.9B for Wildfire Claims in Chap. 11 Filing.)
The other is by PG&E’s unsecured bondholders, which recently partnered with fire victims. The bondholders propose injecting billions of dollars of cash into PG&E and paying $24 billion to settle wildfire claims in exchange for a controlling stake in California’s largest utility and full payment of their notes.
The bondholders and victims made an impassioned plea for their plan in a joint filing Thursday. It says PG&E’s proposal essentially is a sham offer intended to delay proceedings while benefiting one of the utility’s largest shareholders. That shareholder, a high-risk hedge fund from Boston called Baupost Group, bought up billions of dollars in claims from insurance companies, known as subrogation claims, which PG&E recently agreed to settle for $11 billion. (See PG&E and Insurers Agree to Settle Wildfire Claims.)
(Under PG&E’s plan, fire victims would get about $8.4 billion for damages stemming from November’s Camp Fire, the deadliest in state history, and a series of fires in Northern California wine country in October 2017.)
That means even if Baupost loses money on its PG&E stock, much of which it bought for three or four times its current worth, the hedge fund can still make a killing on PG&E’s payments for fire damages, the bondholders and victims argued.
“The settlement of the subrogation wildfire claims will enrich Baupost enormously at the expense of individual wildfire victims that have suffered actual loss,” the joint motion says. “Baupost is reported to hold more than $3.3 billion in subrogation wildfire claims, much of which, upon information and belief, was purchased at approximately 35% of face value. [PG&E’s plan] would pay Baupost’s claims at roughly 59% of face value, allowing it to reap hundreds of millions of dollars in profit from the debtors’ plan, at the expense of actual wildfire victims.”
PG&E said in a news release that the plan by bondholders, led by Elliott Management Corp. of New York and fire victims’ lawyers, is “a blatant attempt to unjustly enrich the noteholders who proposed it. The Elliott proposal would cost all PG&E customers billions of dollars in additional interest payments over 15 years – while providing an unfair windfall for the noteholders and plaintiffs’ attorneys.”
The bondholders and fire victims, called the Ad Hoc Committee of Senior Unsecured Noteholders and the Official Committee of Tort Claimants, asked U.S. Bankruptcy Court Judge Dennis Montali to end PG&E’s period of exclusivity, the time it has to file its own reorganization plan without interference. That period is set to end by the end of this month if Montali doesn’t extend it.
The judge will have to begin to sort through the arguments at Tuesday’s hearing in San Francisco. The parties to the case are all trying to move it along so PG&E can benefit from the state wildfire fund.
The California Public Utilities Commission, which also must approve a reorganization plan, will need months to consider it, adding to the time pressure. The CPUC is scheduled to consider a proposed order to begin an investigation of PG&E’s reorganization plan, and its effects on ratepayers, at its meeting Thursday.
ST. PAUL, Minn. — Google gained a foothold in the MISO system last week as the RTO’s Board of Directors approved a subsidiary’s membership application.
Google Energy joined MISO’s Eligible End-User Customers sector. The subsidiary was founded nearly a decade ago in a push to power its parent’s operations with 100% renewable energy. It has multiple investments and power purchase agreements with wind farms along the western border of MISO’s footprint, enough by 2017 to match its annual electricity consumption.
“Although our 100% renewable milestone signifies that we buy enough renewable energy over the course of a year to match our annual electricity consumption, it does not mean that our facilities are matched with renewable energy in every hour of every day,” the company says. Its ultimate goal “is to source enough carbon-free energy to match our electricity consumption in all places, at all times.”
MISO President of Market Development Strategy Richard Doying said the RTO is anticipating more non-traditional membership applications like Google as more companies become enmeshed with distributed resources’ push to join wholesale markets.
The RTO’s approval of Google’s membership came a day before the company announced a $2 billion global investment in solar and wind generation across 18 new renewable energy deals.
The board also allowed Upper Peninsula Power Co. into the Municipals, Cooperatives and Transmission Dependent Utilities sector. Both applications for membership were approved unanimously.
Lurie Joins Board
The board also filled a vacant seat with former New York Power Authority CFO Robert Lurie. The selection was made without input from MISO membership, as the seat was vacated earlier in the year by Thomas Rainwater. MISO’s bylaws stipulate that vacancies are dealt with by solely the board, and not through the usual Nominating Committee process and subsequent stakeholder vote.
“We had a robust discussion of the candidates and their qualifications, and I think he will serve MISO well,” Chair Phyllis Currie said.
MISO could have seen up to four new faces on its board in 2020, but the Nominating Committee opted only for existing board members as eligible candidates: Todd Raba, Trip Doggett and Barbara Krumsiek. (See MISO Board of Director Briefs: June 20, 2019.) The RTO will again use VoteNet Solutions to conduct its membership vote on the candidates. Electronic polls are set to open Thursday for 37 days.
This year’s Nominating Committee consisted of Directors Baljit Dail, Mark Johnson and Theresa Wise; the two stakeholder seats were occupied by Minnesota Public Utilities Commissioner Matthew Schuerger and Ameren’s Jeff Dodd.
ST. PAUL, Minn. — MISO staff are done assembling the RTO’s 2019 Transmission Expansion Plan (MTEP 19), presenting a nearly $4 billion draft package to the Board of Directors last week.
Instead of concentrating solely on this year’s plan, however, MISO executives at the board’s System Planning Committee meeting Sept. 17 emphasized what changes they would make to modernize the 15-year future scenarios used annually to justify transmission projects.
The proposed 2019 portfolio — 472 new projects totaling nearly $3.9 billion — is open for stakeholder review through the end of the month. The latest draft is trimmed from an earlier version that contained 483 projects at a cost of $3.95 billion. Even with the reductions, it’s still the RTO’s second-most expensive transmission buildout. (See MISO 2019 Transmission Expansion Plan Takes Shape.)
Vice President of System Planning Jennifer Curran told the board to expect some additional changes in response to stakeholder comments.
MISO said MTEP 19 is “consistent” with MTEP 18 because the package primarily consists of reliability projects. That trend appears likely to continue in the 2020 package, as the RTO has announced it would recycle its futures next year. The RTO has promised an extensive reboot of its planning projections beginning with the 2021 portfolio. (See MISO Halts Futures Work for 2020, Plans 2021 Rebuild.)
“I think [with] the status quo coming for 2020, there will be more interest in the 2021 futures,” Director Nancy Lange predicted, urging careful thought from MISO on the new futures. “I think the pace of change is only accelerating, so it’s important for MISO to think about its key planning assumptions.”
Asked by Director Phyllis Currie if there was any discord as MISO prepared MTEP 19 with stakeholders, staff cited discussions over how prominently batteries should be featured in the planning landscape.
“That’s a big focus for our team,” said Executive Director of System Planning Aubrey Johnson, adding that MISO first must create a cost recovery mechanism for storage devices.
Director Trip Doggett asked if batteries are gaining more traction because of recent technological breakthroughs or because of their transmission capabilities.
“I think it’s a ‘Yes, and…’ question,” Johnson responded, noting that batteries can mimic generation.
MISO President Clair Moeller pointed out that MTEP 19, which recommended a single battery project, anticipates just 2.5 MW of load growth. (See MISO Recommending 1st Storage-as-Tx Project.) “For perspective, 2.5 MW is the size that could be compared to a large neighborhood’s load,” he said. Moeller said that although load growth has remained flat since about 2007, load has shifted with demographics.
“So, the standard load growth isn’t driving transmission decisions. … But people are moving around,” he said.
Moeller also said differing state goals regarding their energy mixes have emerged as a planning challenge in recent years.
“When we began the [MISO] market, everyone’s fleet was about the same,” he said. “Now, not everyone thinks high wind penetration is the future. So that complicates things.”
Currie asked if neighboring RTOs were planning transmission around battery storage buildout.
“To my knowledge, we haven’t seen a strong push toward batteries,” Johnson said.
Futures Edit too Late?
Clean Grid Alliance’s Beth Soholt made use of the public comment period to call for a rework to MISO’s transmission planning strategy sooner than MTEP 21.
MISO MTEP 19-20 futures (year 2033) | MISO
She pointed to utility integrated resource plans full of renewable goals, carbon-cutting pledges from state governments and a “huge customer preference and demand for renewables” as evidence that MISO cannot afford another year of waiting before it reshapes its future scenarios.
“Over another year, we’re going to use static futures,” Soholt said. “We risk the MISO system not being able to deliver what customers want in the Midwest.”
Soholt cited MISO’s February 2017 interconnection queue cycle, where all but 250 MW of the originally proposed 5 GW of renewable generation projects dropped out because of prohibitively expensive transmission upgrades.
“The processes and the systems in MISO are misaligned to solve these challenges,” Soholt said, calling the RTO’s current planning method and assumptions “frustrating and irrelevant.” She said needed transmission projects are being overlooked because of MISO’s continued underestimation of renewable growth.
Soholt said the $32 million, 345-kV Helena-to-Hampton Corner circuit project, originally identified in this year’s Market Congestion Planning Study, should have made the cut into MTEP 19. The project was set to solve congestion in southern Minnesota, but MISO said that once forecasted wind generation was removed from the equation, the project quickly lost value.
A System from Interconnection Upgrades?
Organization of MISO States President and Missouri Public Service Commissioner Daniel Hall said the RTO is ignoring “substantial” renewable growth and expressed concern over a “number of interconnection projects dropping out very late” in the queue process. He said some renewable projects were already approved by state commissions and under power purchase agreements when they were forced to exit the queue.
“We’re currently trying to plan a transmission system one interconnection at a time. … It’s a wake-up call,” Hall told the board at its meeting Thursday.
“They’re stale,” Moeller admitted of the four futures.
“I think there’s [been] more planning and more discussion over the two years I’ve been here. … I’ve seen more coordination. I really think it’s a case of just because there’s congestion there doesn’t necessarily mean that it warrants a project to correct it,” Johnson said.
ST. PAUL, Minn. — The MISO footprint didn’t come close to its forecasted summertime peak and is unlikely to hit its forecasted fall peak either. But ways to improve resource adequacy in a time of grid transformation were on the minds of those at MISO Board Week here.
Times a-Changin’
MISO’s interconnection queue is further evidence of the urgency of its resource availability and need (RAN) project, Richard Doying, president of market development strategy, told the Markets Committee of the Board of Directors on Sept. 17. RAN ideas currently include a 30-minute reserve product, a resource accreditation rethink, a seasonal capacity auction and a multiday forecast. (See MISO, Stakeholders Debate Merits of Seasonal Auction.)
Based on utility and state announcements, MISO forecasts wind and solar generation will overtake coal and natural gas. By 2030, wind and solar will total 30 to 35% of generation output, while natural gas and coal will have 29% and 24 to 29% shares, respectively. Nuclear’s contribution is projected to be nearly halved to 9%. In 2018, MISO reported a fuel mix of 48% coal, 26% gas, 16% nuclear and 7% wind and solar combined.
Proposed solar projects currently comprise 59 GW of MISO’s 101-GW interconnection queue. Wind generation has a 27-GW share, while natural gas-fired resources represent 9 GW. Storage resources, still nascent in MISO, total only 3 GW. No new nuclear generation is proposed in the queue.
“We do expect to see more storage,” Doying told the board, adding that MISO is particularly anticipating solar-and-storage hybrids.
“I think you can get the whole community behind this,” Director Baljit Dail said, commending the RTO on RAN’s catchphrase, “All hours matter.”
Dail compared it — in rhetoric only — to 2001’s No Child Left Behind Act. Since last year, MISO has said it needs to shift from its one-day-in-10-years loss-of-load expectation to an approach that accounts for different risks across all operating hours.
“We have not considered ‘No Hour Left Behind,’” Doying laughed.
Director Barbara Krumsiek compared the RAN effort to “changing a tire [while] going 60, 70 mph on the interstate.”
Director Trip Doggett asked if NERC appeared to be also shifting from its one-in-10 reliability standard.
“It is something that lots of other folks are looking at,” Doying said.
But WPPI Energy economist Valy Goepfrich was quick to remind leadership that RAN is merely studying whether MISO needs to pivot to an all-hours risk. She said it could turn out that preparations for a summer peak still cover reliability risks in every other operating hour of the year.
“We’re letting the data drive what the peak is,” she told the board.
“It’s still that one hour that we have to meet. The problem is we don’t know when that hour is any more. It used to be a warm day in July or August. Now that’s shifted,” MISO CEO Joh Bear explained at Thursday’s board meeting.
Peak Forecasts Averted
MISO Executive Director of Market Operations Shawn McFarlane predicted that the RTO won’t hit its forecasted 112-GW fall peak, saying the highest risks of September’s heat have passed. (See MISO Unruffled by Fall Supply-demand Outlook.)
“Right now, the highest load we’ve had is 107 GW on Sept. 7,” McFarlane said.
MISO also fell short of its nearly 125-GW forecast summer peak, instead experiencing a 121-GW summer peak July 19.
MISO forecasted portfolio change | MISO
The RTO weathered a heat wave and a hurricane in July without reliability problems. It declared conservative operations on July 18 and issued an open-ended maximum generation capacity advisory effective 10 a.m. ET on July 19 as several Midwestern cities issued excessive heat warnings and heat indexes exceeded 100 degrees Fahrenheit even in Minneapolis. Both alerts were terminated July 20. MISO’s capacity advisories ask members to prepare for emergency conditions, ready load-modifying resources for a possible call-up and ensure resource availability is up to date in the RTO’s communication system.
On July 11, MISO declared a severe weather alert for its Gulf Coast region for July 12 to 15 as Tropical Storm Barry was forming over the gulf. MISO’s weather alerts ask that maintenance and testing on any critical transmission or generation system be deferred or canceled. The alert lasted through July 20 as Entergy mobilized crews to restore power in flooded portions of Louisiana.
Independent Market Monitor David Patton said the most exciting part of the summer occurred in eastern Texas on Aug. 13, when a transformer lost cooling in the West of the Atchafalaya Basin load pocket from 4 to 6 p.m.
“We were extremely close to shedding load; if there had been another contingency…” Patton trailed off.
MISO interconnection queue breakdown | MISO
Prices during the contingency spiked to $560/MWh, but just over the border in sunbaked ERCOT — which was experiencing high load — prices were $8,800/MWh
Patton said the area should have been more appropriately priced at about $4,000/MWh. He added that ERCOT prices had to be attractive to MISO members, who were prohibited from lending supply because of the RTO’s own reliability risks.
“The reliability situation was far more dire in MISO than in ERCOT,” Patton said.
He again called for MISO to “beef up” its emergency and shortage prices, especially for times when portions of the footprint are “on the verge of load shedding.”
“As we grow our intermittent sources, we’re going to see more shortages,” he warned.
The effort to expand CAISO’s Western Energy Imbalance Market from a real-time trading platform to a day-ahead market took a significant step forward Wednesday, when members of the ISO’s Board of Governors and the EIM’s Governing Body said they supported launching a stakeholder process in October.
The first step will be an issue paper. Then the stakeholder process is expected to continue well into next year, said Keith Casey, CAISO’s vice president of market and infrastructure development. It will address issues such as resource sufficiency in a tightening Western market and interstate transmission challenges, ISO staff said.
Board Chair David Olsen and EIM Governing Body Chair Carl Linvill gave their verbal support to the stakeholder process; there was no formal vote. The occasion was a briefing on the results of an eight-month feasibility study of the extended day-ahead market (EDAM).
Fourteen current and future EIM entities, in addition to CAISO, participated in the assessment.
The non-CAISO entities wrote a joint letter to ISO and EIM leaders emphasizing they have not committed to the EDAM and want to make sure it addresses a number of concerns, including the continued independence of the Governing Body and the representation of a range of interests from across the West.
A continuing worry among EIM participants is that California politicians and CAISO might try to dominate the regional market. CAISO’s bid to form a Western RTO stalled in part because CAISO’s governors are appointed by the governor and approved by the State Senate.
“The issues to be resolved to make EDAM a reality should not be underestimated,” the entities wrote. Those that signed the letter included Arizona Public Service, Idaho Power and PacifiCorp.
“Governance structures must be considered that reflect the new market design and the legitimate interests that all within the broader market footprint will have in the operation and rules of the day-ahead market,” it said. “In addition, it is likely EDAM will need to include a test to ensure that all participating balancing authorities are not leaning on neighbors to meet their continued reliability obligations.”
Estimated Benefits
A goal of the feasibility study was to estimate the financial benefits to EIM participants to gauge their potential level of interest, Mark Rothleder, CAISO vice president of market quality, told the board and Governing Body.
The EIM has continued to add new members, but some entities from the interior West have cited the economic bonuses as their primary motivation while lamenting the tie to California. The uneasy political alliance is part of the reason SPP recently launched its own Western Energy Imbalance Service. (See WAPA, Basin, Tri-State Sign up with SPP EIS.)
Rothleder said the study group and its consultants, E3 and Brattle Group, had projected the operational benefits of a day-ahead market at $119 million to $227 million annually, which he called a conservative estimate. (In their letter, the EIM entities pointed out that the estimate doesn’t consider how “benefits may be reduced should only a limited number of EIM entities elect to participate in EDAM.”)
The expected financial benefits will come partly through more efficient day-ahead hourly trading and better use of available transmission in an organized market, according to Rothleder’s presentation.
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The EIM says its real-time market has saved participants more than $736million since it began in 2014.
A day-ahead market could limit the curtailment of excess renewable resources by up to 2 GWh a year, sending energy where it’s needed and producing tens of millions of dollars in additional revenue for generators, Rothleder said.
Environmentalists have generally supported regional markets as a way to maximize the sharing of renewable resources, for example, by sending wind energy from New Mexico to California and solar power from California to the Pacific Northwest.
Jennifer Gardner, senior staff attorney with Western Resource Advocates and a member of the committee that nominates Governing Body members, praised the move in a news release. Adding a day-ahead market to the EIM would “allow utilities to better plan for and optimize renewable energy use on the grid through more efficient unit commitment and more effective integration of variable energy resources across a larger footprint,” Gardner said.
Sarah Edmonds, transmission director at Portland General Electric, and Jim Shetler, general manager of the Balancing Area of Northern California, were part of the assessment team. They spoke at Wednesday’s meeting and acknowledged the challenges and effects of a day-ahead market that stretches across the Western Interconnection.
“This is going to be significant and complex,” Edmonds said. “It could have consequences for the Western market as a whole.”
EIM Governance Review
The board and Governing Body also named 10 members of a committee to review the governance structure of the EIM, as required by the market’s original charter. (See CAISO OKs EIM Governance Review.)
The charter recognized that the EIM would evolve over time, and the expansion to a day-ahead market could necessitate governance changes, said Stacey Crowley, CAISO vice president of external affairs.
Members named to the Governance Review Committee (GRC) included Gardner; Therese Hampton, chair of the EIM’s Regional Issues Forum and executive director of the Public Generating Pool in the Pacific Northwest; and Eric Eisenman, PG&E’s director of ISO and FERC relations.
Their colleagues nominated Governing Body member Valerie Fong and CAISO Governor Angelina Galiteva as representatives to the GRC.
Board Chair Olsen said he’s hoping to add another member from the EIM’s investor-owned utilities because he felt the committee was light on IOU representation.
The committee will eventually include 11 to 13 members, said Peter Colussy, CAISO manager of regional affairs.
FERC told MISO, PJM and SPP last week that their joint operating agreements don’t provide enough clarity on how the RTOs’ handle generator interconnections along their seams (EL18-26).
The commission agreed in part with EDF Renewable Energy and ordered the RTOs to update their JOAs and Tariffs to make the queue priority process more transparent within 60 days of its ruling Thursday. The commission declined the company’s related request (AD18-8) to expand the review of affected-system coordination in the generation interconnection process beyond MISO, PJM and SPP, however.
“Because the queue priority processes are not described in their tariffs or JOAs, we find that there is a lack of transparency in MISO, SPP and PJM that makes it difficult for interconnection customers to understand how affected-system network upgrade costs are being allocated to them,” FERC wrote. “Requiring the RTOs to detail this information in their JOAs will provide additional transparency to interconnection customers on their potential responsibility for affected system network upgrade costs, thereby reducing uncertainty that may hinder interconnection development.”
| EDF Renewable Energy
The order comes nearly 18 months after FERC staff held a technical conference with the RTOs to address the issues raised in EDF’s October 2017 complaint that their governing documents, particularly the JOAs, lack details about the timing of affected-system analyses, the standards applied to determine impacts from proposed interconnections and how network upgrade costs are assigned. (See FERC Orders Review of PJM, MISO, SPP Generator Studies.)
FERC Order 2003 requires a transmission provider to coordinate interconnection studies and planning meetings with affected systems — electric systems other than the host transmission provider that may be affected by a proposed interconnection.
EDF argued that the lack of clarity regarding the RTOs’ delivery requirements and modeling standards violates the commission’s requirement for transparent, open-access interconnection service.
FERC said that despite insistence from the RTOs to the contrary, their existing documents lack transparency and cause “harm due to uncertainty” for EDF and other interconnection customers who struggle with decisions about whether to remain in the queue for fear of incurring unknown costs.
“Cost uncertainty presents a significant obstacle to the development of new resources, as some interconnection customers are less able to absorb unexpected and potentially higher costs for interconnection facilities and network upgrades that may occur once affected-system study results are considered,” FERC wrote. “This lack of transparency in the current affected-systems coordination process between MISO, SPP and PJM has the potential to hinder the timely development of new resources and thereby to stifle competition in the wholesale markets, resulting in rates that are not just and reasonable or are unduly discriminatory or preferential.”
The commission, however, rejected EDF’s request that the RTOs unify their modeling systems and study timelines, deeming neither necessary for providing greater transparency.
The RTOs’ compliance filings must include:
Current affected-system coordination processes, including the provision of clear references to where affected-system study information can be found in their business practice manuals;
A description of the modeling standard (external resource interconnection service or network resource interconnection service) they use to study, as the affected RTO, interconnection customers that request ERIS in the host RTO and interconnection customers that request NRIS in the host RTO;
The location in their manuals or other coordination documents where interconnection customers can find the modeling details that they use when studying a project as ERIS or NRIS for interconnection requests on their own systems;
For MISO and SPP specifically, a description of how they study the impacts on the affected RTO and clarify that the each RTO’s study criteria apply to its own facilities;
How the three RTOs monitor each other’s systems during the course of each of their interconnection studies;
PJM’s process for monitoring neighboring systems for affected-system impacts; and
PJM’s timeline provided to interconnection customers to review affected-system study results.
