CARMEL, Ind. — A new team considering sequencing parts of MISO’s transmission planning with network upgrades identified in generator interconnection studies held its second meeting Wednesday, with stakeholders outlining the issues they hope to have addressed.
Upcoming discussions of the RTO’s Coordinated Planning Process Task Team (CPPTT) could result in strategies to lower the increasing costs generation developers are facing for network upgrades.
The task team is MISO and stakeholders’ response to complaints from the Environmental and Other Stakeholder Groups sector and others that renewable growth is being hindered by increasingly expensive upgrades. (See Renewables Group Calls for MISO West Tx Construction.)
Several stakeholders have called for the RTO to more closely align its studies that identify network upgrades for the interconnection queue with its annual Transmission Expansion Plan (MTEP) so that transmission that facilitates new renewable output isn’t borne exclusively by generation developers.
The team’s tentative mission is to identify “potential coordination and consistency issues” between MISO’s generator interconnection and MTEP processes.
MISO Manager of Resource Interconnection Arash Ghodsian promised that the team will examine the timing and methodology of the different studies under the interconnection queue and MTEP. “Where can we gain some efficiencies? Where can we gain some consistency?” he told stakeholders. He said the goal is to find the best transmission solutions that can meet a variety of purposes.
Clean Grid Alliance’s Natalie McIntire said the interconnection queue and the MTEP process should share assumptions so that it’s not a race to see which party will foot the bill of a transmission project. “We don’t want to have the timing of the studies determine who pays for the project. Right now, whatever study finishes first determines who pays. That seems to us to be an important principle here. We should have a better process to determine the beneficiaries,” McIntire said.
However, MISO Director of Planning Jeff Webb said it’s impractical to expect the RTO would be able to apply the same set of assumptions to every type of planning study. “It doesn’t make sense. It’s too prescriptive,” Webb said.
McIntire said that interconnection customers are discovering that the costs of network upgrades are “more than the capital costs” of the generation projects themselves.
“I don’t think anyone believes that these several million to $1 billion major upgrades are going to be paid for by interconnection customers,” EDF Renewable Energy Interconnection Manager Anton Ptak said.
He also said MISO “is just at the beginning” of seeing its utilities dramatically alter their fuel mixes and argued that it should identity the beneficiaries beyond the interconnection customer of such expensive upgrades.
“Once upon a time, we were ordered to do cost allocations for generator interconnections instead of the direct assignment approach,” Webb pointed out, noting that MISO has returned to assigning costs directly to interconnection customers and ignoring other beneficiaries. About 14 years ago, the RTO used a 50/50 cost sharing of network upgrades between interconnection customers and load in corresponding transmission pricing zones, with the zonal half collected like baseline reliability projects were, through a blend of 20% postage stamp and 80% sub-regional allocation. To be eligible for the cost sharing, interconnection customers had to become MISO network resources or have proof of a one-year power purchase agreement.
The Union of Concerned Scientists’ Sam Gomberg said MISO should strive to end the “free ridership” of beneficiaries. “Those seem like principles that we should be able to get behind,” Gomberg told attendees.
Great River Energy’s Mike Steckelberg suggested MISO consider creating a transmission project market, where multiple parties can bid in to share project costs.
MISO stakeholders are encouraged to send more issues for the task team to consider through Jan. 2. The CPPTT will hold another a meeting in mid-January.
CARMEL, Ind. — MISO stakeholders last week debated whether the RTO is being too conservative in anticipating industry shifts in its new futures scenarios for transmission planning.
MISO in October released a trio of new 20-year future scenarios to assist transmission planning for the 2021 Transmission Expansion Plan (MTEP 21). (See MISO Sets Course for New Futures.)
Now, the RTO has revised the scenarios’ names to Announced Plans, Accelerated Fleet Change and Advanced Electrification. It has also upped the age at which coal units retire by at least four years in each future and reduced carbon reductions from 50% to 40% in the Accelerated Fleet Change future.
MISO also cut its electrification predictions in both the Advanced Electrification (from 70% to 40% energy growth potential) and Accelerated Fleet Change futures (from 40% to 20%).
Finally, the Announced Plans future now contains an 85% probability instead of total confidence in changes identified in utilities’ integrated resource plans, including coal retirements, new gas-fired generation and emission-reduction targets.
At a special workshop Thursday, MISO Planning Manager Tony Hunziker said the changes were made after the RTO evaluated feedback from stakeholders.
“There was an emphasis on having more conservative assumptions,” he said.
A Question of Coal Retirements
Xcel Energy’s Drew Siebenaler pointed out that his company plans to end all coal use in the MISO footprint by 2030. He also said the RTO should consider that it is often expensive to keep aging coal plants cycling.
“What we’ve learned is it takes a ton of capital to keep these units [operating as reliability]-must-run. I’d like to also see how they’re going to be dispatched,” he told RTO staff.
Veriquest Group’s David Harlan said MISO wasn’t clear on what generation would replace retiring coal units. Hunziker said it would use the Electric Power Research Institute’s Electric Generation Expansion Analysis System (EGEAS) to predict generation expansion.
Clean Grid Alliance’s Natalie McIntire said it didn’t make sense to extend the lifespan of coal plants from 30 years to 35 in the Advanced Electrification future. She said coal use is ending, whether or not members want it to occur.
“I understand that there are a lot of stakeholders that are uncomfortable with an aggressive future. But it’s not MISO’s job to predict the future; it’s to create a reasonable range of plausible futures. We’re not trying to get everyone comfortable with every future. I don’t think it’s reasonable not to have an aggressive future in there, given that all of the [changes predicted] in MISO’s existing futures have been exceeded,” she said.
Comfort not the Goal
Megan Wisersky of Madison Gas and Electric said she agreed that stakeholders shouldn’t be at ease with the scenarios outlined in the futures.
“It’s not our job to make sure that everyone is comfortable. We really need futures that are stretches — that contemplate technological change, political change … that in late 2019, we can’t fathom,” she said.
Wisersky said MISO should craft futures using more intense industry shifts so it doesn’t again use obsolete predictions. The RTO plans to use its existing four futures one last time for the 2020 cycle of its transmission planning.
“It just seems like MISO has scaled back on these in response to a few stakeholders’ comments. These are supposed to be bookends,” McIntire said.
Minnesota Public Utilities Commission staff member Hwikwon Ham suggested MISO assume a 35-year coal plant age retirement in all three futures, then update the ages as utilities announce retirements.
Stakeholders also said MISO should take utilities’ IRP plans at their word, or even assume that utilities will exceed their IRP goals ahead of time. Some suggested that for utilities to publicly announce retirements and not see them through may constitute fraud.
McIntire asked if MISO would include corporate commitments to renewable energy and carbon-cutting in any of its futures.
“We considered that. We didn’t want to double-count them,” Hunziker said.
He said MISO would rely on load-serving entities to include that information in their load forecasting. However, he also said it might consider reaching out to multistate corporations whose renewable goals might be hard to pin down on a single-utility basis.
After MISO revealed its initial futures proposal, the Union of Concerned Scientists’ Sam Gomberg blogged that they were the result of the RTO “lean[ing] into the undeniable transition towards renewable energy resources, emerging technologies like battery storage and the growing momentum behind decarbonizing our economy.”
Gomberg said the new futures are “essential to ensure a modern grid is ultimately ready to support a clean and reliable electricity supply.”
“MISO’s job isn’t easy — making investments now to prepare for an uncertain future. MISO can’t create our clean energy future — that’s up to us as consumers to demand. But MISO, through its function as the regional grid operator, can either complement or hinder our progress. MISO’s proposed revamp of its planning process is a strong step in the right direction to ensure our electricity grid is ready for our clean energy future,” Gomberg said.
Hunziker invited more stakeholder opinions on the three futures. MISO will continue developing the futures scenarios through January, with the definitions completed in either February or March.
BOSTON — ISO-NE on Thursday marked 10 years of its Consumer Liaison Group, whose quarterly meetings serve as a forum for the public to get to know the regional transmission organization, and for the RTO to hear people’s concerns about climate change, their electricity bills and public policy on energy.
As is customary on an anniversary, people took the opportunity to look back, as well as to think about what the future might hold.
The nearly 200 people who attended included state regulators, utility executives, consumer advocates and industry stakeholders — some of whom thought that public policy is outstripping people’s ability to pay, while others said the region is not moving fast enough to meet the challenge of climate change.
Following are highlights of what we heard at the event.
“We are running out of time,” said Mary Beth Gentleman, board member of FirstLight Power and clean energy advocate E4TheFuture. “We have done incredibly creative and smart things in New England, but we’re not doing it fast enough. We face an existential threat, and the kind of consensus and meetings and groupthink that have been the strength of New England now seems at odds to me with the pace that we need to move.”
Gentleman said that the biggest surprise for her in the past decade was that Massachusetts licensed a billion-dollar natural gas-fired power plant, Footprint Power’s 674-MW Salem Harbor Station, which came online in May 2018.
Lisa Linowes, executive director of The WindAction Group, a clean energy advocacy organization, said that most consumers have no idea why electricity prices are so high, or how public policy decisions affect their lives.
“Today I would encourage, if not demand, that the Consumer Liaison Group become much more engaged with consumers, and not people who come to push their own agendas at the state house,” Linowes said.
The RTO deserves a lot of credit for the work it’s done over the past decade, but ratepayers in New England are paying the highest electricity rates in the continental U.S., and third in the country only to Hawaii and Alaska, she said.
“There’s something wrong with the system here,” Linowes said. “Much of the onus, in my opinion, is on the shoulders of the states. Does anyone know how much the Massachusetts [renewable portfolio standard] costs? In 2016, which … is the most recent information we have, it was $645 million; that’s the estimate put out by [the Department of Energy Resources].”
Market Economics
“I don’t think markets are broken; it’s just that the world has changed around the markets,” said Matthew Nelson, chair of the Massachusetts Department of Public Utilities. “Regardless of our personal or political positions, the reality in the market is one of increasing demand for clean resources.
“The question is: Can the market rise to meet that challenge? And if it can, what’s the cost?” Nelson said.
He likened today’s market to a three-legged stool, and said, “We’re trying to balance clean with cost and with reliability. Reliability today is king in the electric market, but the relationship between reliability and clean energy is not binary. The narrative that a clean future can only come at the expense of reliability is false.”
While reliability will decline slightly because of adding variable generation to the resource mix, it’s important to better understand what is “on the margins,” and the connection between decarbonization goals, reliability and costs, he said.
“Our metrics for reliability on the electric side are not easily understood, nor is the cost around different levels of reliability easily understood,” Nelson said.
Clean energy does bring sustainability, “but reliability will decline, so we’re left to decide how to deal with that going forward,” Nelson said. “We’re trying to redesign the market on the fly, while not interrupting service, and that’s a cost.”
If costs go up too much, it would affect businesses in the region, which face global competition, he said.
“I think out-of-market contracts are putting a strain on the system a little bit,” Nelson said. “They’ve got new resources coming in at zero price, but the costs are being passed onto consumers, and that’s interrupting the way the market works.
“We want to be able to balance sustainability with a plan,” he continued. “Where is this energy coming in? How much do we need? These are the decisions we need to think about right now. And are the contracts being purchased to respond to a consumer demand, or a policy demand for clean energy?”
Judy Chang of The Brattle Group spoke on trends in the New England power sector, such as declining load, technological advances, reduced costs of solar and wind, low natural gas prices and increasing environmental restrictions.
“What does it mean to have a market of increasing amounts of zero or negative price energy?” Chang said, suggesting setting up a centralized market for clean energy attributes.
Chang mentioned the power of corporations to affect energy policy, as signified by the growth of the Renewable Energy Buyers Alliance, whose members include many household names. Companies “do want to contribute to decarbonization,” Chang said. “Their customers and employees will be increasingly demanding such action.”
Brian Forshaw of Energy Market Advisors said he brought a consumer-owned utility perspective to the conference, and that his biggest surprise of the past decade “is that the markets have lasted as long as they have” after being created in the aftermath of the 1965 blackout.
Forshaw said the key takeaway from the day came from Nelson, who said that the world has changed around the region’s electricity markets.
Wind, Sun and Storage
Anne George, vice president for external affairs and corporate communications at ISO-NE, presented an update on the RTO’s activities, noting the grid’s transition to renewable resources, a topic to which the grid operator devoted a conference in May. (See ‘Grid Transformation Day’ Highlights ISO-NE Challenges.)
“It’s a much different grid from 10 years ago,” George said. “The amount of wind in our interconnection queue is the greatest we’ve ever had” — 13,720 MW, or 65% of the queue total of 21,138 MW. “And over the next 10 years, we’re going to see a lot more activity with battery storage,” she added.
Solar is growing too, as attested by Robert Dostis, vice president of stakeholder relations at Green Mountain Power, which serves about 78% of Vermont.
“In 2008 when I joined [GMP], I put solar on our roof and it was a novelty,” Dostis said. “It started picking up in 2012, and in 2013, we had 20 MW in the state. Today, just in [GMP] territory, we have 300 MW of installed solar and 130 MW in the queue. We have so much solar that some substations can’t handle any more.”
New England’s grid is transitioning to clean energy resources, which already dominate the ISO-NE interconnection queue. | ISO-NE
CLG Coordinating Committee Chair Rebecca Tepper, chief of the Energy and Telecommunications Division at the Massachusetts attorney general’s office, offered a snapshot of the group’s history.
“I don’t know if people are aware of this, but the Consumer Liaison Group was formed because of a FERC order, No. 719 … which was about enhancing the responsiveness of RTOs and ISOs to customers and other stakeholders,” Tepper said.
Among other requirements, FERC directed each RTO to provide a forum for affected consumers to voice concerns and propose solutions on how to improve the efficient operation of the markets, she said.
Tepper said the CLG will meet next on March 12, 2020, in Vermont.
SALT LAKE CITY — The Western Electricity Coordinating Council will launch an initiative next month to streamline bulk power system planning in the West. The effort seeks to tighten coordination and clarify who does what among the myriad planning groups, utilities and other industry stakeholders across the sprawling region.
WECC will create a new “BPS Roles” task force in January and expects to present an outreach and communication plan to its Board of Directors at the organization’s annual meeting in September 2020.
The effort is one of WECC’s “near-term priorities,” endowing it with a sense of urgency as the region’s BPS faces unprecedented and accelerating change from increased use of renewables and distributed energy resources, expansion of markets such as West’s RC Transition Earns Plaudits.)
Stakeholders attending a WECC Members Advisory Committee meeting Dec. 3 expressed broad support for the effort. Dozens of organizations have a hand in the West’s BPS planning, including formal planning groups (such as the soon-to-be merged Columbia Grid and Northern Tier Transmission Group), load-serving entities, transmission and generation owners, public interest groups and merchant developers. Rounding out the list are “assessment groups” such as NERC, FERC, the Western Interconnection Regional Advisory Board and WECC itself.
Kicking off a technical panel discussion to explain the initiative, WECC System Adequacy Planning Manager Byron Woertz showed a clip from “Miracle,” the 2004 film about the U.S. men’s ice hockey team that defeated a heavily favored Soviet team in the 1980 Winter Olympics.
The scene depicts coach Herb Brooks chiding the overly confident but incohesive team of college athletes following a humiliating loss: “You think you can win on talent alone? Gentlemen, you don’t have enough talent to win on talent alone.”
“In the West, we have talented planners, but we don’t have enough talent to solve our problems on our own,” Woertz told the audience of WECC stakeholders, staff and board members. “We need to coordinate with each other.”
‘The Punchline’
Three panelists joined Woertz to explain the rationale for the initiative, describe how WECC intends to approach it — and to provoke discussion among members.
“We know things are changing. When we look around the system, it’s not the same system that it was 20, 30, 40 years ago,” said Enoch Davies, WECC’s manager of system stability planning. Davies said system planners must gather more data on DERs connected with distribution systems: “That’s one thing that we have to improve coordination on — is how we get that information.”
Chelsea Loomis, regional electric system planning manager at NorthWestern Energy, said the use of the transmission system is also going to change. “And I think we’re experiencing that [change] as well, as entities are entering the Energy Imbalance Market or changing RCs. We’re just seeing a lot of different use on the transmission system itself.”
Woertz noted that — similar to DERs — utility-scale renewable resources are more widely dispersed than the fossil-fueled and hydroelectric resources that have traditionally dominated the grid. “The coordination among not only the organizations and the different planning roles, but [also among] the resources themselves, is going to be a challenge moving forward,” he said.
“As we see everything else changing, we probably need to change with it in our planning methods. I think that’s kind of the punchline of this whole discussion,” Davies said.
“Particularly if we want to maintain the same level of reliability that we’ve grown accustomed to,” Loomis added.
Growth Opportunity
Woertz broke the information-gathering process down to three key points: gathering the right data, from the right people, at the right time.
“There’s a lot of data out there. Make sure you’re getting from the people that really own that data. Make sure it’s timely — that you’re getting current information,” Woertz said.
“Regarding distribution generation, that’s a struggle we’re having today,” Davies said. “Where do we get that data? Is it distribution providers? Maybe that’s the right group; maybe it’s not.”
Loomis also pointed to the increased collaboration needed to create WECC’s “anchor data set,” the compilation of load, resource, unit dispatch and planning base case information to be used by the Western Interconnection’s regional planning groups as part of their transmission plans. That effort, kicked off five years ago, is still a work in progress.
Using the language of personal development, Northwest Power Pool’s Dave Angell, chair of WECC’s Reliability Assessment Committee (RAC), joked that the committee’s creation of the anchor data set has been “an opportunity for growth for a lot of folks.” The group has produced one anchor data set, is starting to produce the second and has set up a task force to review its first effort, he said.
One of Angell’s goals for the RAC is to fix inconsistencies in planning base cases. He noted that power flow base cases designed for planning are also used for reliability studies. “Those engineers that do reliability studies have a particular expectation of what information is in those particular cases, and they’re not at all interested in fictitious transmission lines and resources and all these things that might come about 10 years from now. ‘If it isn’t in the ground today, or if it isn’t under construction today, I don’t want it in my cases.’
“That ends up creating a disparity between looking at the future 10 years out, where a wind plant can be put up in matter of months,” Angell said. “We’re not talking years like older thermal plants used to take, and so things could change much more rapidly out there, and the ability for some of these engineers to embrace this sort of new and different world has been a struggle.”
Davies pointed to further “interesting interactions” with transmission and resource planners. “Transmission planners only want very sure things in their cases,” whereas resource planners want to include more speculative projects. “They need to work together to identify what actually should be showing up in those base cases.”
Loomis recounted a story that illustrated the uncertainty of including speculative projects in base cases, describing a proposed 460-MW wind farm that had triggered the need for a new 230-kV line in NorthWestern’s Montana system.
The project had an interconnection agreement and transmission service, but half of the planning team refused to include it in base cases for local area planning, saying they couldn’t rely on the resource.
“And I kind of pushed back and said, ‘They have an interconnection agreement and transmission service — this is a no-brainer,’” Loomis said. “To acquiesce to me, they put it in one of our sensitivity analyses and, lo and behold, the project did indeed go away. It’s really hard to know.”
Loomis also pointed to the case of the Highwood Generating Station, a 46-MW gas-fired project in Montana that broke ground in 2010 but was decommissioned five years later before it ever commenced commercial operation after its sponsor declared bankruptcy.
“It’s really hard to know exactly what [will get built], so I think trying to establish some common rules or common expectations for those types of generation projects that are driven by outside entities is a good thing,” she said.
“What we’re looking at is all these different perspectives using a common data source and process and methods to process the data and disseminate the information,” Angell said.
Sharing the Success
Woertz said gathering all the data was essential for “timely and relevant” reliability assessments.
“Regional planning groups, utilities [and] the ISO are doing their own analyses,” he said. “All of the organizations within the West are doing their own analyses, and they all give us a little bit different look at what the potential risks might be. Again, there’s a great need for collaboration and coordination so we can learn from each other as we’re doing these analyses.”
“And we don’t want to be duplicating analyses — and we want to do the right ones,” Angell added.
Davies pondered the ephemeral nature of the questions planners are trying to answer with their analyses. He said a decade ago, the industry was assuming a large amount of wind generation would be built to “serve all the huge loads in California.”
“It seems a lot different today, doesn’t it? Trying to evolve all those questions over time also is going to be part of this,” Davies said.
The graphic illustrates the complex interactions among stakeholders involved in Western system planning. WECC’s Woertz said a breakdown showing actual individuals would “look like a snowstorm.” | WECC
Woertz emphasized that another key objective would be putting the reliability results “into the hands of the right people differently and more effectively than we have in the past.”
“It’s not going to be sufficient to send out a mass email just to our committee people,” he said. “There are probably other people we should proactively reach out to, to actually get the message out to folks. WECC deals strictly with information. We don’t build anything; we don’t operate anything. If we have effective information, reliable data and interpretation of that data, that can be shared with other people,” he said.
Promising Signs
Brian Theaker, director of Western regulatory and market affairs for Middle River Power, urged the panelists not to downplay the impact of public policy in its analyses. He also expressed concern that reliability is “taking a backseat” to the imperatives of policymakers who don’t understand the reliability impacts of their decisions.
“What drives everything in California at this point is the race for decarbonization,” Theaker said. “And though there has been some really good work done that tries to look at some of the other perspectives and bring reliability and adequacy into it, there’s still this inexorable drive of public policy towards decarbonization.”
“In California, the policymakers are leapfrogging over the physics of the system,” said Dick Ferreira, of the Transmission Agency of Northern California. “If the lights go out, everybody’s going to point their fingers at each other.”
Loomis agreed with those concerns and noted a similar situation closer to home for her. “Missoula, Mont., announced that they’re going to 100% green by 2030, and everybody besides the city of Missoula is saying, ‘Wow, so you’re looking forward to some brownouts.’”
Maury Galbraith, executive director of the Western Interstate Energy Board, congratulated WECC and the panelists for providing the “most candid conversation” he’s heard about an issue in front of board members in his five years attending WECC meetings. He also reminded them that he brought up the same issue five years earlier with the creation of the anchor data set and the RAC.
“My question to the panelists is: You have a plan for the next nine months [in the BPS Roles effort]. What’s different today? What’s going to energize people to come to the table and try to address these issues, because you still have basically a collaborative approach to getting this data. You’re still trying to work with people and appeal to their best interests and share the data. What’s changed? What’s different now and why are you hopeful that this is going to work?”
Angell replied that RAC participants “are slowly sensing that there is change” and are “slowly changing to catch up.”
“You know the change cycle, right?” Angell said. “The first [reaction] is: ‘You screwed everything up and now you are harming me.’ Well, it takes a little while for some folks to get back out of being stuck in victim mode and to actually step forward and start working towards solving problems.
“We are starting to see some collaboration occur. It’s a start, and I think with this initiative and further emphasis on it, we’ll continue to move forward.”
ST. PAUL, Minn. — Increasing incidents of extreme winter weather, along with threats to physical and cybersecurity, are the most pressing items identified in Midwest Reliability Organization’s draft Regional Risk Assessment, presented at the organization’s Annual Member and Board of Directors Meeting last week.
The report follows NERC’s 2019 ERO Reliability Risk Priorities Report, which analyzed the risks facing electric utilities on a national scale and grouped them into four major categories: grid transformation; extreme natural events, including both weather and geomagnetic disturbances (GMD); security risks; and critical infrastructure interdependencies. (See NERC Board of Trustees Briefs: Nov. 5, 2019.) MRO aimed to determine which areas had a higher or lower potential burden for operators in the region.
Resource Mix Heightens Weather Impact
Given MRO’s footprint, which extends from Oklahoma to as far north as Saskatchewan and Manitoba, it is not surprising that winter weather, along with GMD events, are a higher priority than for regions in warmer regions. However, officials said winter challenges have become more pronounced over the last 10 years, with extreme events such as the 2011 polar vortex straining grid capacity even in the southern areas of the region.
“Winter peak demand is approaching or exceeding summer peak during severe cold spells. For example, on [the] Jan. 17, 2018, [cold-weather] event in the southern portion of the Midwest, all five entities involved exceeded their winter forecast by about 5 to 13%,” said John Seidel, MRO’s principal technical adviser. “It’s pretty interesting what winter … can cause, mainly due to the electric heating that occurs during the severe cold.” The 2018 event led Gen Operators Cool to Winter Preparedness Standard.)
MRO’s changing resource mix can also complicate the cold-weather issues, as conventional synchronous generation is replaced by renewable options such as wind, with output that is harder to predict. Seidel cited the gap between MISO’s predicted and actual wind energy production during the Jan. 30, 2019, cold-weather event as an example of this concern, adding that the problem was exacerbated when the extreme cold led turbines to hit their cutoff temperatures just as the need for their energy was most acute. (See Extreme Weather Tops NERC Winter Outlook.)
Evolving Threats, Lagging Response
Rapid change is also a hallmark of the technology landscape, and the need to determine how to integrate new technology tools while maintaining the reliability of the grid continues to be a source of headaches for security professionals.
Steen Fjalstad, security and mitigation principal at MRO, observed that 2019 saw no reported cyber or physical security incidents in the bulk power system that caused a loss of load, according to NERC’s Electricity Information Sharing and Analysis Center (E-ISAC). Along with this good news, however, there is also no shortage of reminders about the dangers that can arise from deploying new technology without adequate preparation.
“There have been recent breaches, not necessarily in our sector … due to cloud storage, and … identifying if we have the same risks and liabilities is very important,” Fjalstad said. “It’s kind of a gray area still in terms of components: A lot of the controls that might be in the cloud area [are] under contract, and the legalese … of what’s going into these contracts … is really a very valuable opportunity for us to delve further and reduce this risk.”
Risks highlighted in the cyber and physical security section of the report include a lack of adequately trained security staff and internal cultures focused on compliance rather than proactive threat detection. This feeds into other common problems such as incomplete asset inventory, with Fjalstad observing that “if you don’t know what you have to secure, then it is very hard to make sure that you’re mitigating all the risks.” Third-party equipment suppliers must also be considered a potential security backdoor, with vendors held to as high a standard as a utility’s own staff.
Unmanned aerial vehicles pose a unique challenge, as the intersection between physical and cybersecurity that is not well addressed by current law. (See Feds Late to Act on Drone Threat, DHS Official Says.) Utilities that believe drones are monitoring their facilities have no recourse to law enforcement unless their airspace is violated, and even then, tracking down the operator of the vehicle is easier said than done. Fjalstad said operators must find other ways to protect their assets from unwanted surveillance.
Infrastructure Intersections
While environmental and security concerns dominated the presentation, other topics were suggested for future monitoring. One example is the risk that the growth of electric vehicles and charging stations could exacerbate the weather and resource mix issues. Operators also identified copper theft and vandalism as ongoing dangers — not just to their own equipment, but also among the telecommunication companies on which they rely for remote monitoring.
ERCOT will likely welcome back double-digit reserve margins next year and well into the decade, according to the grid operator’s latest capacity, demand and reserves (CDR) report.
While they won’t provide relief from Texas’ blistering summers, the additional reserves will give ERCOT a little more room to work with than it did in surviving 2019’s record demand with a 8.6% margin — up from an initial historic low of 7.4%.
Released Thursday, ERCOT’s newest CDR indicates its planning reserve margin will hit 10.6% in 2020 and 18.2% in 2021. The margin will shrink again after that, reaching a projected 12.9% in 2024. The grid operator has a target planning reserve margin of 13.75%.
ERCOT’s projected resource capacity through 2024 | ERCOT
“Yes, the reserve margin’s improving, and the [later] years seem to be significantly better,” said Dan Woodfin, ERCOT’s senior director of system operations. “While the reserve margin seems higher in 2020, we could still see some operating days with tight conditions. We’re prepared for that, just like we were last year.”
ERCOT shattered its all-time system peak in August, hitting 74.8 GW and breaking the mark set in 2018 by more than 1 GW. While its resources met peak demand, the grid operator ran into tight conditions during the early afternoon when West Texas wind energy dropped off. It was twice forced to call energy emergency alerts to ease the scarcity. (See “ERCOT CEO Briefs Commission on Summer Performance,” Texas PUC Briefs: Aug. 29, 2019.)
Staff are projecting a peak of more than 76.7 GW in 2020, but they also expect an additional 7.6 GW in new capacity for summer 2020, based on preliminary data from generation owners. Most of those resources are renewable or smaller gas-fired peakers.
ERCOT has approved 1,058 MW of installed capacity for commercial operations since the last CDR was released in May. More than 4,650 MW of installed capacity has become eligible for inclusion in the CDR after completing necessary agreements and permits.
Two canceled gas plants with 1,227 MW of capacity were removed from the CDR, and eight solar projects with a 1,056-MW capacity contribution were delayed until 2021, accounting for the reserve margin’s leap to 18.2% that year.
Wind and solar energy will continue to increase their shares of ERCOT’s fuel mix. Solar’s summer capacity is forecast to account for 9.7% of the fuel mix by 2022, while coal will drop to 15.6%. Wind energy is projected to reach 10.2% of the summer mix in 2024.
ERCOT has changed the way it calculates wind and solar capacity for the CDR, switching to a capacity-weighted average instead of a simple average of historical contributions. Staff also split its non-coastal wind region into “Panhandle” and “other” wind regions.
CARMEL, Ind. — MISO says it will look to make improvements to the capacity testing process after sifting through results from its generators and discovering errors.
The RTO received more than 1,800 submittals from approximately 140 generation operators by the Oct. 31 deadline for its generation verification test capacity (GVTC) process. It requires generation owners to test the capability of their units annually to determine maximum capacity to help calculate MISO’s resource adequacy.
At the Resource Adequacy Subcommittee’s meeting Tuesday, MISO Manager of Capacity Market Administration Eric Thoms said the RTO would reach out to about 40 generation owners this month to discuss correcting possible errors in the submittals in time for the 2020/21 Planning Resource Auction.
Some stakeholders asked how MISO had determined errors had been made in the first place.
“It wouldn’t be obvious to me that we’ve even made errors,” MidAmerican Energy’s Greg Schaefer said.
Thoms said MISO performed a quality and validation review at the behest of its Independent Market Monitor. He said the likely errors are centered on temperature corrections for cooling water and air temperature, generator polarity data, and “misinterpretations” of some of the fields on the survey.
RASC liaison Patrick Brown said that over the next year, the RTO will investigate potential GVTC process improvements to “increase the quality of data being submitted and lesson the burden of MISO’s review.”
“We’re not trying to eat the elephant all at once,” Brown said of working in improvements.
Stakeholders Remain Critical of Capacity Deliverability Remedy
MISO remains committed to tightening capacity deliverability requirements using the same method it proposed in October, but some stakeholders are voicing concerns over reduced capacity credits issued to wind resources.
The RTO has said it will use an intermittent resource’s transmission service request value to set its maximum historical output for the average capacity factor, which will likely reduce a resource’s unforced capacity values and stands to reduce capacity credits. It would only apply the solution to its intermittent resources, citing increasing wind curtailments in the footprint. (See “MISO Pushes Back Deliverability Requirements,” MISO RASC Briefs: Oct. 9, 2019.)
MISO’s Darrin Landstrom said the move will “improve the expectation of generators required to deliver capacity to load.”
“Under the current process, an intermittent resource that is not fully deliverable could acquire capacity credit with the same equality as an intermittent resource that is fully deliverable. Revising capacity accreditation calculations to factor in studied levels of deliverability may incentivize intermittent resources to obtain more deliverability if necessary and/or improve the confidence that capacity is being accredited in a method that more closely aligns with deliverability levels,” MISO said.
The Monitor has argued for more than a year that the RTO doesn’t properly account for capacity deliverability because its loss-of-load expectation (LOLE) study assumes that all capacity resources are fully deliverable on an installed capacity (ICAP) basis. However, it also allows resources to demonstrate deliverability only up to the unforced capacity (UCAP) levels, which tend to be about 5 to 10% below full ICAP levels. The Monitor thinks it should assess deliverability for all capacity resources based on full ICAP.
Madison Gas and Electric’s Megan Wisersky said MISO’s proposal may be expensive in that more capacity resources or more transmission capacity will be required to meet peak loads.
“Are we merely trying to jack up the transmission we’re building, increasing costs to our customers?” she asked.
Landstrom said the proposal might leave some of the wind fleet’s effective load carrying capability (ELCC) unassigned. He said the unassigned ELCC might be applied to resources that have secured full deliverability through transmission service. However, MISO may run into problems if it gives a resource more capacity credit than the reliability, including the issue of “how to slice and divide the ELCC pie.” MISO annually calculates a system-level ELCC, which is currently 15.7% of the MISO wind fleet’s registered maximum capacity.
IMM Michael Chiasson also pointed out that there are few benefits to purchasing transmission service for 100% deliverability. He said it’s possible to achieve zonal resource credit requirements “well under” full deliverability.
“We have some homework to do,” Brown said before closing the discussion. He said MISO may need to delay release of its design concept until February and promised another presentation in January. “In my mind, we have a lot of open questions, and I’ll take that, on behalf of MISO staff.”
The D.C. Circuit Court of Appeals indicated Thursday it will reconsider its precedent that allows FERC to issue “tolling” orders to indefinitely delay action on requests for rehearing.
The court vacated an August 2019 ruling by a three-judge D.C. Circuit panel that rejected challenges to FERC’s approval of Williams’ Atlantic Sunrise natural gas pipeline project, scheduling an en banc oral argument for March 31 (17-1098).
The three-judge panel unanimously rejected the challenges by environmental groups and landowners, but Judge Patricia Millett wrote a concurring opinion sharply critical of FERC, saying it had “transformed this court’s decisions upholding its tolling orders into a bureaucratic purgatory that only Dante could love.”
Millett’s concurrence took no issue with her colleagues’ rejection of complaints that FERC failed to consider the pipeline’s downstream greenhouse gas emissions or to substantiate market need for the project.
President Barack Obama nominated Judge Patricia Millett (right) to the D.C. Circuit Court of Appeals in 2013, along with (from left) Robert L. Wilkins and Cornelia “Nina” Pillard. | The White House
But she expressed sympathy for pipeline opponents’ complaint that FERC denied them due process by allowing construction to begin before the certificate of public convenience and necessity could be challenged in court.
Parties seeking judicial review of such a certificate must first seek rehearing from the commission. Because the Natural Gas Act says rehearing requests are deemed denied if the commission fails to act within 30 days, FERC regularly issues tolling orders granting rehearing “for the limited purpose of further consideration.” It also uses tolling orders to circumvent the 30-day deadline on rehearings under the Federal Power Act.
The commission issued a tolling order in response to a request for rehearing and stay of the Atlantic Sunrise certificate order, then took no action on the stay motions for more than five months before denying them.
Pipeline opponents also sought rehearing of the commission’s Sept. 15, 2017, order granting Williams permission to begin construction. The company began construction that day.
In December 2017, more than nine months after the first rehearing request and three months after construction began, FERC rejected the appeals, making its decisions finally subject to court review.
Pennsylvania portion of Williams’ Atlantic Sunrise natural gas pipeline project, which began service late last year after winning FERC approval in February 2017 | Williams
Millett acknowledged that the D.C. Circuit has previously ruled that the commission’s tolling orders qualify under the NGA as an action upon the rehearing request, effectively stopping the 30-day clock.
“But the commission has twisted our precedent into a Kafkaesque regime,” she wrote. “Under it, the commission can keep homeowners in seemingly endless administrative limbo while energy companies plow ahead, seizing land and constructing the very pipeline that the procedurally handcuffed homeowners seek to stop. The commission does so by casting aside the time limit on rehearing that Congress ordered — treating its decision as final-enough for the pipeline companies to go forward with their construction plans, but not final for the injured landowners to obtain judicial review. This case starkly illustrates why that is not right.”
She noted that the court’s acceptance of tolling orders started in a case that involved disputes over money, not property. “Because disputes over monetary payments can be fixed later, the consequences of commission delay were temporary and remediable,” she said. “But allowing the commission to take its time while private property is being destroyed is another thing altogether.”
Millett said the court could require more timely action by the commission on rehearing requests, or FERC could decline to issue construction orders until it resolves certificate rehearing requests on the merits.
“If that is too administratively burdensome, then the commission could try the easiest path of all: take absolutely no action on the rehearing application. That would have the effect of denying the request as a matter of law. And that approach would have opened the courthouse doors to the homeowners … five months before construction started.”
FERC declined to respond to the ruling, saying it doesn’t comment on court proceedings.
ClearView Energy Partners analyst Christi Tezak said FERC’s tolling orders “may be vulnerable to prospective change” but that the court is unlikely to reject the commission’s use of precedent agreements as evidence of the need for new pipelines, although it was part of the homeowners’ appeal.
“Regardless of how this case plays out, we see little risk to the operation of the Atlantic Sunrise project at this time,” Tezak said in a note to clients. “We also would note that neither the FERC’s [National Environmental Policy Act] review nor its contentious policies on downstream greenhouse gas (GHG) emissions appear to be at issue in this en banc review.”
SALT LAKE CITY — The Western Interconnection’s transition to multiple reliability coordinators ended on a high note Tuesday when SPP took over the remaining portions of Peak Reliability’s territory in the Mountain States region.
Western Electricity Coordinating Council CEO Melanie Frye took note of the happy conclusion to the 18-month process the next day with a touch of regret, even as others noted that the challenges were not all in the past. “Going into this, there was a lot of concern and a lot of angst as to how this would all turn out, but once again the industry has come together and proven what we can do,” Frye said during a WECC Board of Directors meeting Wednesday. “I’m really proud to acknowledge that — and a little saddened with Peak being dissolved. They’ve really been great for the interconnection.”
Under mounting financial pressure as more of its customers signaled their intentions to defect to CAISO’s lower-cost RC service (now called RC West), Peak announced in July 2018 that it would shut its doors by the end of this year.
The announcement — coming about a month after Frye assumed the helm at WECC — set off alarm bells for a region accustomed to being served by one major RC, initiating a scramble by WECC and NERC to ensure a smooth transfer of RC responsibility to CAISO, SPP and BC Hydro. But by September, WECC officials were assuring their board members that they and other industry participants had the situation in hand. (See No ‘Hiccups’ for West’s RC Transition.)
Frye lauded the “tremendous amount of work” done by the new RCs, Alberta Electric System Operator’s existing RC and the “engaged and focused” industry participants who ensured “all of the tools were developed.”
She also “selfishly” called out the key contribution by WECC senior engineer Tim Reynolds, team lead for each RC’s certification.
“It’s been a tremendous lift this year, [and] Tim has performed admirably. I know [he worked] lots of weekends and nights — and I’ve seen the texts and the emails, so I think we really should be proud of what has been accomplished in the interconnection,” Frye said.
She also pointed to Peak’s own role in the transition: “My hat’s off to Peak Reliability, [CEO] Marie Jordan and her entire team. They performed until the very last moment that their services were required.”
Tightening the Seams
Branden Sudduth, WECC vice president of reliability planning and performance analysis, said he had been reflecting on where the organization was a year ago, “anticipating the amount of work that was going to be needed in 2019 to make this a successful transition.”
“Between the utilities, the RC transition coordination group, WECC, NERC and other entities — the new RCs [and] Peak — it really was a herculean effort that they were able to accomplish this this year. They did run into several bumps along the way, but the industry really kind of [grabbed] the bull by the horns and they overcame,” he said.
The Western Interconnection is divided into four reliability coordinator territories with the dissolution of Peak Reliability on Dec. 3. | WECC
Sudduth cautioned that WECC’s work with the RCs wasn’t done, but instead entering a new phase.
“This isn’t it. We can’t just say, ‘Alright, perfect, we’re done. The transition’s complete.’ We need to make sure that these RCs are performing effectively,” he said.
Sudduth outlined WECC’s “next steps,” which include ramping up reliability and security oversight activities — the auditing that will verify the new RCs are following NERC standards. He also emphasized WECC’s role in ensuring that the new RCs reach across newly formed boundaries to work with each other.
“We recognize the importance of ensuring that any seams issues between the RCs are addressed, and this coordination and continued communication between the RCs needs to happen,” he said.
Sudduth noted that while WECC will hold its final RC transition webinar next week, “that doesn’t mean we’re not going to receive regular updates on the new RCs. It just means that that will now continue to happen at [WECC’s] Operating Committee meetings,” held quarterly.
The ‘Fragile’ West
WECC Member Advisory Committee member Fred Heutte, of the Northwest Energy Coalition, added his praise during the board meeting’s public comment period.
“I want to thank and commend WECC for stepping up and doing what really needed to happen to make sure that things did not get sideways, did not fall behind,” Heutte said. “The really strong willingness by all of the new RC coordination organizations to make this work was not going to be enough by itself. There needed to be a cohesive approach and enough pushing to make sure that things got done, and WECC has really succeeded in my view.”
But Heutte expressed reservations about the outcome of fractured RC services in the West, questioning whether the new arrangement will stand the “test of time.”
“I wish everybody the best of luck going forward. As I’ve said before, in the future, we may want to reconsider having multiple RCs in the West. There are some distinctive differences in topology here that make the situation more … fragile, perhaps, than [in] the East, but I know that we’ll pursue this current arrangement as best we can.”
Attorneys for Pacific Gas and Electric urged U.S. Bankruptcy Judge Dennis Montali on Wednesday to quickly approve the utility’s proposed $11 billion settlement with insurance companies and hedge funds, warning that claims could rise much higher if it is rejected.
Opponents countered that the settlement would require wildfire victims to sign “one-sided” releases that could leave them far from whole for their losses.
Stephen Karotkin | Weil, Gotshal & Manges
“No one can challenge the reasonableness of the settlement,” PG&E attorney Stephen Karotkin told Montali during a nearly two-hour hearing, saying it represented a 45% “discount” from more than $20 billion in claims.
Karotkin asked Montali to rule by Friday, calling it a “serious drop-dead date” for the subrogation claimants seeking reimbursement for insurance claim payouts. Swift approval of the deal is essential to the utility’s ability to meet the June 30 deadline for eligibility to participate in an insurance fund for future wildfire claims under Assembly Bill 1054, he said.
“From the debtor’s perspective, we don’t want to take the risk that this [settlement] blows up,” he said.
Robert Julian | Baker & Hostetler
But Robert Julian, representing the Official Committee of Tort Claimants, said the case could be settled within days if the “one-sided” release was eliminated.
Wildfire victims facing hospital bills or damaged homes will be forced to sign the release to obtain cash “because they’re so desperate. That’s not choice,” he said.
“You’re asking me to violate the ‘bird in hand rule’ and let this $11 billion bird fly away,” Montali responded, saying that if he rejects the deal, “maybe there will be a $20 billion or $25 billion set of claims. … That’s not a good thing for anybody.”
With the proposed release, “this case is not resolving,” Julian responded. “I can’t get lawyers to agree to any plan in this case or mediation … or anything because they can’t [endorse] something they can’t recommend under the law. … You’re forcing this release down our throats.”
Rebecca J. Winthrop | Norton Rose Fulbright
Rebecca J. Winthrop, attorney for Adventist Health, whose Feather River Hospital was among 18,700 structures damaged or destroyed by the Camp Fire in November 2018, agreed that the release “is not symmetrical.”
“So, if I want to go against those tree trimmers or against my insurers, I can’t. … That is well beyond what is necessary to protect the insurance carriers,” she said.
Nancy Mitchell | O’Melveny & Myers
Nancy Mitchell, representing Gov. Gavin Newsom, said the governor is concerned that the settlement will leave the utility without enough cash to meet the requirements of AB 1054. She echoed claims the governor’s office made in court filings last month that holders of subrogation claims, some of which also hold equity in PG&E, are using the settlement to improve their holdings. (See Fight Escalates over PG&E Settlement with Insurers.)
“This settlement is about leverage. It is not about a debtor who … is trying to do the right thing,” she said. “This plan is making it impossible for us to evaluate other plans because the debtor is only pursuing one plan.”
Gregory Bray, representing the official Committee of Unsecured Creditors, said the $11 billion settlement is “in the ballpark” but that it should apply also to competing reorganization plans.
In his closing remarks, Karotkin denied that the company was acting in bad faith or taking advantage of wildfire victims, insisting the release provisions challenged by the opponents “are customary and typical.”
Gregory Bray | Milbank
“The debtors are not hell-bent on an equity-sponsored plan. What they are hell-bent on is having the best plan, a financeable plan, that is fair to all of the debtors’ economic stakeholders and will get these debtors out of Chapter 11 in a timely basis so they can participate in the wildfire fund.”
Montali ended the hearing with a pledge to make a ruling, “not to defer a ruling,” as some in the case had urged.
“I can’t promise you how soon it will be,” he said. “I’m trying to keep the decisions coming out. I’ll do my best.”
Bloomberg reported Wednesday that PG&E is close to finalizing a $13.5 billion settlement to wildfire victims, half in cash and the rest in stock in the reorganized company. PG&E stock rose 7% on news of the potential deal, closing at $9.47/share after trading as high as $10.75.
