California EPIC Symposium Talks Trees and EVs

Discussion of high-tech solutions to climate change and the proliferation of electric vehicles turned to soil amendments and forest management at last week’s California Energy Commission EPIC Symposium.

The annual three-day summit is an expo for the cutting-edge projects funded by the state’s Electric Program Investment Charge (EPIC) to ratepayers. The program awards more than $130 million a year to entrepreneurial efforts to electrify buildings and transportation, and to store renewable energy and enhance grid resilience.

Typically, the summit fills exhibit halls with the latest electric vehicles from the likes of Honda and BMW and packs ballrooms with hundreds of participants. This year’s summit tried to recreate that experience with virtual exhibit halls and a variety of forums in which stakeholders discussed the state’s latest efforts toward decarbonization.

On Wednesday, Wade Crowfoot, secretary of California’s Natural Resources Agency, talked with CEC Chair David Hochschild in an online “fireside chat” about the state’s role in clean energy innovation. Crowfoot said an Oct. 7 order by Gov. Gavin Newsom to better manage the state’s forests and farmlands was a new front in the battle against climate change and wildfires.

More than 4 million acres have burned in California this fire season, one of the worst on record. Smoke blanketed the West and traveled to the Midwest and East Coast. Particulate matter choked Los Angeles and San Francisco, giving California the worst air in the world at times in August and September.

Tens of millions of tons of greenhouse gasses billowed skyward, canceling out the state’s gains in reducing emissions from fossil fuel generation and gas-powered vehicles, Crowfoot said.

“All that smoke that’s going into the air and going into our lungs is obviously finding its way into the atmosphere,” Crowfoot said. “And unfortunately, this catastrophic fire [season] is actually wiping out these emissions savings that we have in all of these other areas. So, smart land management of working forests, for example, will reduce emissions from these catastrophic wildfires.”

Newsom’s order instructs Crowfoot’s agency and other state entities to develop strategies to restore wetlands, manage forests and improve soils, with the goal of sequestering more carbon.

“There’s been an increasing global movement that recognizes the way that we steward land — both our natural areas and our working lands, like farms and ranchlands — actually matters to the global effort to combat climate change,” Crowfoot said. One effort he cited involves recycling organic waste and adding it to farmland, allowing soil to absorb more carbon and retain more water.

The governor’s order was sparse on details, leaving implementation to state agencies. The extent to which the state can direct forest owners to act on the order must still be determined. Millions of acres of the state’s forests are owned by the federal government, logging companies and utilities such as Pacific Gas and Electric. Those forests contain immense stands of dead and dying trees from years of drought and bark beetle infestation. The Creek Fire in the rugged Sierra Nevada foothills near Fresno grew into one of the largest fires ever, at 359,000 acres, by feeding on dead trees in and around the Sierra National Forest.

On its Earth Observatory website, NASA showed the dense concentrations of black carbon fouling the air after a series of lightning-sparked wildfires in mid-August.

EPIC Symposium — Smoke from California wildfires covered the West in August. | *NASA Earth Observatory*

“Black carbon particulates, commonly called soot … can harm humans and other animals by entering the lungs and bloodstream; it also plays a role in global warming,” NASA said.

Mass Switch to EVs and Electric Heating Needed

Crowfoot called a Newsom order on EV adoption a “huge and bold stroke” toward electrifying transportation. The Sept. 23 order requires all new passenger vehicles sold in the state to be zero-emissions vehicles (ZEVs) by 2035 and provides a much needed market signal to car manufacturers to focus their efforts on EV production, he said.

The transportation sector accounts for more than half of California’s carbon emissions; the order will reduce automobile emissions of GHGs by 35%, the governor’s office said. (See Calif. to Halt Gas-powered Auto Sales by 2035.)

Meeting Newsom’s mandate — and the state’s larger decarbonization goals — will require rapid acceleration of EV sales and charger installations. (See Can California Meet Its EV Mandates?)

Senate Bill 100 requires the state’s load-serving entities to provide retail customers with 100% carbon-free energy by 2045, and an executive order by former Gov. Jerry Brown requires the state to attain carbon neutrality the same year. Brown signed both in September 2018.

To meet the requirements, Southern California Edison estimates that 75% of light-duty vehicles on the road must be EVs by 2045, along with two-thirds of medium-duty vehicles and a third of heavy-duty vehicles, Russell Ragsdale, SCE’s director of asset and engineering strategy, said during a symposium panel on accelerating the integration of renewable energy.

SCE is pushing forward with adoption of EVs through its “charge-ready” programs for light-, medium- and heavy-duty vehicles, Ragsdale said. The utility is “looking to accelerate the adoption [of EVs] across California by enabling access to charging and helping to limit range anxiety,” the fear drivers have of running out of power, he said.

In August, the California Public Utilities Commission gave SCE’s efforts a big boost by authoriz ing $437 million to fund the installation of 38,000 charging ports for EVs via SCE’s Charge Ready 2 infrastructure program, the largest single-utility EV charging program in the nation. (See CPUC OKs 1.2 GW of Storage by 2021, 38,000 EV Chargers.)

Switching to EVs won’t be enough; Californians must electrify buildings so that 75% of water and space heating will be electric to meet the state’s 2045 decarbonization requirements, Ragsdale said.

Moreover, California will need huge new amounts of renewable energy, including 80 GW of utility-scale generation and 30 GW of utility-scale storage, plus 30 GW of distributed generation and 10 GW of distributed storage, he said.

“This combination of cleaning the power source and then electrifying these various uses will help us to get the carbon out of our economy,” Ragsdale said.

October 26, 2020

ISO-NE Planning Advisory Committee Briefs: Oct. 21, 2020

ISO-NE last week presented its notice of initiation for the Cape Cod Resource Integration Study, which will focus on potential infrastructure to interconnect queued generation and quantify resources that could interconnect with new transmission according to the network capability interconnection standard (NCIS).

Conceptual cluster-enabling transmission upgrades include adding new 345-kV transmission infrastructure between West Barnstable and Bourne, Mass. The study will also identify the number of megawatts that could be interconnected while recognizing the export limitation from Cape Cod from a 2019 economic analysis by the New England States Committee on Electricity (NESCOE).

The Cape Cod Resource Integration Study will focus on the addition of new 345-kV transmission infrastructure between West Barnstable and Bourne, Mass. | *ISO-NE*

Al McBride, a system planner for ISO-NE, said the RTO had completed several interconnection studies on Cape Cod, most recently a system impact study for the proposed Vineyard Wind 2, which would connect to the 345-kV West Barnstable substation.

The project, which is under evaluation by utilities in Massachusetts, could be either 400 or 800 MW; ISO-NE studied the 800-MW option. It would require network upgrades, including a 345-kV line from West Barnstable to Bourne, a new 345-kV substation at Bourne and a 345/115-kV autotransformer at West Barnstable.

There are also several more interconnection requests in the queue, including 2,948 MW of generation and an elective transmission upgrade, seeking to interconnect to Barnstable/West Barnstable or Bourne.

The conditions used in NCIS system impact studies, described in Planning Procedure 5-6, include peak-load and light-load testing and resources modeled at their nameplate ratings (50 or 0 degrees Fahrenheit, as appropriate). New resources may also dispatch against existing resources under NCIS interfaces modeled at the transfer limit.

One admittedly “curious” stakeholder asked McBride why the RTO is initiating this study now, as potentially eligible projects for this cluster have already had feasibility studies done.

“This isn’t a new realization that there are more megawatts here than can be fully deliverable from the cape,” the stakeholder said.

McBride said there was consideration given to starting the cluster “sooner … but because we were able to complete [the Vineyard Wind 2 study] serially, we did so, and we feel that’s the way that the process is supposed to be implemented.” McBride added that “given our experiences with [Vineyard Wind 2], and what we were seeing on the system, and then our jump ahead into the future through the economic study … all of the conditions became apparent, and so that’s why we’re initiating it now.”

Another stakeholder asked McBride if the peak load for Cape Cod “is different rather than simultaneous with the system peak, how is it going to be handled in this study?”

“Somewhere like the cape, for nine months to approximately a year, you’re going to be experiencing lower loads, and you might use less of these injected megawatts,” McBride said. “And if there are any time constraints, getting megawatts off the cape might add to that. … I don’t have anything necessarily specific that we might add into this study, but it’s something that we’re thinking of, and if we have anything more, we’ll come back” to the committee.

The RTO will accept additional stakeholder feedback on the initial conceptual transmission upgrades until Nov. 20 and present results of the Cape Cod Resource Integration Study within 12 months. However, the economic analysis previously performed by NESCOE and the interconnection studies is expected to speed up this time frame.

After the publication of the final report, the RTO will open the window for eligible projects to proceed to the cluster system impact study (CSIS) phase. Eligible projects must meet CSIS entry requirements to move into the study, including submitting a cluster participation deposit.

Lessons Learned on Order 1000 Competitive Solicitations Process

ISO-NE’s Michael Drzewianowski introduced the RTO’s plans to gather feedback for “lessons learned” on competitive solicitations under FERC Order 1000. The recently completed Boston 2028 transmission solicitation was the RTO’s first-ever request for proposals under Order 1000.

“While the cost of the competitive solicitation was considered a success, the ISO and stakeholders have noted areas that could be improved, and the ISO is taking this formal process to collect and evaluate feedback from stakeholders,” Drzewianowski said.

The RTO ran its initial RFP from December 2019 through July of this year. The process concluded with selecting a $49 million project by utilities National Grid and Eversource Energy, which was the cheapest of the 36 received proposals. (See ISO-NE Chooses Incumbent as Boston RFP Winner.) ISO-NE also promised stakeholders, who challenged its selection process, discussions on what did not work well or could be improved in future RFPs and their execution, including developing a submittal template that will summarize any recommendations and guide Tariff and process changes. Drzewianowski added that the RTO already initiated one-on-one discussions with qualified transmission project sponsors who submitted proposals.

Drzewianowski said if there are issues with the RFP or suggested improvements, he would encourage stakeholders to work through the process. Comments on the draft lessons learned submittal template are due Nov. 2, and the final template will be distributed at the Nov. 6 PAC meeting. Completed templates should then sent to the RTO by Nov. 25, with a discussion of the submittals slated for the Dec. 16 committee meeting.

October 26, 2020

Overheard at MISO Market Symposium 2020

RTO officials, stakeholders and academics discussed the challenges of operating a grid with increasing renewables and uncertainty at MISO’s three-day Market Symposium last week. Here’s some of what we heard.

Removing Barriers, Accepting Regional Differences

FERC Commissioner Richard Glick, speaking with Richard Doying, MISO’s executive vice president of market and grid strategy, said the commission has done much in the last decade to remove barriers to entry for new technologies, noting its rulemakings in Order 764 (intermittent generation), Order 841 (electric storage), Order 845 (demand response) and Order 2222 (aggregation of distributed energy resources).

“But there’s more to do, for instance, on hybrid technologies,” he said, noting the commission’s technical conference on the subject in July. (See Hybrid Resource Developers Ask for Uniform Rules.)

On Tuesday, the commission will hold a technical conference on offshore wind. “I think there’s a lot we can do in terms of transmission development and transmission planning to figure out if there are any barriers to the development of transmission systems that would enable a significant number of offshore wind farms to be developed” on the East Coast, he said.

Glick also commented on the commission’s tradition of letting grid operators in different regions adopt tailored approaches to compliance with FERC’s rulemakings, joking, “I wish I had a dime for every time I hear, ‘Let a thousand flowers bloom.’

“I think it’s important for the commission to continue to allow RTOs … the flexibility they need,” he said. “I would say it’s still important that we have a baseline,” he added. “We need to … make sure that the goal is achieved.”

360-degree Review for RTOs

Lisa Barton, American Electric Power’s executive vice president for utilities, joined MISO Chief Operating Officer Clair Moeller on Wednesday for a discussion about seams coordination and right-sizing infrastructure investments.

Asked how MISO could improve its seams management, Barton said the RTO should engage in a lessons-learned exercise with its neighboring RTOs and subject itself to a 360-degree review by regulators, industry and other stakeholders: “What are we doing well? What do we need to work on? What … would help move the ball from a seams standpoint?”

Barton said other stakeholders should subject themselves to a similar review. Individual stakeholders “don’t always behave as well as we should either. … We can be self-interested. But this is an industry that must be about the customers. It must be about the communities,” she said.

“I think if there’s one thing we know about the future, it’s got to be about decarbonizing. … If we can accelerate the transformation … to electric vehicles, think about what that does for the industry. Think about what that does for the environment. There’s so many good things associated with that.”

Moeller agreed. “There’s something for everybody if we all pull together. … When we wander into the parochial — ‘my interest is more important than everybody else’s interests’ — we tend to get into trouble.”

While the industry excels at responding to hurricanes and other crises, Barton said, it needs to become more proactive and shouldn’t worry so much about overbuilding.

“I hear that from economists quite a bit. ‘Well, there might be 5% of capacity in that transmission line that’s not used.’ That’s OK. We shouldn’t be afraid of that,” she said. “What we should be afraid of is having load-shed events [and] not having sufficient resource adequacy. … That’s when you cannot have electric vehicles be a part of your future and a part of the solution.”

“I ask people occasionally, ‘Which mistake would you like to make: the one where you build a little too much a little too early, or the ones where you didn’t build enough?’” Moeller responded. “The ramifications of those two mistakes are dramatically different.”

Moeller said he believes a growing “coalition of the willing” is in favor of an “interstate highway sort of grid” to facilitate the kind of energy transfers that allowed MISO to maintain reliability during its last polar vortex.

“We had a 25% forced outage rate on every resource: coal, gas, demand-side management, wind. You guys in PJM were kind enough to send us 19,000 MW an hour for about six hours, which for us was the difference between load shed and not load shed. …

“I think we need to find a way to value that [resilience] so it shows up in a business case, so we can make the investments we need to make the future safe and affordable,” he added.

Jay Caspary, vice president of consulting firm Grid Strategies, had a similar take in a session moderated by Jennifer Curran, MISO vice president of system planning and chief compliance officer, on “Infrastructure as an Enabler.”

“One of the benefits I think we have in the near term is there’s a lot of assets that are reaching their end of life. I think if we started working with our neighbors, we can identify some key [transmission] corridors and target those in our regional and interregional plans and move forward,” Caspary said.

“You know, when [President Dwight] Eisenhower [proposed] the interstate highway system in 1955, it took decades for that to come into fruition. And it had to evolve as things changed, and spurs were added and toll roads [were added] to make the traffic flows efficient around metropolitan areas. I think we need something like that that we can all buy into.”

Macrogrid or Microgrid?

Anjan Bose, Washington State University | *MISO*

“It’s fashionable in some circles to say the big grid is going to go away. I doubt that that is the case,” said Anjan Bose, regents professor at Washington State University. “As long as there is going to be cheaper generation resources like wind somewhere in the country and a lack of it in other areas, we are going to see the need for transmission. But I do want to emphasize that the microgrid concept — the fact that there are a lot of technologies coming in [at] the edge of the grid — is not going to go away, and it will probably speed up. The question is, how do we work that into planning, and how do we make sure we take advantage of these microgrids?”

Planning Challenges

“The need to plan for extreme events … has always been difficult because of the infrequency at which they occur. So instead, we plan to the standard reliability criteria: N-1 or N-1-1, maybe N-2. And extreme events which may be N-K — where K is a very large number — don’t get that much attention,” said James McCalley, a professor in electrical and computer engineering at Iowa State University. “Yet it is clear that we may be seeing more frequent occurrences of hurricanes, floods, wildfires — and being from Iowa, I’m very sensitive to derecho, the straight-line winds that we had recently here in my state.”

Bose questioned whether the kind of probabilistic methods used in planning would be applicable for operations.

“In planning, we tend to take into account the probability of these occurrences. The question in my mind is: Are those same tools good enough in the operations area, or even applicable in the operations area?

“In operations, we are not using probabilistic methods to determine how probable the region is to overload or under-voltages or whatever. We use very deterministic methods, meaning we say, ‘Well, if this happens, then we will be able to survive it. Or if this happens, we’ll really have a problem over in this part of the grid.”

Planning is also more difficult because there are “so many different objectives to be taken care of,” he continued.

“The reliability criteria are getting more difficult to find out what they actually mean. … In California, for example, where we ran out of resources [and were forced into load shedding in August], the question really was: Is the loss of wind an N-1 contingency, and should we be putting that into our studies?”

Although NERC reliability standards currently have no metrics for measuring resilience, “it’s obviously going to come,” with the risk of forest fires, earthquakes and derechos to be considered in some regions, he said. “That has to be translated into mathematics and the tools that we have.”

Julian Leslie, head of networks for National Grid Electricity System Operator in the U.K., said grid operators need data and input about stakeholders’ visions of the future to ensure they build the right tools for managing operations.

“I never thought working for a transmission system operator [that] I’d be talking to electric vehicle manufacturers or Google [and Amazon] and people like that just to really understand what their direction is, what is their future strategy.”

McCalley called for increasing “the dimensionality of the solution space — that’s a complicated way of saying we need more ways to solve our problems.”

He suggested voltage source converter-based HVDC technology and making better use of demand response. (See related story, MISO Seeks Rx for Increased Uncertainty.)

It also means tapping into the control capability of wind. “They have inertia. They have control capability,” McCalley said. “Let’s use it.”

Gathering Data

Growing amounts of wind and solar will increase net-load ramps both in frequency and magnitude. Out-of-market actions taken during emergencies can lead to price suppression, and the absence of price-responsive demand requires MISO set prices administratively during shortages. | *MISO*

Bose acknowledged complaints that the research community has not been getting the data needed to be able to do proper studies. “But I think [the Department of Energy] and others are now trying to get enough synthetic data on which research can be done, which doesn’t expose [the] sensitivity of actual transmission data.

“The bigger problem in my mind is the power companies getting the data that they need to do their planning work. This is a serious [problem], especially on the Eastern Interconnection where data exchanges have been somewhat limited.

“I think this needs to be looked at from an industry point of view and a national security point of view as to how this data can be kept so that everybody — all the power companies — can do legitimate work on the expansion planning. … All the data exchanges that take place today is done by bilateral agreements. This is ridiculous because you know there are 18,000 power companies in the country. So, there need to be agreements that are countrywide. That needs to happen so that this data is available. As to what data is needed, that depends on the tools we have [and] on what we are trying to solve.”

Caspary said the industry is good at sharing operational data. “When it gets to planning data, we share models, but we really don’t get into the actual performance characteristics of the components in the system. I would be particularly interested in the remaining life that’s being projected on assets and how we would … project the availability of those assets and the mean time to failure.”

Current models assume every asset has the same probability of failure, he said. “I just don’t think that’s a very smart way of planning the system.”

October 26, 2020

MISO Symposium Tackles Data Analytics

Officials from CAISO, NYISO and French grid operator RTE joined MISO on the final day of its Market Symposium on Friday to discuss the challenges of developing data analytics to support system operators’ decision-making.

Elliot Mainzer, who became CAISO’s CEO last month after 18 years at the Bonneville Power Administration, said one of his first actions in his new job was creating a new chief operating officer position.

“We’re integrating our operations and transmission infrastructure and market policy and technical groups under one executive so that we can maximize alignment among those groups and make sure that the technical platform evolves as efficiently across the organization as necessary.”

When BPA started adding wind generation more than a decade ago, it had no tools to address ramping issues and curtailments. The difference between “accommodating” renewables and “integrating” them in the system was developing those tools, he said in a conversation with Todd Ramey, MISO’s chief digital officer.

MISO Symposium — Todd Ramey, MISO (L) and CAISO CEO Elliott Mainzer | *MISO*

“If you want to really integrate them as efficiently as possible, you have to take that time to do the design work,” Mainzer said.

BPA introduced intra-hour scheduling, held a competition to find the best wind forecasting provider and aligned its tariff and pricing mechanisms to encourage operators to use the new tools.

He said he learned the need to involve control center operators in the design of the systems from the beginning.

“Something that was very important was, first of all, making sure that the systems were integrated so that folks weren’t running around having to make 12 decisions at the same time. … We just don’t have a lot of room for a lot of friction in the system anymore as we’re trying to meet our resource adequacy requirements.”

David Edelson, NYISO’s manager of operations performance and analysis, said operators need to make “second-to-second decisions.”

“There’s really little time to interpret data; therefore, that data needs to be presented to control room operators very clearly, in ways that suit their preferences so that they can make quick decisions — generally binary decisions,” he said during a panel discussion moderated by Keri Glitch, MISO’s chief information security officer.

Avoiding False Positives

“They can’t be presented with unnecessarily large volumes of data — large numbers of false alerts — because that’s going to lead to mistrust of the data, as well as hesitations in their response,” Edelson said.

False positives was also the subject of remarks by Mykel Kochenderfer, a Stanford University associate professor who develops applications for aerospace and automated vehicles. “Many of the challenges are exactly the same” as in the power sector, he said, recalling his work on an aircraft collision avoidance system.

“In this situation, you have imperfect sensor information, so you don’t know exactly the current state of the world. And you also have imperfect information about how the world will evolve: You don’t know the future trajectories of the other aircraft. And you have competing objectives. On one side, you want it to be extremely safe, and on the other side, you want to be efficient. You don’t want to be alerting the pilot constantly to avoid collisions when there’s not a significant threat present.”

The system took about a decade to develop, “and much of that time was just establishing trust that the system will behave correctly in operation,” he said.

For that reason, Kochenderfer said, not all artificial intelligence is suited for mission-critical systems. “A lot of artificial intelligence is just using statistics and optimization together, but it has also come to mean … the use of neural networks.

“Neural networks are incredibly powerful. We’ve had major breakthrough in terms of computer vision applications and natural language processing applications. But in those domains, failure is tolerable. If Alexa doesn’t recognize your question correctly, people won’t be losing power; airplanes won’t be crashing.”

Edelson said the power sector will have to overcome its conservatism to get the most out of advanced analytics.

“We operate the system conservatively, justifiably so, because of its importance. … We apply margins large enough to accommodate fairly infrequent events. [Getting] system operators to rely on more advanced data analytics that allow for the system to be operated leaner will require organizational, cultural changes. That’s going to be a challenge.”

Changes will be required as the grid moves away from the traditional dispatchable thermal resources to much more variable generation, Mainzer said. As “we start running into real resource adequacy challenges … using every megawatt of available supply in the system — both bulk [system] resources and the behind-the-meter and distributed energy resources — is going to become increasingly important,” he said.

‘Trash in/Trash Out’

Anthony Papavasiliou, associate professor in the Department of Mathematical Engineering at the Catholic University of Louvain in Belgium, talked about the “trash in/trash out” challenge in estimating the need for system reserves.

“One of the reasons why … stochastic unit commitment is difficult is that you need to create reasonable inputs, the scenarios: Which resource should be outaged? Which forecast error should we consider? Building that input so that you get a meaningful answer from the optimization itself can be as difficult an exercise as actually solving the optimization problem that gives you the answer.”

Kochenderfer said early AI applications sometimes failed because they did not properly account for uncertainty.

“Another potential pitfall is using overly complicated methods. … We should definitely strive to test out the simplest possible ones first and then only use more complicated methods if we can justify that complexity in terms of performance on well defined metrics.”

Some complexity can’t be avoided, however, said Antoine Marot, AI team lead for RTE, the French transmission system operator.

“There’s been a lot of research for the last 10 years about how do we endure more uncertainties in the system. How do we go beyond [the] N-1 deterministic role [to] considering more probabilities?” he said. “Since we have a lot more risk and uncertainties to assess …. the thing we’d like to do for sure is speed up the computation of the simulations.”

October 26, 2020

NEPOOL Reliability Committee Briefs: Oct. 20, 2020

NEPOOL’s Reliability Committee failed to endorse cost overruns on Eversource Energy’s Greater Boston Transmission Project during the committee’s monthly meeting Oct. 20.

The proposal won 60% support, below the 66.7% needed for a recommendation to the PC.

The project’s cost increased by $191 million (33%), primarily because of the underground Wakefield-Woburn, Mystic-Woburn and Sudbury-Hudson lines. Those three lines will cost an additional $147 million, which brings their total to $352 million.

The need to underground the 115-kV Sudbury-Hudson, initially proposed as an overhead line, accounts for an increase to $91 million, which is more than double the original cost of $45.3 million. Eversource was unable to secure property leasing rights from the Massachusetts Bay Transportation Authority (MBTA) for an overhead line. The project has an in-service date of December 2023.

Eversource performed an updated alternative analysis and found that a new 9-mile, 115-kV underground transmission line within an MBTA right of way was the “most cost-effective and constructible alternative.” The two alternatives analyzed — a new 10.3-mile, 115-kV underground transmission line entirely in roadways ($110.4 million), or multiple upgrades to convert a 14.5-mile, 69-kV line to 115 kV, reconductor 11.6 miles of other 115-kV lines and upgrade seven substations ($116.1 million) — had higher costs.

NEPOOL — Hydro‑Québec transmission substation

The Wakefield-Woburn and Mystic-Woburn lines increased to a combined $260.6 million from $160.2 million, representing more than half of the total cost increase. Eversource said additional restrictions on the design and construction required a realignment of underground work within roadways to avoid interference with existing utilities. Restrictions on work hours and the number of crews also increased the construction bids, the company said.

The remaining 30 parts of the project saw an additional 12% increase in cost to $411 million from $367 million. However, these transmission cost allocations were previously supported by the RC and approved by ISO-NE.

RC Supports Proposed Revision to ISO-NE/NYISO Coordination Agreement

The RC voted in support of the RTO’s proposed revisions to its Coordination Agreement (CA) with NYISO to eliminate the need to make a FERC filing when the grid operators update their description of shared interconnection facilities.

The grid operators share interconnections at NY/NE Northern AC Interconnection (comprising the PV-20, K7, K6, E205W, 393, 690/FV and 398 interties), the Northport-Norwalk Harbor Cable and the Cross-Sound Cable Interconnection (CSC).

ISO-NE and NYISO will update the detailed list of interconnection facilities on their respective websites rather than maintaining it in Schedule A of the CA, which requires a FERC filing any time changes are made to it. The addition or removal of an interconnection would still go through the grid operators’ respective stakeholder processes and filed with FERC.

ISO-NE and NYISO have agreed to add the “+/-” notation to the CSC Intertie, which is in the list of interconnections within the list of interconnection facilities that will be posted on both websites. ISO-NE will use “its best efforts” to notify the RC within one week following the posting of any revision to the listing of interconnections. If an RC member identifies and reports a perceived error, the RTO will contact NYISO and discuss the concern. The posting will be modified if they agree a change is warranted. ISO-NE will notify the RC member and explain why the change is not justified as well. Entities can also subscribe to the ISO-NE webpage to receive immediate notices of the revision of posted documents.

The Participants Committee will vote on the CA revisions at its Nov. 5 meeting. ISO-NE and NYISO expect to file the revised CA by the end of the year with an effective date in early 2021.

ICR and Related Values for ARAs Recommended by Vote

The RC voted to recommend that the PC support ISO-NE’s proposed installed capacity requirement (ICR) and related values for Forward Capacity Auction 12’s three annual reconfiguration auctions (ARAs) to be conducted in 2021.

The committee approved net ICRs of 32,925 MW for 2021/22 (ARA 3), 32,765 MW for 2022/23 (ARA 2) and 32,980 MW for 2023/24 (ARA 1). The committee also approved a 958-MW value for the Hydro-Québec interconnection capability credit for ARA 3, with the amount rising to 969 MW for ARA 2 and down to 941 MW for ARA 1.

The PC will vote on the ICR and related values on Nov. 5, with a FERC filing expected by Nov. 30.

October 26, 2020

ERCOT Briefs: Week of Oct. 19, 2020

ERCOT staff have begun issuing price corrections and resettling 25 operating days affected by two market errors earlier this year.

The Board of Directors approved the price corrections earlier this month, as the errors were not caught in time by staff to resettle the operating days on their own. Staff are working with stakeholders to better define “significance,” the only threshold required to take pricing errors to the board. (See “Board Approves 2 Sets of Price Corrections,” ERCOT Board of Directors Briefs: Oct. 13, 2020.)

Staff began issuing market notices with the final resettlements last week, two days at a time. The grid operator released tables with the resettled amounts for the June 8-9, June 10-11, June 12 and 15 and June 16-17 day-ahead operating days.

In an email to RTO Insider, Dave Maggio, ERCOT’s director of market design and analytics, said the resettlement tables are intended to provide a “market-wide net change in dollars broken out by different components of settlement.”

As an example, he said, the June 10 price correction addresses the effect on market participants that had day-ahead energy sales for that day. A net amount of approximately $5,000 will be redistributed to those participants.

“It’s worth noting that the same market participant is likely to be involved in multiple components of settlement,” Maggio said. “For example, an individual market participant may be receiving additional dollars for day-ahead energy sales and may owe additional dollars for day-ahead real-time obligations that were purchased.

“When it comes down to it, the resettlement is really just a shuffling of dollars around between market participants,” Maggio said.

RTC Group’s Protocol Work Completed

Staff said a stakeholder group working on revision requests needed to implement real-time co-optimization (RTC) has completed its review process by reaching consensus on all proposed protocol changes.

The revision requests will be finalized and posted with urgent status before going before several stakeholder groups, culminating in the Technical Advisory Committee and Board of Directors meetings in November and December, respectively. The TAC and the board will be asked to endorse and approve 11 change requests.

The Real-Time Co-optimization Task Force has met 33 times since April 2019, first developing key principles and then protocols. The Texas Public Utility Commission in 2019 directed ERCOT to add RTC, a market tool that procures energy and ancillary services every five minutes to find the most cost-effective solution for both requirements. The grid operator plans to go live with the tool in 2024. (See ERCOT Stakeholders Dig into Real-Time Co-optimization.)

ERCOT OKs Petra Nova’s Mothballing

ERCOT said on Oct. 20 that a reliability analysis has determined NRG Energy’s Petra Nova Power Unit 1 is not needed to support the transmission system and can be mothballed as requested.

NRG last month sent the grid operator a notification of suspension of operations (NSO) that indicated it intended to place the resource in seasonal mothballs, effective Dec. 20. The unit will be available to the market June 1 to Sept. 30. (See NRG to Mothball Petra Nova CCS Plant.)

Petra Nova has a summer capacity of 71 MW. It was retrofitted at a cost of $1 billion to capture carbon from one of NRG’s nearby W.A. Parish Generating Station coal-fired units. Industry analysts don’t expect the plant to return to operation until oil prices stay consistently above $50 or $60/barrel.

ERCOT’s protocols require it to perform the reliability analysis before approving an NSO.

October 26, 2020

NERC Opens Voting for Standards Committee

Voting is underway through 8 p.m. Nov. 4 to fill nine spots on NERC’s Standards Committee that are slated to open at the end of the year, following a nomination period that closed Oct. 15. (See NERC Seeks Nominations for SC Vacancies.)

Committee members — apart from the chair and vice chair — are elected from each of 10 industry segments to serve two-year terms. Each segment nominates two representatives, with terms staggered so that half of the membership is replaced each year.

NERC received only one nomination for the following segments, so they will run unopposed. Appendix 3B of NERC’s Rules of Procedure (ROP) requires each nominee to receive at least one vote before taking their seat:

Segment 1, Transmission Owners: Troy Brumfield, American Transmission Co.;
Segment 2, RTOs and ISOs: Charles Yeung, SPP;
Segment 3, Load-serving Entities: Linn Oelker, LG&E and KU;
Segment 4, Transmission-dependent Utilities: Barry Lawson, National Rural Electric Cooperative Association;
Segment 5, Electric Generators: James Howell, Southern Co.;
Segment 7, Large Electricity End Users: Venona Greaff, Occidental Chemical;
Segment 8, Small Electricity End Users: Philip Winston, unaffiliated (formerly with Southern Co.); and
Segment 9, Federal, State and Provincial Regulatory or Other Government Entities: Kimberly Jones, North Carolina Utilities Commission.

Four of the nominees — Yeung, Oelker, Lawson and Greaff — are already serving on the committee. Of the remaining new members, Brumfield would replace Dominion Energy’s Sean Bodkin; Howell would replace William Winters of Consolidated Edison; and Winston would take over from independent member David Kiguel. The Segment 9 seat is currently vacant.

The Segment 7 seat will be vacant through December 2021. NERC sought an additional nomination to fill this position, but because only Greaff was nominated, the position will remain open for another year. Segment 6 (Electricity Brokers, Aggregators and Marketers) will see a competitive election, with current member Rebecca Moore Darrah of ACES Power challenged by Justin Welty, senior manager of NERC reliability standards at NextEra Energy.

Members of each segment will be sent emails with a link to vote for their respective election. Each registered ballot body in an industry segment may cast one vote per position being filled. Proxies are allowed, but members must designate their proxies via email to NERC prior to voting.

Canadian Nominees Still Lacking

Segment 10 (Regional Reliability Organizations and Regional Entities) will use an “alternate election procedure” as allowed in the ROP to choose its nominee, according to an announcement. No details about the procedure were provided; NERC’s only requirements for such actions are that the process be ratified by at least two-thirds of the registered entities in the segment in which it will be applied and that it be approved by NERC’s Board of Trustees.

The status of Canadian representation on the committee is also not clear at this time. Currently, only two representatives from Canada serve on the committee: the independent David Kiguel and Robert Blohm of Keen Resources. While Blohm will remain on the committee through December 2021, Kiguel is planning to step down at the end of the year.

This means that Blohm is set to be the country’s sole representative on the committee in 2021, which is not permitted because of a requirement that the committee have at least two Canadian members. Under the ROP, if the regular election does not result in enough Canadian representation, the Canadian candidate who receives “the next highest percentage of votes within their respective segment(s)” will be named as an additional member to serve until the following year’s election.

It is not clear what happens if none of the segments nominates a suitable candidate. However, with Segment 10 the only division yet to submit a nominee and none of the other candidates qualifying, the committee may have to consider more options soon.

October 26, 2020

Plan Would Consolidate, Cull WECC Stakeholder Groups

WECC’s Stakeholder Engagement Task Force (SETF) last week floated a straw proposal that would make sweeping changes to the regional entity’s stakeholder group structure by consolidating or replacing most of its standing committees while winnowing out subcommittees not engaged in vital projects.

The proposal would have WECC retain its Reliability Assessment Committee (RAC) while disbanding the Market Interface (MIC) and Operating (OC) committees. It would also create a new Operations, Security and Market Interface Committee (OSMIC). Membership in the two remaining committees would be limited to a fixed number of stakeholders serving staggered terms, WECC said.

The RAC is the key stakeholder group involved in WECC’s resource adequacy initiative. “The RAC has developed a study program that provides reliability assessments aligned with the WECC Long-Term Strategy and Reliability Risk Priorities,” the SETF wrote. “Because this is a committee focused on delivering impactful work products, we propose to retain this committee.”

WECC earlier this year identified RA as seminal to its “invented” future, which is “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.” (See WECC Seeks to ‘Invent’ Future with RA Forum.)

Meanwhile, the SETF said that while the OC and the MIC periodically deliver work products, they are primarily “networking and information sharing” committees.

“We believe that the primary purpose of the standing committees should be the delivery of seasonal, quarterly, annual or biannual work products. Stakeholder networking and information sharing should be viewed as a secondary benefit of participation on a standing committee,” the proposal contends.

The SETF plan would also disband the Joint Guidance Committee and create a new Performance Review Board (PRB) “to ensure the RAC and OSMIC are delivering relevant and timely work products to the appropriate audiences.”

The PRB would establish performance and stakeholder metrics to gauge the output and effectiveness of standing committee projects. The performance metric would focus on the “quantity and timeliness” of a committee’s work, possibly measuring the number of work products produced and the ability to meet deadlines. The stakeholder metric could focus on the “quality and dissemination” of that work, with specific metrics for the number of downloads or requests for presentations of a work product by outside organizations.

“We believe the best way to improve both the quality and quantity of stakeholder engagement at WECC is to give stakeholders the chance to help develop timely, relevant and meaningful work products. If WECC is producing rigorous and impactful work products, the best and brightest subject matter experts will want to participate,” the SETF wrote.

The PRB would report to WECC’s Board of Directors. It is proposed to be a small group with members drawn from WECC management, the board and stakeholders. The group would meet “as needed, but at least annually,” to evaluate standing committee performance.

“The PRB should provide guidance and leadership direction to the standing committees. It should not simply monitor the standing committees. The PRB should be an ‘active,’ not a ‘passive,’ body that scrutinizes the work of the standing committees,” the proposal states.

The proposal would also see WECC staff move beyond providing “administrative assistance” to stakeholder groups to assuming more of a “partnership” role in which those staff would contribute subject matter expertise to committees. WECC’s executive team would also assign a staff member as project management support for every standing committee project or initiative that will produce a work product, “ensuring all work meets WECC’s high standards of quality and rigor.”

The plan also seeks to disband all subcommittees, work groups and task forces not directly involved in developing standing committee work products.

“All stakeholder gatherings to share information, discuss issues and network will be managed through the WECC Strategic Engagement team and will take the form of trainings, workshops and forums,” the proposal said.

WECC is seeking stakeholder comments on the straw proposal by Nov. 2.

October 25, 2020March 11, 2025

OSW Group Seeks Changes on Tx Planning, Cost Allocation

Offshore wind advocates are calling for changes to RTO transmission planning and cost allocation rules to reduce costs and development risks for connecting an estimated 30 GW of generation on the East Coast through 2035.

In a white paper released Oct. 26, the Business Network for Offshore Wind lays out its view of the policy options facing FERC, RTOs and states and the changes it says could ensure the most cost-effective transmission buildout. Grid Strategies’ Michael Goggin, who contributed to the paper, will be among 25 witnesses scheduled to appear Tuesday at a FERC technical conference on offshore transmission.

Brandon Burke, policy and outreach director for the Business Network and the primary author of the paper, said current RTO processes fail to capture all the benefits of offshore transmission, particularly that of an interregional network that could improve resilience in PJM, NYISO and ISO-NE.

It also says OSW development could be hamstrung by the “free rider” problem: that transmission upgrades paid for by an individual generator can benefit those who did not contribute.

Potential offshore wind transmission topologies | Business Network for Offshore Wind

OSW Targets, Projections

Connecticut, Maryland, Massachusetts, New Jersey, New York and Virginia have set targets to procure 29.1 GW of OSW by 2035, with almost 6.3 GW of procurements awarded, according to the American Wind Energy Association. The departments of Energy and the Interior say the U.S. could deploy up to 86 GW of OSW, including on the West Coast and in the Great Lakes by 2050. “Aggressive decarbonization” could result in more than 100 GW on the East Coast alone, according to the white paper.

Although OSW resources on the East Coast are relatively close to load centers, they are generally distant from optimal points of interconnection to onshore transmission networks. “In many areas, only lower-voltage transmission and distribution lines extend to the coast, though at certain points high-capacity transmission lines do extend to existing or retired coastal power plants,” the Business Network said. “When the capacity of the existing onshore electricity grid is reached, and low-cost points of interconnection have been utilized, these grid/interconnection constraints could arrest the future growth of the U.S. OSW project pipeline.”

The report identifies eight models for offshore transmission and its cost allocation, including private generator lead lines — the approach being used for the first group of U.S. OSW projects — and one employing partial federal funding.

Planned vs. Project-by-project Approach

“The optimal outcome will almost certainly involve a mix of both generator tie-line and network elements,” the group said. “While there is debate about the optimal configuration of offshore transmission and the onshore grid upgrades necessary to integrate it, a planned transmission strategy is almost always ultimately more efficient than an unplanned, project-by-project approach.”

An offshore transmission network that connects multiple OSW projects would optimize onshore upgrades and make more efficient use of the limited number of optimal onshore interconnection points. It also could benefit from economies of scale by using higher-capacity transmission lines and converter stations, the Business Network says.

Networked offshore transmission also would allow for rerouting power during interruptions on a single tie line and increase the utilization factor of individual network lines “because geographic diversity causes wind plants to have different output patterns, allowing sharing of network capacity.”

Brattle Group analyses of New England and New York have found that a planned approach could minimize environmental disruptions by reducing the total length of installed cable by about half versus a project-by-project approach.

Costs, Curtailments

The paper says putting 30 GW of OSW in service would require about $100 billion in capital spending, up to $20 billion of it for offshore transmission; onshore upgrades would be “comparably large.”

It cited a Brattle study that a planned offshore network in New England would cost $500 million less in capital spending with savings of $55 million annually from reduced power losses. It could also produce another $300 million in yearly savings by delivering power to higher-priced locations on the grid.

After the first 6.7 GW of OSW is installed, Brattle said, using generator tie-lines to interconnect the remaining 8 GW of capacity in the New England OSW lease areas would result in 13% curtailment, compared with 4% under a planned approach.

East Coast wind lease areas and major onshore transmission | Business Network for Offshore Wind

Risks of Network Model

But the paper acknowledged “considerable debate regarding whether a planned offshore transmission network connecting multiple OSW facilities to shore versus an incremental approach driven by generator tie lines serving individual OSW installations will better facilitate the steady expansion and long-term success of the U.S. OSW industry.”

An offshore network entails more regulatory, political and other risks than generator tie lines for individual projects, which it said can undermine the ability to attract investors.

“As the scale of the proposed transmission solution increases, from an individual offshore wind facility tie line, to a line serving multiple OSW projects, to a network line with multiple onshore points of interconnection, and finally to an interregional offshore network, there are increases in both the potential benefits and the policy and political challenges that must be overcome. …

“The permitting process [for shared offshore transmission] is at best unclear,” the Business Network said, noting FERC’s ruling in July that PJM can deny injection rights to merchant offshore transmission networks unless the project also connects to another grid operator. (See FERC Rules Against Anbaric in OSW Tx Order.) Anbaric appealed the ruling to the D.C. Circuit Court of Appeals on Oct. 16.

Role for Government

The paper said “the most fundamental problem” with RTOs’ transmission planning is the reliance on the generator interconnection queue process to determine what transmission should be built. “The lens of generator interconnection is just one of many benefits of those transmission upgrades.”

Because of the “free rider” phenomenon, the white paper says “there is an essential role for government policy in ensuring that adequate transmission is built to realize … societal benefits, similar to the role governments play for highways, sewer systems and rail networks.”

In many regions, the cost of large upgrades to the grid are assigned to interconnecting generators even though the upgrades benefit the entire region, the group said. “An analogy to that policy would be requiring the last vehicle entering a congested highway to pay the full cost of adding another lane to the highway.”

Potential landing spots for offshore wind generators | Business Network for Offshore Wind

The group said the risks of network models can be reduced by policy changes clarifying “how transmission will be planned, paid for and permitted.”

The white paper also sees a potential role for DOE in optimizing transmission development, noting that three RTOs and their 20 states and D.C. will have roles in determining transmission planning and cost allocation for OSW on the East Coast.

“Currently, there is no single entity responsible for planning offshore transmission across the East Coast, convening stakeholders and working with the industry and states on transmission options,” it said, suggesting DOE could provide technical research and support for stakeholder engagement. “Potential studies include analyzing the benefits of different scales and configurations of transmission expansion, quantifying how expanded transmission can reduce capacity and energy costs by capturing interregional diversity in electricity supply and demand, and finding solutions that minimize the total cost of onshore and offshore transmission.”

Beyond Order 1000

It called on FERC to build on Order 1000 by requiring RTOs to incorporate public policy requirements — such as states’ renewable portfolio standards and OSW procurements — into transmission planning. Order 1000 “only required regions to ‘consider’ public policy requirements. State OSW mandates and procurements need to be integrated into transmission planning, as they are law and the procured offshore projects are being built,” it said.

The group also says current interregional transmission planning processes have failed to identify large projects that would benefit multiple regions because “although Order 1000 requires neighboring transmission planning regions to coordinate planning, it does not require a joint process or evaluation of interregional solutions and their benefits.”

PJM’s response to Order 1000 — the “state agreement” approach — “provides an opening for eastern PJM states with OSW targets to partner [and] pay for transmission” but fails to address the free rider problem, the Business Network said. “If a state will benefit from another state’s transmission investment whether they pay for it or not, they have little incentive to pay for it. However, if each state refuses to pay for transmission upgrades that benefit the entire region, nothing gets built and the entire region suffers.”

It said the interconnection queue cluster process, in which a large number of interconnection applications are evaluated simultaneously and share upgrade costs, could achieve some economies of scale but also fails to allocate the costs to all those who will benefit from additional transmission capacity. “Moving transmission planning and cost allocation to the regional transmission planning process is the only solution for that problem,” it said.

The current interconnection process also leaves generation developers at risk that initial upgrade estimates will escalate if others in the transmission queue drop out.

Counting all Benefits

The Business Network also says RTOs are “leaving economic, reliability, resilience, hedging and other benefits on the table” because they are difficult to quantify. “In cases in which precise quantification is not possible, using an estimate will result in a more optimal level of transmission investment than arbitrarily assigning zero value to a benefit that is widely acknowledged to be large. If benefits are not quantified, they should be at least qualitatively taken into account in the planning process.”

It said transmission planners should use at least a 15-year time horizon for OSW transmission cost-benefit analyses and use advanced modeling to co-optimize transmission and generation planning.

RTO planners “have chosen short time horizons, often 10 years, to calculate the benefits of transmission because of future uncertainty around generation and load. With renewable resources, however, future generation additions will occur in the locations with optimal resources. Those locations are known today and are unlikely to significantly change over time,” the Business Network said. “Transmission assets typically have a useful life of 40 years or more, and that lifetime can often be indefinitely extended by replacing key pieces of equipment.”

Success Stories of Proactive Tx Development

As examples of the “proactive” approach to transmission planning that facilitates renewables, the Business Network cited Texas’ Competitive Renewable Energy Zones, California’s Tehachapi Wind Resource Area near Los Angeles and MISO’s Multi-Value Projects.

“MISO’s approach considers the value of transmission for meeting economics, reliability and public policy (renewable interconnection to meet state RPS requirements) needs. MISO made sure to spread planned transmission projects across the entire MISO footprint to ensure that all zones received projects and had a strong benefit-to-cost ratio, ensuring their support for the overall portfolio.”

October 25, 2020

PJM MRC/MC Preview: Oct. 29, 2020

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees 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)

B. The MRC will be asked to endorse revisions to Manual 15: Cost Development Guidelines resulting from the biennial periodic review process. The revisions include reformatting and rewording in sections 2.6.1 and 2.6.8 to provide more clarity.

Endorsements/Approvals (9:10-9:45)

1. 2020 Installed Reserve Margin Study Results (9:10-9:25)

Members will be asked to endorse the 2020 Reserve Requirement Study results, including the installed reserve margin (IRM) and forecast pool requirement (FPR). PJM is recommending an IRM of 14.4%, down from 14.8% in 2019. The FPR is essentially the same as 2019, at 1.0865 (8.65%) instead of 1.086 from the previous year. The study determines the IRM and FPR for 2021/22 through 2023/24 and establishes the initial values for 2024/25. The results are based on the 2020 capacity model, load model and capacity benefit of ties. (See “Installed Reserve Margin Study Results,” PJM PC/TEAC Briefs: Oct. 6, 2020.)

2. Liquidation Process (9:25-9:45)

Members will be asked to endorse proposed Tariff and Operating Agreement revisions addressing PJM’s rules for liquidating defaulted financial transmission rights positions. PJM is looking to re-establish the ability to liquidate defaulted FTR open positions and to provide flexibility in the way it exercises liquidation rights based on market liquidity, the size of the defaulted portfolio and market conditions. (See “Liquidation Process,” PJM MRC/MC Briefs: Sept. 17, 2020.)

MC endorsement will be sought on the same day.

Members Committee

Endorsements/Approvals (12:45-1:15)

1. Schedule 9-2 Options (12:45-1:00)

Stakeholders will be asked to endorse near-term changes to PJM’s administrative rates as recommended by the Finance Committee. The RTO recovers its operating expenses through Schedule 9 of the Tariff, with 90% of Schedule 9 revenue tied to actual load multiplied by a transmission factor, and the rest connected to transactional activity.

The transactional FTR billing volume, which has increased 97% since 2011, is tied to Schedule 9-2, PJM said, with the FTR administration service revenues exceeding costs because of an increase in the volume of FTR bidding activity. (See “Schedule 9-2 Options,” PJM MRC/MC Briefs: Sept. 17, 2020.)