Page 1105 – RTO Insider

April 29, 2020

MISO Preps for Balmy Summer with Pandemic Effects

A forecast for warmer-than-usual weather means MISO will likely have to declare an emergency this summer — even without heavy loads or a high volume of generation outages, the RTO said Tuesday.

The RTO is projecting a 125-GW summer peak and 152 GW of total capacity on hand to manage the load before generation outages are factored in.

“We expect higher load than usual … but we have adequate resources,” Executive Director of Energy Operations Rob Benbow said during a summer readiness conference call.

MISO’s all-time summer peak of 127 GW occurred July 20, 2011. MISO last year registered a 121-GW summer peak in mid-July, far short of the nearly 125-GW peak forecast. The RTO last year had 149 GW of available capacity to cover peak demand.

Benbow warned that challenges await if MISO experiences high load coupled with high outages in July or August, circumstances that would likely prompt it to declare an emergency and dip into load-modifying resources and operating reserves.

MISO summer resource adequacy projections | *MISO*

The National Oceanic and Atmospheric Administration forecasts “warmer-than-normal temperatures for a majority of the MISO footprint,” Resource Adequacy Coordination Engineer Eric Rodriguez said.

In a probable scenario, MISO will have about 117.4 GW worth of capacity for a 116.6-GW average load during June. July contains the most risk, with even a probable load of 124.2 GW eclipsing its 121.4 GW of available resources. In August, the RTO still runs the risk of tapping into its emergency stack, with a probable 122.2 GW of load exceeding its 121.2 GW worth of nonemergency resources.

MISO is all but certain to declare emergency procedures during all three months should it experience even lower available capacity than in a probable scenario. Benbow said it also is preparing for the possibility of hurricanes in MISO South.

“On top of that, we’ll run into challenges with COVID-19,” he said, adding that MISO expects to continue to encounter difficulties forecasting day-ahead load as lockdowns and social distancing measures persist into the summer.

The RTO expects forced generation outages this summer to exceed its five-year average but still remain below the summer of 2018, when outages neared 25 GW in all three months. Outages will hit about 23 GW in June, then hover around 15 GW in July and August, it said. A fraction of the increased generation outage activity in June can be put down to impacts from the coronavirus pandemic.

As of April 20, 19.5 GW of planned generation outages had been canceled or rescheduled as a result of the pandemic. About 1.1 GW of those outages are tentatively rescheduled for early June, but more generation owners are planning to reschedule in the fall.

MISO outage coordinator Trevor Hines said generation owners are rescheduling outages thoughtfully, with concern for summer conditions. He said the outage disruptions so far will not affect reliable operations.

The RTO has also seen 101 — or about 16% — of its planned transmission outages changed since the pandemic required utilities to separate personnel, limiting some maintenance activity. Half have been canceled altogether, with the other half to be spread out over May and June, Hines reported.

Continuity in Uncertainty

South Region Operations Director Tag Short said that as MISO moves into summer, it will focus on “business continuity” even as staff remain physically separated between control rooms in three different states and working from home.

Short said MISO will continue working with states “to gain access to test kits so our control room personnel can be tested in advance of shift changes.”

The RTO is already monitoring the body temperatures of control room staff and distributing face masks for employees that remain on-site. Its janitorial staff is also sanitizing facilities more often.

“We tried to reduce as many touch points as possible, and that’s not easy when they share a bathroom and a kitchen,” Short said of MISO’s control room staff.

Manager of Forecast Engineering Blagoy Borissov said load continues to track about 10% lower than normal since closures and lockdowns became the norm in MISO states. He added that morning and evening ramps remain flatter than usual.

Borrisov said MISO’s forecasting team had to “freeze” its forecasting model prior to the pandemic taking root in the footprint so the model wouldn’t make load shape adjustments or match the forecast to recent history, which is temporarily an unreliable benchmark.

“We are pretending that our load forecasting model has not been updated since March 13,” Borissov explained.

Borissov said an inevitable uptick in load will be difficult to anticipate as temperatures rise and states begin testing the relaxation of pandemic measures.

MISO will continue to restrict visitors to its facilities through at least June 1. Vice President of System Planning Jennifer Curran this week said it’s “too early” to tell when the RTO can return to normal operations.

April 28, 2020February 19, 2025

DC Circuit Skeptical of FERC Tolling Orders

The full 11-member D.C. Circuit Court of Appeals spent three and a half hours Monday grilling attorneys in a case that could decide whether FERC is allowed to give itself deadline extensions for when it must decide whether to rehear its decisions.

If the court overturns its precedent of allowing FERC’s use of so-called “tolling” orders — in which the commission grants a request for rehearing for the “limited purpose of further consideration” so that it is not automatically rejected — it could create a glut of litigation.

On the other hand, it might not have any real practical effect, as some judges seemed to indicate in their questioning.

Atlantic Sunrise

The case stems from FERC’s 2017 approval of — and subsequent rehearing request rejection for — Williams Companies’ Atlantic Sunrise project, an expansion of the company’s existing Transcontinental Pipeline. The project’s main component was a new 177-mile segment running from Susquehanna County in northern Pennsylvania to Lancaster County, near the state’s border with Maryland. Williams began construction on the pipeline in September 2017 — three months before FERC rejected rehearing requests from landowners and environmental groups — and it entered service in October 2018 (Allegheny Defense Project, et al. v. FERC, 17-1098).

Pennsylvania portion of Williams’ Atlantic Sunrise natural gas pipeline project, which began service in late 2018 after winning FERC approval in February 2017. | Williams

Under Section 19a of the Natural Gas Act (15 U.S.C. § 717r(a)), “unless the commission acts upon [an] application for rehearing within 30 days after it is filed, such application may be deemed to have been denied. No proceeding to review any order of the commission shall be brought by any person unless such person shall have made application to the commission for a rehearing thereon.”

Since 1969’s California Company v. Federal Power Commission, the D.C. Circuit has judged that issuing a tolling order within the 30-day time frame meant that FERC had “acted upon” the request under the language of the statute, and that parties must wait until the commission’s review of the request is actually complete before seeking relief from the court. Citing this precedent, a three-judge panel of the court in August 2019 rejected the plaintiffs’ petition.

But in December, the full court agreed to rehear the case en banc. The plaintiffs had also argued that FERC had failed to consider the pipeline’s downstream greenhouse gas emissions in an environmental impact statement or that its reliance on precedent agreements to indicate need was incorrect. But the court specified that it was only interested in the plaintiffs’ argument that FERC’s use of tolling orders had improperly delayed their ability to seek relief from the court, depriving them of due process. (See DC Circuit to Reconsider FERC Tolling Orders.)

The court’s original March 31 date for oral arguments was delayed because of the COVID-19 pandemic. Instead of meeting at the E. Barrett Prettyman U.S. Courthouse, the court heard arguments by teleconference Monday, which was streamed live on YouTube.

An Issue of ‘Finality’

Some of the judges at first seemed confused by what the plaintiffs were seeking. They asked attorney Siobhan Cole, of White and Williams LLP, whether she was arguing that the NGA’s language meant FERC had to rule on the merits of the rehearing request within the 30-day deadline.

Not necessarily, Cole said. “The request for rehearing could be granted and then something else could follow to decide the merits of whether the underlying certificate order should actually be altered,” she said. “But the key distinction there is that the finality of the underlying certificate order has to be stripped away as soon as rehearing is granted.”

Some judges were skeptical that the rehearing process would be different even if they eliminated tolling orders. They wondered whether FERC could grant rehearing within 30 days but still take an indefinite amount of time working on the rehearing order itself.

Judge Merrick Garland said he was “happy to accept the idea that a tolling order, which is only granted for purposes of giving more time, is not envisioned by the statute,” but he seemed skeptical of the idea that granting rehearing automatically “abrogates the underlying certificate.”

Cole acknowledged that there was no such provision in the NGA, and even granted that, absent an order from the commission or the court to stay the project, the certificate would remain in force while the judicial process played out. But she said granting what Garland eventually termed an “honest” rehearing would allow parties to seek a stay in court while the commission worked on the merits of the request.

“If the commission is going to rehear its order, it cannot at the same time say that it is confident in the accuracy of the order such that construction and takings [of property using eminent domain] can move forward,” Cole said.

Judge Judith Rogers expressed a similar sentiment as Garland. “I understand how you come out ahead for your client in the formulation that any grant of a petition by the commission destroys the finality of the underlying certificate.” But she did not understand what her clients would gain absent that specific finding.

“It still gives them at least the opportunity for judicial review, and it leaves open the possibility that if the commission were acting under an error of judgment or otherwise incorrect … the court could find fault with FERC’s determination, or simply decide the question of irreparable harm,” Cole responded.

ClearView Energy Partners said the arguments mean “that the D.C. Circuit might be prepared to consent to judicial review of the underlying order if FERC’s ‘action on rehearing’ was only a tolling order. Then, to the extent the commission wanted more time, it could request it of the court, not indefinitely stop the clock until it chooses to act.”

April 28, 2020

FERC: New Goldman Unit an Affiliate

FERC on Monday granted Goldman Sachs Renewable Power Marketing (GSRPM) authority to make market-based sales but said it would consider it an affiliate of The Goldman Sachs Group investment bank despite its objections (ER20-547-001).

“Complete victory,” responded Tyson Slocum, energy program director for Public Citizen, who filed a protest calling for the affiliate declaration. “This is a win for transparency.”

GSRPM, which filed an application to sell electric energy, capacity and ancillary services in December, is a wholly owned subsidiary of Goldman Sachs Renewable Power (Renewable Power). It is managed by a three-member board of directors: Andrew Galloway, John Lewis and Andrew Johnson.

Renewable Power owns entities that own or control generation facilities in CAISO, the Balancing Authority of Northern California (BANC) and the PacifiCorp East (PACE) balancing authority area. The company sells the plants’ output under long-term power purchase agreements.

The applicant said the directors are independent of the investment bank, which owns less than 5% of Renewable Power. Thus, the applicant said it should not be considered an affiliate of the investment bank under commission regulations.

But the commission said Goldman Sachs Asset Management’s (Asset Management) role as Renewable Power’s investment manager created a link to the investment bank.

FERC Goldman Sachs — Goldman Sachs global headquarters in Manhattan

The applicant said Asset Management’s authority does not include day-to-day operations or routine management of nonfinancial activities. It said Asset Management, a wholly owned subsidiary of the bank, operates as a separate business division, separated from other units of the bank by information barriers and other policies.

But it acknowledged Asset Management has existing relationships with the three board members because they serve in a similar capacity for other companies and private equity funds for which Asset Management is investment manager.

FERC said the company was “correct that where a person owns, controls or holds with power to vote, less than 10% of the outstanding voting securities of a specified company, there is a rebuttable presumption of a lack of control.”

But it said that because Asset Management can exercise Renewable Power’s voting rights in GSRPM, it makes Asset Management and the investment bank an upstream affiliate of the applicant. “Thus, the rebuttable presumption does not apply,” FERC said.

Protest

Public Citizen said the three board members “serve together on at least an additional 63 boards of shell companies with clear ties to Goldman Sachs. In addition to his role serving alongside Lewis and Johnson, Andrew Galloway serves on at least 15 additional boards (without Lewis and Johnson) of shell companies with clear ties to Goldman, for a total of 79 boards. So, calculating a $5,000 retainer plus the $13,000 annual fee, the directors are getting paid at least $1.1 million a year, excluding expenses, to serve on dozens of Goldman-connected shell companies.”

“An individual receiving annual compensation in excess of $1 million from a single source is likely going to want to keep that gravy train going and would be likely be reluctant to operate in a manner that may result in not being appointed to additional boards with ties to Goldman Sachs,” Public Citizen added.

It said The Goldman Sachs Group “has paid billions of dollars in fines and settlements over the last several years directly related to abuse of its internal “information barriers.”

PJM’s Independent Market Monitor filed an answer Thursday saying it agreed with Public Citizen that “designating Goldman Sachs Renewable Power and The Goldman Sachs Group as affiliates is essential” for enforcement of FERC’s anti-manipulation rule and to ensure just and reasonable rates. But the commission rejected the Monitor’s filing as untimely.

Market Power Analyses

The commission said GSPRM lacked horizontal or vertical market power, even though — by virtue of its affiliation with Asset Management — it is also affiliated with J. Aron and Global Atlantic.

FERC said market power analyses for the CAISO market and the PACE and BANC balancing authority areas showed GSRPM passed both the pivotal supplier and wholesale market share screens.

GSRPM qualified as a Category 2 seller in the Northwest region and a Category 1 seller in all other regions. Category 1 sellers, which are limited to a maximum of 500 MW of generation per region, are not required to file regularly scheduled updated market power analyses. Sellers that do not qualify for Category 1 are considered Category 2 sellers and must file updated market power analyses.

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.”