Page 1116 – RTO Insider

April 7, 2020

PJM Preps 3rd Control Room, Plans for Sequestration

By Michael Yoder

No PJM dispatchers have tested positive for COVID-19 yet, but RTO officials are planning just in case their luck runs out.

During the weekly coronavirus update Friday, PJM officials were asked how they would respond if a dispatcher tested positive for the virus.

Paul McGlynn, PJM’s executive director of system operations, said no control room workers have tested positive, but that the RTO has enough employees to fill gaps if someone becomes infected.

McGlynn said PJM’s control center best practices document includes procedures for bringing back former employees in an emergency. “We look at staff that has previously worked in the control room and develop plans to get them trained and ready so that they could go back on the board if needed,” McGlynn said.

Telecommuting Extended

Scott Heffentrager, PJM’s chief security officer, said the RTO is extending telecommuting for all personnel until May 4. Heffentrager said the telecommuting measure does not apply to the control room staff, IT operations center, security or other critical on-site support personnel.

Crews have been prepping the PJM campuses for more than a week for sequestration — healthy workers required to remain on site if the pandemic becomes worse — if it becomes necessary. Heffentrager said crews are installing temporary bedding, entertainment, food and other accommodations for employees.

“We have not made the decision to go to sequestration, but this was just to prep the campus in the event that we do pull the trigger to do that,” Heffentrager said.

Besides adding accommodations for employees, a team has also been working on converting PJM’s control room simulator to a potential third control room in case of an emergency. Heffentrager said the control room is currently being tested, and security and compliance teams are converting the room to a “physical security perimeter” to meet NERC standards.

Generator Outage Coordination

PJM’s David Schweizer updated stakeholders on generator outage coordination, saying most generators intend on going ahead with planned and maintenance outages despite the pandemic. He said the RTO continues to track any changes that members bring to PJM’s attention, including planned outages.

PJM COVID-19 — David Schweizer, PJM | © *RTO Insider*

About 5% of the planned outages this spring have been canceled outright without being rescheduled, Schweizer said, with about 25% being deferred until later this spring, the fall and the spring of 2021. Schweizer said many generators are reducing the scope of the spring outages by supplementing them with short duration maintenance outages during off-peak hours.

PJM has also continued coordination with gas pipelines to make sure gas is still being sent to generators. Schweizer said teams are tracking any pipeline maintenance plans, especially those that could “affect generation in the PJM footprint.”

Stakeholders are continuing to compile best practice information through a survey of generators that was started last month, Schweizer said. The survey was designed to be a portal to provide supplemental information to PJM so that the RTO is aware of issues related to outages, complications with contractor availability and other support needs.

Schweizer said the questionnaire is meant to be a “dynamic, ongoing survey” that will be updated regularly. He said one of the biggest concerns that has been voiced by generators are supply chain problems for outage-related materials coming from outside the immediate area.

“I think the thing we’re seeing mostly is comments about contractor availability not being 100% assured due to the fact that many outages are relying on critical workforce and resources coming from out of state or even from overseas,” Schweizer said.

Load Modeling

Elizabeth Anastasio, PJM senior meteorologist, said long- and short-term load forecasters are attempting to determine the impact of COVID-19 by comparing actual load with historical temperature and load data.

Anastasio said forecasters have been seeing some trends in load forecast errors.

After the first two weeks of March, the error in one of the short-term models fluctuated between +2% and -2%, Anastasio said, averaging out to a bias near zero for the forecast model.

In the last two to three weeks of March, she said forecasters observed the forecast error increase in magnitude, seeing an error of 4 to 6% depending on the time of day. She said the error has largely remained positive in that time, as the “models are over-forecasting almost exclusively.”

Anastasio said the warmer-than-usual weather has been playing a role in lower load levels.

“We’re doing our best to figure out how much of our decrease in load is due to the warmer temperatures and how much is due to COVID-19,” she said.

Chris O’Leary of PSEG Energy Resources asked if Anastasio believes PJM will be able to quantify the effect of COVID-19 with the higher-than-normal March temperatures and other factors.

Yes, Anastasio said. At least three or four methodologies are being pursued, she said, with each one having limitations that include simplistic modeling and subjectivity.

“What we’ve seen from early results of this analysis is that many of the methodologies are converging on a similar solution,” Anastasio said. “I suspect that we’ll be able to present a little bit more in this line at our Operating Committee meeting presentation” on April 15.

Additional Updates

PJM’s Donnie Bielak provided an update on transmission outage coordination, saying most planned transmission upgrades are proceeding on schedule. Although some transmission operators decided in late March to defer nonessential work until later months, time-sensitive work is proceeding as planned, Bielak said.

Michael Hoke, PJM’s senior lead trainer, updated stakeholders on operator training schedules. Hoke said his team is in the process of finalizing online simulations. He said the online simulations are used for operators who need a certification renewal in the next month or two and need simulation hours to complete the process.

April 7, 2020

DOJ Joins NextEra Appeal of Texas ROFR Ruling

By Tom Kleckner

The U.S. Department of Justice last week again threw its weight behind NextEra Energy’s ongoing effort to repeal a Texas law giving incumbent transmission companies the right of first refusal to build new power lines in the state.

Attorneys with the department’s Antitrust Division filed an NextEra Appeals Court Decision on Texas ROFR Law.)

Assistant Attorney General Makan Delrahim and other division attorneys urged the 5th Circuit to vacate the district court’s judgment and remand the motion to dismiss. The division also filed a brief in NextEra’s lawsuit before the U.S. District Court for the Western District of Austin. (See DOJ Weighs in on Texas ROFR Lawsuit.)

DOJ questioned whether the district court properly dismissed a dormant Commerce Clause challenge to SB 1938. The legislation, passed last May, essentially allows only incumbent transmission companies to build new power lines in Texas by granting regulatory certificates of convenience and necessity to the owners of the endpoints of a new transmission line.

Delrahim noted that the Commerce Clause gives Congress the power to regulate interstate commerce and that the Supreme Court has interpreted the clause to contain the negative implication that “strikes at one of the chief evils that led to the adoption of the U.S. Constitution, namely, state tariffs and other laws that burdened interstate commerce.”

NextEra has used the same argument in its appeal before the 5th Circuit.

In its brief, DOJ said the district court made three analytical errors in its decision, including:

Erring in its evaluation of discrimination, improperly distinguishing “binding Supreme Court precedent articulating principles of ‘ordinary Commerce Clause jurisprudence,’” failing to consider in-state physical presence requirements that are “viewed with particular suspicion” and affording improper significance to the location of a utility’s parent company.
Misreading and misapplying precedent from the Supreme Court ruling in General Motors Corp. v. Tracy to a “noncompetitive, captive market in which the local utilities alone operate.” DOJ said, “The unique factors and concerns for utility markets that determined the outcome in Tracy are not present here and were not evaluated by the district court.”
Failing to weigh whether any of the alleged burdens from SB 1938 “substantially outweigh the law’s putative benefits,” as required under precedent.

April 7, 2020

SPP Seams Steering Committee: April 2, 2020

SPP and MISO are picking up the pace of developing their 2020 coordinated system plan (CSP), staff told the Seams Steering Committee last week.

SPP’s Neil Robertson said both RTOs have published project needs to their individual stakeholder groups. Once the project submissions come in, he said, staff will begin the evaluation phase of those projects. The RTOs will reveal their final portfolios in October and December, respectively.

The RTOs agreed to conduct a CSP this year to determine whether there are any interregional projects worth pursuing. (See MISO, SPP Staff Recommend 2020 Joint Study.)

SPP Director of System Planning Casey Cathey once again expressed his optimism that the CSP will result in a joint project this year. Three previous attempts between SPP and MISO have been fruitless, but Cathey said there has been a large jump in MISO’s prevailing north-to-south system flows.

“The likelihood of economic and reliability projects that meet the thresholds in the [joint operating agreement] is much higher this cycle,” he said. “That’s just by nature of MISO updating their models and SPP’s regional approach to reflect their range of futures and growth, including all new generation in the north.”

MISO’s models include additional wind generation in its northern regions not found in SPP’s models. Cathey said staff are aware of the situation and pondering additional sensitivities to meet those needs.

SPP, AECI Agree to Joint Study

SPP has also agreed to a joint CSP in 2020 with Associated Electric Cooperative Inc. following a March 30 meeting of their Interregional Planning Stakeholder Advisory Committee, Robertson told the SSC.

A scope document has been approved, and solutions will soon be shared. Robertson said the entities plan to finish their analysis in August, after which SPP will have to file a contract with FERC.

The joint CSP could include a 345-kV competitive project approved in January by the RTO’s board as part of the 2020 SPP Transmission Expansion Plan. Robertson said the $152 million, 105-mile Work Creek-Blackberry upgrade in Kansas and Missouri will be included in the study to determine whether there are any system reliability impacts. (See “Directors Approve $545M Transmission Expansion Plan,” SPP Board of Directors/MC Briefs: Jan. 28, 2020.)

Committee Endorses Study of MISO RDT Flows

The committee unanimously endorsed a summary report on the effect of MISO’s contract path to its southern footprint, after first inserting language making it clear the study “should not be used to draw broad conclusions about the impact of MISO RDT [regional directional transfer] flows” to SPP’s region.

The study was inconclusive as to whether MISO’s above-capacity RDTs created a “pattern of financial harm.” Several members pointed out the analysis does not consider the costs of real-time deviations from day-ahead market positions or the economic redispatch of the MISO system. (See “Congestion Study Inconclusive on MISO Contract Path,” SPP Seams Steering Committee Briefs: March 12, 2020.)

The study looked at the SPP day-ahead market’s external flows and solution costs to determine whether RDTs above the contract path capacity between MISO’s South and Midwest sub-regions created additional congestion or operating costs for SPP’s market. MISO is limited to 1,000 MW of contracted, firm capacity over the contract path as a result of a 2015 settlement agreement. (See SPP, MISO Reach Deal to End Transmission Dispute.)

SPP Again Winds up with Positive M2M Settlements

SPP recorded another $1.06 million of market-to-market (M2M) settlements in February, the fifth straight month — and 44th in 60 months — the M2M process with MISO has settled in its favor.

SPP’s market-to-market settlements were once again in its favor in February. | *SPP*

SPP has now earned $73.59 million from M2M settlements with its neighbor since the two began the process in March 2015. The process provides a compensation mechanism when SPP or MISO have to re-dispatch transmission around congested flowgates.

Temporary and permanent flowgates on the RTOs’ seam were binding for 453 hours during January. Temporary flowgates accounted for 385 of the binding hours.

— Tom Kleckner

April 7, 2020

FERC Sets Tech Conference on Hybrid Resources

FERC will hold a technical conference July 23 on the “technical and market issues” raised by the growth of hybrid generation and storage resources.

FERC said the conference will run from 9 a.m. to 5 p.m. ET and will be held either in person at commission headquarters at 888 First St. NE, Washington, DC 20426 (with a WebEx option available) or solely via teleconference if necessary due to the coronavirus pandemic.

The commission will issue a supplemental notice before the conference with the agenda and a decision on the venue.

Those interested in participating as panelists must submit a nomination form by 5 p.m. May 15. Individuals can register to attend at https://www.ferc.gov/whats-new/registration/07-23-20-form.asp.

More information is available from K aitlin Johnson (202-502-8542) for technical questions and Sarah McKinley (202-502-8368) for logistical issues.

Commissioners may participate in the conference.

Commissioner Richard Glick called for a technical conference on hybrids at the Energy Storage Association’s annual Policy Forum in February. Among the questions the commission needs to answer, he said, are how the addition of storage to an existing solar or wind project affects its position in interconnection queues and whether it is treated as a dispatchable or intermittent resource. “We need to learn what some of these issues are — what some of the barriers are — for hybrid technologies,” he said. (See Energy Storage: All Gro w n Up?)

FERC hybrid — Duke Energy began testing a hybrid ultracapacitor-battery energy storage system (HESS) at its Rankin Substation in Gaston County, N.C. in 2016. The substation is connected to a 1.2-MW solar installation a mile away. | *Maxwell Technologies*

Hybrids have been an increasing topic of conversation in the RTOs.

PJM’s Markets and Reliability Committee will be asked at its April 30 meeting to approve creation of a new senior task force to clarify how existing rules for intermittent and energy storage resources would apply to inverter-based solar-battery hybrids. The task force will also consider requirements needed to incorporate hybrids into PJM markets. There are more than 10,000 MW of co-located generation and energy storage hybrid resources in the PJM interconnection queue — more than 95% of the capacity is solar-battery hybrids. (See PJM MRC Moves Forward on Storage, H ybrids.)

NYISO began work in January on development of a model for market participation by front-of-the-meter energy storage resources paired with generation. The Hybrid Storage Model project will evaluate whether co-located storage resources can receive a single dispatch schedule. Co-located resources are currently required to be separately metered. (See NYISO P r epares Hybrid Storage Market Participation.)

In MISO, some stakeholders say hybrid resources are a more pressing matter than the RTO’s storage-as-transmission assets (SATA) proposal. (See MISO Undecided on Amending Sto r age Plan.)

CAISO is continuing a hybrid resources init i ative it began last year. Developers in the state have proposed 25,000 MW of projects that pair storage with existing or new generation. (See CAISO’s 2020 Vision Anticipa t es Big Change.)

— Rich Heidorn Jr.

April 7, 2020

UPDATED: Court Won’t Endorse Letter to PG&E Fire Victims

By Hudson Sangree

The judge overseeing PG&E’s massive bankruptcy said he wouldn’t approve a letter that lawyers for wildfire victims want to send asking the victims to hold off voting on the utility’s Chapter 11 reorganization proposal.

The victims’ lawyers can send the letter independently, but a court endorsement would be inappropriate and would only cause confusion in a balloting process that’s already complex enough, said U.S. Bankruptcy Judge Dennis Montali in a ruling issued late Tuesday afternoon. Parties in bankruptcies are free to solicit support for their point of view.

“A massive undertaking for sending voluminous materials and soliciting votes on the plan is well-underway,” Montali said. “Hundreds, if not thousands, of members of the class have already voted.

“The [Tort Claimants Committee] apparently does not want to upset those votes, but it is beyond doubt that confusion will reign if the court permits the proposed letter to go out, leaving countless fire victims confused even more than they might be now. Are their cast votes valid? Should they ask to withdraw them? And what happens if there is a pause, and voters do not recast their votes in time?”

“The court is satisfied that agreeing to the TCC’s request will cause more harm than good, and court-approval of its proposal is ill-advised and must be rejected,” the judge said.

Lawyers in PG&E’s bankruptcy case argued Tuesday morning about whether the court should approve a letter to more than 70,000 fire victims informing them of potential flaws in the $13.5 billion settlement that PG&E agreed to in December.

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

The main problem, the fire victims’ attorneys told federal Judge Dennis Montali, is that the $6.75 billion in PG&E stock promised in the deal may be worth far less because of PG&E’s stock volatility, exacerbated by its heavy debt load and the coronavirus pandemic.

Utility stock is supposed to fund half the victims’ $13.5 billion trust, but the dollar amount isn’t guaranteed — only the percentage of PG&E shares allocated, lawyers explained. At the time the deal was reached, it was anticipated that the shares, amounting to a 21% equity stake in the company, would be worth about $6.75 billion.

That may no longer be the case, victims’ attorney Robert Julian told Montali. Another lawyer estimated the shares would be worth only $4.85 billion, he said.

Julian said he didn’t necessarily agree with such a low an estimate. Even so, he said, the case’s official Tort Claimants Committee (TCC), which he represents, no longer could support the settlement plan and wants fire victims to hold off on voting for PG&E’s Chapter 11 reorganization proposal until the stock issue and other matters can be resolved. (See Fire Victims C hallenge PG&E Deal as Vote Looms.)

He accused PG&E at one point of planning to postpone funding the trust with stock until the end of the year as a way to cushion current shareholders from the coronavirus impact. Victims were told previously that the trust would fund in August, he said.

In his ruling, Montali said all the issues raised by the TCC were known when he approved PG&E’s disclosure statement three weeks ago and should have been dealt with then. (See PG&E Tries to Put Bankruptcy Plan in Layman’s Terms.)

‘This Silly Letter’

The proposed letter, as it was filed with the court on Monday, would have asked fire victims to hold off voting for PG&E’s Chapter 11 plan until May 1, but plaintiffs’ lawyers backed off that request Tuesday and suggested April 25 as a deadline to try to negotiate the issues while keeping victims informed by mail.

“We want the truth to be told to the victims,” Julian said.

Other creditor groups that settled with PG&E, including insurance companies and hedge funds, will receive all-cash payments, Julian noted. “Fire victims are the only ones standing with this risk of not getting paid or not getting what they bargained for,” he said.

PG&E lawyer Stephen Karotkin called “this silly letter he wants to send out” a negotiating tactic by Julian and other victims’ lawyers to see if they can get a better deal than the settlement agreement they reached months ago after lengthy negotiations.

“Enough is enough on this issue” of guaranteeing the value of PG&E’s stock, Karotkin said.

PG&E’s plan was recently outlined in a disclosure statement and sent to tens of thousands of creditors along with ballots for the creditors’ — including fire victims — vote on the plan. At this point, any party is free to try to persuade other creditors to vote yes or no, Karotkin said.

Julian and the other TCC attorneys want the court to approve the letter as a shield against malpractice claims later on, he said. Karotkin didn’t oppose the letter but argued strongly against the court adding it’s “imprimatur” by approving it before it is sent to victims.

“[Mr. Julian’s] a big boy. Let him make a decision whether he wants to send it out,” Karotkin told the judge.

‘A Pot of Gold’

Montali said he would take a day or two to consider the arguments before issuing a written ruling, but he made his decision hours later

With the courthouse closed due to coronavirus, the hearing took place during a teleconference frequently interrupted by technical glitches. Some participants were in New York, others in San Francisco. The judge, apparently calling from home, was disconnected twice.

The bankruptcy hearings, with dozens of participants, have continued by phone during the state’s coronavirus lockdown because of the tight deadline PG&E faces.

PG&E is trying to end its bankruptcy by June 30 to take advantage of a state wildfire insurance fund and to avoid a state takeover. Montali approved an agreement Tuesday between PG&E and California Gov. Gavin Newsom that would allow the state or a third party to purchase the company if it doesn’t complete its reorganization by the end of June. (See PG &E Deal with Gov. Allows for Utility’s Sale.)

May 15 is the designated end for voting on the reorganization plan. The June 30 deadline prevents what would otherwise be an ordinary extension of the bankruptcy proceedings, Montali said. The coronavirus has resulted in courts and government agencies extending many other deadlines, he noted.

The strict timeline that PG&E is under could be jeopardized by a growing grassroots movement among fire victims to reject PG&E’s offer.

Recently, three members of the 11-member TCC, made of up of fire victims, resigned so they could openly criticize the $13.5 billion settlement proposal as a poor deal. One said the TCC’s lawyers had breached their fiduciary duty to victims by failing to disclose its risks. (See Fire Victims Challenge PG&E D eal as Vote Looms.)

At Tuesday’s hearing, fire victim Will Abrams, a frequent self-represented litigant in the bankruptcy court, supported the TCC’s letter and said some lawyers seemed to be telling victims to vote first and ask questions later.

“They’re pitching this as ‘there’s a pot of gold and all you have to do is vote yes,’” Abrams told the judge.

Abrams was one of thousands who lost their homes in the Northern California wine country fires of October 2017 and the Camp Fire in November 2018. State fire investigators blamed most of the wine country blazes and the Camp Fire, the deadliest in state history, on failed PG&E equipment.

PG&E sought bankruptcy protection in January 2019 after the fires saddled it with an estimated $30 billion or more in liabilities to those who lost family members, homes and businesses.

Its bankruptcy is now estimated to cost close to $60 billion, making it among the largest in U.S. history.

April 7, 2020

Solar Subsidy Program Ending in New Jersey

By Michael Yoder

New Jersey is winding down a solar energy program that helped place the state near the top of solar production in the country.

The New Jersey Board of Public Utilities announced Monday it was directing staff to close the state’s Solar Renewable Energy Certificate (SREC) registration program effective April 30.

The Clean Energy Act of 2018 (AB-3723), which Gov. Phil Murphy signed into law in May of that year, set new clean energy standards in New Jersey, including a requirement that the BPU would close the SREC program by June 2021 or when 5.1% of the kWh sold in the state was generated by solar. The board said it expects to reach the 5.1% milestone by the end of April.

New Jersey Solar Subsidy — The Six Flags Great Adventure amusement park in Jackson, N.J., is mostly powered by a 23.5-megawatt solar project that began operation last summer. | *Six Flags*

The BPU established the SREC program in 2004 to complement the state’s existing solar rebate program. Since then, state officials said more than 3.25 GW of solar systems have been constructed throughout New Jersey, including more than 118,000 residential solar systems.

“While today marks the end of one chapter, it also marks the beginning of a new chapter that I believe will lead to a very successful solar future while also lowering costs for New Jerseyans,” said BPU President Joseph L. Fiordaliso. “With a record year for solar in 2019, the New Jersey solar industry is strong, and I am confident it will continue to be healthy and profitable while playing a key role in fighting climate change and reaching the governor’s goal of 100% clean energy by 2050.”

The SREC program allowed New Jersey to become one of the leading solar energy producers in the country despite its relatively small land size and available space. According to data provided by the BPU, it’s currently ranked seventh in the nation in installed solar capacity and ninth overall in clean energy jobs, with nearly 9,000 solar industry jobs throughout the state.

The most recent report from New Jersey’s Clean Energy Program shows that 447 MW of solar capacity commenced commercial operations in the state between Jan. 1 and Dec. 31, 2019, bringing the state’s total capacity up to 3,190 MW through the end of the year. The state’s previous record for the highest amount of installed solar capacity within a calendar year was in 2011, when 446.8 MW commenced commercial operations.

Six Flags said its array — 11 MW of solar carports and 12.5 MW on 40 acres of ground-mounted solar panels — makes it New Jersey’s largest net metered solar project. | *Six Flags*

The BPU is replacing the SREC program in two phases, beginning with the Transition Incentive Program, approved by the board in December. The new program was designed to serve as a bridge between the SREC and a yet-to-be determined successor program by issuing fixed-price, 15-year Transition Renewable Energy Certificates (TRECs) to projects that entered the SREC pipeline after Oct. 29, 2018, but had not reached commercial operation as of April 30.

An order issued March 10 by the BPU set the price at $152 per TREC, which a project earns after generating 1 MWh. By comparison, SRECs traded at a weighted average price of $208.99 in February, according to the BPU. The long-term successor program to SREC is currently under development by BPU staff.

Solar projects currently in the system that have yet to be finalized through the SREC were given a 90-day extension by the board because of permitting and inspection issues caused by the COVID-19 pandemic.

“Having leveraged the generous ratepayer subsidies of the past 20 years, the industry can now survive and thrive at a lower cost to ratepayers,” the BPU wrote in its decision. “The board anticipates that New Jersey’s solar market will continue to be a vital and dynamic one as it transitions to a new incentive mechanism, but it has nonetheless made every effort to ensure that this is so.”

The Solar Energy Industries Association estimates solar investment in the state totals more than $10.1 billion and says prices have fallen 38% over the last five years. The trade group expects growth to slow, however, projecting 1.8 GW over the next five years, 41st in the nation.

April 6, 2020

NERC Requests FERC Defer Standards Implementation

By Holden Mann

Citing the need to “provide registered entities with regulatory certainty” during the COVID-19 pandemic, NERC has requested that FERC delay the implementation of several reliability standards that are scheduled to take effect this year (RM15-4, et al.). The organization asked that FERC consider the request on an expedited time frame and issue its decision as soon as possible.

NERC FERC — FERC headquarters in D.C. | © *ERO Insider*

Under NERC’s request, the following cybersecurity supply chain standards that are scheduled to become effective July 1 would be delayed to Oct. 1:

CIP-005-6 (Electronic security perimeter(s))
CIP-010-3 (Configuration change management and vulnerability assessments)
CIP-013-1 (Supply chain risk management)

In addition, the following standards scheduled to take effect Oct. 1 would be moved to April 1, 2021:

PER-006-1 (Specific training for personnel)
PRC-027 -1 (Coordination of protection systems for performance during faults)

Two other standards that are already effective would see some compliance deadlines pushed back. Under PRC-002-2 (Disturbance monitoring and reporting requirements), which took effect July 1, 2016, entities are required to demonstrate 50% compliance with requirements R2-R4 and R6-R11 by July 1; this would be moved back to Jan. 1, 2021. Also, PRC-025-2 (Generator relay loadability) requires entities to establish compliance with certain measures by July 1; this deadline would also be deferred to Jan. 1, 2021.

NERC said extending these deadlines would be “just, reasonable, not unduly discriminatory … would not adversely impact reliability” and would allow utilities to focus on the response to COVID-19 rather than on time-consuming compliance activities. The organization indicated that implementation delays for additional standards may be warranted depending on the progress of the outbreak and subsequent recovery efforts.

NERC Pursues Active Pandemic Response

The request for delay follows a number of steps by NERC and FERC in response to the pandemic. In March the organizations announced they would use regulatory discretion to relax compliance burdens for utilities related to maintaining personnel certification, performance of required periodic actions, and on-site activities such as audits and certifications. (See FERC, NERC Relax Compliance in Light of COVID-19.)

Last week, FERC agreed to give NERC more time to complete two compliance filings ordered earlier this year. (See FERC Extends NERC Compliance Filing Deadline Again.)

NERC said last week that the industry has “[taken] aggressive steps” in response to the pandemic, with most utilities either having a written response plan or currently developing one, and a majority pledging to support mutual aid requests from others involved in a pandemic emergency. (See Industry Pandemic Prep Encouraging, NERC Says.) The organization’s own response includes the issuance of a Level 2 alert in March, activation of its Business Continuity Plan and shifting upcoming meetings to conference calls or video conferences.

In addition, GridSecCon, the annual security conference sponsored by the Electricity Information Sharing and Analysis Center scheduled for Oct. 20-23, has been canceled this year.

According to the World Health Organization’s latest situation report, more than 1.2 million coronavirus infections have been confirmed worldwide since the disease was first reported in Wuhan, China. More than 67,000 deaths have been directly attributed to the virus globally.

April 5, 2020

Van Welie: ISO-NE Pandemic Transition Going ‘Smoothly’

By Michael Kuser

ISO-NE CEO Gordon van Welie said that the RTO activated emergency operation procedures to counter the COVID-19 pandemic on March 12 and that “it’s been really gratifying to see how smoothly the transition went.”

“We have all these contingency plans, emergency plans, and have experimented with half the workforce working from home, but we never had to implement them for real before now,” van Welie told the New England Power Pool Participants Committee on Thursday.

The RTO has more than 95% of its workforce now working remotely, with remote deployment to continue through at least May 4, and is taking special care for the health of crews for the two control centers, ISO-NE COO Vamsi Chadalavada said.

“The industry has really come together in a very refreshing and collaborative way,” he said. “I think folks have closed ranks; there’s a lot of cooperation; and best practices are being shared in near real time. There are extensive communication protocols across the country and internationally.”

ISO-NE Van Welie — Comparison of a few similar days between 2019 and 2020 for midweek in the second half of March. 2020 load curves show as lower and delayed ramp in the morning; overnight loads are lower with closings of 24-hour operations. | *ISO-NE*

The Electric Power Research Institute has been hosting sessions, and the RTO conducts its own conference calls with generators and every key link in the supply chain to ensure reliability, Chadalavada said.

Chadalavada reported overall March 2020 demand approximately 3 to 5% lower than in prior years, with load curves having changed shape with the pandemic outbreak from the second half of March as the New England states started to require people to stay home.

“The load curves that are now being established mimic snow days when people typically stay home and businesses are either shut down or otherwise operating at not full speed,” he said. “We see that the morning ramp is delayed. What used to be a ramp around 7 a.m. is now extending to 8 a.m. or even 9 a.m.”

The situation presents a challenge to forecasting load, especially now, and the deviation from actual load has in the last few days been “north of 3%, so we’re clearly not meeting our target 1.8% error, but our forecasters are vigilant and staying very close to system conditions,” Chadalavada said.

The RTO is exploring the risk of underestimating loads after the pandemic-induced economic shutdown, he said.

With continued choppiness expected over the next week, “we are trying to train our models, but as you can assume, two weeks of training is almost insufficient for any model to upgrade its performance,” Chadalavada said. “Coming out of it will be an even bigger challenge, so right now I see the algorithmic foundation as the biggest challenge for forecasting load.”

In terms of settlement, the RTO has well established procedures, he said.

“If there are any delays in flow of data, and if we have to make adjustments to it because of any reason, I’m sure we will act quickly and work with all of you to do so,” Chadalavada said.

In his monthly litigation report, NEPOOL Secretary David T. Doot delivered noted FERC’s actions last week to delegate additional authority and issue waivers of some requirements in response to the pandemic. (See related story, FERC Loosens Requirements in Pandemic.)

April 5, 2020

NextEra Said to be Eyeing Evergy as Acquisition Target

By Tom Kleckner

A publication that covers financial mergers and acquisitions said Friday that NextEra Energy is toying with the idea of acquiring Kansas City utility Evergy.

According to M&A by Reorg, recent activist pressure from Elliott Management, which manages funds that own an economic interest equivalent to approximately 10 million shares of Evergy’s common stock, may make the company more willing to consider a sale.

NextEra has hired Citi to advise on the potential acquisition, and internal evaluations are at the preliminary stages, according to the report.

The publication said American Electric Power and Ameren are also said to be interested in Evergy.

NextEra declined to comment, following its policy to not respond to market rumors.

The Florida-based company failed in a 2016 effort to buy Texas utility Oncor. (See Texas Commission Denies NextEra’s Bid for Oncor.)

AEP and Ameren also declined to comment. Ameren did note it is focused on executing its strategic plan, which is based on “strong organic growth” in its regulated businesses.

Evergy announced in early March that it had reached an agreement with Elliott to establish a new strategic review committee to explore ways to improve shareholder value. Elliott said at the time that Evergy is now “well positioned to significantly increase investment in critical electric infrastructure to benefit key stakeholders.”

Evergy also agreed to add two new independent directors to its board, raising the number of directors to 17. The board’s membership will be reduced to 13 by retirements before the May shareholders’ meeting.

The two new directors, former Energy Future Holdings senior executive Paul Keglevic and NRG Energy CFO Kirk Andrews, will comprise half of the Strategic Review & Operations Committee, which will look at “potential strategic combination(s)” or a modified long-term standalone operating plan. It can retain its own independent consultants, advisers and counsel to facilitate its review and has an information-sharing agreement with Elliott.

“Elliott recognizes our commitment to serving the best interests of all Evergy stakeholders,” Evergy CEO Terry Bassham said in the announcement. “We welcome these new, highly qualified directors and the significant and valuable experience they bring to this effort. The comprehensive strategic and operating review we are undertaking will help ensure that Evergy is directing capital to the greatest opportunities and continuing to consider all opportunities to enhance shareholder value.”

Evergy, an SPP member, was created in 2018 by a merger between Kansas City Power and Light and Westar Energy. It serves 1.6 million customers in Kansas and Missouri.

April 5, 2020

FERC Stands Firm on Form 715 Assessments

By Rich Heidorn Jr.

FERC said Friday that PJM must rebill parties with interest to reverse incorrect cost assignments for transmission projects to meet individual utilities’ planning criteria.

In 2015, the commission approved a PJM Tariff change that assigned 100% of the costs of Form 715 transmission projects to the sponsoring utility’s ratepayers. But FERC reversed itself last August after the D.C. Circuit Court of Appeals said it had erred.

The court said FERC’s approval was “arbitrary” and would result in a “severe misallocation of the costs” of projects that have regional benefits. (See FERC Opens Local Tx Projects to Competition, Cost Sharing.)

The commission on Friday rejected rehearing on its August order and clarified that PJM should issue refunds dating back to May 25, 2015, with interest (ER15-1387 -005 , ER15-134 4-006).

The commission rejected arguments by Linden VFT and Consolidated Edison Company of New York that the commission should have limited its remand order to high-voltage facilities.

FERC Form 715 — Dominion Energy replaced a 500-kV line between the Cunningham and Elmont substations. | *Dominion Energy*

“PJM’s Tariff uses the solution-based DFAX [distribution factor] method to determine whether transmission facilities have benefits outside of the zone of the transmission owner constructing the project and allocates costs to zones based on the application of that methodology,” FERC said. “Because the benefits of lower-voltage facilities may accrue to other zones, we do not see a basis for limiting cost allocation for lower-voltage facilities planned under Form No. 715 local planning criteria to only the local zone of the constructing transmission owner.”

Linden also sought rehearing on the issue of refunds, arguing that the commission’s “default” policy is to reject refunds in cases of rate design.

The commission responded that it “does not have a general policy concerning refunds” but makes decisions based on each case individually.

“Here, the commission has found the facts and equities favor refunds,” it said. “For example, requiring refunds in this case requires only redetermining past payments; it does not involve the difficult issues often associated with the rerunning of auctions.”

The commission on Friday also accepted PJM’s compliance filing with revised cost responsibility assignments to correct the allocations made under the 2015 Tariff amendments (ER15-1387 -006 , ER15-134 4-007).

PJM said it identified 443 transmission projects that had been assigned 100% to the zone of the TOs filing the Form 715 planning criteria between May 25, 2015, and the remand order on Aug. 30, 2019. It determined that it needed to revise allocations for 44 of the projects.

The new allocations reassigned costs for several projects in the Public Service Electric and Gas zone to Con Ed, East Coast Power, Neptune Regional Transmission System, Rockland Electric, PECO Energy and Jersey Central Power & Light.

Dominion Energy, which had been assessed for 100% of the rebuild of the Elmont-Cunningham 500-kV line, is now sharing the cost with 23 other utilities.