Maine Presents Microcosm of Massive Climate Challenge

A webinar last week to discuss strategies for meeting Maine’s renewable portfolio standards and emission-reduction targets presented a stark reminder of just how challenging decarbonizing the entire power sector and curtailing global climate change will be.

The Environmental & Energy Technology Council of Maine (E2Tech) on Wednesday invited four panelists to present their own strategy for meeting Maine’s ambitious goals: a 45% greenhouse gas emissions reduction below 1990 levels by 2030, and at least 80% by 2050; and 80% renewable energy by 2030 and 100% by 2050.

Though each speaker emphasized different methods, all would involve an unprecedented buildout in solar and wind energy and a paradigm shift in how electricity is valued on the wholesale and retail markets. It would also involve massive electrification of all sectors of the state’s economy.

“One of the things that became clear as we prepared [for the webinar] is that we are overlapping quite a bit in our findings,” said Jürgen Weiss, a principal with The Brattle Group. “I think that by itself is an interesting observation. We’ll quibble about the last 5% or maybe the last 10% in the details here and there, but the overall conclusions that we come to are strikingly similar actually.”

Richard Silkman, CEO of advising firm Competitive Energy Services, said that converting all end uses of energy to electricity in the state would more than triple the 12 TWh used annually to about 40 TWh, while peak demand would go from about 2 GW to about 10 GW.

Weiss used a previous Brattle study that analyzed New England’s trajectory to obtaining 80% renewables by 2050 to present a comparison to Silkman’s projections. The study showed that the region would need about 200 GW of total capacity, over six times more than it has currently.

“The current pace of adding wind, solar, etc. falls far short of what is needed to build the needed renewable portfolio of 200 GW by 2050, but a steady growth rate of 10% or less per year would do it!” according to Brattle’s Jürgen Weiss. | *The Brattle Group*

“So if I want to scare anybody about how hard it will be to do it, I’ll frame it this way: We took 100 years to build the current electric system of something like 30 GW. Now we have 30 years to build an entirely new system of 200 GW,” Weiss said. “So that’s pretty scary.”

One of the biggest challenges for Maine and the rest of New England is that solar does not have as large a capacity factor as it does in other, sunnier parts of the U.S. New England’s demand also peaks in winter, when sunlight is less productive. That means the state will have to build an extraordinary amount of solar facilities to replace the large, retiring fossil fuel plants in the region, panelists said.

That presents its own challenges, said Richard Perez, senior research associate at the University of Albany’s Atmospheric Sciences Research Center. He focused his presentation on “ultra-high penetration PV,” as he said solar has the highest potential to meet global demand. “When we think of a ‘mix’ of solutions, for me the mix is solar,” he said. “Most of the other energy sources are byproducts of solar.”

Solar has the highest potential capacity of all generating resources, the University of Albany’s Richard Perez said. | *E2Tech*

The main challenge is converting solar from being a seasonal, intermittent resource to a firm, dispatchable one: “something that’s available 24/7/365, without downtime,” Perez said. A massive buildout of storage is one solution, he said, but “extremely expensive … even assuming very low future costs for storage.” Perez’s idea is to build more solar than is actually needed and purposefully curtail it, a model he calls “implicit storage.”

The problem is “nobody pays you to curtail,” making his solution “not dependent on technology; it’s more dependent on the policy and the rules of remuneration.”

The state will also have to evolve from its customer-driven model of renewable procurement. Perez related his own experience with making his New York home a net zero energy consumer: rooftop solar panels, an in-home battery and an electric vehicle. “None of those millions of customers [in his home city of Albany] could do what I did; they don’t have the space or maybe the financial position to do it. And the big industrial customers can not do that either.

“So if I [can] solve my problem and be proud about it, it’s far from solving what we need to do for [the] climate,” he said.

Another challenge is that Maine residents are also very protective of their state’s heavily forested land and scenic mountain views. Under Silkman’s analysis, onshore wind would also have to significantly increase, though not as much as solar, from 1 GW currently to 2.5 GW. That’s “problematic in Maine, I understand, given people’s love for mountaintops,” he said.

Perez noted grassroots, environmental opposition to PV development on the grounds of protecting land and trees. He said it would take 8,500 square miles to power the U.S. with 55% solar under his model of overbuilding. “So, it looks gigantic … until you put it in perspective and look at the ground distribution in the U.S.” That 8,500 square miles represents about 1% of farmland in the contiguous U.S., he said.

The yellow dot in the southwestern corner of the map represents the space necessary to generate 55% of Maine’s electricity with solar power. | *E2Tech*

In Maine, assuming the same proportion of solar in the generation mix, facilities would only take up 37 square km — compared to the state’s nearly 56,000 square km of forest. “There’s so much space, in fact, you could even foresee doing away with wind” and using 100% solar, he said.

‘Fall Far Short’

The panelists’ projections and strategies made it clear that Maine and New England are behind on achieving their goals.

“At the current rates of deployment of renewables that are now on the horizon for the next decade, we’re going to fall far short of building these large capacities of renewable resources by 2050,” Weiss said. “We have to roughly increase the annual average deployment rate [by] four to eight times … about [3,000] to 6,000 MW per year” between now and 2050. “So that’s scary.”

Regarding emissions reductions, Silkman said that the state’s 2050 goal is still possible if it significantly ramps up its electrification and renewable buildout. “But it’s not going to happen in the 2020s, no matter what we do,” he said. “This decade’s gone. But we can start to see some serious reductions in the 2030s and 2040s.”

Kurt Adams, CEO of Summit Utilities, concluded his remarks by encouraging attendees. “Stay humble and work hard,” he said. “We’re changing the status quo. It’s very, very difficult. And it’s very difficult for a lot of reasons. So it just takes a lot of work and a lot of checking yourself and thinking about how you’re moving things forward, rejecting your ideas if they’re not being successful and picking the next one up and driving forward.”

June 16, 2020

Vistra, Oncor in for COVID-19’s Long Haul

Two of Texas’ largest power companies say they are in no hurry to return employees to their offices, an indication of the electric industry’s caution around the coronavirus pandemic and its importance to the economy and everyday life.

Vistra Energy CEO Curt Morgan and Oncor CEO Allen Nye both said during a recent Gulf Coast Power Association video panel discussion that they are taking great care in returning their staff to the workplace.

Nye at GCPA webinar — Oncor CEO Allen Nye details COVID-19’s impact on the company. | *GCPA*

“We’ll probably be one of the last to go back to the workplace. We have no intention of bringing anyone back until we’re certain we can do so in a healthy manner,” Nye said during the June 4 discussion. “We recognize the critical nature of the service we provide. It’s been made abundantly clear to me that we have to keep the lights on. We have productivity in the company and the lights are on.”

“How, as the CEO of a company, can you bring people back if you can get the same productivity from people at home but you’re adding incremental risk to your people?” Morgan said. “It’s a very simply equation for us. Our people don’t want to do it. They’re afraid. Some have kids and don’t want to bring anything home. We’re not coming back until we have a vaccine or a therapeutic that works.”

It’s not just electric utilities taking a go-slow approach. MISO has gone so far as to call off all in-person meetings until next year. (See Wary of Contagion, MISO Bars Visitors for 2020.) CAISO has shut down in-person meetings until mid-September. PJM’s companywide telecommuting posture is likely to extend well into the fall.

SPP said last week it has postponed by two months its plan for returning staff to its facilities in Little Rock, Ark. — until Sept. 8, at the earliest. The RTO had originally planned a July 6 phased return, but the state has experienced a rise of confirmed cases, with hospitalizations up 88% and active cases nearly doubling since Memorial Day.

In an email to stakeholders, CEO Barbara Sugg said SPP “will always put [employees’] health and safety first” when deciding to return them to the office. The grid operator has hired an epidemiologist to tour its corporate headquarters and review the controls it has put in place.

“We are also examining internal policies and resources to support a longer-term transition” that also allows for continued telecommuting, Sugg said.

The RTOs and utilities have discovered that the office environment is actually conducive in spreading the coronavirus. Elevators, coffee machines and office kitchens, once taken for granted, now present dangers in a COVID-19 world.

“I’ve found from other [companies] sending people back that the restroom is the issue,” Morgan said, pointing to social-distancing requirements that would force employees to wait in lines. “It’s going to be really difficult to be productive when you have to stand in line to go to the bathroom.”

Vistra has organized a “planning-ahead” team to determine how best to bring back about 1,000 employees to its large open office space. Morgan said the team is working on more than 100 tasks to ready the office. The company also has an in-house doctor and is trying to get access to testing.

“I’m anxious to get back. Employees are asking us when we’ll return,” Morgan said. “Safety is bigger than anything else. Health is bigger than anything else.”

Cultural Shift

Vistra shut down its offices very early, Morgan said. He said the company has a “number of folks” from China, including some from Wuhan, where the coronavirus originated. As early as mid-February, Morgan said, Vistra started getting reports “that there was something terribly wrong in China.”

Morgan at GCPA webinar — Vistra CEO Curt Morgan participates in a GCPA panel discussion. | *GCPA*

The company’s early focus was on Luminant, its competitive generation business. The company began testing employees, primarily at power plants, and discovered “a number” of people with high temperatures. “That made people think, ‘This is really serious,’” Morgan said.

Concerned employees were allowed to stay home without taking paid time off. That created a cultural shift for power plant staff and others, Morgan said.

“Power plant employees want to go to work. They want to be at the plant,” he said.

Luminant added portable washing stations at its plants and tried to socially distance as much as possible. Contractors helping with spring maintenance outages stayed in local hotels and were required to undergo temperature checks before entering the plants’ front gates.

“Those types of things were important to also get contractors to have that same mindset [as staff],” Morgan said. “We got a little pushback, but we told them they would not step on site if they didn’t do the things the way we did.”

Through it all, a staff of 3,000 or so Luminant employees and contractors completed 86 outages without a single plant-related infection.

“I don’t think it’s a coincidence,” Morgan said. He did note a couple of employees tested positive for COVID-19, “but that was because of contact tracing.”

Closer Through Distancing

Oncor took similar early action, dusting off its 13-year-old pandemic plan and implementing it in early January. By March 16, the company reached the highest of four levels and sent everyone home.

Everyone, that is, except the 1,200 or so service staff, line workers and other field employees. Each employee was assigned a vehicle that could be taken home at night and sanitized. Because it moved early, Oncor was able to lease enough additional vehicles and secure personal protection equipment for those in the field.

The company has adapted its processes to the new normal. Safety meetings are now conducted virtually. Employees are no longer shared with other teams, and they have to make appointments at their shops to pick up tools. Backup facilities are used so that as one group finishes its 12-hour shifts, that facility is cleaned during the next 12 hours while employees work out of the primary facility. Catered food is brought to the field, where employees can eat in their trucks.

Nye said only two employees have tested positive for COVID-19 and both have recovered. “That indicates the plan is working very well.

“I had my doubts when we started this,” said Nye, who participated in the panel after an earlier video call with 800 employees. “It’s an entirely different world. We’ve never gone this remote, this virtual, but I’m very pleased with how the technology has held up. We’re all working longer and harder, but overall, I’ve been very encouraged and very relieved that it’s worked out as well as it has.”

Like Nye, Morgan said communications with a virtual staff had held up well. Vistra is attracting as many as 3,000 employees to its weekly live streams, and executives are answering as many as 400 comments after each event. A recent request for pictures of staff’s home offices and their helpers drew hundreds of photos.

“It’s interesting how many people have pets,” Morgan said. “I think our company today is closer than we were prior to this. I like being in the same room with people, but we try to do the best we can with what we have.”

June 14, 2020

NYPSC Approves Cooling Relief for New Yorkers

The New York Public Service Commission on Thursday approved more than $70 million in electric bill relief over the summer for low-income Consolidated Edison customers in New York City and Westchester County (20-M-0231).

The commission also initiated a proceeding to identify and address the effects of the COVID-19 pandemic on utility and other regulated services and programs statewide (20-M-0266).

“Since the start of the pandemic and the economic downturn, the commission has acted to respond to the most pressing COVID-related impacts for customers on a timely basis as these issues have emerged,” PSC Chair John B. Rhodes said. “With this action today, we continue to enable prompt responses on pressing needs for relief and adjustments, as well as dealing with the full range of the impacts in a comprehensive, thoughtful and thorough manner.”

New York City had petitioned the PSC for bill relief for the more than 400,000 customers enrolled in Con Ed’s low-income bill discount program for the months of June through September. The program is intended to remove financial impediments of using air conditioning this summer when officials expect limited availability of public facilities such as cooling centers and public pools as a result of the pandemic. The population density of the city makes these public facilities crucial during the hot summer months, Rhodes said.

The emergency summer cooling credit will add up to $40/month in relief, which, for most customers, is more than double the size of the current low-income program bill discount.

“It is my suspicion that the population of low-income customers eligible for this program or for any number of programs will grow substantially,” Commissioner John Howard said. “There’s a very real possibility that the dollars we have set aside for the program may not go far enough as we move into the summer.”

2019 Reliability and Safety Scores

Con Ed and New York State Electric and Gas (NYSEG) were the only utilities that failed to meet their reliability targets in 2019, the PSC reported last week.

The report on 2019 Electric Reliability Performance in New York State relies on two primary metrics to measure electric performance: System Average Interruption Frequency Index (SAIFI or frequency) and the Customer Average Interruption Duration Index (CAIDI or duration) (20-E-0045).

The most significant events influencing reliability performance, outside of major storms, were two significant outages Con Ed incurred last summer. Some 72,000 customers on Manhattan lost power for three to five hours on July 13, 2019, as Con Ed lost six networks. On July 21, 2019, it de-energized customers in Brooklyn during a heat wave, impacting 30,000 customers for an average of 11.5 hours.

Excluding major storms, the statewide interruption duration for 2019 was 2.05 hours, an increase from 2018’s 1.96 hours and five-year average of 1.94 hours. Excluding Con Ed, the 2019 average was 1.88 hours, the same as 2018 and close to the five-year average.

Department of Public Service staff are investigating the Manhattan and Brooklyn outages and developing recommendations for improvements. (See Con Ed: Failed Relay Protections Caused NYC Blackout.)

New York PSC — Statewide customer hours of interruption in New York, including major storms, in the 2019 Electric Reliability Performance Report | *New York DPS*

Excluding storms, the statewide interruption frequency for 2019 was the same as 2018 and five-year average, with equipment failures, tree contacts, and accidents or events not under the utility’s control responsible for 83% of interruptions.

Con Ed and NYSEG failed to meet their reliability targets for outage frequency, and Con Ed also failed to meet its target for outage duration. Tree contacts and equipment failures were responsible for more than two-thirds of NYSEG’s interruptions.

Rochester Gas & Electric will be penalized $525,000 for failing to meet its targets for estimated meter reads and answering customer service calls in 30 seconds.

“While most utilities are doing a good job providing safe and reliable service, three utilities have fallen short of our expectations in certain areas, and we will continue to act aggressively to ensure utilities improve performance,” Rhodes said. “This is a foundationally important topic, and I’m very eager to see us resume progress.”

Commissioner Diane Burman said the presentations on customer service performance, electric reliability and electric safety standards were “very helpful to us, especially as we look to further planning and refinement as necessary. It’s also helpful, as the focus is on the major causes of interruption that may occur from the past year that may have timely information on the status of any pending matters that we may be looking at.”

Stray Voltage

DPS staff also delivered the 2019 Electric Safety Standards Performance report, whose special focus on testing stray voltage from streetlights highlighted the increasing ownership of such lighting by municipalities (20-E-0098).

In 2019, manual stray voltage testing was performed on approximately 1 million utility facilities statewide, resulting in the identification of only 302 stray voltage conditions, all of which were quickly remediated, the report said. In addition, the utilities also performed mobile scans in major cities, and all stray voltage findings from those surveys were remediated.

“This is a reassuring report,” Commissioner James S. Alesi said. “All of the utilities are following testing standards for stray voltage, and these efforts are successful to the extent that no revenue adjustments have been required, so that’s good news.”

Howard said that he had “a little personal history with this issue.”

“In the ’90s when I was working in the legislature, there was a serious problem with stray voltage, ranging from people and pets being injured in New York City, largely related to streetlight issues, as well as to cows being shocked upstate,” Howard said. “It’s very gratifying that over this period that has been greatly improved for the safety of the public.”

Howard added two cautionary notes.

“First, to echo Commissioner Burman’s comments regarding as municipalities take over the responsibility for owning and operating their streetlighting systems, they understand that along with the savings goes the responsibility of maintaining the streetlighting system to a very high standard,” he said.

“The second item is — and it goes hand in hand with my first comment — is as we build out the 5G network across the state, it largely will be connected to streetlights,” Howard said. “That work will largely be done by third-party vendors; we should put particular emphasis on how the 5G buildout is done, and that no safety issues occur because of bad practices that may occur from one or more vendors.”

June 14, 2020February 19, 2025

FERC Revises Pipeline Policy on Landowner Concerns

Seeking to address due process concerns over its use of tolling orders, FERC said last week it will no longer permit gas pipeline developers to begin construction until it acts on the merits of any rehearing requests (Order 871, RM20-15).

The commission issued the final rule June 9 as it awaits a ruling by the D.C. Circuit Court of Appeals on its controversial practice of issuing tolling orders granting rehearing for the “limited purpose of further consideration.” Under the Natural Gas Act and Federal Power Act, rehearing requests are considered denied if not acted on by the commission within 30 days.

The commission typically takes months — in some cases years — before acting on the merits of the requests, during which pipeline developers have sometimes completed construction.

The D.C. Circuit previously ruled that issuing a tolling order within the 30-day time frame meant that FERC had “acted upon” the request under the language of the statute, and that parties must wait until the commission’s review of the request is actually complete before seeking relief in federal court. But at oral arguments in April, the court seemed to be rethinking its position. (See DC Circuit Skeptical of FERC Tolling Orders.)

FERC pipeline policy impacts construction

Natural gas pipeline construction | Williams

D.C. Circuit Judge Patricia Millett has called the commission’s practice a “Kafkaesque regime” that allows “the commission [to] 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.”

FERC’s new policy applies to pipeline projects under Section 7 of the Natural Gas Act and import and export requests under Section 3.

The new rule follows Chairman Neil Chatterjee’s September 2019 pledge that FERC would seek to reduce tolling orders and act on landowner rehearing requests within 30 days. In February, the chairman announced the creation of a new rehearing section within the Office of the General Counsel to expedite action.

“These are complex issues, with a diverse array of stakeholder input, but I remain firmly committed to doing what we can to make the FERC process as fair, open and transparent as possible for all those affected while the commission thoroughly considers all issues,” Chatterjee said in a statement.

In a partial dissent, Commissioner Richard Glick called the policy change a “step in the right direction.” But he said it fell short because it still allows pipeline companies to commence eminent domain proceedings under Section 7 before landowners can go to court to challenge the certificate.

Glick said the commission should presumptively stay Section 7 certificates pending its action on the merits of any rehearing requests.

“The harm to an individual from having his or her land condemned is one that may never be fully remedied, even in the event they receive their constitutionally required compensation. Bearing those basic facts in mind, there is something fundamentally unfair about a regulatory regime that allows a private entity to start the process of condemning an individual’s land before the landowner can go to court to contest the basis for that condemnation action,” Glick wrote.

Although the rule will not take effect until 30 days after publication in the Federal Register, the commission said it will not authorize construction on any projects pending rehearing in the interim.

After issuing the ruling, FERC filed an “additional submission” advising the D.C. Circuit of its action.

In a note to clients, ClearView Energy Partners said the commission’s order is an attempt to preserve its ability to issue tolling orders and prevent certificates from being stayed during the rehearing process. “We also think that the FERC’s action lowers risk that it could lose the ability to toll rehearing action across all its activities, including the considerably more numerous electric proceedings it acts on each year,” ClearView said.

June 14, 2020

OMS-MISO Survey Sees Uncertain Supply Future

MISO’s margins are tighter and the footprint could face a generation shortfall as early as 2022, but interconnection projects could save the day, according to the annual capacity projection by the Organization of MISO States and the RTO.

The OMS-MISO resource adequacy survey released Friday forecasts 0.8 GW in excess firm capacity beyond the planning reserve margin for 2021. All other years in the five-year outlook contain the potential of a capacity shortfall.

However, the survey still shows greater potential for surpluses larger than any possible deficit through 2025. In addition to the nearly 1 GW near-certain excess in 2021, there’s also potential for a surplus as high as 7.2 GW. And while 2022 could hold a 0.4-GW shortfall, it would see a 11.2-GW surplus if all proposed resources in the interconnection queue were realized.

The best of times, worst of times picture gets starker over the next three years:

2023 could bring a 3.5-GW deficit or 12.5-GW in excess capacity;
2024 could hold a 5.6-GW shortfall or an 11.1-GW surplus; and
2025 might contain a 6.8-GW deficit or a 10-GW surplus.

The survey paints a less rosy supply picture than last year’s assessment. MISO attributed the greater possibility for near-term shortages to a steadily climbing planning reserve margin — upped from nearly 16% in 2017 to about 18% today — and “modest” load growth. Last year’s survey predicted adequate reserves through 2022 and showed MISO’s footprint could experience anything from a 6.8-GW surplus to a 2.3-GW shortfall by 2024. (See Supply Future Brighter, OMS-MISO Survey Shows.)

OMS-MISO Survey Results — 2020 OMS-MISO survey results | *MISO*

Speaking at a special conference call to review the results Friday, MISO Executive Director of Market Operations and Resource Adequacy Shawn McFarlane said that since the last survey, some generation completed MISO’s interconnection queue, reducing possible risks, though some zones remain vulnerable. This year’s assessment singled out Lower Michigan’s Zone 7, Southern Illinois’ Zone 4, Wisconsin and Upper Michigan’s Zone 2, and Indiana and western Kentucky’s Zone 6 for the greatest resource adequacy risks. The 2019 survey also called out Zone 7, Zone 4 and Zone 6 for supply risks.

McFarlane also said MISO’s projected annual demand growth rate rose from 0.2% in 2019 to 0.3% this year. He added that the survey also does not contemplate the long-term effects of the coronavirus pandemic.

“Even with the supply risk, we do have a healthy queue, and it looks like zones will be able to firm up resources in the coming years,” McFarlane said. “The range that we have here is a reflection that resource planning is an ongoing process. … In fact, one of the purposes of the survey is to have utilities and regulators react to the risk and plan accordingly.”

Clean Grid Alliance’s Natalie McIntire asked if MISO is considering that it also needs a transmission buildout, especially in the Upper Midwest, to facilitate the generation in the interconnection queue that the RTO is betting will cover deficit risks. “Not only do we need generation in the queue, we need transmission to deliver it,” she said.

Customized Energy Solutions’ David Sapper also asked about the “mass exodus” in the queue last year, when several planned projects were canceled because of high network upgrade costs. MISO had about 100 GW in the queue last year; that has since dropped to about 80 GW.

“I’m not trying to imply that, ‘Everything’s great; we can relax.’ I’m saying there’s enough generation with a high degree of certainty in the queue that can help with risks in these coming years,” McFarlane said. “Certainly, looking out to 2025, there’s some ground to plow in terms of getting to a comfort level in resource adequacy. … The queue does have several projects in advanced stages that could turn potential capacity into committed.”

OMS President Matt Schuerger said the survey is more important than ever as the generation mix changes. This year, MISO said more than 94% of load-serving entities responded to the survey.

MISO will again review survey results with stakeholders during the Resource Adequacy Subcommittee’s July 8 conference call.

June 14, 2020

MISO: New Outage Rules Boosted Mich. Capacity Prices

MISO confirmed last week that a new rule prohibiting resources on extended outages from offering capacity contributed to the historic spike in Lower Michigan prices in April’s Planning Resource Auction (PRA).

Zone 7 cleared at the cost of new entry (CONE) price of $257.53/MW-day for the 2020/21 planning year that began June 1, while all other zones cleared under $7/MW-day. Zone 7 fell 123 MW short of its nearly 22-GW local clearing requirement and had to turn to other zones for capacity procurement, activating the CONE price. (See Michigan Prices Soar in 8th MISO Capacity Auction.)

MISO Outage rules impacted Zone 7 in the PRA — MISO’s Zone 7 | *MISO*

MISO now restricts extended planned outages to a cumulative 90 days in the first 120 days of the planning year — June 1 to Sept. 30 — which it deems the most critical months for demand and loss-of-load risk. Resources that will be unavailable for more than 90 days are disqualified from PRA participation.

MISO Manager of Capacity Market Administration Eric Thoms told the Resource Adequacy Subcommittee on Wednesday that if the long-term outage policy had also been in effect for the 2019/20 PRA, Zone 7 would have fallen short of its local clearing requirement then as well.

Zone 7 also would have come up short by nearly 222 MW, Thoms said. Last year, Zone 7 had a 21.8-GW local clearing requirement and received slightly more than 22 GW from capacity offers and utilities’ fixed resource adequacy plans. However, about 474 MW of capacity wouldn’t have qualified for the auction based on planned outage schedules.

Under the new outage rule, MISO analysis showed a loss of load in Zone 7 occurring one day in six years in 2019. If the zone had not imported capacity this year to meet its local clearing requirement, the risk would have been one day in eight years. MISO adheres to a one-day-in-10-years standard.

MISO adopted the rule after the Independent Market Monitor last year criticized the RTO for allowing a large generator in Michigan to clear the PRA even though it was slated to be on outage the entire planning year. (See Emergencies Prompt MISO to Re-examine LMR Protocols.) Had MISO disqualified the generator from the auction, prices in Zone 7 might have hit $243.37/MW-day instead of the $24.30/MW-day clearing price in 2019, the Monitor said.

Coalition of Midwest Transmission Customers attorney Jim Dauphinais said MISO’s analysis shows the importance of the new rule.

June 14, 2020

MISO Seeks Extension on Midwest-South Tx Limit

Without a viable alternative on the horizon, MISO will likely extend its settlement agreement for flows on the Midwest-South subregional transmission constraint through early 2023.

“Until there’s a longer-term solution in place … the recommendation is to extend that settlement agreement until Jan. 31, 2023,” MISO Director of Seams Coordination Jeremiah Doner told stakeholders during a Market Subcommittee teleconference Thursday.

Doner said discussions with SPP and the other parties to the agreements on its future are in the early stages.

MISO Transmission Limit — Parties to the settlement agreement for MISO’s Midwest-South subregional transmission constraint | *MISO*

Starting Jan. 31, 2021, the settlement may be terminated by any party with a year’s notice. Without a replacement settlement, flows would be limited to MISO’s original 1,000-MW contract path in either direction. The settlement limits MISO to 3,000 MW of flows in the north-to-south direction and 2,500 MW of flows in the other.

Earlier this year, the parties signed a memorandum of understanding that they wouldn’t propose changes to the settlement until Feb. 1, 2022. Doner said an extension until 2023 will buy time for them to explore eventually changing the terms of the agreement.

Stakeholders asked if MISO would consider negotiating an increase in its transfer capability.

“I think it’s fair to say everything is on the table at this point,” Doner said, adding that MISO hasn’t ruled out a transmission project to increase transfer capability between its South and Midwest regions. After completing a special study, MISO last month said it wouldn’t recommend any upgrade to secure more transfer capability to its Board of Directors this year. (See “No Midwest-South Tx Solution this Year,” Price Tag Rising for MTEP 20.)

Doner said that while some aspects of the settlement discussions are confidential, MISO will share what it can with stakeholders in upcoming public meetings.

A two-year extension would keep in place MISO’s current cost allocation for transmission above 1,000-MW flows. MISO’s payments to the other parties for such flows are recovered from market participants through a combination of load ratio calculations and flow-based beneficiary allocations.

The load-based share declined every year since 2016 as the flow-based portion increased. From Feb. 1, 2016, to Jan. 31, 2017, the allocation was 45% load-based and 55% flow-based. From Feb. 1, 2020, to Jan. 31, 2021, the mix is 10% load-based and 90% flow-based. Doner said MISO would keep the current allocation under the extension.

Because of the declining importance of the load-based allocation, some stakeholders said MISO’s next logical step would be to use a 100% flow-based allocation through early 2023.

Doner took no position on the suggestion but noted MISO would have to win FERC approval for a Tariff revision to either change the cost allocation or pursue an extension of the current rate schedule.

“If all of the parties are good with the terms of the agreement, that settlement agreement can continue in perpetuity, essentially,” Donner said. He said the settlement also contemplates an extension of the original terms, with 2% annual cost escalations written in for use of the regional directional transfer.

However, if any changes to the settlement agreement are made before the Jan. 31, 2023, extension is up, it would trigger a requirement to also review the existing rate schedule.

Doner asked for written stakeholder comments on the extension by July 2.

June 14, 2020

MISO Drafts COVID-19 Waiver for LMRs

MISO last week said it will file a one-time waiver with FERC to make sure market participants can replace load-modifying resources (LMRs) impacted by the coronavirus pandemic.

Some LMRs that cleared in the Planning Resource Auction in April “may be unable to perform at their full accredited value as a result of COVID-19-related temporary — or, in some cases, permanent — closure of businesses that constitute their LMR assets,” MISO Manager of Capacity Market Administration Eric Thoms said during a Resource Adequacy Subcommittee teleconference Wednesday.

Thoms said market participants that manage a cleared LMR that is directly impacted by the pandemic must attest via email that the asset can no longer fulfill capacity obligations.

If FERC accepts MISO’s filing, those market participants will have the opportunity to use new LMRs with MISO to “bolster their portfolio,” Thoms said.

The waiver won’t allow members to change existing LMR registration records, Thoms said. Instead, market participants must make a replacement registration in MISO’s capacity tracking tool. That way, the RTO will have an “audit trail of replaced LMR resources and modified underlying assets,” Thoms said.

MISO plans to make the filing this month and will ask the commission for a July 1 effective date. From there, market participants will have 90 days through September to register replacement LMRs.

Usually, MISO market participants must register existing LMRs by Feb. 1, new LMRs for use in fixed resource adequacy plans by Feb. 15 and new LMRs not used in fixed resource adequacy plans by March 1 for the upcoming planning year.

“We’ll have an ability to reassess the effects of the pandemic after 90 days,” Thoms said, adding that MISO will have the “option to request a renewal of the waiver” if the pandemic is still affecting LMRs’ ability to respond.

But stakeholders argue that MISO isn’t considering the full gamut of difficulties wrought by the pandemic.

Xcel Energy’s Kari Hassler asked how the waiver could help a large LMR that permanently closes, taking with it both load and some measure to control it.

Thoms said MISO isn’t currently considering any reductions in planning reserve margins from load losses caused by the pandemic.

Multiple stakeholders argued that reserve margins should also be lowered because the load that needed to be curtailed no longer exists.

“I agree that there’s a mismatch here,” Customized Energy Solutions’ Ted Kuhn said.

Thoms said MISO does not yet know what LMR closures might be temporary or permanent.

“We have a financially binding construct that is already settled,” he explained. He also said impacted market participants are not obligated to use the waiver and can instead notify the RTO through the MISO Communications System that their LMRs are less available. LMRs are required to respond to at least five emergency events per year.

Alliant Energy’s Mitch Myhre said his utility has had difficulties even performing the MISO-required LMR testing, as some large commercial and industrial customers haven’t been operating as usual. Other stakeholders said they were experiencing similar testing difficulties.

This is MISO’s second filing for a waiver of Tariff requirements in response to the pandemic. FERC granted the RTO’s request for a 60-day extension of its June 25 site control demonstration deadline late last month as the pandemic slowed construction and shuttered government offices (ER20-1794). (See “Queue Waiver Request Before FERC,” Wary of Contagion, MISO Bars Visitors for 2020.)

June 14, 2020

PJM MRC/MC Preview: June 18, 2020

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committee meetings on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

Members will be asked to endorse the following manual changes:

B. Manual 14A: New Services Request Process, Manual 14E: Upgrade and Transmission Interconnection Requests and Manual 14G: Generation Interconnection Requests.

Periodic review, including clarifying and administrative changes.

Endorsements/Approvals (9:10-9:35)

1. Emerging Technologies Forum (9:10-9:20)

Members will be asked to endorse the charter of a new group to provide transparency for PJM’s Advanced Technology Pilot Program (ATPP), a testing ground to study the technologies to enhance system reliability, operational and market efficiency, and resilience. The group was changed to a forum after stakeholders expressed concerns about adding another subcommittee. It will provide reports to the MRC, as well as the Planning, Operating and Market Implementation committees. (See “Emerging Technologies Subcommittee Proposed,” PJM MRC Briefs: April 30, 2020.)

2. Stakeholder Group Sunsets (9:20-9:35)

Members will be asked to endorse the sunsetting of eight stakeholder groups, which PJM determined were either dormant or had implemented their original tasks. (See “Task Force Sunset,” PJM MRC Briefs: May 28, 2020.)

Members Committee

Consent Agenda (10:35-10:40)

B. Members will be asked to endorse Tariff revisions to allow surety bonds as a form of collateral. The proposal, originally endorsed in October 2018 at the MIC, allows the use of surety bonds for all market purposes except financial transmission rights, with a $10 million cap per issuer for each member and a $50 million aggregate cap per issuer. (See “Surety Bond Proposal Endorsed,” PJM MRC Briefs: May 28, 2020.)

Endorsements/Approvals (10:40-11:35)

1. PMA Credit Requirements (10:40-10:50)

Members will be asked to endorse proposed Tariff revisions related to peak market activity credit requirements for federal, state and/or local law transfer of charges or credits. The revisions address a regulatory change in Ohio concerning the billing of network integration transmission service. (See “PMA Credit Requirements,” PJM MRC Briefs: May 28, 2020.)

2. Transparency and End-of-life Planning (10:50-11:35)

Joint stakeholders, including American Municipal Power, Old Dominion Electric Cooperative, LS Power and members of the PJM Industrial Customer Coalition, will ask for a vote on their transparency and end-of-life (EOL) planning proposal for revisions to the Tariff. The EOL proposal narrowly failed last month at the MRC meeting. (See PJM End-of-life Proposals Fail at MRC.)

June 14, 2020

WECC Seeks to ‘Invent’ Future with RA Forum

The Western Electricity Coordinating Council last week kicked off a resource adequacy initiative that revealed as much about how the organization hopes to position itself for the future as it does about its efforts to address a looming RA shortage.

WECC’s new Resource Adequacy Forum is the product of a half-day reliability workshop held in Seattle in February, where industry stakeholders from across the West engaged in a series of group exercises to help the NERC regional entity identify its near-term priorities.

During a “walk-around” exercise at the workshop, participants were encouraged to circulate throughout a conference room decorated with posters showing descriptions of NERC-identified risks. The largest contingent clustered around the “Resource Adequacy and Performance” poster when it came time to vote on what risks WECC should prioritize. (See WECC Should Keep it Regional, Stakeholders S ay.)

During a kick-off webinar that attracted nearly 170 participants Thursday, WECC staff emphasized the loose structure of the RA forum, saying it won’t report to any committee, establish a charter, keep meeting minutes or produce binding rules. WECC hopes to convene the forum in person twice a year, including this fall.

So why is WECC advancing the effort?

“The first ‘why’ really has to do with WECC’s identity as an organization,” said Vic Howell, the RE’s director of reliability risk management.

“WECC has been undergoing a very purposeful and deliberate transformation initiative that began a few years ago, where we’ve begun to ask ourselves some hard questions about our identity as a company,” Howell said.

After examining its “default future,” he said, WECC sought a different, “invented” future “characterized by a partnership where we put a strong focus on collaborating with stakeholders to strive for what we consider to be our common goal of having a reliable and secure interconnection.”

(In an email to ERO Insider, WECC Manager of Communications and Outreach Julie Booth defined the default future as “our future with no intervention or attempt to change the course of that future. WECC acknowledges that our future will happen, but we choose to shape what that future looks like.”)

“We really see this forum as a manifestation of that invented future, because we’re partnering with you folks to collaboratively address the reliability topic of resource adequacy,” Howell said. “That’s really the foundational reason why we’re creating this forum. Also, many of you know that recent studies have shown that resource adequacy is an emerging reliability risk in the interconnection.”

Turning to more concrete goals, Howell said WECC intends to “supplement” NERC’s annual Long-Term Reliability Assessment (LTRA) with its own RA assessment.

“We learned that there are several aspects of the NERC LTRA that really could use some improvement to better meet the needs of policymakers in the West,” Howell said. Rather than changing the NERC process, WECC would perform a separate RA study or set of studies that allow for more flexibility in assumptions and reporting assessment techniques, as well as inclusion of a wider range of scenarios, he said.

“This way we’re able to meet our obligations to NERC and adhere to their rules while at the same time producing a separate work product that’s more tailor-made for the West.”

Howell said WECC also aims to “partner” with its entities to support their RA work, which could include:

reviewing and comparing study assumptions;
assisting entities with their assumptions on their seams;
providing insight and education as entities develop RA programs; and
helping with model-building and interpretation of results.

WECC also hopes its forum will become a “hub” for RA discussions.

“When it comes to resource adequacy assessments, we have a good wide-area view,” Howell said. “In our reliability-focused studies, we’re looking at the entirety of the Western Interconnection, while others are looking at their specific areas. We believe that this broader view can supplement — not replace — the resource adequacy studies that are currently being done at the entity level.”

Howell touted WECC’s position of policy neutrality as being a “big deal.”

“We believe that positions us well for serving as a hub for adequacy discussions — that independence aspect of WECC that we bring,” he said.

‘Honest Broker’

WECC’s new vice president of strategic engagement and general counsel, Jordan White, picked up on the theme of the RE being an “honest broker” of information.

“As a regulator who was formerly charged with making resource planning decisions, I know that unbiased and transparent information and analysis are really key and essential in making sound decisions that impact long-term resource adequacy in the region,” said White, who joined WECC in May after serving on Utah’s Public Service Commission since 2015. “I know the same is true for policymakers, resource planners and utility executives who all rely on sound information to inform their respective resource adequacy roles.”

White said WECC wants to better understand the “world” of its stakeholders.

“What are the drivers and levers of your planning and decision-making? What are your modeling tools, planning cycles, data sources and assumptions? We want to know what keeps you up at night and how we can help. In turn, we hope you gain a better understanding of WECC’s methodologies, data sources and tools, and where there might be potential collaboration opportunities,” White said.

He also urged regional stakeholders “to break down unproductive information silos and to allow facts and analysis to drive sound decisions that promote reliability for the entire Western Interconnection.”

Looking ahead to brighter days post-pandemic, WECC Manager of Performance Analysis and Resource Adequacy Matt Elkins said, “What we want is a forum where we can all get together and discuss, for multiple days, and have different topics of discussion.

“We want this to be a place where people can come and present their processes. They can come and present the projects they’re working on … the results they’re finding. It’s just a place where subject matter experts can get together,” he said.

In response to a participant’s question, Elkins clarified that the forum is not intended to replace or duplicate the Northwest Power Pool’s nascent RA efforts to ensure sufficient capacity in eight Western U.S. states and two Canadian provinces. While WECC would welcome NWPP’s contributions to the forum, WECC’s RA models will remain at a “very high level,” focusing on balancing areas, he said. (NWPP’s effort will drill further down to the needs of the 18 entities currently funding the program.) (See Western Resource Adequacy Program in the Works.)

“It’s just for us to kind of pinpoint where risk is in the system,” Elkins said of WECC’s approach.

Another participant asked whether WECC has a desire to set a minimum reserve standard to ensure that no utilities are “leaning” on the capacity of others.

Elkins acknowledged stakeholder concerns that the region is “double-counting” its capabilities in some areas, with some market participants unknowingly relying on the same capacity.

But he said, “I don’t know that we need to have a standard.

“I think everyone’s doing a great job. I think we need to communicate more on what our model assumptions are and those kinds of things, and that’s really the point of this resource adequacy forum.”

Survey Says …

WECC wrapped up the webinar with an anonymous survey that elicited real-time participant responses to a handful of questions about the RA effort. The comments provided a flavor of stakeholder concerns — and wishes — regarding RA in the Western Interconnection.

One said WECC should set minimum RA standards for utilities in the region. Another called for the “need to connect the dots between policymaking and its effect on resource adequacy.” A third said regional coordination should “include different pathways to move to a Western RTO.”

One participant asked that WECC provide both in-person and virtual options for participants from companies that will not soon allow staff to travel because of COVID-19 concerns.

Another hinted at the paradox in WECC’s desire to help “invent” a future while maintaining its position of neutrality on the RA issue. “While the forum doesn’t have any defined ‘outputs,’ does WECC have the intention of anything more than information exchange? I think WECC might want to consider a related effort to host a technical RA inter-model comparison effort to understand different approaches to RA assessment and perhaps move toward a regional consensus.”