Page 1021 – RTO Insider

November 8, 2020

NY Power Panel Looks at Methane, Renewables

The New York Climate Action Council’s Power Generation Advisory Panel on Thursday decided to take on the issue of methane gas leakage as part of an effort to scope out by next fall a statutorily mandated path to reduce the state’s greenhouse gas emissions 40% by 2030 and no less than 85% by 2050.

New York PSC Chair John B. Rhodes | *New York DPS*

“After good discussion about the narrower methane leaks and associated emissions and safety consequences on the natural gas system, we’re going to turn this analysis into statements that reflect collective thinking,” said John B. Rhodes, chairman of both the panel and the state’s Public Service Commission. The panel is one of six, each sector-specific, advising the CAC.

The panel also discussed the broader issue of developing and integrating renewable energy resources onto the New York grid.

The Climate Leadership and Community Protection Act (CLCPA) directs the state’s Department of Environmental Conservation (DEC) to include upstream emissions in its statewide emission calculations. New York on Oct. 27 concluded its hearings and public comment process on statewide emissions limits for 2030 and 2050 proposed by the DEC — 60% and 15%, respectively — of estimated 1990 GHG emissions. (See New York Holds Final CLCPA Emissions Hearings.)

The Future of Gas

Kit Kennedy, director of energy and transportation for the Natural Resources Defense Council, said that addressing methane leakage is a natural part of dealing with GHG emissions, but that it should be done in a way that doesn’t extend the life of the natural gas system.

“We do know we are going to have to get off gas to meet the CLCPA goals, at least fossil gas,” Kennedy said. She said she was concerned about language indicating a continued need for natural gas in the near to medium term. “I don’t know what that means, [as well as] needing gas to ensure reliability. I prefer that we keep those issues as distinct as possible.”

New York’s GHG emissions in 2015 were virtually unchanged from 1990 levels, according to a recent study that highlights upstream impacts and the role of methane under the state’s revised reporting rules. (See NY Study Highlights Rising Methane Emissions.)

New York Power Panel — A 100-year time frame map of methane (CH4) emissions by county in New York state in 2017; officials expect in January to issue the 20-year time frame study mandated by the CLCPA. | *NYSERDA*

The issue of methane leakage is inexorably tied with a solution for the missing 25% of emissions reductions in 2040, said John Reese, senior vice president of Eastern Generation, which controls approximately 5,000 MW of generation in the state, including some peaker units.

“We need to look at what it takes to mitigate the leakage, and [if we are] going to use the natural gas system infrastructure system going forward to meet some of the other needs that currently are unfilled in 2040,” Reese said. “Looking at this in a stovepipe or isolated manner will be problematic. The impact piece of this is the first step before we can look at how we go about dealing with this larger issue.”

Macy Testani, assistant project manager at the New York State Energy Research and Development Authority (NYSERDA), said that consumers, not utilities, pay for leaks from points beyond the main natural gas pipelines and that there is little incentive to fix the aging pipes that run to many residences and businesses. She referred to a 2019 study that breaks down the leakage in-state in terms of upstream, midstream and downstream sides, the latter contributing significantly to overall emissions attributed to gas infrastructure.

Rhodes interrupted to say that, “It is certainly the case that the state regulatory apparatus and the utilities are prioritizing repair to the riskiest stretches of leak-prone pipe, in this case being a safety concern of explosion.”

William Acker, executive director of the New York Battery and Energy Storage Consortium (NY-BEST), said that methane is more impactful but also more reactive, meaning a lot of the methane in the atmosphere is naturally consumed each year.

“You can stop the leaks, or you can react the methane and get rid of it,” Acker said. “It might be that there’s an economically viable path that stops the major leaks and reacts some of the methane to get rid of it. … Has there been any research on that, or is that an area being considered at all? … It may be a crazy idea.”

Testani said that NYSERDA and the DEC have not looked at the reactivity of methane in the current mitigation project, but “we’re at the point where we need all crazy ideas to consider.”

The CLCPA also requires that methane emissions be compared with CO2 over a 20-year period rather than the 100-year time frame still used by virtually all other governments in the world. Testani said NYSERDA expects to issue the draft 20-year time frame analysis in January.

Bring on the Renewables

The CLCPA requires that 40% of the benefits of state investments in clean energy reaches disadvantaged communities, which are often located near the dirtiest oil- and gas-fired peaker plants. The state is taking “an accelerated approach” to meeting those investment goals, said John Williams, vice president for policy and regulatory affairs at NYSERDA.

A big challenge in retiring those peakers “is not just a peaking issue; it’s also an overall energy production issue,” NYISO Executive Vice President Emilie Nelson said.

Many studies show that, especially in light of climate change, sustained periods of weather patterns, such as lulls in the wind or less sunshine in winter, are not conducive to high renewable output, she said.

“That could happen on a seasonal basis for quite a long duration, so it’s a daily cycle; it’s a seasonal cycle; so, that’s not just a peak issue,” Nelson said.

NRDC’s Kennedy brought up possible barriers to developing renewables, such as the buyer-side mitigation policies from NYISO that were partly rejected by FERC Rejects NYISO Bid to Aid Public Policy Resources.)

“Despite the new siting law in New York, siting and community concerns and opposition are still a big issue … as is access to all for renewables, which ties into equity and environmental justice concerns,” Kennedy said. “I’d also like us to dig a little deeper into some of the assumptions … like lack of suitable space for large-scale renewables downstate.” S

he urged panel members to “make sure we are not locking ourselves into traditional thinking.”

Lisa Dix, New York representative for the Sierra Club Beyond Coal Campaign, brought up barriers in NYISO to dispatching storage and said she wanted to “amplify the question mark” on the lack of space issue, suggesting that NYSERDA officials assessing build-ready sites look in New York City and Long Island.

“In the process of getting rid of dirty peaker plants, how will those sites be reused?” Dix said.

In response to Dix, Nelson said that in August, “NYISO did implement a full complement of storage rules that allow participation of storage directly in our energy markets. … So, there is an option for participation and dispatchability by storage resources within the wholesale markets.” (See NYISO’s 2nd Storage Compliance Almost Hits Mark.)

November 8, 2020

Industry Cooperation Key to Hurricane Recovery

The rapid restoration of electric service to customers in the southern U.S. following Hurricane Laura this summer was a testament to the need for collaboration between all industry stakeholders in an increasingly volatile hurricane environment, representatives of SERC Reliability and MISO told NERC’s Member Representatives Committee (MRC) on Thursday.

“2020’s been a record year in many ways, and it’s taken a lot of work by a large number of folks to get through this storm season, and we’re not done yet,” said Tim Ponseti, vice president of operations at SERC. “Hurricane Laura’s a tremendous example of our entire industry, along with regulators and the government … rising to the occasion and pulling together in a way that’s truly patriotic. … If only other parts of our country could pull together in a similar way.”

Strong Hurricanes a Known Threat

Grid operators knew by this spring that 2020’s hurricane season would be unusually active, with additional stress expected from the ongoing COVID-19 pandemic. (See Pandemic Adds to 2020 Hurricane Season Challenges.) But Laura proved an even trickier challenge than expected, growing in strength from Category 2 — with 100-mph sustained winds — to Category 4 — with sustained wind speeds of more than 150 mph. When the storm made landfall Aug. 27 near Lake Charles, hurricane-force winds were felt as far away as the Louisiana-Arkansas border.

The storm damaged or destroyed more than 1,900 transmission structures and damaged 430 substations, resulting in 342 initial sustained transmission line outages. More than 1 million customers lost power in Louisiana, Texas, Arkansas, Tennessee, Mississippi and Oklahoma. Damage estimates so far total more than $14 billion.

NERC hurricane recovery — Damage to power lines after Hurricane Laura made landfall in Louisiana, August 2020 | *SERC*

“We use the word ‘restoration’ a lot. This was not a restoration; this was a reconstruction for many pieces of the system,” said Todd Hillman, chief customer officer at MISO. “This was not like other storms, and the messaging [and] story around that was pretty important.”

Recovery work was further hindered by the arrival of Hurricane Delta, which made landfall Oct. 9 in Creole, La., just 12 miles east of the spot where Laura hit six weeks earlier. While Delta was a much weaker storm than Laura, at 100-mph sustained winds, and lost strength rapidly after landfall, it still knocked out some of the critical 500-kV lines that crews had restored following damage from Laura and caused 820,000 customers in four of the same states to lose power again.

Advance Prep Helped Speed up Response

Despite the devastation, crews worked rapidly to restore service; all customers affected by Laura regained electricity by Oct. 1, while the outages caused by Delta were addressed by Oct. 15. While some bulk electric system transmission lines remain under repair, the major lines serving their areas were restored by Oct. 18. Ponseti credited the effective response to SERC’s recognition of the growing threat from severe weather, particularly after the incorporation last year of the Florida Reliability Coordinating Council’s territory. (See FERC OKs SERC’s Expansion into Florida.)

“SERC’s regional risk report identified extreme weather as one of the top two risks the BES system faces within our footprint, and Hurricane Laura proved this point in spades,” Ponseti said. “And with the addition of the Florida peninsula to SERC, it’s almost impossible for hurricanes to miss the SERC footprint.”

Along with hurricane risk, the merger with FRCC also brought SERC a team of professionals experienced in dealing with severe weather, which the regional entity put to use as Laura approached to draw up a set of restoration guidelines to share with MISO, Entergy, Cleco Power and other utilities in its footprint.

‘Tough Calls’ Needed in Emergency

The guidelines include specific actions to be taken by the various types of entities. However, SERC placed the greatest emphasis on establishing industrywide coordination, with clear responsibilities and points of contact between SERC, MISO and utilities. Such arrangements are crucial for ensuring massive grid damage can be repaired both quickly and safely.

“When you’re in the middle of the event, the utilities of course want to get their members back online. One of the roles of an ISO/RTO is to take that wider system view,” Hillman said. “[That] made us make some tough calls … [because] we were understanding that there were bigger impacts and potentials if more of the system [came] down. … It’s not great to hear, ‘No, you can’t restore those customers yet; no, you can’t get that back online yet; we need to make sure that we’re sequencing this in the right way.’”

Although the arrival of Delta so soon after Laura put pressure on already hardworking crews, Hillman and Ponseti said the second storm did provide an opportunity to test what the entities learned from the first, “as the ink was still drying.” MISO, SERC and their utilities came away from the experience with a renewed appreciation for the fundamental work of thoroughly studying support requirements for extreme weather response; public communication to ensure that customers understand the scope of the problem; and above all, preparing staff through constant practice and assessments.

“You do a lot of drills, and you think to yourself, ‘Oh my gosh, it’s another drill. It’s another black start drill; it’s another system restoration drill,’” Hillman said. “Well, all those drills matter. It’s important to keep our operators trained … because when you’re in the heat of things, you … absolutely do not want to be the person that says, ‘Where do I find that information, and who do I talk to about it? How does that work?’ We didn’t have time to do any of that. And so [the] preparation and drills really played a key part in us getting the system back online.”

November 8, 2020

Group Hopes West Can be Wired for Grid Collaboration

David Bobzien, the director of the Nevada Governor’s Office of Energy, summed up the key takeaway from the Western Interconnection Regional Electricity Dialogue (WIRED) initiative in one word.

“Coordination, coordination, coordination,” Bobzien told listeners on a webinar hosted by the Committee for Regional Electric Power Cooperation and Western Interconnection Regional Advisory Board (CREPC-WIRAB) Friday.

A participant in the WIRED effort, Bobzien was referring to the initiative’s conclusion that Western states must step up collaboration on grid planning to accomplish their increasingly ambitious policy targets — even if their goals don’t always align.

The initiative was conceived last year to develop recommendations to Western governors on how to improve regional coordination in three key areas: transmission planning and development, resource adequacy and greenhouse gas accounting. Final draft reports for each topic area were issued this month.

“All three areas of the WIRED initiative … are really front-and-center, important issues for us right now in Oregon, as both policy and the market are rapidly driving the clean energy transition in our state,” said WIRED participant Kristen Sheeran, energy and climate change policy adviser to Oregon Gov. Kate Brown. “And as Oregon makes that transition, we want to continue to do so in ways that complement the efforts of our other Western states.”

Bobzien said he advised his boss, Nevada Gov. Steve Sisolak, that grid coordination would be “the most complicated, wonky energy policy issue you will face as governor,” but also one in which he could make the most impact.

“And you can make that impact by working and continuing in the conversation with your fellow governors across the West,” he said.

Bobzien pointed out that even states without strong clean energy policies are home to investor-owned utilities that “are making similar commitments on carbon reduction” as the most aggressive states.

The WIRED initiative is a collaboration between Colorado State University’s Center for a New Energy Economy (CNEE) and the Western Electric Industry Leaders (WEIL) Group, which comprises utility executives from 10 U.S. states and one Canadian province.

WEIL Steering Committee member Jim Shetler, general manager of the Balancing Authority of Northern California, said WEIL members last year became concerned about the way generation and transmission operations could be affected by the “ever increasing” number of individual state energy policies with different criteria for renewable portfolio standards and greenhouse gas accounting.

“We recognize that the physics governing the grid don’t necessarily respect state boundaries, and so we have to plan for that,” Shetler said.

Former Colorado Gov. Bill Ritter, now CNEE director, said he was invited to speak at a 2019 WEIL meeting after several states had passed climate and clean energy measures. He recounted that WEIL members asked him how states could improve their policy coordination and how governors could make decisions more collaboratively.

“I said, ‘That’s really not going to probably happen,’” Ritter said. “In some conversations, you might get some agreement among Western governors, but to have states all agree on the same renewable portfolio standard or agree on the same climate targets — that’s not going to happen.”

But Ritter said that conversation then turned to what steps the industry could take to “move us toward greater regionalization and collaboration.”

He accompanied utility CEOs at talks with governors about the “benefits of a regional conversation,” something the state leaders said they were ready to convene.

“We made an agreement with both the governors’ offices and the utilities that we did not have a preordained conclusion here about a regional market, about expanding something or tying into another thing,” Ritter said.

Tricky Transmission Planning

Those discussions gave rise to WIRED.

“We know that there will be further incorporation of renewable resources across the Western grid, and as pointed out by the Western Flexibility Assessment, if we don’t address some of these issues, we’re going to have some challenges in the 2030s and beyond,” Bobzien said.

Published by the Western Interstate Energy Board in December 2019, the assessment found that Western states must improve policy coordination to meet the flexibility needs of the Western Interconnection as states advance on their clean energy targets over the next 15 years.

Bobzien, who took part in the WIRED working group studying transmission planning, said transmission development must be linked to resource planning because the two are “very tightly” intertwined.

He also noted that cost allocation is the “trickiest” aspect of transmission planning. “Trying to figure out cost allocation nirvana is going to be important over time.”

The final draft report from the transmission working group lays out several recommendations for governors to consider in their directions to state agencies, utilities and planning entities, including:

creating a mechanism to better coordinate development of integrated resource plans “informed by potential transmission implications and requirements” and ensuring those needs are addressed in relevant transmission planning processes;
establishing a format for information sharing;
supporting coordinated study processes and timelines;
creating a decision-making framework that includes principles for fairly allocating costs for new projects; and
setting financial incentives that recognize and support the long-term nature of transmission investments.

The working group also advised governors to pledge that their states will evaluate their current resource planning processes “to help ensure implementation of resource planning and transmission needs identified in a formal multistate process.”

While Bobzien said it was important for the West to improve coordination around transmission planning, he also counseled to avoid “stepping on toes.” The goal at this point is to continue the conversation around collaboration, he said.

“No matter what your policy is … you are in the same boat as the rest of the West,” Bobzien said.

‘Big and Critical’

Speaking for the WIRED resource adequacy working group, Sheeran said “it’s important to note that different states are at different starting places when it comes to resource adequacy.”

Oregon’s Sheeran said she joined the working group because RA has “already emerged as a really big and critical issue” in the state.

“And this was even before the potential for rolling blackouts across the West this summer sort of greatly elevated the profile of this issue and fixed more eyes on this working group,” Sheeran said.

The group first set out to agree on a rough definition of resource adequacy, she said. It arrived at “a forward-looking planning framework to identify future resource needs, considering transmission deliverability, resource capabilities and limitations, [and] planning for uncertainties,” such as generation and transmission outages and variability in demand.

“There are many definitions of resource adequacy out there, and the goal wasn’t to elevate this one above others,” she said.

But the working group did start from the assumption that some kind of regional RA program would be beneficial for the West from a cost, reliability and policy perspective. With that in mind, the group recommended that governors issue a multistate declaration recognizing those benefits while working together to support:

establishment of a regionwide framework “of sufficient transparency, granularity and quality” that evaluates sub-regional RA and “provides information helpful for ‘unlocking’ regional diversity benefits and investment cost savings”;
advancement of regional or sub-regional RA programs and industry-driven RA programs; and
creation of state-driven RA programs that can be “harmonized” with regional or sub-regional RA frameworks or a regional RA assessment framework.

Asked whether the recommendations would have an impact on the Northwest Power Pool’s current RA effort, Sheeran said, “We want to ensure this work is supportive and complementary to that effort.”

Another questioner asked how the recommendations could guide Oregon in developing a state-level RA program.

“I don’t think we’re looking for a state-level program,” Sheeran responded, noting the state is instead looking to participate in regional and sub-regional efforts and trying not to get “further out ahead of our neighbors.”

Lauren McCloy, senior policy adviser to Washington Gov. Jay Inslee, said the efforts of the GHG accounting working group were driven by the need to determine a more uniform way to identify the clean energy attributes of resources despite differences among states’ clean energy programs.

McCloy said the group also wanted to support or maintain compatibility with other economic sectors subject to clean energy standards (CES) and also account for the potential increase in electric load from decarbonization of those sectors.

“We want to make sure we’re enabling achievement of state policy goals,” McCloy said.

The GHG working group urges Western governors “to align and harmonize” GHG accounting methods across states “where possible.” The accounting methodologies don’t have to be identical, but they should be consistent, Sheeran noted.

The group also recommends creating attribute-based systems — which are designed to prevent double-counting of clean energy attributes in different programs — for compliance with RPS and CES programs and renewable and non-emitting fuel type accounting. It also advises states to work collectively and with the Western Renewable Energy Generation Information System (WREGIS) “to consider whether a regional, attribute-based system may be developed for emissions accounting.”

The group additionally recommends that any market design “should reflect or support state policy where appropriate and should not undermine state policy objectives.” Relatedly, “state policy should be informed by market design to avoid unintended consequences that could undermine the operation of wholesale electricity markets.”

No Missteps

Ritter lauded the efforts of the working groups, saying, “This was a broad group of stakeholders that worked very hard to get to a place of consensus.”

He said the goal of the initiative is “to get some agreement on what the process would look like” for engaging in further discussion and collaboration among Western states. WIRED participants are now asking governors and WEIL participants to take time to review the final draft reports.

The group hopes to have something formal to present to the Western Governors’ Association meeting next May.

Ritter acknowledged that “we don’t know what shape that takes, whether it’s a memorandum of understanding or a Western governors’ resolution or some other thing.” The document would help governors decide whether they want to participate in the next part of the process, which would “really be about fulfilling the recommendations and doing a more substantive bit of work on these kinds of issues” and getting “deeper into regionalization.”

“There was no foregone conclusion about a regional market, but it’s also not excluded as one of the possibilities,” Ritter said. “But in watching what has happened to these discussions before about regional markets, one thing you don’t want is the discussion to be undermined by a false step, or misstep, or politics, or a lack of a discussion about governance that had broad participation from all of the states and all of the stakeholders.”

November 8, 2020

MISO to File Midwest-South Tx Rate Extension

MISO will file at FERC in December to extend a rate schedule that determines the payments market participants shell out for using the RTO’s Midwest-to-South transmission path.

Staff revealed Thursday that they are only asking for a one-year extension through Jan. 31, 2022. MISO had first proposed two years.

The rate schedule, set to expire in February, lays out the cost allocation for market participants that use the subregional transfer limit beyond the 1,000-MW contract path linking MISO’s Midwest and South regions. The rate schedule is separate from the RTO’s 2014 settlement agreement with SPP and other parties that set a 3,000-MW limit on north-to-south flows and a 2,500-MW limit in the other direction.

MISO Director of Seams Coordination Jeremiah Doner said the shorter timeline would allow MISO to begin stakeholder discussions on a possible new cost allocation.

Doner said it makes sense to work on a longer-term rate schedule because MISO will likely continue to use the transmission transfer limit for the foreseeable future. The grid operator does not have any transmission projects lined up that can serve as an alternative. Earlier this year it ruled out using new transmission upgrades to secure more transfer capability between its subregions. (See “No Midwest-South Tx Solution this Year,” Price Tag Rising for MTEP 20.)

“It was pretty much locked down in August. Why the sudden change?” Mississippi Public Service Commission consultant Bill Booth asked of the one-year extension.

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

Doner said that in August, some stakeholders seemed eager to renegotiate the rate schedule. He also said the shorter extension lines up with a possible new agreement with SPP and the joint parties.

Effective Jan. 31 next year, the agreement may be terminated by any party with a year’s notice. However, the parties signed a memorandum of understanding that they would not propose changes to the settlement until Feb. 1, 2022. (See MISO Seeks Extension on Midwest-South Tx Limit.)

Without a revised settlement, flows would be limited to MISO’s original 1,000-MW contract path in either direction.

Under this approach, Doner said negotiations on the settlement and cost allocation can take place in tandem in 2022. The rate schedule would reflect any new terms from the settlement agreement, he said.

Currently, MISO’s payments to SPP and other parties for flows across the transfer limit are recovered from market participants through a combination of load-ratio calculations and flow-based beneficiary allocations.

The load-based share has 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.

November 8, 2020

SPP MMU: Summer Load up 2% in 2020

This summer’s average hourly load in the SPP footprint was 2% higher than the year before, according to the Market Monitoring Unit’s quarterly S tate of the M arket report for June through August.

The MMU credited warmer weather for the increase. Heating and cooling degree days were about 16% above the summer of 2019, with June degree days 36% higher than 2019 and July and August both up about 10%. The average hourly loads in the latter two months were nearly identical to the previous two summers.

Coal-fired generation continued to slide, down a point to 35% of the total generation mix. Wind generation increased to 25% of total generation from 20% last summer.

SPP MMU — SPP’s hourly average summer load for the past three years | *SPP Market Monitoring Unit*

Average day-ahead prices and real-time prices were both down 12% from 2019. Day-ahead prices were $20.32/MWh and real-time prices were $19.69/MWh.

The MMU also reported that:

market commitment status was 75% of all offered capacity, up from 68% the year before. Offered capacity in self-commitment status was down to 23%, a drop of 7 points from the year before.
generation outages, which had increased from summer 2018 to 2019, reversed this year, with outages falling from 26,000 GWh to 22,500 GWh.
day-ahead make whole payments doubled, from just over $7 million to more than $15 million, with coal payments increasing from $3.2 million to almost $8.7 million, and gas, simple-cycle payments jumping from $3.4 million to $5 million. “This increase is likely attributable to more resources in market status as compared to self-scheduled status and lower prices during the period,” the MMU said.

The report’s special issues section describes the MMU’s involvement in SPP’s transmission planning process, which has increased since 2018. The Monitor said it has served in an advisory capacity as the planning outcomes influence the market’s long-term efficiency through congestion patterns, operational effectiveness, costs and reliability.

The MMU will host a webinar to discuss the summer report on Wednesday.

November 8, 2020

MISO Embarks on Order 2222 Work

MISO is gearing up to draft FERC-mandated rules before it welcomes potentially thousands of distributed energy resource aggregations into its markets.

Last week’s preparation and discussion was in response to FERC’s Order 2222, which directs RTOs and ISOs to allow DER aggregators to compete in their markets. (See FERC Opens RTO Markets to DER Aggregation.)

During a teleconference Thursday, MISO’s Market Subcommittee voted to create a stakeholder task force to handle the work. The Steering Committee is expected to approve the task force’s creation Monday.

“It was 2016 when FERC issued its first DER aggregation Notice of Proposed Rulemaking,” MISO DER Program Director Kristin Swenson told stakeholders. “We’ve been waiting for this a long time.”

Swenson said MISO must create a “coordination framework” for compliance purposes that facilitates communication among itself, regulatory authorities, distribution utilities and DER aggregations. She said the RTO’s many state jurisdictions means the grid operator faces a challenge in creating multiple operating procedures.

“MISO has a tall order in front of us. … We need to learn how to work with each other in a new way to facilitate all of these new resources on the distribution system,” she said. The grid operator will create a new market participation model for DER aggregators, she said.

“Some folks said that this is the first time they’ve seen a FERC order leading the technology development,” Swenson said. “It’s a pretty exciting order.”

Swenson said staff will focus on how MISO can avoid double-counting DERs in metering and telemetry. “How do we avoid double-counting a DER in both the retail and wholesale markets? To be determined,” she joked.

Earlier this year, Swenson said MISO views visibility into DERs as its first challenge.

“We need to obviously understand shifts in pattern [and] in load. If a lot of rooftop solar is installed, for instance, that can affect our load patterns,” she said during the Reliability Subcommittee’s meeting in April. “We’re mindful that we need to better match some of our processes to changes in the industry.”

Swenson said staff continue to look for solutions to MISO’s “aggregation balance problem,” when the market system, burdened with several thousand points of generation, cannot solve. The system could have trouble locating aggregated DERs’ precise location to alleviate reliability issues.

MISO has until July 2021 to submit a compliance filing at FERC. Swenson said she hopes it’s “pencils down” in June to give time for legal staff to review the proposed compliance.

Swenson said the RTO is planning to hold multiple workshops on how it designs its Order 2222 compliance. The grid operator is also supportive of stakeholders and its state regulators’ decision to form a task force to guide compliance, she said.

The Organization of MISO States (OMS) pressed for a state regulator-led task force as soon as possible during a conference call of the RTO’s Steering Committee on Nov. 3.

“OMS is interested in digging in as soon as possible,” Executive Director Marcus Hawkins said.

Some Steering Committee members bristled that OMS would propose a MISO task force with handpicked leadership in mind. Hawkins said he was only giving the stakeholder community a heads-up that multiple OMS members are interested in helming a new task force. He said the usual stakeholder vote on task force chairs would naturally take place.

“OMS is just being transparent with the fact that it will put people forward,” Hawkins explained.

Swenson said coordination with OMS will be pivotal to MISO’s compliance filing.

“We know this is a state-jurisdictional system; so, much of how this order plays out will be determined by the [relevant electric retail regulatory authorities],” she said. “Understanding what the plans are of each state is critically important to us.”

Stakeholders asked during the Market Subcommittee meeting Thursday whether FERC’s rules always necessitate an RTO task force.

“It depends on the complexity of the issue. And this order touches on several areas,” subcommittee Chair Megan Wisersky said.

November 8, 2020

MISO Concurs with Most 2020 Monitor Recommendations

MISO agrees with nearly all the new market recommendations its Independent Market Monitor issued this year, though the grid operator said executing the ideas may take some time.

The Monitor issued five new recommendations in June in the annual State of the Market report. The recommendations focus on better management of flows across MISO’s seams, implementing dynamic transmission line ratings and disqualifying all energy efficiency resources from the capacity auction. (See IMM Issues 5 Recs in MISO State of the Market Report.)

Kevin Vannoy, MISO’s director of market design, said staff are persuaded on four out of the five ideas, questioning only whether the RTO can single out energy efficiency resources from participating in its annual capacity auction. Vannoy said FERC itself has included energy efficiency in its definition of distributed energy resources with its recent order on DER participation in wholesale markets.

“We feel that’s a reason that we should evaluate whether these resources can or should sell capacity in Planning Resource Auctions,” he told stakeholders during a Resource Adequacy Subcommittee teleconference Wednesday.

Monitor David Patton has said energy efficiency has no place in the capacity market.

“You can see that the quantities are growing rapidly, and MISO needs to look at this before it becomes 2,000 [or] 3,000 MW,” he said in July. “The only way to quantify energy efficiencies is to use a series of highly speculative assumptions, and I think MISO does a reasonable job. It’s just that they’re in an impossible situation.”

Energy efficiency installers are already paid once through savings on their bills, Patton argued.

“It’s hard to come to any conclusion but that [the additional capacity payment is] inefficient,” he said.

Staff say ambient-adjusted transmission line ratings are doable in the footprint, provided transmission owners are forthcoming with ratings. Vannoy said MISO will look for line constraints that could benefit most from variable ratings.

Patton said a “broad adoption” of ambient-adjusted ratings could have reduced the RTO’s congestion costs by as much as $150 million in 2018 and 2019. Over those two same years, TOs could have saved $114 million in congestion costs had they simply provided short-term emergency ratings.

Patton said MISO routinely exceeds $1 billion in the annual value of its real-time congestion, due in part to “very conservative, static ratings by most transmission operators.”

“I think more are becoming aware of this problem,” Patton said, citing last year’s FERC technical conference and the Organization of MISO States’ interest in the footprint’s TOs implementing dynamic ratings.

Vannoy said there will be more development on dynamic line ratings in 2021. The grid operator’s new modular market platform will make it easier for staff to employ dynamic line ratings, he added.

Past Recommendations Put to Bed

Staff said that since last year’s market report, they have fulfilled a 2014 recommendation to create a short-term energy reserve product and delivered on a 2016 recommendation to limit the duration of capacity resources’ outages. Additionally, in the 2021/22 capacity auction, MISO will require full transmission deliverability of capacity resources and enforce a stricter capacity accreditation for load-modifying resources. That will check off two 2017 recommendations.

The RTO said work remains on another 2014 recommendation to use seasonal capacity market procurements. MISO is now studying which hours throughout the year — not just a summer peak — may contain loss-of-load risk. Staff said they continue to explore a more accurate capacity accreditation by accounting for planning resources’ unreported or unforced outages.

MISO is also considering excluding offline resources from setting LMPs and upping its value of lost load and emergency pricing, which would button up Monitor recommendations made in 2015, 2016 and 2018, respectively.

November 6, 2020

Exelon Discusses Potential Generation Spinoff

Exelon officials confirmed during a third-quarter earnings call Wednesday that the company is considering spinning off its generation business into an independent company.

CEO Christopher Crane said the company began a review of its corporate structure earlier this year with the help of outside advisers. The review resulted from the evolving landscape of the generation business and the shrinking of “competitive integrated companies in our sector,” Crane said.

The news comes just a few months after Exelon announced the closing of its Byron and Dresden nuclear plants in Illinois, which face hundreds of millions of dollars in revenue shortfalls because of declining energy prices. (See Exelon to Close Ill. Nukes as Gov. Touts Clean Energy Plan.)

Crane said the goal of the review is to see whether two healthy companies could be created that can stand on their own financially and “provide the support needed for the balance sheets, the customers, the employees [and] the shareholders as we go forward.”

“I want to emphasize that the separation of the companies would involve addressing some complex operational, financial and regulatory issues,” Crane said. “No decision has been made, but we continue to do the work to determine the best outcome for our stakeholders.”

Nuclear Plants

The Byron nuclear plant is slated to close in September 2021; the Dresden plant will shut down in November 2021; and Mystic Units 8 and 9 will retire at the expiration of its cost-of-service commitment in May 2024. (See FERC Rejects Exelon’s Mystic Complaints Against ISO-NE.)

Exelon said it experienced a “$500 million impairment of its New England asset group and non-cash charges for Byron, Dresden and Mystic of $260 million.” It said the charges were related to materials and supplies, employee-related costs, construction and other items.

Crane said Byron and Dresden produce 30% of Illinois’ carbon-free electricity while also employing more than 1,500 full-time employees and paying $63 million in annual taxes. He said that without the plants and others at risk of closing, Exelon customers could pay $483 million in increased annual energy costs under PJM’s capacity market structure with an increase of 70% in greenhouse gas emissions.

(See Clock Ticking on Exelon Illinois Nukes Under MOPR.)

“Despite being among the most efficient, reliable units in the U.S. nuclear fleet, they face revenue shortfalls, declining energy prices, lack of capacity revenue and market rules that allow fossil plants to underbid clean energy resources in the PJM market auction,” Crane said.

Earnings

Exelon said it earned $501 million ($0.51/share) for the quarter, 35% less than the $772 million ($0.79/share) it earned for the same period last year. The company brought in $8.85 billion in total revenue for the quarter, slightly less than the $8.93 billion it posted last year.

CFO Joseph Nigro said the company was raising its year-end earnings guidance to $3 to $3.20/share from $2.80 to $3.10/share. Exelon has invested $4.5 billion so far this year to improve infrastructure and increase grid reliability, he said.

Shares of Exelon were down 25 cents, or 0.59%, to $42.22 as of closing on Wednesday.

November 6, 2020March 9, 2025

NERC Board of Trustees/MRC Briefs: Nov. 5, 2020

NERC’s Board of Trustees and Member Representatives Committee (MRC) will hold their first meetings of 2021 remotely because of the COVID-19 pandemic, board Chair Roy Thilly told the groups at their quarterly conference calls Thursday. The meetings had been planned for Feb. 3-4 in Manhattan Beach, Calif.

“We hope that [the pandemic] will be dying down, but of course we don’t know. And there are so many travel restrictions in place on employees of various stakeholders — [at the] Canadian border and other things — that it is prudent for us to do the meetings virtually,” Thilly said.

The pre-meeting and informational session will be held via conference call Jan. 6 as scheduled. A decision has not yet been made on the next board and MRC meetings, planned for May 12-13 in D.C.

Choudhury Elevated to MRC Chair

Paul Choudhury of BC Hydro, who is currently serving as vice chair of the MRC, was unanimously elected to take over from Exelon’s Jennifer Sterling as chair for 2021. ElectriCities CEO Roy Jones will serve as vice chair.

Elections for sector representatives will be held Dec. 7 to 17 to replace members whose terms expire in February 2021. The MRC is accepting nominations through Friday.

The MRC also approved revisions to its NERC MRC Briefs: Nov. 5, 2019.) This year’s changes are intended to give the committee more flexibility by removing unnecessary requirements from the MRC’s procedures for conducting conference calls.

Standards Actions

Howard Gugel, vice president and director of engineering and standards at NERC, presented three standards for approval by the board: CIP-005-7 (Cybersecurity — Electronic security perimeter(s)), CIP -010-4 (Cybersecurity — Configuration change management and vulnerability assessments) and CIP-013-2 (Cybersecurity — Supply chain risk management).

The standards were developed under Project 2019-03 in response to FERC Order 850, which directed NERC to submit modifications to address electronic access control or monitoring systems (EACMS) for high- and medium-impact bulk electric cyber systems. (See FERC Finalizes Supply Chain Standards.) A final ballot concluded on Sept. 10 with 80.78% of industry stakeholders in approval.

The board voted unanimously to approve the standards along with NERC’s 2021-2023 Reliability Standards Development Plan (RSDP), which provides schedules and anticipated resource needs for each project under development or expected to begin. NERC posted the draft RSDP for an informal comment period in August prior to its approval by the Standards Committee in October. After approval, the document will be filed with FERC and Canadian and Mexican government authorities. (See NERC Opens Comments on Standards Plan.)

“[This] is not a static document; it’s … a snapshot as far as things stand today,” Gugel said. “Certainly as new [standard authorization requests] are accepted by the Standards Committee, or new directives [are] issued by FERC, it would augment this plan going forward.”

Winter, Long-term Assessments Previewed

Board members also received an update on NERC’s 2020-2021 Winter Reliability Assessment, set to be released next week, and the 2020 Long-Term Reliability Assessment, which will be released in December.

NERC engineer Stephen Coterillo told the board that all regions are expected to have sufficient resources “under normal winter weather conditions,” echoing FERC’s 2020/2021 Winter Energy Market and Reliability Assessment released last month. (See COVID-19, Weather Drive FERC Winter Outlook.) Fuel and energy assurance pose significant risks in some areas — notably ISO-NE and NYISO — and extreme weather conditions could “result in the use of operating mitigations or energy emergency alerts to meet extreme peak demands.”

Anticipated reserve margins and reference margin levels for 2022 peak season | NERC

Although no specific threats were noted from the COVID-19 pandemic, Coterillo acknowledged that the coronavirus continues to cause “uncertainty in electrical demand projections and … heightened cybersecurity risk.” Damage to electricity infrastructure in Louisiana from this year’s hurricanes could also impact the local grid’s resilience, though the affected systems are expected to be restored by early winter.

On the longer scale, NERC expects sufficient on-peak capacity in most areas for the next five years, with the exception of Ontario and MISO, where planned reserves have the potential to fall below their reference margin levels. NERC Senior Engineer Mark Olson said the team identified several trends that bear watching over the long term, including the rapid projected growth of wind and solar generation resources — expected to comprise 57% of added on-peak capacity over the next five years — and the addition of distributed energy resources, particularly rooftop solar panels, across the North American grid.

November 6, 2020November 6, 2023

Work Gets Underway for WECC Path Task Force

WECC’s new Path Task Force (PTF) on Wednesday kicked off an effort to examine the role of existing transmission path rating procedures in Western Interconnection planning and operating processes and whether they are still applicable to a changing grid.

The regional entity’s Joint Guidance Committee (JGC) authorized creation of the PTF in September to identify the “relevance and role” of total transfer capability (TTC), path ratings and the “three-phase” ratings process in both the operations and planning horizons for industry participants. (See New WECC Task Force to Examine Path Rating Processes.)

The three-phase process is designed to address planned new transmission facilities and the upgrading or rerating of existing facilities through a review group consisting of project sponsors and representatives of other systems that could be affected by the project, according to WECC.

The path rating process provides transmission project sponsors with the means to obtain an “accepted” rating that meets the RE’s criteria and NERC reliability standards.

During the PTF’s kickoff meeting Wednesday, WECC Director of Reliability Risk Management Vic Howell, the staff liaison to the task force, added some flesh to the mission, explaining the stakeholder group will also “identify and explain the changes in regulatory, markets and business practices, as well as changes in operations in planning that support [the PTF’s] conclusions and recommendations.”

Those findings will be reported to the JGC, although the PTF will also give presentations to WECC’s Operating Committee (OC) and Reliability Assessment Committee, Howell said.

Howell said the idea for the PTF originated in July after the Western Area Power Administration gave a presentation on an internal project to more dynamically calculate near-term and real-time TTCs to be posted on its Open Access Same-Time Information System (OASIS), rather than relying on seasonal TTCs.

“That led to some discussions of the shortcomings of too much reliance on seasonal TTC values,” Howell said. “And as we talked about it at the OC meeting and the joint standing committee meetings, there were a lot of questions and discussions about the use of total transfer capability in the operations and the planning horizon, and the discussion led to asking, ‘How does the path rating fit into this whole equation? And where does the three-phase ratings process come into play?”

Howell lauded the professional diversity of the 12-member task force.

“We wanted to make sure that as we choose members for this task force, we get representation from operations, that we get expertise from planning and … from business practices — scheduling and markets and things of that nature,” he said.

Members Speak

In a get-acquainted exercise, Howell asked PTF members to describe their interest in the path ratings issues.

“The one thing that really stands out is tackling this time frame issue that’s come up,” said PTF Chair Matthew Veghte, an engineering supervisor at WAPA.

“We don’t just look at [the power system] from a seasonal perspective or a next-day perspective; we’re looking at all the way from planning — which can be five years, to a year, to six months to 30 days out — to one day out,” Veghte said. “We have all these different time points that have different things going on, and we’re tasked with, ‘How do we figure out TTC with that?’”

Transmission planning consultant Chifong Thomas said she was interested in exploring how to apply planning restrictions to the operating world in a way that’s not “overly restrictive.”

“Because things change when you go from planning to operations, and so how do we communicate the information that was important to help the operating system,” Thomas said.

Gary Trent, transmission planning manager at Tucson Electric Power, cited the fact that his utility will be joining the Western Energy Imbalance Market in spring 2022 while also transitioning to NERC’s MOD-30-02 flowgate methodology for calculating short-term transfer capability.

“I believe that we’re going to see more and more companies heading that way as time moves on, and being able for us to be on the ground here with that is going to help us all out,” Trent said.

Hari Singh, principal engineer at Xcel Energy, said his interest stems from his view that there is “quite a bit of intersection” between the concepts of transfer capability and system operating limits.

“Now whether we say that system limit is for the operations horizon or the planning horizon, I don’t see why they should be very different if the system we’re looking at five years out in the planning horizon is almost the same as what we’re operating today,” Singh said. “I guess I’m certainly very interested in trying to de-mystify this concept of path ratings we’ve had in WECC and how it relates to total transfer capability and system operating limits.”

Audrey Stevenson, operations planning engineer at Bonneville Power Administration, said, “I think the thing I’m most excited about this task force is identifying and trying to reconcile the differences that are present between the performance requirements and planning horizon, which lead to path ratings and operating horizons, which lead to the short-term TTC and also exceedance identification.”

The task force also includes Dede Subakti and Larry Bellnap of CAISO; Brenda Ambrosi of BC Hydro; Peter Mackin of GridBright; Igor Kormaz of Tri-State Generation and Transmission Association; Clint Savoy of SPP; and Bill Shemley of PacifiCorp.