Page 1109 – RTO Insider

April 28, 2020

PG&E Seeks to Finalize Deal with FEMA, Calif. Agencies

The judge overseeing Pacific Gas and Electric’s bankruptcy on Saturday rebuffed the utility’s request that he fast-track approval of agreements signed last week between it, fire victims and the government agencies that had once sought to recoup billions of dollars from a fire victims’ trust.

Lawyers for PG&E filed a motion Saturday urging U.S. Bankruptcy Judge Dennis Montali to approve the agreements in a hearing on May 6 with objections due by May 4 — an unusually short timeline for other parties to weigh in.

Montali quickly rejected the request in a rare weekend exchange, saying he’ll stick to his established schedule for reviewing the agreements.

PG&E’s urgency was prompted by the fact that nearly 80,000 fire victims must vote on the utility’s reorganization plan by May 15.

“Because the motion seeks to resolve critical claims allowance, classification and other issues that could otherwise impact confirmation and the recoveries to fire victims under the plan, a prompt hearing on the motion is appropriate,” PG&E’s lead attorney Stephen Karotkin wrote in a declaration filed in support of the motion.

PG&E FEMA — PG&E still has many workers rebuilding Paradise, the town destroyed by the Camp Fire in November 2018. | © *RTO Insider*

The basic terms of the settlements have been known since March 10, when PG&E and the Federal Emergency Management Agency told Montali they had agreed during mediation to settle for $1 billion of the agency’s original $3.9 billion claim. (See PG&E Resolves Dispute with Fire Victims, FEMA.)

Other federal and state agencies also agreed to accept far less than they claimed to be owed. They, along with FEMA, also agreed to be paid only after all fire victims claims are settled. The agreements were signed April 21, according to the motion PG&E filed over the weekend.

“The governmental fire claims settlements resolve the treatment of approximately $7.5 billion in aggregate of fire claims that have been asserted by the various governmental agencies in these Chapter 11 cases for an allowed $1 billion … to be subordinated and junior in right of payment to all other fire victim claims that may be asserted against the fire victim trust,” Karotkin told the judge. (The $7.5 billion figure is exaggerated because most of the federal and state claims overlap, Montali noted in a prior hearing. The actual figure is closer to $4 billion.)

FEMA and the federal Small Business Administration will share in the $1 billion, though they may ultimately receive less or nothing if fire victims consume most of the $13.5 billion allotted to the trust.

The state agencies, including the governor’s Office of Emergency Services, agreed to relinquish billions of dollars in claims that overlapped with FEMA’s.

In the settlement agreements filed with the court Saturday, PG&E said it will pay $115.3 million to the California Department of Forestry and Fire Protection and $89 million to half a dozen other state agencies that incurred expenses from PG&E sparked wildfires in recent years. The utility will pay the U.S. Department of Justice $117 million for legal expenses.

The total — $321.3 million — will come from interest earned on the fire victims trust over three or four years or from profits from the sale of the PG&E stock that will partly fund the trust, the utility said.

‘Not Warranted’

The court still must approve the settlement agreements, and PG&E’s attorneys made it clear Saturday they were hoping that would happen quickly.

PG&E said it was hoping to reassure fire victims that the money owed to the federal and state governments would not be deducted from the $13.5 billion trust until all the victims’ claims are paid.

The fire victims may be the last obstacles between PG&E and its need to exit bankruptcy by June 30 — the deadline for the utility to participate in a state wildfire insurance fund and to avoid a possible state takeover. It’s also the date CEO Bill Johnson said he will retire. (See related story, PG&E CEO Johnson Says He’ll Step Down.)

The fire victims, creditors and affected parties, about 250,000 in all, must vote on PG&E’s restructuring plan by mid-May.

Some victims have urged a “no” vote, saying the $13.5 billion settlement is half-funded with PG&E stock that could end up being worth less after the utility leaves bankruptcy heavily indebted.

“The proposed settlement with the federal and state agencies, that has been in the works for some time, is a significant milestone,” Montali said in his order rejecting PG&E’s request. “But filing the necessary pleadings on a weekend and asking to shorten time to require objections by May 4, and a hearing two days later, is not warranted. … Given the difficulties all are experiencing with the current [COVID-19] crisis … the court denies the request to shorten time.”

The judge said he’ll consider the settlement agreements at an already-scheduled hearing on May 12.

PG&E filed for bankruptcy in January 2019 after two years of devasting wildfires ignited by its transmission lines. The blazes included the Camp Fire in November 2018, the deadliest and most destructive wildfire in state history.

The company recently agreed to plead guilty to 84 counts of involuntary manslaughter in that fire. It is scheduled to be sentenced May 26 in Butte County Superior Court.

April 28, 2020

NJ Solar Program Amended for COVID-19 Interruptions

The New Jersey Board of Public Utilities acted Monday to help solar project developers who face a looming registration deadline at the end of the month despite continued interruptions from the COVID-19 pandemic.

The BPU unanimously passed special procedures for registrants in the Solar Renewable Energy Certificate (SREC) program who would have completed all necessary steps to secure eligibility by April 30 but were prevented by the pandemic from obtaining municipal code inspections or permission to operate from their electric distribution companies.

The board announced April 6 that it was directing its staff to close the SREC program by the end of the month because it was about to achieve a Clean Energy Act of 2018 (AB-3723) requirement that it be ended when 5.1% of electricity sold in the state was generated by solar. (See Solar Subsidy Program Ending in New Jersey.)

The BPU established the SREC program in 2004 to complement the state’s existing solar rebate program. The program helped the state become one of the leading solar energy producers in the country.

New Jersey COVID-19 — BPU President Joseph Fiordaliso | © *RTO Insider*

BPU President Joseph L. Fiordaliso said the measure was “certainly appropriate” in light of the emergency. He noted that New Jersey utilities have been cooperative during the pandemic and toward the state’s ratepayers.

“The least we can do is to try to make some accommodations in order to relieve some of the pressure and stress that some of these developers have been experiencing,” Fiordaliso said. “I believe that this action will certainly do that.”

Scott Hunter, manager of the BPU’s Office of Clean Energy, presented the rule waiver to the board, saying the measures were necessary to give the SREC administrator flexibility in determining when projects have commenced commercial operations to qualify for the program.

The waiver extends the due date of finalized SREC paperwork to 90 days from the date when New Jersey’s emergency declaration is rescinded. Hunter said eligibility is limited to projects that are currently enrolled in the program and have been kept them from receiving final approval from local inspectors because of the pandemic.

“We’ve heard anecdotes from solar developers and the electric distribution companies [EDCs] through connections to staff representatives of local municipal inspection processes slowing down,” Hunter said. “And since municipal compliance is a prerequisite to EDCs granting permission to operate, the result has presented a barrier for some projects to achieve their commencement of commercial operations despite being mechanically complete.”

The new process creates a procedure to show the SREC projects were mechanically complete by April 30. Hunter highlighted six requirements:

An affidavit from the project owner that the failure to obtain permission to operate was because of pandemic-related closures of local government offices or delays in the issuance of permission to operate from the EDC.
An affidavit signed by a person with direct personal knowledge of the solar project stating the project was complete except for final inspections or final permission to connect to the grid prior to April 30.
Date-stamped pictures of the array, inverter and balance of system.
Date-stamped evidence that project representatives attempted to communicate with local code officials, including emails requesting an inspection, or communication with the EDC to connect if the project had already been inspected.
A milestone report form that reflects the status of the project, including request dates for inspection or an application to connect to the grid.
Any other evidence BPU staff or the SREC administrator may request.

Replacement Solar Program

The board also unanimously voted to consider amendments to the proposed renewable portfolio standard rules approved at its March 27 meeting and create new rules establishing the solar Transition Incentive Program.

The BPU is replacing the SREC program in two phases, beginning with the Transition Incentive Program, designed to serve as a bridge between the SREC and a yet-to-be determined successor program. The board is 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.

SREC Program Administrator Ariane Benrey said that following the board’s vote, staff posted an advance copy of the proposal to the BPU website, which received questions and comments from stakeholders.

Staff proposed approving a new version of the proposal that includes modifications intended to clarify certain elements of the transition program related to the length of time and process for project registration, Benrey said.

The rule proposal will now move to the Office of Administrative Law, Benrey said, where it will be open to public comment for 60 days before returning for final board approval.

“Staff continues to learn from the implementation of the Transition Incentive Program prior to the close of the SREC registration program on April 30,” Benrey said.

Stakeholders said after the meeting that the amendments were a positive step in keeping solar projects thriving in New Jersey. Solar advocates also pointed out the new program needs improvements.

“The transition program will allow some solar to move forward, but we need a long-term solution,” said Jeff Tittel, director of the New Jersey Sierra Club. “We need to move quickly to develop a new program and come up with a new funding mechanism so that the solar program can come back.”

April 28, 2020

FirstEnergy Sees Modest Earnings Impact from Pandemic

FirstEnergy said last week it remains confident in its earnings projections despite lower electricity demand and the likelihood of a recession from the coronavirus pandemic.

During a first-quarter earnings call Friday, the company said weather-adjusted load in its territories was down by almost 6% from mid-March to mid-April compared with last year.

Smart meter data from Pennsylvania showed residential loads up by 6% because of Gov. Tom Wolf’s stay-at-home order, while commercial and industrial load is down almost 13% compared to the company’s prior four-year average.

CEO Chuck Jones said the company’s rate structure and scale — with operations across 65,000 square miles in five states — will cushion it from the impact of the economic slowdown.

“We believe our distribution and transmission investments will continue to provide stable and predictable earnings,” Jones said. “As the situation continues to develop, the diversity and scale of our operations gives us the flexibility to shift our investments if needed and continue deploying capital throughout the system.”

Almost two-thirds of the company’s base distribution revenues are from higher-margin residential customers, with 28% from commercial and 7% from industrial customers, which are lower margin. About 80% of commercial and 90% of industrial distribution revenue is from customer and demand charges, not energy consumption.

One-fifth of its retail load — in Ohio — is decoupled, insulating the company from revenue losses because of energy efficiency and peak demand reductions. “This mix partially insulates FirstEnergy from recessions,” CFO Steve Strah said.

Protecting the Workforce

The company has increased cleaning and disinfecting measures at its locations and has 7,000 employees — more than half its workforce — working remotely, including its call center employees.

Workers unable to work remotely have been issued surgical masks, thermometers and other protective equipment and are reporting to locations that permit social distancing.

“We have positioned crews so they are working with the same small group of people each day on what we call pods. They’re consistently using the same vehicle and the same equipment to limit exposure. And we are managing our work to minimize potential exposure with the public,” Jones said.

The company has reported nine COVID-19 cases among its 13,000 employees. “One of those cases in New Jersey unfortunately resulted in a death,” Jones said. “But we’ve had zero cases where the disease has been transferred at work.”

Results

The company reported first-quarter 2020 GAAP earnings of $74 million ($0.14/share) on $2.7 billion in revenue, down from $315 million ($0.59/share) on revenue of $2.9 billion a year earlier. Operating (non-GAAP) earnings for the first quarter were 66 cents/share versus 67 cents/share in 2019.

Strah said 2020 GAAP results included a $318 million non-cash mark-to-market adjustment on the company’s pension and other post-employment benefit plans that it was required to recognize when its former merchant company, FirstEnergy Solutions, emerged from bankruptcy at the end of February. FES is now an unaffiliated independent company, Energy Harbor.

“In February, we used the proceeds from our senior note issuance, together with cash on hand, to fund the final settlement payment of $853 million to Energy Harbor upon their emergence,” Strah added.

The company affirmed its 2020 earnings guidance of $2.40 to $2.60/share and its expected compound annual growth rates (CAGR) of 6 to 8% through 2021 and 5 to 7% through 2023.

Capital Expenditures and Supply Chain

Jones said that much of the company’s guidance in its CAGR is driven by capital expenditures. “We don’t see any supply chain interruptions that we’re worried about right now. And that includes the workforce supply chain, because most of the significant capital investment that we’re making is being done with a contracted workforce that we lined up many, many years ago,” he said.

The company’s Buy America strategy, implemented about four years ago, has the company purchasing more than 80% of its supplies domestically, Jones added. “When you put that all together, I’m confident that that there’s not going to be any material swing in weather-adjusted revenues that are going to take us off track from delivering on our guidance … or I wouldn’t have reaffirmed guidance.”

Jones noted that the company has more than $2 billion in operations and maintenance expenses. “If we need to get a little more diligent at O&M discipline to offset some of what might be happening on the meter side of things, we’ll do that,” he said. “We can work to deliver on our commitments.”

Analyst Stephen Byrd of Morgan Stanley asked whether the company might have to slow its capital expenditures next year to reduce costs for its customers if the economic recovery is slow. “Is that viewed as … critical work that needs to be done? Or is there any consideration of customer ability to pay?” he asked.

“The impact on customers is always something that we’re very thoughtful about as we make these investments,” Jones responded. “But I do believe these investments are investments that are needed. The transmission and distribution infrastructure we have at FirstEnergy is old. It’s in some cases in need of repair and modernization.”

Bad Debts?

Jones said he wasn’t concerned about cash flow problems resulting from the company’s announcement last month that its 10 utility companies had temporarily discontinued power shutoffs for customers who are past due on their electric bills.

He thanked the Maryland Public Service Commission for issuing an order allowing utilities to defer for future recovery of prudent, incremental pandemic-related costs. The company can also recover incremental uncollectible expenses through existing riders in Ohio and New Jersey, he said.

“I’ve been in this business for 40 years; I don’t think it’s fair to assume that every customer who can’t pay their bill today is going to end up being a bad debt,” he said. “My experience is customers want to pay their bills; they don’t want a black mark on their credit history. And as long as we’re flexible and work with them the right way, we can generally get to where we don’t end up writing off a lot of what’s going to get backed up here today.”

Earnings transcript courtesy of Seeking Alpha.

April 28, 2020

FERC Denies Rehearing on Affected System Order

FERC on Friday denied rehearing of a 2019 order that directed MISO, PJM and SPP to shine more light on how they perform their affected-system studies (EL18-26).

The commission last September told the three RTOs that their joint operating agreements don’t provide enough clarity on how they handle the study of generator interconnections along their seams. (See Affected-system Rules Unclear, FERC Says.) It ordered them to update their JOAs and tariffs to make the queue priority process more transparent.

A handful of renewable generation developers in the RTOs called for rehearing on the grounds that FERC’s order didn’t go far enough to unify their affected-system studies. Invenergy argued that FERC should order all RTOs to use energy resource interconnection service (ERIS) — as opposed to network resource interconnection service (NRIS) — as the modeling standard to determine affected-system impacts.

But FERC noted that its September order “did not make a final determination as to the justness and reasonableness of the use of either an ERIS or NRIS modeling standard to study impacts as an affected system by any RTO.”

“Consequently, we dismiss as premature Invenergy’s rehearing arguments as to the RTOs’ use of an ERIS or NRIS modeling standard to study impacts as an affected system,” the commission said. It said it will individually evaluate MISO, PJM and SPP’s modeling standards for affected-system studies in the RTOs’ compliance filings.

Affected System FERC Order — | © *RTO Insider*

FERC also declined to adopt a specific timeline for RTOs to make their affected-system study modeling available. The commission said the deadline issue was already addressed in FERC Order 845, which requires transmission providers to maintain network models, “including all underlying assumptions,” on either password-protected sites or their Open Access Same-time Information System sites, FERC said.

Multiple renewable developers questioned why FERC directed SPP and MISO to revise their JOA to include timelines for the sharing of affected-system information but didn’t require the same timeline alterations to MISO and PJM’s.

FERC said the end goal of the directive to MISO and SPP was to heighten transparency, something that was already written into the MISO-PJM JOA.

“The commission found that the MISO-PJM JOA met the goal of transparency because it detailed the process, including target dates for information exchange, and consequently did not warrant further modification,” FERC said, adding that the generation developers knew that the RTOs already had information-sharing timelines in place but were seeking changes out of scope to speed up the interconnection process.

FERC similarly didn’t require MISO and PJM to add a description of how they study impacts on affected systems, as it prescribed for the MISO-SPP JOA.

The same developers asked FERC to require the same descriptor in the MISO-PJM JOA, but FERC said it continues to find that JOA “includes sufficient detail on how each RTO studies affected-system impacts.”

The developers took a final shot at rehearing when they argued the commission should have required PJM to include affected-system study results with interconnection study results, something that MISO and SPP already try to do.

The commission pointed out that MISO and SPP only include affected-system study results in respective interconnection studies “if they are available.” It said the attachment of results in all interconnection studies would take a monumental alignment effort from the three RTOs.

“We reiterate that in order for the RTOs to include affected-system RTO information with their own study results, the cycles would essentially have to be aligned, as the affected-system RTO information would have to be available at the time the RTO’s study results conclude,” FERC said. “There are significant differences between the processes and time frames used by the various RTOs, and we do not find that a realignment of these processes is necessary to ensure that interconnection customers have time to review affected-systems studies before making further financial commitments.”

April 28, 2020

FERC Rejects 4 SPP GIA Requests

FERC on Thursday rejected without prejudice four unexecuted generator interconnection agreements (GIAs) filed by SPP, finding that the RTO had not shown the agreements with four proposed wind farms to be just and reasonable (ER19-2747, et al.).

The commission found the allocation of costs for a shared network upgrade under each of the GIAs should not have been included because a restudy of the interconnection requests determined the upgrade was no longer needed and would not be built.

The Emporia upgrade “is no longer a ‘but for’ facility that is needed for the interconnection” of the affected interconnection customers, FERC said.

The four interconnection customers, all wind farms in Oklahoma and Kansas, submitted their requests to SPP before a 2016 deadline to be included in a study queue. The RTO performed five restudies following the initial study, one of which identified a shared network upgrade necessary to accommodate the wind farms. The fifth restudy concluded that the upgrade was no longer needed because of the pending development of the Wolf Creek-Blackberry competitive transmission project, approved by SPP’s Board of Directors in January.

SPP GIA Requests — The Skeleton Creek and Wheatbelt wind farms both plan to use GE’s 2-MW turbines. | GE

SPP filed the GIAs in September. The requests were filed as unexecuted because the wind farms disagreed with the proposed cost allocation provisions.

The RTO told FERC it is revising the unexecuted GIAs to reflect the fifth restudy’s results and that none of the GIAs have been executed by the wind farms.

The proposed wind farms are Frontier Windpower (141.8 MW), Skeleton Creek Wind (250 MW), Wheatbelt Wind (220 MW) and Chilocco Wind Farm (200.1 MW).

The Wolf Creek-Blackberry project, a $152 million, 105-mile, 345-kV upgrade project in Kansas and Missouri, was approved as part of the SPP’s 2020 T ransmission Expansio n Plan. (See “Directors Approve $545M Transmission Expansion Plan,” SPP Board of Directors/MC Briefs: Jan. 28, 2020.)

April 28, 2020

Renewable Investors See Light at End of COVID Tunnel

Wind and solar energy resource developers are bracing for a tumultuous year, but investors last week expressed confidence that renewables were poised for a rebound when the U.S. economy recovers from the COVID-19 pandemic-induced downturn.

In a webcast hosted by the American Council on Renewable Energy on Wednesday, investors in renewable resources said that despite some short-term delays, most projects that were already under construction before the downturn are still on target for completion, as construction work has been deemed critical.

“We are starting to see delays in some places, primarily just due to shelter-in-place orders where people are not able to access sites and … not able to get the attention of government officials to proceed through development milestones that require permitting,” Generate Capital CEO Scott Jacobs said. But he said that even amid the pandemic, his firm has raised $300 million worth of equity and “closed on a significant amount of new project financing debt capital.”

“So the money is flowing. … There is a lot of appetite for these kind of resilient investment opportunities, and if we just changed the word ‘sustainable’ to ‘resilient,’ we might actually appeal to a wider pool of people.”

George Strobel, co-CEO of Monarch Private Capital, said his company has not seen any of its projects experience supply chain disruptions because those that had 2020 target dates had started ordering supplies last year.

BloombergNEF Head of Americas Ethan Zindler began the webinar with an analysis of the pandemic’s impact on renewable development this year. The company projects 22 GW in total renewable capacity additions in the U.S., down 20% from its estimate earlier this year, before the crisis began. (See US Renewable Investment Hits Record $55.5B.)

He noted the figure was much lower than the U.S. Energy Information Administration’s projection of about 32.7 GW earlier this month, with wind and solar down 5% and 10%, respectively, from the agency’s report last month. (See EIA: Renewable Capacity to Grow in 2020.)

Zindler also noted that “delays are not cancellations.” For example, he projected utility-scale solar additions to decrease slightly this year, to 6.8 GW, but then skyrocket to 14.8 GW in 2021.

The panelists were asked by moderator Susan Mac Cormac, a partner with Morrison & Foerster, whether the crisis is making investing in renewables even more attractive.

Jacobs said many investors “are interested in the uncorrelated risk that these assets represent relative to the rest of their portfolio. And so, while that has been a pitch made by pitchmen for many years about renewable energy and infrastructure, it has also been proven true in recent years in these kinds of macroeconomic disruptions like we’re seeing right now.”

“I don’t foresee a snapback to the way of thinking short-term and ignoring problems that seem too big to challenge,” said Ed Rossier, vice president of renewable energy investments for U.S. Bank. “And on top of that, we’re going to see a lot of data after this is over showing the inequitable impact on people in this country … and it’s going to be really hard to ignore that.”

Zindler’s determinations were based on the optimistic assumption that there is “substantial short-term disruption” in global economies over the next three months, before growth resumes in the fourth quarter. BloombergNEF, however, is developing analyses on more dire scenarios. The first assumes that major outbreaks occur in two to three waves over the next year, with economies restarting every few months only to shut down again, and global growth only picks back up in the second quarter of 2021.

Such a scenario, Strobel said, was his company’s biggest worry.

“We’re doing fine right now,” Strobel said. “I think this is an event proving that a diversified business model makes sense.” Along with renewable energy, Monarch invests in low-income housing and renovations of historic buildings, as well as in the federal tax credits for those types of projects. “Our worries are that … things will get better this summer, but what if they get worse come October? That for us is our biggest concern.

“All of us [referring to the panel] are fine; we have cash in our checking accounts, and we have investment savings, but most of the people in this country don’t have an investment portfolio, and they’re running out of cash. So if we have a renewal of this crisis in the fall, that’s going to be very catastrophic for our economy.”

The second scenario being developed by BloombergNEF, however, would be far more catastrophic: Virus outbreaks continue until a vaccine is developed, which health experts have said will take at least a year and a half.

April 28, 2020

Adjusted to New Normal, Chatterjee Looks Ahead

Like many Americans, FERC Chairman Neil Chatterjee has seen his life upended by the COVID-19 coronavirus.

While the commission and its staff have been “going about our business” — conducting its April open meeting and all other meetings virtually — Chatterjee has assumed additional responsibilities at home. With his three children now sequestered at the family’s Virginia home, he has taken on the role of middle school and elementary school teacher. This weekend, he added barber to his duties.

“Seventh-grade math is probably more challenging than the oversight of wholesale markets,” Chatterjee said during a virtual fireside chat conducted by the nonpartisan Atlantic Council think tank.

Chatterjee COVID-19 — FERC Chair Neil Chatterjee during Tuesday’s webinar.

Chatterjee appeared to be speaking from the FERC offices. That is, unless he collects and stores governmental flags at his home.

“We really are making a conscious effort to keep the commission running as normal as possible,” he said. “Seven weeks in, we have transitioned all our employees, here in D.C. and across the country, to full telework.”

Chatterjee said the commission has faced the pandemic’s regional stay-at-home orders with a three-phased approach.

First, he said, FERC made clear to its stakeholders that, given the lack of face-to-face meetings, it recognized that not all compliance obligations could be met. “We tried to provide transparency and clarity and let them focus on their No. 1 priority: keeping the lights on,” Chatterjee said.

The second phase is keeping the commission running and letting stakeholders know FERC is still open for business. Check.

The third phase, and probably most important, is preparing the electric grid and industry for what happens “when we come out of this,” he said.

Chatterjee cited the load shift from industrial and commercial demand to residential demand, the moratorium on customer cutoffs and the suspension of infrastructure work as examples of changes in the industry.

He also noted an increase in the dispatch of gas-fired plants as natural gas prices plummeted along with that of oil.

“Gas being dispatched at a higher rate is putting [financial] pressure on renewables, nuclear and coal. We could see shutoffs and shutdowns occur as a result of economic pressure, then see a surge in demand when we re-open,” he said. “I want to start talking about these things now … and getting people at the commission, federal and state levels to start thinking through some of the challenges we’ll face when we reopen.”

Noting social distancing and stay-at-home orders have reduced demand as much as 9% in some regions and affected intraday load shapes, Chatterjee warned of their impacts over the long term.

“You could have RTOs and ISOs and utilities cancel projects. Developers might cancel projects because of lower loads,” he said. “These are really thorny issues. This goes back to the balance we have to continually strike between consumer concerns and utility concerns. It’s a reason why we not only need to be focused on how to get out of this pandemic, but we have to be ready when we come out.”

Until then, Chatterjee’s concerns will rest with the electric industry and its workers. He said utility workers have been “real heroes” during the pandemic, along with other front-line workers and first responders.

“Most people are working from home. Power plant operators have moved from home to work,” he said, alluding to those who have set up camp at their plants to protect their health. “It’s really, really patriotic and heroic. When this is all over, I hope utility workers get their due for the sacrifices they have made.”

April 28, 2020

NYISO Contemplates 500-MW Boost for SENY Reserves

NYISO may shift 500 MW of the statewide reserve requirement to Southeastern New York (SENY) in order to boost resource flexibility and provide ready access to resource capability following a contingency event, ISO officials said Monday.

The proposal would not change the New York Control Area’s 2,620 MW of 30-minute total reserves but would add to the existing 1,300 MW of reserves in SENY, the Installed Capacity/Market Issues Working Group (ICAP-MIWG) heard during a teleconference.

However, the proposal would not add to the existing reserve requirements currently applicable to Zones J and K covering New York City and Long Island, respectively. The proposal seeks to increase the current 30-minute reserve requirement for the broader SENY region, which encompasses Zones G through K. The proposal would also reduce the NYC real-time reserve requirements to zero megawatts during thunderstorm alerts (TSAs).

NYISO reserves — Proposed SENY 30-minute reserve demand curve. | *NYISO*

“The proposal here is to have a reserve requirement that allows us to bring transmission facilities back to normal transfer criteria following a contingency,” said Ethan Avallone, the ISO’s technical specialist in energy market design, who presented the analy s is on reserves for resource flexibility.

The proposal is based on the current system topology. However, it was acknowledged that NYISO continually evaluates its reserve requirements to account for material system changes.

“In the future, if we have to reevaluate the requirement to account for anticipated transmission upgrades, or after any large change to transmission, we would still look to procure enough reserve to bring transmission facilities back to normal transfer criteria in that case,” Avallone said.

Market Mechanics

Absent procuring the proposed additional SENY reserves, the ISO could at times need to use out-of-market actions to return transmission facilities to normal transfer criteria, Avallone said.

The additional reserve would be procured at all times in the day-ahead and real-time markets.

“Up until this point, the reserve requirement for SENY is designed to allow the ISO to take the system back to emergency transfer criteria, and if the system doesn’t recover post-contingency, out-of-market actions may potentially be taken to bring the transmission facilities back to normal transfer criteria,” he said.

Couch White attorney Kevin Lang, representing the city of New York, asked how often the ISO has needed to resort to out-of-market actions for such cases. The ISO did not have immediate access at the meeting to the specific data to quantify the frequency. The ISO was asked to provide such data as part of future discussions related to the proposal.

“You’re looking at procuring these additional reserves on an ongoing basis, so there’s a payment required for that from Zone J,” Lang said. “If you’ve only been required to use out-of-market actions once a year or once every two or three years, then there isn’t a justification for increasing these costs to Zone J and adding this new requirement, even though it’s just shifting the location for procuring reserves from NYCA to SENY.”

The ISO needs to demonstrate a reason to increase the reserve requirement to SENY, Lang said. Without knowing how many times the grid operator has needed to resort to out-of-market actions, market participants “have no way of knowing whether this is really necessary, or whether this is just a hypothetical concern,” he said.

“We look at this proposal as a market-based way to reflect the flexibility operators are looking for on a reliability basis into the market,” Avallone said.

Aaron Breidenbaugh of Luthin Associates, who represents a group of nonprofit institutional customers known as Consumer Power Advocates, echoed Lang’s concern.

“Right now, with what’s going on in New York City and what’s going on in our state, this isn’t the time to start layering more costs on New York City customers,” Breidenbaugh said.

Mark Younger of Hudson Energy Economics suggested that the ISO not look at the data only in terms of what percent of the time the ISO had to take out-of-market actions to secure the transmission, but what portion of time there was a contingency that required action by the ISO.

“Contingencies are rare,” Younger said. “We have reserves to make sure we can operate when contingencies happen, so looking at it in terms of all time is not the appropriate way to do it.”

Consumer Impact Analysis

In addition to estimating potential energy market impacts, the NYISO will estimate both the potential short-term and long-term capacity market impacts of the proposal using revised reference prices calculated for the 2020/21 capability year ICAP demand curves, said NYISO Senior Manager and Consumer Interest Liaison Tariq N. Niazi.

He presented an o u tline of the methodology to be used in a consumer impact analysis of the proposed change in SENY reserves.

Niazi assured stakeholders that the results of the consumer impact analysis would be presented before seeking approval before the Business Issues Committee and Management Committee. “So just in case we have to revise the analysis, I think there should be time. … We actually seek to present the impact analyses at least 30 days before seeking a vote at BIC,” he said.

The ISO also will evaluate reliability and environmental impacts, as well as the impact on transparency as part of its consumer impact assessment. In terms of the future timeline, if the proposal obtains stakeholder approval, the ISO would seek to begin developing the necessary software in 2021 to facilitate implementing the proposed enhancements in 2022.

Pallavi Jain, a NYISO market design specialist, prese n ted a related project to revise ancillary services shortage pricing.

The shortage price for the current 1,300-MW SENY 30-minute reserves is $500/MWh, and the ISO proposes a shortage price value of $25/MWh for the 500-MW increase in the SENY 30-minute reserve requirement.

The ISO has proposed to increase the initial $25/MWh shortage pricing value for these additional SENY 30-minute reserves to $40/MWh upon implementation of the subsequent proposed enhancements related to the separate ongoing effort to reevaluate the current reserve shortage pricing values for all products and locations. However, for the reserve requirements applicable to Zones J and K, the ISO is not proposing to increase the current $25/MWh shortage pricing value due to the limited number of eligible suppliers in New York City and Long Island, respectively.

April 26, 2020

Ohio OKs FirstEnergy Brokerage Despite Protests

By Michael Yoder

Ohio regulators last week approved the application of a FirstEnergy subsidiary to operate as an energy broker and aggregator despite protests from consumer advocates and competitors over what they called a conflict of interest.

The Public Utilities Commission of Ohio on Wednesday granted approval for Suvon, doing business as FirstEnergy Advisors, as a competitive retail electric service (CRES) provider to help customers select electricity suppliers. FirstEnergy filed its application in January, and PUCO staff recommended approval of it earlier this month.

Critics, including the Ohio Consumers’ Counsel and the Northeast Ohio Public Energy Council (NOPEC), challenged the filing, saying use of the FirstEnergy name provided an unfair advantage and represented “too great a threat” to Ohio consumers in the retail electric market.

The OCC and NOPEC argued that having Suvon’s offices in the same building as the FirstEnergy’s headquarters in Akron, and having the company controlled by members of the same management team that controls the FirstEnergy utilities, violates state law requiring that a competitive retail electric supplier be “fully separated” from its regulated utilities.

FirstEnergy owns three utilities — Ohio Edison, Toledo Edison and The Illuminating Co. — with monopoly electricity distribution services regulated by PUCO.

NOPEC and the OCC argued that barring the use of the FirstEnergy name was consistent with a 2018 report filed by SAGE Management Consultants, PUCO’s outside auditor, in the commission’s corporate separation audit. The report recommended disallowing a former FirstEnergy affiliate, CRES provider FirstEnergy Solutions (FES), from using the FirstEnergy name.

FES recently emerged from bankruptcy under a new name, Energy Harbor, but the corporate separation case remains pending before the commission (17-974-EL-UNC).

FirstEnergy Brokerage — FirstEnergy’s Akron, Ohio, headquarters

The commission said that issues regarding Suvon’s use of the trade name and compliance with corporate separation requirements “are best raised” in that proceeding, noting that the commission has not adopted the SAGE report’s conclusions. “The finding and conclusions of the auditor should be litigated in that proceeding rather than this case,” it said.

PUCO also determined that the shared service arrangement between FirstEnergy and Suvon does not present a conflict of interest and is permissible under federal law. The commission cited other utility subsidiaries that have been certified as CRES providers, including a case involving Interstate Gas Supply’s (IGS) DPL Energy Resources in 2000.

“We note that the existing requirements for proper disclosure of the affiliate relationship has been considered to be a necessary and sufficient protection in all prior cases,” the commission ruled. “We expect Suvon to include and present the required disclosure in a conspicuous and efficacious manner in all communications with consumers.”

The OCC, Vistra Energy and NOPEC, Ohio’s largest nonprofit energy aggregator, filed motions opposing the certification. The Northwest Aggregation Coalition called for a hearing on it.

“In the long run, what we know in Ohio is when there is no competition, prices go up,” Chuck Keiper, NOPEC’s executive director, said in an email to RTO Insider. “We’ll be moving back to a toxic environment where the utilities control the marketplace.”

In a separate request, NOPEC and the OCC also asked PUCO to release public records of any communications the commissioners or staff had with FirstEnergy Advisors. Keiper said his concern that the commission did not hold a hearing in the case led to the public records request.

“We’re not afraid of another electricity broker coming into the market,” Keiper said. “In fact, we welcome it. But bring it on in a fair, honest, legal and transparent way. Let everyone see communications, if any, between FirstEnergy Advisors and the public body PUCO. Taxpayers and electricity consumers in Ohio are owed that and a fully public process to investigate this application.”

The commission noted that several of those intervening in the case were competitors of Suvon. “Competition should be determined ultimately by acumen in the marketplace, not by presumptive inhibition through a commission certification proceeding,” it said. “Although we have granted intervention in this case to Suvon’s competitors, we will carefully monitor the practice of competitors intervening in certification proceedings to ensure that this does not become a widespread, abusive practice and that competition is not unduly stifled by unnecessary litigation.”

PUCO denied the public records request, saying the staff determination that Suvon has the capabilities to serve as a power broker make the request “moot.”

“Staff has thoroughly reviewed Suvon’s managerial, technical and financial capability and has recommended that Suvon’s application should be approved,” the commission said. “Upon review of the many motions and memoranda filed in this case, we find that no other parties have raised material issues regarding Suvon’s managerial, technical and financial capability.”

J.P. Blackwood, a spokesperson for the OCC, said Thursday the organization was not satisfied by the decision.

“The Ohio Consumers’ Counsel is disappointed that the PUCO granted FirstEnergy Advisors’ operating certificate without imposing the conditions that we and many local governments recommended for consumer protection and fair competition,” Blackwood said.

April 26, 2020

SPP Western Markets Briefs: April 23, 2020

SPP’s effort to stand up the Western Energy Imbalance Service market is on budget and on schedule, the grid operator’s staff told the Western Markets Executive Committee last week.

“It’s going to take all of us to make that happen,” SPP’s David Kelley, director of seams and market design, told the WMEC during a conference call Thursday. “Understand when we’re pushing you and you’re pushing us, it’s to keep us marching to the same objective, and that’s to get the market up and running.”

SPP plans to begin operating the WEIS in February 2021. Modeled on the Energy Imbalance Market the RTO operated from 2007 to 2014, the WEIS has attracted eight participants. (See SPP Board OKs $9.5M to Build Western EIS Market.)

SPP Western Markets — SPP’s legacy and WEIS footprints | *SPP*

Kelley said that while the overall market development project’s status is yellow because some tasks are behind schedule, the project’s end date is “not in jeopardy.”

“We’ve been able to make up lots of lost ground we had early in the project,” Kelley said. “I’m still comfortable with where we are. The delays in some of the tasks won’t affect the overall health of the program.”

SPP staff are currently testing the first markets release from its vendor and have taken delivery of two key software systems. They are also preparing for various system tests, with market trials scheduled for the month of October. Parallel operations are scheduled to begin Dec. 10.

Kelley said SPP has yet to fill five of the 13 positions necessary to run a Western markets desk in its operations center because the RTO’s two control rooms have been “basically” locked down during the COVID-19 pandemic to protect the operators, he said.

“We have ample time to get the desk stood up and tested,” Kelley said.

The pandemic has also caused a change in training WEIS participants. SPP originally planned for in-person training in July but has now shifted to virtual, instructor-led classes.

FERC Finds SPP’s WEIS Tariff Deficient

FERC on April 20 issued a letter notifying SPP that its proposed WEIS Tariff, Western joint dispatch agreements and WMEC charter are deficient and requested additional information for the filings (ER20-1059, ER20-1060).

The commission asked for a response to 12 different categories by June 4, throwing into doubt SPP’s original requested effective date of May 21. The RTO filed the Tariff and other documents in February.

FERC asked SPP to break down the six categories of costs included in both its projected $9.5 million implementation costs and its ongoing administrative costs to be recovered through the WEIS rate. The RTO has proposed a WEIS rate of 22 cents/MWh of net energy for load, based on an estimated annual $5 million operating cost. That number includes the annualized payback of implementation costs.

FERC also asked SPP to explain why using its Integrated Marketplace market power mitigation thresholds are appropriate for the WEIS. The RTO said the market will be subject to market power monitoring and mitigation performed by its Market Monitoring Unit.

The proposed Tariff includes provisions for demand response and notes that aggregators of retail customers “shall be treated comparably to other market participants offering resources.” FERC said there was no mention of compensation for DR resources and asked the RTO to clarify whether those resources would be compensated at LMP like other participants; “if not, please explain how they will be compensated and why.”