California Needs Huge Number of EV Chargers

California will need to double the pace of electric vehicle sales and install millions of chargers to meet its goal of having 5 million EVs on the road by 2030, researchers told the state’s Energy Commission (CEC) in four sessions on EV charging infrastructure last week.

The state will likely hit its midterm target of having 1.5 million zero-emission vehicles (ZEVs) by 2025, assuming 11% sales growth, said Joshua Cunningham, chief of the Advanced Clean Cars Branch at the California Air Resources Board (CARB), which regulates vehicle emissions.

But the pace of sales is projected to increase incrementally to 13%, which is not enough to meet the state’s long-term goal, Cunningham said. CARB predicts there will be 2.5 million EVs sold by 2030, he said.

Former Gov. Jerry Brown established the targets in an executive order.

“We’ll only to get about half of the electric vehicles we think we need under the prior governor’s target of 5 million by 2030 in current business-as-usual policies,” Cunningham said.

CARB presented another “extreme sales trajectory” scenario in which all vehicles sold in the state would be EVs or plug-in hybrid vehicles by 2035. Even that, however, will not be enough to meet the state’s goal, mandated by another Brown executive order, of achieving carbon neutrality by 2045, Cunningham said. About 20% of all cars on the road would still use gas as their sole fuel source under the scenario, he said.

California EV Chargers — Millions of cars, trucks and buses in California will need EV charging infrastructure by 2030. | *California Energy Commission*

The transportation sector is the biggest single source of greenhouse gasses in the state, contributing 37% of all carbon emissions. Light-duty vehicles, mainly personal vehicles, are responsible for 28% of all GHGs.

The only way of reaching the state’s decarbonization goal is to sell 5 million ZEVs by 2030, Cunningham said. CARB is working to determine policy changes needed to make that happen, the results of which will be issued in the coming months, he said.

CARB’s board members will likely vote on more stringent vehicle regulations for post-2026 model years next year, he said.

“We recognize this is a trajectory that needs to be further reviewed, and that’s what we’re doing this fall,” Cunningham said.

Meeting Charging Demand

If the state does have 5 million EVs on the road by 2030, plus medium- and heavy-duty trucks and buses, it will need far more charging stations, researchers said.

State law (Assembly Bill 2127, signed by Brown in 2018) requires the CEC, working with CARB and the Public Utilities Commission, to assess EV charging infrastructure needs. The CEC and outside researchers use computer simulation programs to do that.

Eric Wood, a research engineer with the National Renewable Energy Laboratory, said that of the projected 5 million personal EV owners in 2030, 82% will have access to charging in single-family homes, most requiring new wall chargers.

Providing charging at apartments and workplaces, and in public settings such as shopping centers or gas stations, will require an additional 565,000 to 1.15 million plug-in parking spots, Wood said.

“We estimate that 3.4 [million] to 3.8 million plugs will be necessary to meet demand at single-family homes, with an additional 150,000 to 300,000 level 2 plugs being necessary at or near apartment buildings,” he said. “Demand for level 2 charging away from home is estimated to require up to 358,000 while-at-work plugs and up to 413,000 while-in-public plugs.”

Projected demand is based on the “aggressive forecast” from CARB and applied by NREL “in an attempt to have infrastructure deployment lead vehicle sales,” Wood said. But the figures are fluid, he noted, requiring additional research underway at the University of California, Davis, and other institutions.

Researchers are still working to estimate charging needs for medium- and heavy-duty vehicles such as school buses, delivery trucks and tractor-trailers, said Bin Wang, an energy and environmental policy research scientist with the Lawrence Berkeley National Laboratory.

CARB’s clean-truck regulations require an increasing number of trucks sold in California to be ZEVs starting in 2024 and for all trucks sold to be ZEVs by 2045, he noted.

Preliminary estimates show the state must deploy at least 67,000 50-kW chargers and more than 10,500 350-kW chargers to serve future demand, the scientist said.

Heavy-duty trucks will need the higher-voltage chargers to fuel up quickly during the day, he said, while the lower-voltage chargers can fuel fleet vehicles overnight.

“I want to emphasize that these are our first preliminary results, which are subject to change as we keep gathering more data,” he said.

August 11, 2020January 29, 2024

Overheard at NY-BEST’s 10th Annual Meeting

Tropical Storm Isaias battered New York City and Long Island on the first day of the three-day, 10th annual conference held last week by the New York Battery and Energy Storage Technology Consortium (NY-BEST).

The storm on Aug. 4 left nearly 1 million island and city residents without power and prevented Mike Voltz of PSEG Long Island from participating as scheduled in a utility storage panel, while technical problems with the virtual platform made New York Public Service Commission Chair John B. Rhodes the de facto opening speaker.

None of those problems, however, seemed to stop the more than 400 conference participants, nor the panelists dedicated to energy storage in all its permutations.

NYISO and all power-related state agencies are working to achieve the goals set out by last July’s landmark Climate Leadership and Community Protection Act (CLCPA), which include getting 70% of the state’s electricity from renewables and deploying 3 GW of energy storage by 2030.

“Everything is combining all at once now, so it’s impossible not to be bullish on New York whenever it comes to batteries,” said Jeff Bishop, CEO of Key Capture Energy.

Following is some of what we overheard at the event.

Setting the Table

Rhodes said the PSC’s most important action on storage so far has been issuing its December 2018 order to “set the table” for the deployment of storage, with milestones now of 1.5 GW by 2025 and 3 GW by 2030 (18-E-0130).

“Our investor-owned utilities will continue to procure at least 350 MW of bulk storage dispatch rights,” Rhodes said. “And we are examining — as many of you have urged us to — storage demand charges within the revised standby rates based on a cost allocation approach that is more granular, but importantly, more accurate.”

He said the PSC is reviewing the IOUs’ proposals for three-year dynamic load management, starting in 2021. In storage, dynamic load management means optimizing load so that power is evenly distributed to all resources that are charging simultaneously, including electric vehicles, and that the batteries charge to full volume when capacity is sufficient.

“In terms of resource adequacy, our staff and the New York State Energy Research and Development Authority continue to advocate for changes to NYISO’s buyer-side mitigation [BSM] rules,” Rhodes said. “That’s a set of actions that will come ahead of our resource adequacy proceeding.”

FERC Partly OKs NYISO Mitigation Language.)

To demonstrate the rapid growth of storage resources in New York, Rhodes shared a graph showing how storage interconnection queues grew from 887 MW to 1,264 MW in the first half of the year.

David Lovelady, a principal engineer at National Grid, spoke of co-optimizing storage projects through value stacking to maximize total benefits, in particular with a solicitation last year for four storage projects upstate and in the capital region, each to be a minimum 10 MW.

“Perhaps during spring load periods when the load is lighter … we can participate more in the ISO market, and when it comes to the summer period when we have peak load, then we might need to hold some state of charge back for a reliability event,” Lovelady said. “We’re working closely with NYISO on these projects.”

Global Politics and Safety

Professor M. Stanley Whittingham of Binghamton University, winner of the 2019 Nobel Prize in chemistry for his work with lithium-ion batteries, gave the conference a unique perspective on the storage industry.

A NY-BEST founding director and still the organization’s research chair, Whittingham in January was named by Gov. Andrew Cuomo to lead a task force to provide the state with an aggressive roadmap to the EV future.

“The lithium-ion battery will help mitigate what I call the messing up of the world,” Whittingham said.

“We need to further build a New York state ecosystem for energy storage,” he said. “We’ve got great universities; we’ve got Brookhaven National L ab, with all its capabilities; we’ve got New York BEST [and] the very supportive state government; but what we really need to do is develop new manufacturing technologies.”

Whittingham said that the U.S. and Canada need to use research and development to leapfrog the existing 30-year-old technologies used in Asia.

“We need to be to some extent self-contained,” he said. “All the anode materials, the graphite, comes through China, and essentially all the cobalt comes through China, so that is creating issues and will create issues in the future.”

The industry also should strive to eliminate toxic chemicals from the manufacturing process and, in time, to make the cells in a way that enables deconstruction and makes recycling easier, Whittingham said.

“Another way we could have a large saving in capital expense is to provide for an effective solid electrolyte interphase formation. This is the layer formed on the graphite anode. It takes from one week to three weeks of break-in on the manufacturing site. If we could do that during the actual manufacturing of the cells, we’d save a lot of money for everybody,” he said.

One area that has been somewhat neglected, Whittingham said, is to provide for more effective heat management and safety.

“We’ve seen the issues with Samsung, and there were safety issues we saw in the Boeing 787, where really those batteries had not been designed for effective heat management or for safety,” he said. “Right now, a group of us are working to propose building a new factory, a pilot battery facility with manufacturing capability within the state. … We believe there are opportunities to build U.S. manufacturing and the supply chain within the U.S. and Canada, which has lots of nickel and quite a lot of lithium.”

Exciting Times

The year 2020 would have been an unusually impactful one for the state’s grid operator even without the adjustments necessitated by the COVID-19 pandemic, NYISO CEO Rich Dewey said.

“When you look at what’s going on in the utility industry — the electric space — it probably is the most exciting time, certainly in my career, and maybe in the history of the industry,” Dewey said.

The CLCPA has amped up the approach and the process to transitioning to a clean energy power sector and economy, but NYISO is first and foremost responsible for reliability, markets and planning, he said.

In planning for the changes underway, the ISO is not taking “a deterministic approach but really looking at what are the guiderails, what are the options, and that will allow developers, policymakers and system planners the ability to see what different mixes of different resource types will look like, and ultimately what they’ll cost, and what is the most efficient resource mix,” Dewey said.

The ISO’s planning team knows that the interconnection queue has been a barrier to timely and rapid entry for new technologies, he said.

“Storage technologies can probably be deployed faster than any of the other renewable or innovative types of resources, so we knew we had to revamp the interconnection class year, and I’m happy to say we’re getting very close to finishing up the first class year under these new rules,” Dewey said. “The previous class year had 26 projects, and it took us 26 months. … This year’s class year started with about 91 projects, and I think we’re going to be on target to [complete the reviews in] about 13 months, maybe 14 months.”

Dewey also highlighted the ISO’s progress on formulating market rules for storage, noting that earlier in the week, FERC gave final confirmation on most of the rules. (See related story, NYISO’s 2nd Storage Compliance Almost Hits Mark.)

Because hybrid resources such as solar paired with storage are increasingly popular with developers, NYISO last month decided to accelerate its hybrid modeling capability, both within its markets and within its system. The ISO hopes to complete the market enhancement next year, he said.

“More broadly, properly sited and properly configured and performing storage provides tremendous flexibility to different transmission scenarios,” Dewey said. “Whether it’s a two-hour asset or a four-hour asset, whether it’s in New York City close to the load or located upstate near a critical transmission constraint, we want to be able to start exposing some of those variations to our planning studies, so then developers can make investment decisions that most benefit the system and give them the highest return.”

In the Market

LS Power subsidiary Ravenswood Power, the largest power plant in New York City, representing more than 20% of installed capacity in Zone J, last year won regulatory approval to build a 316-MW battery storage facility on its site in Queens. (See “Largest Storage Project in New York,” NYPSC Projects Lower Winter Energy Prices.)

“We’ve seen with the advent of policies over time, like Local Law 97 [capping greenhouse gas emissions for buildings] and CLCPA, there will be a need for replacement capacity to be developed to serve the needs that our facilities currently serve, so we want to be on the forefront of developing that capacity,” Ravenswood CEO Clint Plummer said.

For a big increase of capacity from intermittent renewable resources to work on a system level, “we’re going to need large-scale bulk and distributed energy storage in quantities that have not been seen on systems anywhere else in the world, and New York remains out in front in terms of a policy perspective of thinking through what that means,” Plummer said.

Allyson Sand is a project developer at Plus Power, a battery energy storage company focused on utility-scale storage using a data-driven approach, with a portfolio of 2,000 MW in projects around the country.

In New York, Plus Power is developing several projects, with a focus on zones A, K and G, Sand said.

“At the state level, we see a lot of positive activity happening, with significant investment from the utilities and from NYISO to incorporate storage,” Sand said. “It’s clear to us that the state is really committed to achieving their goal and making storage possible on a larger scale.”

August 11, 2020

PJM PC/TEAC Briefs: Aug. 4, 2020

Load Model Endorsed

The PJM PC/TEAC Briefs: July 7, 2020.)

Patricio Rocha Garrido of PJM’s resource adequacy department presented the committee with the results of the RTO’s load model selection process, which analyzed 105 load model candidates for the 2020 RRS for the 2024/25 delivery year. Rocha Garrido said the analysis was based on the 2020 PJM Load Forecast Report released in January.

Load model candidate vs coincident peak 1 from load forecast. Stakeholders unanimously endorsed PJM’s recommendation to use a 13-year load model with data from 2002 to 2014 for the 2020 reserve requirement study. | *PJM*

The load model candidates were compared to PJM’s “coincident peak 1” (CP1) distribution analysis, Rocha Garrido said, which represents the highest load expected for the forecast year, using two separate approaches. The previously selected load model was not one of the top candidates this year, Rocha Garrido said, because of a new CP1 distribution analysis.

Rocha Garrido said the load model selection has to be done because the coincident peak distributions from the PJM load forecast cannot be used directly in the PRISM modeling software.

“We need to find a load model that is a good match for the PJM load forecast that we can then input into PRISM,” Rocha Garrido said.

Endorsement of Manual 14 Changes

Stakeholders also unanimously endorsed changes to Manual 14, including new sections detailing the requirements for surplus interconnection requests, a new definition of permissible technological advancements and a section outlining the evaluation procedure for surplus interconnection requests.

FERC required PJM to add language on how the RTO handles surplus interconnection service and incorporation of technological advancements in its interconnection process in its second Order 845 compliance filing. (See FERC O K s Most of PJM Order 845 Compliance Filing.)

Onyinye Caven of PJM presented the changes to Manuals 14A, 14B and 14G, which incorporate Tariff changes from the Order 845 compliance filing. Caven said there were “no substantive changes” from the first read that was conducted at the July PC meeting.

Caven said the changes related to the incorporation of technological advancements in the FERC order took effect on July 20, while the changes for surplus interconnection service will take effect in November.

Stakeholders will vote on final endorsement of the changes at the Markets and Reliability Committee meeting Aug. 20.

Interconnection Study Statistics

Susan McGill, manager of interconnection analysis for PJM, presented the interconnection study statistics for the first half of 2020, a new requirement for the RTO under FERC Order 845. McGill said one of the changes out of Order 845 was the collection of common interconnection metrics across the country.

McGill said PJM requested that FERC allow the RTO to calculate for a six-month period to align with its six-month queues instead of the quarterly reports used more commonly.

FERC established a performance rate standard of 25% or below for report delays, McGill said. Entities having two consecutive reporting periods greater than a 25% performance rate are required to issue a detailed filing to the commission explaining the delays and describing mitigation efforts.

The rate is calculated as the sum of the studies issued late and those backlogged, divided by the sum of backlogged studies and total studies issued.

McGill said PJM issued 321 feasibility studies in the first half of 2020. Of those, three were late and one was backlogged or “currently delayed.” The average completion time was 88 days, and the performance rate was 1.2%.

A total of 305 system impact studies were issued at the same time, McGill said, with 35 late and 53 backlogged. The average completion time was 187 days, and the performance rate was 24.6%.

Of 25 facilities studies issued in the first half of the year, all but one was late and 145 are currently backlogged. The average completion time is 747 days, and the performance rate is 99.4%.

McGill said PJM is working to fix the facilities studies delays. She said the RTO is adding contract support to perform studies and project facilitation, including eight new contract engineers by the end of the summer to work on interconnection reports and analysis.

“We’re going to talk internally to see what type of plans we have to address the facilities studies,” McGill said.

She said the total number of studies is increasing “drastically” in PJM. In 2018, 583 studies were due, compared to 1,434 studies due in this year.

The backlog of studies is decreasing at the same time, McGill said. After peaking in March 2019 at 353 studies, or about 28% of projects, the backlog has dropped to 207 studies, or 17% of projects.

“We’re making a lot of headway even though there’s still work for us to do,” McGill said.

COVID-19 Load Impacts

Weekday load peaks remain below normal because of the COVID-19 pandemic lockdowns, although not as dramatically as in previous months, PJM’s Andrew Gledhill told the PC in a presentation.

Gledhill said the weekday load peaks have come in 6.8% less, or approximately 6,600 MW, than what would normally be anticipated since states started instituting lockdown measures around March 23. Gledhill said the peak reductions are slightly lower than what was announced at the July PC meeting, when the load peaks dropped 8.2% (about 7,700 MW).

The peak load impacts have softened because of several factors, Gledhill said, including the continued easing of stay-at-home restrictions among PJM states and the opening of businesses.

Estimated impact of COVID-19 on daily peak and energy | *PJM*

Gledhill also said ongoing social distancing efforts have pushed more load to the residential sector than normal. He said residential loads have a greater sensitivity to weather conditions.

The PJM zones that have seen the smallest load impacts tend to be those with proportionately more residential load.

The average energy reduction has been 7.1% since March 23, Gledhill said, compared to 8% announced at the July PC meeting. The impact on total electric consumption has continued to exceed the impact on the peak.

Gledhill emphasized that the COVID-19 impacts are estimates and not definitive data. “There’s no way to observe the actual impact of COVID-19, so we create estimates to understand the path of the pandemic and its impact on the grid,” he said.

Transmission Expansion Advisory Committee

Reliability Analysis Update

2020 RTEP reliability violations. The 2020 RTEP window for solutions to the violations under PJM, NERC, SERC Reliability, ReliabilityFirst and local TO criteria opened July 1 and is scheduled to remain open until Aug. 31. | *PJM*

Aaron Berner of PJM provided an update on the 2020 Regional Transmission Expansion Plan (RTEP) analysis. The 2020 RTEP window for solutions to reliability violations under PJM, NERC, SERC Reliability, ReliabilityFirst and local transmission owner criteria that opened July 1 is scheduled to remain open until Aug. 31.

As of Aug. 4, 207 eligible flowgates had been posted in the window. About 290 eligible flowgates were originally posted, Berner said, but some were removed because of no-cost solutions that were found during the review process.

PJM also opened a second RTEP window for an end-of-life issue on the 500-kV Doubs-Goose Creek transmission line in the Dominion transmission zone. The 30-day RTEP window closed on July 31, Berner said, and PJM received one proposal for the project.

The project, which was originally presented at the June TEAC meeting, involved replacing steel lattice structures along the approximately 18-mile-long line. A third-party assessment determined that the towers have corroded to a point of instability and could result in failure and a collapse of the line if left unaddressed.

August 11, 2020March 11, 2025

FERC Report Touts High-voltage Benefits

Development of new high-voltage transmission lines could provide myriad benefits for the U.S. electricity system, including improved reliability, greater sharing of resources across regions and a means for states to achieve environmental policy goals, FERC said in a recent report to Congress.

But such a transmission buildout also faces significant obstacles, given the patchwork of federal and state regulations developers must navigate to develop projects, including in existing rights of way.

The report is a product of the 2020 Further Consolidated Appropriations Act, which directed FERC to provide the appropriations committees of both houses of Congress with a study “outlining the barriers and opportunities” for high-voltage transmission in the U.S. Although the report was dated June, it was apparently sent to Congress last week.

While the report offers no concrete steps for policymakers to take, its findings offer a boon to renewable advocates, buttressing the case for building transmission to tap resources in remote areas with an argument favoring the accompanying reliability benefits.

“High-voltage transmission can improve the reliability and resilience of the transmission system by allowing utilities to share generating resources, enhance the stability of the existing transmission system, aid with restoration and recovery after an event, and improve frequency response and ancillary services throughout the existing system [while also] providing greater access to location-constrained resources in support of renewable resource goals,” the report says.

“Americans for a Clean Energy Grid is excited to see the strong endorsement of large-scale regional and interregional transmission,” said Rob Gramlich, the organization’s executive director and president of Grid Strategies. “The report begins an important national discussion about making much greater use of highway and rail corridors as a way around some of the well known barriers to transmission.”

Reliability and Resilience

FERC’s study defines “high-voltage” transmission as AC lines 345 kV or above and DC lines of at least 100 kV, including overhead and underground networks. It notes the land-use efficiency of transmitting power at higher voltages, which reduces line losses, ensuring that a greater volume of power generated will reach its destination.

“For example, one 765-kV line on a 200-foot-wide right of way can carry the same amount of power as 15 double-circuit 138-kV lines with a combined right-of-way width of 1,500 feet,” the report says.

The report addresses four key reliability and resilience benefits of high-voltage transmission:

Sharing of resources across regions by improving interregional power transfer capability. FERC points out that high-voltage transmission can allow a region to access additional generation when local resources become unavailable. The report notes that during the 2014 and 2019 polar vortex events, the East and Midwest experienced high generator unavailability in concert with demand spikes. During the 2019 event, imports served 9% of load, compared with 3% during the 2014 event. But FERC cautions that “the potential benefits provided by proposed and existing high-voltage transmission are not uniform and need to be studied and verified with detailed simulation modeling of the transmission grid prior to integrating any proposed high-voltage transmission solution.”
Aiding with restoration and recovery after an event. FERC said that during a wide-area blackout, system restoration can benefit from neighboring in-service transmission facilities to restore generation, lines and electrical service, especially in cases where local black start units become unavailable.
Improving frequency response. The report notes that HVDC lines between neighboring interconnections can provide frequency support in cases of a large loss of generation.
Enhancing the stability of the interconnection transmission system. Citing the operation of the Pacific DC Intertie linking the Pacific Northwest with Los Angeles, FERC notes that active modulation of the line has been used effectively to maintain system stability in the Western Interconnection “by dampening interarea modes of oscillation.”

The report also cites the recent CapX2050 study by 10 Midwestern utilities, which found that “retirements of dispatchable generation and the movement toward non-dispatchable wind and solar generation will change transmission congestion patterns and introduce more variability in power flows, thus requiring new solutions to mitigate congestion and ensure reliability.” (See CapX2050 Calls for More Tx, Dispatchability in Midwest.)

Opportunities, Obstacles

The “opportunities” section of the report points to trends that could fuel the development of new high-voltage transmission, including states’ renewable portfolio standards.

“These regulatory mandates and voluntary targets are contributing to the buildup of renewable energy resources (e.g., solar, wind, hydropower and geothermal) that are often located in remote areas far from population centers. Transmission developers have proposed numerous high-voltage transmission projects in the United States that could integrate renewable energy resources onto the grid and connect them to regions with high electricity demand,” the report says.

The report also points out that high-voltage transmission developers could benefit from the effort of states and localities to increasingly electrify transportation and building heating to reduce carbon emissions. It cites a 2019 Brattle Group study that finds “the U.S. will need an average investment of $3 billion to $7 billion per year through 2030, in addition to investments needed to maintain existing transmission systems and integrate renewable energy generation to meet existing load, to meet the changing needs of the system due to electrification.”

| © RTO Insider

Another upshot of increased transmission buildout: improved competitiveness in wholesale markets through reduced congestion and the increased ability of low-cost resources to participate. To support the claim, FERC cited 2017 and 2019 reports from ISO-NE showing how new transmission could help New England integrate low-cost resources, decrease congestion and uplift costs, and reduce renewable energy curtailments.

The report delves into how transmission development could benefit from the existence of federal and state laws that support co-location of lines along transportation corridors, including highways, pipelines, railroads (both existing and retired) and canals.

“In some cases, the co-location of transmission in transportation corridors could reduce both the negative effects caused by a project and the cost of project development. Siting transmission in transportation corridors could minimize the creation of new rights of way on undisturbed lands, which could result in reduced effects on private landowners and environmental, cultural and visual resources,” the report says.

The report additionally points to FERC’s own efforts to encourage interregional transmission development, including issuing Order 1000 in 2011, which aimed to address deficiencies in the transmission planning and cost allocation requirements, including participation by nonincumbent developers in regional planning processes, interregional coordination, and methods to allocate the costs of new regional and interregional transmission facilities.

But FERC acknowledged that transmission development still faces significant barriers in the post-Order 1000 world, especially the number of new projects being developed outside the competitive processes envisioned in the order. Those include the continued ability of incumbent transmission owners to maintain a federal right of first refusal for local projects and upgrades, as well as the existence of threshold limits (such as costs and voltage levels) and other exceptions to Order 1000 requirements in regional planning processes.

“Some entities have suggested that incumbent transmission owner utilities may have a preference for developing projects outside of regional competitive transmission planning processes, which may obviate the need for longer-term solutions that might qualify for these processes,” the report says. “Others argue that the transmission development occurring post-Order No. 1000 is focused on reliability and local needs, with only a modest increase in regional projects to address market efficiency and public policy needs.”

The report also addresses barriers to development in co-location corridors. FERC points to the example of development along highways, where the Federal Highway Administration (FHWA) and state transportation agencies share joint authority. The state agencies develop the standards they will use to approve applications from utilities, which FHWA must review to ensure consistency with federal guidelines.

“Some states’ utility accommodation policies expressly prohibit transmission and other longitudinal utility facilities in highway rights of way. Others restrict the co-location of transmission in highway rights of way based on various factors (e.g., transmission voltage or specific highway features),” the report notes.

Siting of high-voltage transmission in other areas generally falls under state jurisdiction, requiring developers to negotiate multiple state processes, as well as those at the federal and local levels — and all this after navigating regional transmission planning procedures, FERC notes.

“The time required to develop a high-voltage transmission facility that meets mandatory reliability standards, maximizes system benefits and strikes a balance among interested stakeholders (including states) can be in excess of a decade,” the report says.

August 11, 2020

PJM MIC Briefs: Aug. 5, 2020

PJM stakeholders unanimously endorsed deadline changes for adjustments associated with finalizing the zonal network service peak load (NSPL) values in Manual 14D and Manual 27.

Ray Fernandez, PJM manager for market settlements development, reviewed updates to the generator operational requirements in Manual 14D and the Open Access Transmission Tariff Accounting section of Manual 27. The Manual 27 revisions were endorsed at Wednesday’s Market Implementation Committee meeting, while the related Manual 14D revisions were endorsed the following day at the Operating Committee meeting.

The revisions are related to the border yearly charge (BYC) — the charge for long- and short-term point-to-point transmission service for points of delivery at PJM’s border, which goes into effect on Jan. 1 of each year.

Fernandez said deadline dates in both manuals conflicted with the deadline dates of the BYC, including ones for the NSPL verification and zonal adjustments.

In Manual 14D, the behind-the-meter generation business rules had a Dec. 1 deadline for a load-serving entity to request a downward adjustment to its NSPL or obligation peak load. PJM proposed revising the deadline from Dec. 1 to Oct. 31.

Changes in Manual 27 included adding clauses to section 5.2 stipulating adjustments that need to be provided to PJM Market Settlements by Nov. 10. Any adjustments provided after the deadline will not be included in the NSPLs for the next calendar year and won’t be used in the BYC calculation.

The manual changes were originally up for endorsement at the July MIC meeting, but Fernandez said stakeholders raised objections with language contained in Manual 14D relating to BTM generation. Fernandez said PJM met with stakeholders to address the issue and were able to reach an agreement on compromise language.

ARR/FTR Market Task Force Poll

Members voted to put the ARR/FTR Market Task Force on hiatus until an independent consultant completes a review of PJM’s auction revenue rights and financial transmission rights market constructs.

Dave Anders, PJM director of stakeholder affairs, reviewed the results of the task force poll taken in July and discussed its recommendation to go on hiatus.

The nonbinding poll had 140 respondents, with 124 voting (89%) to put the group on hiatus until the consultant completes its work.

Anders said feedback from stakeholders resulted in an increase in the scope of the work to be completed by the consultant. (See PJM Revises Consultant Scope for ARR/FTR Review.)

Anders said PJM is “in the final throes” of awarding the contract for the consultant and close to completing the final negotiation for the scope of work. He said stakeholders should expect an announcement “shortly” on the hiring.

Erik Heinle, of the D.C. Office of the People’s Counsel, asked Anders if stakeholders will have an opportunity to meet with the consultant as they’re working on the report or after it’s completed. Anders said plans are being finalized, but he expects there will be some interaction between the consultant and stakeholders.

Market Suspension Settlements

PJM is exploring the development of business rules to address a market suspension from an emergency or some other incident.

Tim Horger of PJM provided a first read of a problem statement and issue charge to develop business rules. The RTO is looking for approval of the issue charge at the September MIC meeting.

Horger said PJM has been contemplating scenarios of a market suspension with no day-ahead or real-time LMP results and realized that it had limited guidance on how to handle settlements during a suspension.

PJM has never experienced a market suspension event and doesn’t anticipate that it would occur, Horger said, but the RTO feels it needs to create business rules to apply to all possible scenarios.

The key work activities and scope for the issue include:

reviewing instances for which a market suspension may occur;
reviewing consequences to the market associated with a suspension;
reviewing PJM’s existing business rules, along with procedures of other RTOs/ISOs in the event of a suspension; and
reviewing options for how settlements can be determined in the event of a suspension.

Horger said work on the issue is estimated to take about three months and could start as early as October if the issue charge is approved next month.

Sharon Midgley, Exelon | © *RTO Insider*

Sharon Midgley of Exelon asked if the problem statement and issue charge only relate to the energy market or if it could also apply to all of PJM’s markets.

Horger said the “obvious” market seemed to be energy, but it could apply to all markets and would be determined in the key work activities.

Midgley said she thought the duration of the work needs to be considered because of the complexity of the issue. “I don’t think it’s going to get done in three months unless there’s already a solution in mind,” she said.

August 11, 2020

WEC Manages Modest Increase in Q2 Earnings

WEC Energy Group managed a 2-cent earnings per share improvement in the second quarter over last year, with several factors offsetting the COVID-19 pandemic’s economic consequences.

The Wisconsin utility recorded net income of $241.6 million ($0.76/share) compared to $235.7 million ($0.74/share) in the same period in 2019.

“Despite the negative margin impact in this year’s second quarter related to the pandemic, we were still able to achieve quarter-over-quarter earnings-per-share growth,” WEC CFO Xia Liu said during an Aug. 4 earnings call. She said “significantly warmer-than-normal weather,” an increase in the return on equity for WEC’s American Transmission Co. and execution of the utility’s five-year capital spending plan helped blunt the impacts of lower energy demand.

“We remain optimistic and confident in our ability to create value despite the challenges presented by the pandemic,” Executive Chairman Gale Klappa said.

WEC said it has about 11,000 more electric and 27,000 more natural gas customers compared to a year ago. The utility serves 4.5 million customers in Wisconsin, Illinois, Michigan and Minnesota. Compared to the second quarter of 2019, residential electricity sales were up 17.1%, small commercial industrial electric sales were down 8.6% and large commercial and industrial sales were down 12.9%.

WEC predicts continued economic recovery through the end of the year; however, COO Scott Lauber said the company has a plan in place if recovery proves more sluggish.

“We are prepared if the level of recovery would drop back to what we saw in the second quarter. We estimate that the additional impact to the pre-tax margin would be approximately $10 million to $15 million. We believe we could absorb this margin compression through efficiency measures already in place,” he said.

Lauber also said that the Wisconsin Public Service Commission’s April decision to allow utilities to track and defer uncollectible expenses and pandemic-related costs helps the company’s bottom line.

WEC Energy Group — Tatanka Ridge wind farm | *Acciona*

Klappa said WEC’s $15 billion capital investment plan from 2020 through 2024 remains unchanged.

“We have ample liquidity and no need to issue new equity,” he told investors.

Klappa said WEC’s announcement late last month that it will pay $235 million to acquire an 85% ownership interest in the 155-MW Tatanka Ridge wind farm in South Dakota is part of the capital plan.

However, he reported that construction at the 300-MW Thunderhead Wind Farm in Nebraska hit a snag that will likely delay it “several months” beyond its 2020 year-end in service date. WEC will have a 90% stake in the project.

“We now project a several-month delay because the local utility has paused construction of a substation that’s needed to connect the Thunderhead project to the transmission network. We continue to work with all the relevant parties to minimize the delay,” Klappa said.

CEO Kevin Fletcher said WEC still has designs on more utility-scale solar generation. He said work continues on two solar projects totaling 200 MW for Wisconsin Public Service.

In addition, subsidiary We Energies will still invest — along with Madison Gas and Electric — in construction of the delayed $194.9 million Badger Hollow II solar farm, which is now expected to be in service by the end of 2022.

August 11, 2020

New CenterPoint CEO Promises to ‘Simplify the Story’

A month into his new job, CenterPoint Energy CEO David Lesar said in his first quarterly earnings call with financial analysts last week that the company will “simplify the story” as it attempts to overcome recent bad news.

The former Halliburton CEO said CenterPoint would focus on cost management, rebuilding regulatory relationships, evaluating options for its Enable Midstream Partners with OGE Energy and properly aligning its businesses. The Texas Public Utility Commission in February approved a settlement that cut the company’s proposed rate increase for its Houston Electric utility from $161 million to $13 million.

Days before the earnings call Thursday, CenterPoint announced it was immediately merging Houston Electric and Indiana Electric into one organization, saying “the alignment of CenterPoint Energy’s generation, transmission, distribution and engineering areas into one organization” will improve efficiency, operations and reliability.

“When we say ‘simplify the story,’ as I sort of look back at how we’ve communicated with shareholders over the past several years, we really have not had a consistent message,” Lesar said during the call. “We’ve had a relatively complicated story. We’ve had a lot of [mergers and acquisitions]. We’ve had regulated versus nonregulated.

“A simple message to shareholders consistently executed quarter after quarter will, I think, help regain confidence that shareholders have in us. … Give me some time. Thirty days is not enough time to give you a complete answer, but we’re definitely headed in that direction,” he said.

The road will be a steep one, as CenterPoint reported second-quarter earnings of $59 million ($0.11/diluted share), driven by customer growth, rate relief and “disciplined” operations and maintenance management. A year ago, the company delivered quarterly earnings of $165 million ($0.33/diluted share).

Still, that was better than CenterPoint’s first-quarter report, when it took a $1.2 billion loss after writing off $1.6 billion in losses from Enable. (See Enable Losses Slam CenterPoint, OGE Energy.)

CenterPoint’s stock price closed Friday at $20.41, up $1.36 (7.1%) from its open before the earnings announcement.

“I believe our share price is too low and trades at an unreasonable discount,” Lesar said. “After speaking with many of you in the short time I’ve been here, I believe I have a better understanding for the reasons why this discount exists. You believe we have let you down, and it’s certainly my job to address those issues that concern you as we move forward.”

Lesar joined CenterPoint’s board of directors in May and is leading a Business Review and Evaluation Committee (BREC) conducting a comprehensive, five-month review of CenterPoint businesses, assets and ownership interest.

“I can clearly tell you that nothing is off the table in the BREC review process,” he said.

Lesar replaced interim CEO John Somerhalder in July. Somerhalder replaced Scott Prochazka, who resigned after seven years at the helm in February. (See Prochazka Steps down as CenterPoint CEO.)

Lesar left Halliburton in 2018 when he hit the oilfield-service giant’s mandatory retirement age of 65 for executives, a policy he helped install.

Asked about his age, Lesar said, “I see myself as 67 going on 50. I’ve got a lot of energy; I like being a CEO; I like being a leader. I have not set a timeline on my tenure here, but I’ll know it, [and] the board will know it, when it’s right for me to move on. I’m raring to go.”

OGE Survives ‘Challenging Times’

OGE also reported second-quarter earnings on Thursday of $85.9 million ($0.43/diluted share) during what CEO Sean Trauschke called “challenging times.” A year ago, the Oklahoma City-based company reported quarterly earnings of $100.2 million ($0.50/diluted share).

Earnings adjusted for nonrecurring costs came in at 51 cents/share, beating analysts’ expectations of 49 cents.

The ongoing earnings exclude a non-cash charge of $780 million associated with OGE’s impaired investment in Enable. The natural gas midstream company contributed $19 million to OGE’s net income and $18 million in cash distributions, down from last year’s second quarter of $27 million and $35 million, respectively.

“When we created Enable, our goal was to turn it into a standalone entity. From that perspective, it has worked very well,” Trauschke said. “We are always evaluating the value of all of our assets, including Enable. We’re not going to talk publicly about strategic alternatives, because that does not help increase value.”

Like many utilities, OGE subsidiary Oklahoma Gas & Electric has seen its energy usage shift from commercial and industrial consumers to residential during the COVID-19 pandemic. Weather-adjusted residential sales were up 2.3% in the first six months of 2020, while commercial and industrial were both down, 5.6% and 7.6%, respectively. Total weather-adjusted sales are approaching pre-COVID 19 levels but still down 3.2% through June.

OGE’s stock price gained 31 cents after the announcement, finishing the week at $33.28.

August 10, 2020

WECC Tackles Wildfires as Reliability Threat

WECC waded into California’s wildfire troubles Thursday in an effort to understand how catastrophic blazes could affect regional grid stability and what can be done to protect the bulk power system.

In the first in a series of webinars planned this month, major utilities and transmission operators, including Southern California Edison and Pacific Gas and Electric, briefed WECC stakeholders on fire-prevention planning.

The state’s summer and fall fire season has begun, with several large wildfires burning in Southern California. The largest, the Apple Fire, had burned more than 32,000 acres and was 40% contained as of Sunday afternoon, the California Department of Forestry and Fire Protection reported.

Massive fires sparked by utility equipment killed dozens of people and destroyed thousands of homes in Northern and Southern California during fire seasons in the past three years.

“The timing of this presentation is such that I don’t need to spend a lot of time explaining the risk or the severity,” said Tom Brady, senior manager of emergency response at SCE. “We know that California does have a serious wildfire problem, and it’s something that continues to get worse.

“I recall growing up and remembering a time when there was a start and an end to fire season,” Brady said. But “it seems with today’s current events, that window is extending, and it’s really difficult to say there’s a fire season anymore because there’s always a risk for ignition and spread.”

Ten of the state’s 20 most destructive wildfires have happened in the past five years, posing an “existential crisis” for investor-owned utilities, he said.

‘Extreme Natural Events’

In a June report, WECC cited the West’s propensity for epic natural disasters as one of the gravest threats to the grid. (See WECC Board Adopts Reliability Risk List.)

WECC should “prepare for and evaluate impacts on the bulk power system caused by extreme natural events,” such as wildfires, drought, flooding and earthquakes, it said, with an emphasis on sharing best practices and lessons learned from individual state and utility experiences across the Western Interconnection.

On Thursday, utility representatives described efforts to head off wildfires, starting this fall.

Brady said SCE had installed 650 miles of insulated wire in the areas at highest risk of fire in its sprawling service territory. The utility plans to install a total of 1,200 miles of covered conductor by the end of this year, he said.

WECC wildfires reliability threat — A smoke plume from the Apple Fire, burning in Southern California, rises behind transmission towers. | *U.S. Forest Service*

SCE also placed 1,200 fuses and remote-controlled sectionalizing devices on its system to interrupt power more quickly and prevent ignitions.

Sectioning off its grid also allows SCE to limit the extent of public safety power shutoffs (PSPS) — the intentional blackouts California IOUs use to keep electrical equipment from starting fires during dry windy conditions.

“We’re able to minimalize, sectionalize and isolate the smallest footprint possible so that we’re not interrupting a lot of customers,” he said.

During a weather event the weekend of Aug. 1, SCE warned hundreds of customers in Kern County they might be subject to power shutoffs. Sectionalizing allowed the utility to limit the number of affected customers to 17, Brady said.

PG&E said it is following the lead of SCE and San Diego Gas & Electric by installing hundreds of weather stations and hilltop cameras in its high-risk fire zones, which make up about half the utility’s 70,000-square-mile service territory.

Matt Pender, director of PG&E’s community wildfire safety program, told the WECC audience that 70% of ignitions in its territory resulted from vegetation contacting power lines (48%) or equipment failure (22%).

The November 2018 Camp Fire, the deadliest in state history, started when a PG&E conductor fell, igniting dry vegetation below. Investigators determined a 100-year-old C-hook had broken after decades of wear, dropping the high-voltage line. (See Ancient C Hook, Financial Manipulation Caused Camp Fire.)

Pender said PG&E had inspected every asset in its high-risk fire areas during six months in 2019. The work, helped by drones and machine learning, might have taken five years under PG&E’s “old regime” of line inspections, he said.

Planes equipped with infrared sensors can now inspect lines at night, he said.

The utility also is using sectionalizing devices, as well as placing generators at substations, to limit the scope and duration of PSPS events this fall. Last year, PG&E blacked out hundreds of thousands of customers for up to a week at a time during multiple events. (See California PUC Approves Microgrids, Fire Plans.)

The company’s goal with PSPS is to “to make them smaller, shorter and smarter this year,” Pender said.

Upcoming Webinars

WECC said its next wildfire webinar, on Aug. 13, will be an in-depth “technical exploration into wildfire preparedness and the bulk power system, including system hardening, technology deployment, advanced weather modeling, weather stations, predictive fire spread modeling and high-definition camera installations.”

A third webinar Aug. 20 will examine the “mitigation, right-of-way and vegetation-management aspects of wildfire preparedness. The webinar will explore actions that entities may take to stay compliant and assist in the preparation and prevention of wildfires.”

August 9, 2020

MISO Prolongs Terms on Midwest-South Tx Limit

The MISO stakeholder community appears to support the RTO’s plan to extend the current arrangement on transmission flows between its Midwest and South regions.

Jeremiah Doner, MISO’s director of seams coordination, told stakeholders during a Market Subcommittee teleconference Thursday that the grid operator will file by Nov. 1 to add two years to a cost allocation agreement with SPP and six other parties. MISO agreed to a settlement, which manages the regional directional flows over SPP’s system to connect the Midwest and South regions, with the seven parties in 2016.

Midwest to South Transmission Limit — MISO Midwest and South | *MISO*

Doner said the agreement’s extension was generally well received by stakeholders.

But not all were happy.

MidAmerican Energy’s Greg Schaefer said he was disappointed because his company’s location in Iowa means it is shouldering a heavy financial burden for MISO’s use of SPP’s system above its 1,000-MW contract path.

“All the costs are being loaded onto a relatively small number of parties,” Schaefer said. “It’s not surprising that there is a consensus here.”

MISO’s payments to the other parties for regional flows above the contract path are recovered from its market participants using a special rate schedule, which increasingly has put emphasis on a flow-based beneficiary allocation over a load ratio calculation. The current calculation is 90% flow-based and 10% load-based, which will continue into 2023. (See MISO Seeks Extension on Midwest-South Tx Limit.)

The 2016 agreement can be terminated by any party with a year’s notice beginning Jan. 31, 2021. Without an extension or alternative solution, MISO’s flows would be limited to its original 1,000-MW contract path in either direction. The agreement limits MISO to 3,000 MW of flows in the north-to-south direction and 2,500 MW in the other direction.

MISO has said a two-year extension of the original terms will buy time for it, SPP and the other parties to explore eventually reopening the agreement’s terms. MISO has also said it may revisit the idea of constructing new transmission capacity to supplant the agreement. (See “No Midwest-South Tx Solution this Year,” Price Tag Rising for MTEP 20.)

August 9, 2020

MISO Investigating LMR Availability Problem

MISO last week said it will begin hunting for solutions to mitigate “significant gaps” between load-modifying resources (LMRs) that clear capacity auctions and what actually shows up to help mitigate emergencies.

The RTO acknowledged during a Resource Adequacy Subcommittee teleconference Wednesday that it had a problem with the amount of LMR-accredited values and what is listed as available to allay demand during summer peak times.

Market Design Adviser Dustin Grethen said that when MISO hit its summer peak in July 2019, 6 GW of LMRs were listed as available, though 11.5 GW cleared the Planning Resource Auction a few months earlier.

Grethen said some of the availability issues result from LMR outages, fear of penalties by overstating load-reducing capability, overly generous LMRs accreditation, voluntary self-deployment or difficulties using the RTO’s availability reporting tool, the MISO Communication System (MCS). Some LMRs that double as emergency demand response enter availability through a separate RTO tool and not the MCS, he said.

Even those reasons cannot explain all the widespread unavailability, Grethen said. He promised MISO would investigate why some LMRs are no-shows after clearing the capacity auction.

Customized Energy Solutions’ Ted Kuhn suggested the grid operator start by checking the MCS’ availability against the metered data LMRs are required to provide.

The LMR availability gap is part of MISO’s ongoing resource availability and need suite of market improvements. The RTO is still gauging which combination of new resource adequacy and capacity market rules it might adopt to reduce the number of maximum-generation emergency events it declares. (See MISO Closer to Seasonal Capacity, Reliability Reqs.)

As part of that, the grid operator will now scrutinize the actual availability of conventional generators and for what they’re accredited. Planning Adviser Davey Lopez said MISO’s planning reserve margin requirement is likely understated because it doesn’t model real-world generation outage scenarios.

Pandemic Still Muddying Forecasts

MISO is still calculating emergency resources’ response during its most recent emergency event on July 7. (See Max Gen Event Managed Efficiently, MISO Says.)

MISO LMR Availability — MISO’s Little Rock headquarters | *MISO*

Executive Director of Market Operations Shawn McFarlane said MISO didn’t have to resort to LMRs that day. He said the peak would have been higher had not thunderstorms popped up in the northern part of the footprint.

McFarlane also said the pandemic continues to complicate load forecasting, as air conditioning load is likely skewed to more residential use this year than in others because of customers working from home.

“We think there’s some offsetting things that made it very hard to predict summer peak,” he said.

Despite that, McFarlane called the event “one of the most orderly max gens I’ve seen,” as MISO responded quickly and committed more resources appropriately.

MISO President Clair Moeller said not much has changed in the RTO’s modus operandi after the pandemic’s announcement.

“The risk profile doesn’t seem to be changing much,” Moeller said during an Informational Forum on July 21. “The good news is the operational impacts of the pandemic are manageable … and we don’t expect that to change.”

Moeller said load “crept back up” in July and is now about 5% less than its normal load average.

“We’re still learning how to forecast in this new environment,” he said.