Page 1126 – RTO Insider

March 13, 2020

MISO Eyes Sleeker Interconnection Queue

By Amanda Durish Cook

Fresh off approval for one change to its interconnection process, MISO is still looking for more ways to advance generation projects more quickly through its queue, stakeholders learned Tuesday.

The RTO put out the renewed call for ideas during an Interconnection Process Working Group (IPWG) meeting that was converted to a conference call as MISO responds to the COVID-19 coronavirus outbreak. (See related story, MISO Steps Up COVID-19 Response.)

MISO is seeking ideas to allow it to simultaneously perform analyses under the definitive planning phase (DPP) and the annual Transmission Expansion Plan, possibly identifying projects that can meet multiple needs. (See MISO Committees Tackle Queue, Tx Planning Disparities.)

“We’re going to strive to improve the process for our customers,” MISO engineer Cody Doll said. “If we’re on the same timeline, we could have common models and joint solution development. … It won’t be a bifurcated effort. It’ll be a coordinated effort between the two functions.”

MISO Interconnection Queue — MISO queue | *MISO*

Doll said he would return to the IPWG in May with more discussion and early proposals. MISO doesn’t yet have a specific target date for when it would file changes to its queue.

It takes just under a year for a proposed generation project to clear the interconnection queue. MISO’s current queue contains 489 projects representing 76.5 GW. Nearly 60% of the projects are proposed solar generation.

“Keep in mind we were over 100 GW after last April’s application deadline,” MISO Manager of Resource Utilization Project Management Jesse Phillips told stakeholders. MISO’s next project application window for the interconnection queue closes June 25. The deadline was extended because of the late April rollout of a new online application tool. (See MISO to Debut Online Queue Requests.)

MISO is also drafting Business Practices Manual language for its new, firmer requirement that project sponsors prove exclusive land use for generation projects entering the queue.

The RTO in December won approval to require interconnection customers to demonstrate 100% site control 90 days before proposed projects enter the first phase of the three-phase DPP of the interconnection queue for study. It also scrapped the previous practice of accepting a $100,000 cash deposit in lieu of demonstrating site control. (See MISO OK’d to Require Site Control in Queue.)

The RTO’s site control land requirements are now 50 acres/MW for wind generation, 5 acres/MW for solar generation, 0.1 acres/MW for battery storage facilities and a standard 10 acres for conventional generating facilities.

MISO has said it will use contractors to help review site control documentation. The cost for project reviews will be charged to customer’s study deposit, similar to other queue study costs. Paul Muncy, of MISO’s transmission access planning division, said the RTO uses contractors for “numerous other project-related studies.”

Muncy said MISO “intends to review site control documentation for each project in order to ensure that no projects are able to take an unfair advantage in proving that they have met all requirements.”

After stakeholder inquiries, Muncy said MISO had more work to do to outline in the BPM what official documentation it will accept as proof of land use. Multiple stakeholders said the style of documentation varies on a county-to-county level and that the RTO’s documentation requirements could be overly burdensome by not accounting for those differences.

March 11, 2020

Technology Offers Cheaper Alternatives to Tx Construction

By Tom Kleckner

AUSTIN, Texas — Some utilities are taking a hard look at non-wires alternatives (NWAs) given the difficulty and expense of getting transmission projects approved, gaining regulatory sign-off, and siting and building lines.

technology transmission construction — Hudson Gilmer, LineVision | © *RTO Insider*

Speaking last month at Infocast’s ERCOT Market Summit, Hudson Gilmer, founder and CEO of line-monitoring firm LineVision, said his company and others like it offer options in the likely absence of a second competitive transmission build in Texas.

The first such effort — kicked off in the mid-2000s — resulted in 3,600 miles of transmission facilities able to carry 18.5 GW of capacity. The Competitive Renewable Energy Zone buildout, which ended in 2014 and cost $6.8 billion, connected barren and windy West Texas with the state’s eastern and southern urban centers and set the stage for the massive development of renewable energy that was to follow.

Those lines are now full. ERCOT, which operates 90% of the state’s grid, had 23.9 GW of wind capacity at the end of 2019. Another 12.2 GW of wind energy could be added by the end of 2022, while solar capacity could quadruple to nearly 10 GW during that same time.

“What we heard from the wind and solar developers is that transmission is the single-largest obstacle to continue integrated new renewables on the grid,” Gilmer said. “What we’re seeing with new, large transmission projects is that they tend to be fully subscribed. It’s a chicken-or-egg thing. We believe there is an opportunity … to take a fresh look at transmission. Not in the way we’ve built it during the last 75 years, but as a way to unlock additional capacity on the grid.”

Gilmer said he recently learned that typical usage on the average ERCOT transmission line is under 20%.

“That makes me pretty mad,” he said. “If we can use technology to unlock additional capacity on those lines, that makes a difference and can make a project more viable when it suddenly didn’t pencil out.”

LineVision offers continuous monitoring of transmission line conductors to confirm they are performing within their acceptable operating limits. By taking advantage of low-cost sensors, Gilmer said, his company can watch for sagging lines and push out additional capacity when the line cools.

“Not every line is monitored in ERCOT,” he said. “The transmission operator has to make very conservative assumptions about the line.”

Gilmer said topology control, which uses a software-based solution to identify grid reconfiguration opportunities on open relays and alleviate congestion, can offer a similarly less capital-intensive solution to building new high-voltage transmission lines.

Noting that close to half of all congestion in ERCOT is outage-related, he said LineVision advocates a shift in transmission construction.

“Traditionally, we build through towers and wires. Here’s an opportunity to invest in Texas using software and analytics at a fraction of the cost, making the grid much more flexible and reliable and less expensive,” Gilmer said.

Making the Case

David Townley, director of public policy for CTC Global, plugged his company’s advanced conductors. CTC’s conductors use high-strength, lightweight carbon and glass fibers that helps them withstand extreme peak-load conditions and reduce thermal sag.

“By replacing steel with carbon fiber, you’re changing the performance of [the wire’s] steel core, so it doesn’t sag that much,” Townley said. “Less sag allows you to put more current through the line.”

Townley said the conductors have resulted in about a 20 to 60% increase in operating capacity on an existing system, and “up to 100% in emergency situations.”

“Freeing up that capacity gets more out of the existing system,” he said.

“I sleep better at night when I don’t have to worry about how close a conductor is sagging to the ground,” said Jonathan Greene, senior vice president of transmission operations for Lower Colorado River Authority. “Not having to upgrade or replace wire to get 15 to 20 additional feet is a benefit.”

Greene said LCRA has installed advanced conductors in four locations, three of them in river or lake crossings, using 30-year-old existing towers. He said the cooperative has seen increased line ratings but noted that LCRA hasn’t seen that advanced conductors are cost effective for a full line upgrade.

“Advanced conductors are fantastic, but they’re still fairly expensive,” Greene said.

Gilmer, who advocates a shared-cost model, empathized with Greene.

“Regulated utilities need incentives to adopt these technologies. If you alleviate congestion with one of these technologies, you should get to share a percentage of those savings,” Gilmer said. “We’ve been very encouraged by the response we’ve gotten at the federal level and at some state commissions. We’re seeing, especially in the wake of California and the wildfires, an increased awareness of the safety risk for unmonitored lines. We feel like there’s a very compelling return on investment in deploying sensors for situational awareness and anomaly detection.”

Electric Transmission Texas President Kip Fox, whose joint venture between American Electric Power and Berkshire Hathaway Energy was involved in CREZ, posited that NWAs could actually increase returns on transmission lines.

“There’s a lot of downward [regulatory] pressure on returns,” Fox said, voicing an imaginary argument in favor of NWA upgrades. “‘Hey, I’ve made this line more valuable [through NWA]. Why can’t I have a higher return on this line?’”

March 11, 2020

LS Power Challenges PJM on MEP, SATA

By Rich Heidorn Jr.

PJM’s Planning Committee delayed a vote Tuesday on a new regional targeted market efficiency project (RTMEP) process to consider whether it can be approved without first considering related cost allocation rules.

The RTO said cost allocation is the responsibility of transmission owners under the Consolidated Transmission Owners Agreement (CTOA) and should not be considered until FERC approves the planning change. It cited the timeline for the recent change to the market efficiency benefit/cost ratio, which was approved by FERC in February 2019 (ER19-80) and followed by a cost allocation filing in January 2020 (ER20-776).

LS Power’s Sharon Segner acknowledged that cost allocation is the TOs’ responsibility. But she said FERC Order 1000 requires any regional planning process to be accompanied by a “cost allocation methodology.”

LS Power PJM — Sharon Segner, LS Power | © *RTO Insider*

“We believe this is a different situation than in the past … What’s being proposed here is an entirely new type of regional planning project with … new parameters; new conditions; new modeling,” she said. “We don’t think it’s possible to separate the cost allocation from the planning protocol under Order 1000, and stakeholders deserve to understand both at the same time.”

PJM attorney Pauline Foley disagreed with Segner’s conclusion, saying FERC has historically reviewed planning processes separately from cost allocation. “We believe, based on historical practices, that should not forestall us moving forward,” she said.

The committee ultimately approved a motion by Alex Stern of Public Service Electric and Gas to defer the vote for two months and allow LS Power to share a legal memo with the PC outlining its arguments. The issue of cost allocation had been ruled out of scope in the proceedings of the Market Efficiency Process Enhancement Task Force, which developed the three sets of packages on which the PC had been scheduled to vote.

Stern made his motion after Segner said she would raise a point of order via a legal memo on the issue at the Markets and Reliability Committee meeting if the package advanced beyond the PC before considering the cost allocation. “I’d rather discuss it in a collaborative fashion rather than a contentious one,” he said. “We worked hard to get consensus. While I don’t necessarily agree with LS Power’s legal conclusions, I would like to see them before I’m having to see them at the MRC.”

The packages address changes to the benefit calculation, the window for capacity drivers and the RTMEP process, and included proposals from PJM, the Independent Market Monitor, American Electric Power and FirstEnergy. (See “Market Efficiency Process Enhancement Packages,” PJM PC/TEAC Briefs: Feb. 4, 2020.)

Storage as Transmission

LS Power also challenged PJM during a discussion on the RTO’s efforts to develop rules for treating energy storage as a transmission asset.

PJM hopes to develop rules by the end of the year for treating storage that would be dispatched by the RTO to address thermal, voltage or stability violations or to relieve transmission constraints. Other potential drivers are operational performance (mitigating real-time violations not identified in planning studies) or public policy (grid enhancements requested by a state to further its policies). The PC is scheduled to review a draft issue charge at its April meeting.

Segner has raised questions about a proposal by AEP to use storage to correct repeated outages on its Falcon-Prestonsburg 46-kV circuit (AEP-2018-AP010). AEP said the 23-mile line, which dates to the 1940s and 1950s, is plagued by rotted wood poles and damaged guy wires and cross arms.

The company proposed a supplemental project to install a 2-MW battery at its Middle Creek substation at a cost of $9.7 million; rebuild 8.5 miles of 46-kV line between Prestonsburg and Middle Creek station ($25.5 million); and retire 14.5 miles of 46-kV line between Falcon and Middle Creek ($6.1 million).

AEP said the total cost of $41.3 million would save almost $30 million over the $70 million cost of rebuilding the entire 23-mile line.

Segner said PJM cannot include non-transmission alternatives such as storage in the Regional Transmission Expansion Plan until it has been designated as transmission by FERC. Allowing AEP to win approval of the project under the M-3 process — which is limited to TOs — discriminates against non-TOs, she said.

PJM’s Aaron Berner said the RTO disagrees with LS Power’s position. “We don’t believe there are any issues about how the M-3 process is being followed,” he said. “The asset is being proposed in accord with that process.”

Segner said her company might seek to use the dispute resolution process under M-3.

“We would like to avert dispute resolution,” Berner said. “But if you wish to continue that … we can start discussions on how to move that forward.”

A similar dispute has arisen in MISO SATOA Proposal Faces Opposition.)

“Hopefully FERC will rule on the MISO issue sooner rather than later,” Segner said. A few hours later, FERC did rule, ordering its staff to schedule a technical conference on the issue. The commission said MISO’s Tariff changes “may be unjust, unreasonable, unduly discriminatory or otherwise unlawful” (ER20-588). (See related story, MISO SATOA Proposal Set for Technical Conference.)

March 11, 2020

FERC Reverses Ruling on ISO-NE ‘Economic Life’ Rules

By Rich Heidorn Jr.

FERC Chair Neil Chatterjee and Commissioner Bernard McNamee on Tuesday reversed the commission’s November 2018 order correcting a key calculation in evaluating ISO-NE’s capacity delist bids (ER18-1770-002).

At issue is how ISO-NE’s Internal Market Monitor calculates the economic life of resources that want to retire or permanently leave the capacity market. Such a resource must provide at least five years of cash flow estimates to justify their delist bids, which specify the price at or below which it would retire. The rule change was intended to correct calculations that ISO-NE said overstated the true economics of some resources and could result in improperly high delist bids.

“We find that the benefits of ISO-NE’s economic life revisions do not outweigh the disruption to market participants’ settled expectations associated with changing an FCM [Forward Capacity Market] rule regarding delist bids after the [Forward Capacity Auction] 13 qualification process for those delist bids had commenced,” the commissioners wrote. “Thus, we reject the economic life revisions in their entirety, effective Aug. 10, 2018.”

The 2-1 vote granted a rehearing request by the New England Power Generators Association (NEPGA), which asked that the commission make the economic life revisions effective, “if at all, beginning in FCA 14.” That auction was held last month. (See ISO-NE Capacity Prices Hit Record Low.)

In the 2018 ruling approving the calculation changes, Commissioner Richard Glick joined with then-Commissioner Cheryl LaFleur in the majority. Chatterjee filed a dissent saying that making the change effective for FCA 13 violated the commission’s rule against retroactive ratemaking because market participants had made commercial decisions based on Tariff rules in place before the ruling. (See Split FERC OKs New ‘Economic Life’ Rules for ISO-NE.)

ISO-NE delist deadline — ISO-NE Forward Capacity Auction prices  (2013-2020) | *ISO-NE*

This time around it was Glick dissenting, insisting that the original ruling “correctly balanced the harms and benefits of ISO New England’s proposal.”

“I note that nothing in today’s order precludes ISO New England from refiling substantially the same provisions tomorrow,” he added. “Today’s order, as I understand it, is concerned only with the timing of ISO New England’s previous filing and not its merits.”

ISO-NE spokesman Matt Kakley said Wednesday the RTO will determine its next steps after reviewing the order.

Chatterjee and McNamee agreed with NEPGA’s contention that a market participant that chose not to submit a retirement delist bid in FCA 13 based on the then-existing economic life calculation might have submitted such a bid under the revisions based on expectations of future FCA clearing prices.

But they declined to order FCAs 13 and 14 be rerun without the economic life revisions, saying that would create more harm than benefit.

“We acknowledge the harm to market participant confidence resulting from changing the economic life calculation for delist bids midway through the FCA 13 process,” they said. “However, we find that, because rerunning FCA 13 and FCA 14 would further decrease market participant confidence, such action is ill-suited to providing market participants relief in these circumstances.”

Deadline Waiver Granted

The commission also granted a waiver allowing market participants to adjust or withdraw their retirement or permanent delist bids for FCA 15 based on potential changes to ISO-NE’s Energy Security Improvements proposal (ER20-759).

ISO-NE is expected to file the ESI proposal on April 15, following a vote by the New England Power Pool Participants Committee on April 2 — after the FCA 15 delist deadline of March 13.

The RTO requested the waiver, saying that market participants’ retirement bid decisions may be affected by revenues they will earn or costs they incur under the ESI proposal.

The commission said it will extend the March 13 deadline through seven calendar days after the PC vote. If ISO-NE makes “a non-clerical change” to the ESI proposal after March 13, market participants will have seven calendar days following the vote to either withdraw their bid or update their retirement bids to reflect the changes.

March 11, 2020

MISO, SPP Staff Recommend 2020 Joint Study

By Amanda Durish Cook and Tom Kleckner

MISO and SPP staff are both recommending that the RTOs take another stab this year at a coordinated system plan (CSP) in their elusive pursuit of an interregional project.

Staff have identified 10 congestion areas that merit further evaluation and shared them with stakeholders Tuesday during the Interregional Planning Stakeholder Advisory Committee’s annual issues review. The areas were selected based on their level of congestion and shadow prices, which both RTOs use to identify economic congestion issues.

MISO and SPP have conducted three joint studies since 2014 but have yet to come up with a project to which both could agree. The RTOs modified project criteria last year to improve their chances of reaching an agreement, although differences still remain. The changes included a mandated frequency of CSP studies, elimination of the $5 million cost threshold for the projects, addition of avoided costs and adjusted production cost benefits to project evaluation, and removal of the joint modeling requirement in favor of individual RTO regional analyses. (See MISO, SPP to Ease Interregional Project Criteria.)

The recommendation to undertake a CSP must still be approved by the Joint Planning Committee, which is composed of a representative from each RTO and meets later this month. Assuming its approval, the CSP process would begin shortly thereafter with the scope’s development. Initial portfolios would be filed by each grid operator in August.

The Advanced Power Alliance (APA), American Wind Energy Association and Clean Grid Alliance (CGA) filed a joint letter with the IPSAC supporting the need for interregional planning. They said it is a need that “continues to increase as the use of the grid evolves” with renewable energy’s replacement of fossil fuel generation.

“It should now be clear that forward-looking regional transmission planning is indispensable to ensure both reliability and cost-effective results for customers,” the organizations wrote.

APA’s Steve Gaw highlighted the need to address current restrictions on moving power between MISO North and South. Ben Stearney, MISO’s interregional planning adviser, said the RTO has been evaluating the issue since last year but has found placing the solutions in the CSP to be a “gray area.” (See Interregional Projects May Become Reality for SPP, MISO).

CGA’s Natalie McIntire raised concerns about MISO’s 2019 futures, which are also being used in its 2020 Transmission Expansion Plan models, saying they are “not very representative of what the future is likely to be like.”

Stearney said his staff are working “diligently” on its 2021 futures. However, the futures are not likely to be ready for the 2020 study.

“Part of the advantage of the new process is that it allows us to refresh on an annual basis,” Stearney said.

Regulators’ Seams Committee Wants More Info

Meanwhile, the Organization of MISO States (OMS) and the SPP Regional State Committee’s (RSC) Seams Liaison Committee (SLC) is seeking more information from the RTOs before it scopes its own interregional issues analysis.

The committee decided this week it wants an updated analysis on historical congestion across flowgates and more information on the process behind evaluating interregional reliability projects.

Adam McKinnie, chief economist with the Missouri Public Service Commission, said the SLC is seeking transparency into how individual transmission owners collaborate to propose potential reliability projects across the seams to the RTOs.

“We’re looking for how that evaluation takes place,” McKinnie said during a conference call Monday.

The committee said it has identified “a potential disconnect and general lack of coordination in the [CSP] interregional planning process.”

“Although reliability projects can be proposed through the interregional planning process, this does not occur, and planning for reliability continues to happen predominately separately, or on an ad hoc basis through individual transmission owner collaboration,” the SLC wrote.

To date, MISO and SPP have not approved a seams reliability project, instead favoring regional projects. MISO officials have attributed that to low load growth in recent years, saying the RTOs haven’t had the need for reliability projects along their seams. Staff from the RTOs have also maintained that their reliability planning processes are fundamentally different.

“I don’t have the belief that the seams are so different that we couldn’t benefit from a coordinated reliability process,” McKinnie said.

The SLC will also ask MISO and SPP for a presentation on historical market-to-market congestion using 2018 and 2019 data that could be used in an upcoming CSP. Finally, the SLC is also asking that MISO and SPP detail how it plans to address flowgate congestion now that it has an improved CSP process in place.

The committee won’t select a direction or draft a scope for their seams analysis until they have more information on the two topics.

The OMS and RSC in January laid out the option to either re-examine the RTOs’ past analyses of proposed interregional projects or embark on a series of smaller studies on congested flowgates that could produce entirely new project proposals. (See MISO, PJM Weighing New Interregional Study.)

March 10, 2020

Texas RE CEO Lanford Announces Retirement

By Tom Kleckner

Texas Reliability Entity CEO Lane Lanford announced Tuesday that he will retire in December after occupying his position since 2012.

Texas RE will immediately begin a search for his successor, with the intention of having that person in place when 2021 begins.

“It has been a privilege to serve Texas RE for almost a decade, and the time is right for me to retire and allow the company to continue to grow under new leadership,” said Lanford, who joined the organization in 2010 as chief compliance officer.

Texas Reliability Entity Lanford — Lane Lanford | *Texas RE*

“I appreciate the bonds I’ve built with colleagues at the [Texas] Public Utility Commission, NERC and the other regional entities and value what we’ve accomplished together,” he said. “But most of all, I am proud of the team we’ve built at Texas RE and am confident about the future of electric reliability in our state. It is in very good hands moving forward.”

Lanford is credited with leading Texas RE’s transition to risk-based compliance and helping to create a cohesive Electric Reliability Organization with NERC and the other regional entities. That drew praise from NERC CEO Jim Robb and others who have worked with Lanford.

“[Lanford] was one of the principal architects of our risk-based compliance monitoring approach, and his knowledge and leadership have served the reliability and security of the Texas Interconnection very well,” Robb said in a statement. “He has also built a great team at Texas RE that I am sure will carry on his legacy of excellence.”

“His steady leadership and presence will be greatly missed, but his legacy will continue to shape the future of our industry for years to come,” said PUC Chair DeAnn Walker.

Texas RE Board Chair Fred Day, himself in the final year of his term, said the organization was “fortunate” to have Lanford as CEO the last eight years.

“Under his steadfast leadership, Texas RE has become a well-respected reliability leader at the NERC level while still maintaining the [Texas RE] region’s uniqueness and independence,” he said.

A nominating committee formed in February to find a new independent director will also be tasked with searching for the organization’s next CEO, said Day.

Lanford came to Texas RE from the PUC, where he served as executive director from 1997 to 2010. Previously, he was the Texas Department of Economic Development’s chief administrative officer for five years and gained experience in management and information technology while working for several financial institutions.

March 10, 2020

PG&E Resolves Dispute with Fire Victims, FEMA

By Hudson Sangree

The Federal Emergency Management Agency dropped its claim Tuesday to a large chunk of the $13.5 billion trust that Pacific Gas and Electric plans to fund for wildfire victims as part of its Chapter 11 reorganization.

Lawyers for FEMA and PG&E told U.S. Bankruptcy Judge Dennis Montali in San Francisco that FEMA had settled for $1 billion of its original $3.9 billion claim for wildfire expenses and can only recoup its money from the trust once all the individual wildfire victims have been paid.

PG&E FEMA — Judge Dennis Montali | *Commercial Law League of America*

Residents and business owners harmed by PG&E-sparked fires in 2015, 2017 and 2018 have filed more than 77,000 claims in the utility’s bankruptcy case. Montali pointed out the deal could mean FEMA winds up getting nothing from the trust, which is what wildfire victims have wanted.

“I’m sure the fire victims will be happy to see the outcome, and so am I. Congratulations,” Montali told attorneys Stephen Karotkin, who represents PG&E, and Matthew Troy, with the U.S. Department of Justice.

The dispute over whether FEMA could share in the victims’ trust was one of the biggest threats to PG&E exiting bankruptcy by June 30, which it must do to take part in a wildfire insurance fund established by the state last year.

FEMA, along with a number of California state agencies, argued it was entitled to get back billions of dollars it spent responding to disasters started by poorly maintained PG&E equipment, including the November 2018 Camp Fire that killed 86 people and destroyed the town of Paradise.

Fire victims were angered by the claims and rallied against the agencies. (See FEMA Wan t s $4 Billion from PG&E in Bankruptcy.)

PG&E and the government agencies reached the agreement during a mediation session Monday intended to resolve disputes over PG&E’s disclosure statement, a simplified explanation of its reorganization plan for fire victims and others. The statement will soon be sent to more than 300,000 interested parties who can vote on PG&E’s bankruptcy plan, the judge said. (See P G &E Tries to Put Bankruptcy Plan in Layman’s Terms.)

Montali ordered the mediation before retired U.S. Bankruptcy Judge Randall J. Newsome last October to try to bring a timely end to one of the largest bankruptcies in U.S. history. PG&E and its adversaries, including lawyers for the fire victims’ Tort Claimants Committee (TCC), said they’d worked out several disputes involving the disclosure statement in Monday’s mediation session.

“We’re pleased to report that objections raised by the TCC, the United States government and state agencies … have all been resolved,” Karotkin told the judge. The agreements will be filed with the court in next few days.

“Thanks to the involvement of former bank bankruptcy Judge Newsome, who’s been working very hard over the last few days … we were able to reach these agreements,” Karotkin said.

Montali responded: “He’s my secret weapon. I’m going to turn him loose on the coronavirus next.”

A hearing on PG&E’s planned financing to exit bankruptcy is scheduled for March 16.

The bankruptcy, now estimated by PG&E to cost close to $60 billion, relies on new stock and debt offerings. Fire victims and Gov. Gavin Newsom have expressed concern that a highly leveraged PG&E may be unable to upgrade its aging infrastructure or to fully compensate those who lost homes and family members.

March 10, 2020

MISO Steps Up COVID-19 Response

By Amanda Durish Cook

MISO on Monday introduced temporary measures to contain the COVID-19 outbreak, converting all in-person meetings to conference calls and barring visitors from its three offices until further notice.

The prohibition on visitors covers RTO offices in Carmel, Ind.; Eagan, Minn.; and Little Rock, Ark. Indiana and Minnesota both recently recorded their first cases of COVID-19, while Arkansas so far has no confirmed cases.

MISO’s measures come about a week after other RTOs announced they were suspending in-person meetings. (See NYISO, MISO Join Grid Operators in Suspending In-person M e etings and RTOs Take Steps to Address COVID –19’s Spread.)

MISO has tightened access to its control room and put a hold on all control room tours. It has also suspended all non-essential business travel for its employees.

MISO COVID-19 — MISO Little Rock headquarters | *Google Maps*

The conference call policy applies to this week’s March 10 Interconnection Process Working Group meeting and March 11 Planning Advisory Committee meeting and Integrated Roadmap workshop. MISO doesn’t have any in-person meetings scheduled March 16-20. It said decisions about future meetings will be “communicated as they are made.”

“The plan is to continue the conference-call only policy for the foreseeable future,” MISO spokesperson Allison Bermudez told RTO Insider.

The RTO is conducting a reassessment of attendance at its Boar d Week in New Orleans March 24-26, asking all registered attendees to change their registration status by March 12 if they no longer plan on traveling to the meetings.

Bermudez said MISO leadership is still evaluating the board meetings in New Orleans and will communicate their decision with attendees.

MISO said its “top priorities are the health and well-being of our employees and stakeholders and the reliability of the bulk electric system.”

In a March 9 message to stakeholders, CEO John Bear said, “MISO’s Incident Management Team continues to track the situation closely and is consulting with experts on appropriate safety steps that help protect employees and ensure grid reliability.” The RTO has initiated more cleaning practices, and employees and contractors are similarly limiting large, in-person gatherings. He also said MISO is prepared to have employees work from remote locations.

“All areas within MISO have business continuity plans that enable work to continue from alternative locations if necessary. We will continue to monitor developments and implement additional protocols as necessary to minimize risk to the MISO community,” MISO said, adding that new developments will be posted on its Twitter page and misoenergy.org.

March 10, 2020

MISO SATOA Proposal Set for Technical Conference

By Amanda Durish Cook

MISO’s contentious first storage as transmission assets (SATA) proposal will become the subject of a future technical conference to allow FERC to weigh the merits of the plan, the commission ruled Tuesday.

FERC formally accepted MISO’s bid to include storage options in its annual transmission planning while also suspending the new Tariff provisions until Aug. 11 after determining they might be “unjust, unreasonable, unduly discriminatory or preferential.” Details of the upcoming technical conference will be included in a later notice (ER 2 0-588).

The commission said the conference will most likely tackle MISO’s plans for evaluating and selecting storage as a transmission-only asset (SATOA), the existing formula rate providing a cost recovery process for SATOA projects and the operating guides applying to the projects. FERC will also discuss SATOA’s “market activities and any potential wholesale market impacts of those activities” and how the projects could potentially impact the RTO’s generator interconnection queue.

MISO’s plan — which stipulates that storage as transmission be limited for now to transmission-only functions and thus operated solely by transmission owners — drew several protests from stakeholders criticizing the RTO’s filing as giving its transmission owners an unfair advantage. Multiple entities said MISO’s ruleset is primed to allow incumbent transmission owners to effectively have a monopoly on storage assets functioning as transmission, harming competition. Several urged FERC to reject the filing. (See MISO SATOA Proposal Faces Opp o sition.)

MISO SATA — Invenergy’s Grand Ridge Battery Storage Facility in Illinois | *BYD*

The commission said it will collect comments after the technical conference and will consider them in further action on the filing.

MISO has said its ruleset would avoid introducing complexities around cost recovery, particularly related to how non-transmission owners would be compensated for providing transmission services.

RTO staff have also repeated assurances that they will soon begin designing new rules that will allow SATA to function as transmission while simultaneously participating in MISO’s energy markets.

MISO officials have also said storage developers and owners who are not classified as transmission owners could still propose projects under the RTO’s existing rules for selecting non-transmission alternatives (NTAs) in the place of transmission projects. MISO last year placed several mentions of electric storage resources into BPM 20, the business practice manual managing NTAs.

But MISO storage owners and developers said the treatment remains unequal since NTAs must first clear the RTO’s approximately three-year generation interconnection queue. The queue is not a requirement for transmission owners proposing SATOA, who instead submit their projects for study through the annual MTEP process.

MISO’s 2019 Transmission Expansion Plan (MTEP 19) includes American Transmission Co.’s Waupaca area energy storage project, which is meant to ease transmission reliability issues in central Wisconsin. The first-ever SATOA project in the RTO’s footprint was withheld from final MTEP 19 approval as MISO waited on the SATOA rules for its cost recovery method. The RTO had planned for its Board of Directors to hold a special March vote on approval of the project once it had FERC’s go-ahead on its rules and cost recovery method. (See MTEP 19 Could Yield First MISO SATA Project.)

March 10, 2020

NYISO, MISO Join Operators in Suspending In-person Meetings

By Tom Kleckner, Robert Mullin and Rich Heidorn Jr.

NYISO and MISO on Monday joined PJM, ERCOT and CAISO in suspending in-person stakeholder meetings in response to the spreading COVID-19 coronavirus.

The New York ISO said all stakeholder meetings would be conducted via teleconference until further notice. It also suspended nonessential business travel. MISO said late Monday that it has changed all in-person meetings for this week to webinar. The RTO is also weighing the possibility of canceling its quarterly Board Week, scheduled for March 24-26 in New Orleans.

The two grid operators’ announcements followed PJM’s on Thursday. The RTO said stakeholder meetings would be webcast only through March 20, when it will begin re-evaluating access to its Valley Forge campus weekly. During that period, it is suspending all visits to its offices except for “essential business personnel and vendors that need to deliver critical items or services.” All business travel for PJM employees and contractors is suspended, including speeches and trainings.

The RTO also is canceling the first three weeks of the PJM Operator Seminar set for Baltimore on March 10, saying “it was not prudent to have a concentration of grid operators in one place.” It is considering replacing portions of the in-person training with online training. It will also consider the need to cancel the remaining weeks of the seminar scheduled in April and May in Columbus, Ohio, and at PJM.

COVID-19 has infected more than 97,800 people worldwide, killing more than 3,300.

the PJM grid operator holds their stakeholder meetings at a conference center in Audubon, PA. — In-person stakeholder meetings at PJM’s Conference and Training Center in Valley Forge, Pa., are being replaced with web conferences because of the COVID-19 coronavirus outbreak. | © *RTO Insider*

ERCOT

ERCOT was the first to scrap in-person meetings, announcing March 3 that it was replacing them through March 15 with webinars or conference calls. The Texas grid operator has instituted restrictions for visitors to all of its facilities and is canceling nonessential business travel by staff and contractors for the same period.

On Monday, the grid operator extended the restrictions through March 31. ERCOT said on Friday that it was canceling six sessions of its black start training, which was to begin March 17. The monthly Technical Advisory Committee meeting scheduled for March 25 has been postponed until at least April 1.

ERCOT is also monitoring staff and their family’s international travel, instructing staff with illness or symptoms to stay home, and deep-cleaning its facilities. It said it will review its restrictions on a weekly basis and alert stakeholders to any changes.

“ERCOT provides a critical service to Texans, and we are taking an abundance of caution to ensure the health and safety of our staff during this time,” spokesperson Leslie Sopko said in an email.

On March 1, the state’s largest energy conference was canceled because of COVID-19’s spread. (See CERAWeek Canceled as COVID-19 Virus Spreads.) And on Friday, Texas caused even bigger waves when Austin canceled the South by Southwest media festival. The annual event draws hundreds of thousands of people to Texas’ capital and contributes an estimated $450 million to the local economy.

CAISO

CAISO alerted stakeholders Wednesday that “to protect the health of the company’s staff and prevent possible disruption to critical business operations,” it has issued temporary restrictions on all in-person meetings through April 1 or until further notice. In-person meetings hosted by CAISO and its Western Energy Imbalance Market will be conducted as teleconferences or webinars when possible, the ISO said.

The policy applies to a series of key meetings scheduled for this month, including those for CAISO’s Board of Governors; the Western EIM Governing Body and Governance Review; the Market Surveillance Committee; the Market Performance and Planning Forum; and the 2021 Local Capacity Requirements process. The decision will also impact CAISO’s March 11 Resource Interconnection Fair.

The ISO has also restricted visitor access to its facilities and suspended nonessential business travel for employees.

“We understand that the new protocol may be an inconvenience, and we apologize for any changes in travel plans, but continued reliable operation of the electrical system is our company’s first priority,” CAISO CEO Steve Berberich said.

ISO-NE and SPP

ISO-NE and SPP had not canceled in-person meetings as of Thursday, although all said they were monitoring the outbreak and following guidance from federal, state and local health agencies to mitigate COVID-19’s spread.

ISO-NE suggested members’ employees not meet with its staff or visit its facilities if they feel ill or show symptoms. The RTO referenced CDC’s expectation that the number of coronavirus cases will continue to grow, and recommended stakeholders consider following its guidelines.

“It is important to stress that, at this time, the risk to [ISO-NE] business operations remains low,” the grid operator said in an email to members.

SPP told RTO Insider it is continuing to work with health officials to monitor COVID-19 and influenza threats and respond appropriately. The RTO said it would use its communication channels and social media to alert its stakeholders of any steps being taken.

On Thursday, SPP emailed its stakeholders to say it had stopped some international travel, but that it had not cancelled meetings or placed restrictions on domestic travel to and from its offices. The RTO encouraged those attending SPP business meetings who feel ill or who are restricted by their organizations from traveling to use its web and teleconference options.

“We have a robust emergency management and business continuity plan that exists to maintain uninterrupted provision of our critical services,” SPP’s Derek Wingfield said. “Our goal is to ensure both the health and safety of our employees and the continued reliability of the grid.”