Page 1106 – RTO Insider

April 29, 2020

COVID-19, Electrification Stir MISO Futures Debate

MISO on Monday presented stakeholders a long-awaited set of transmission planning futures that it insists are final despite calls for an additional scenario that models an economic downturn stemming from the COVID-19 pandemic.

“Keep in mind we’re not trying to predict what will happen; we’re trying to predict bookends of what could happen,” MISO Planning Manager Tony Hunziker told stakeholders during a teleconference to discuss the three, 20-year future scenarios.

The RTO will begin relying on the three new planning fut u res starting with the 2021 cycle of the Transmission Expansion Plan (MTEP 21). The scenarios have undergone multiple alterations in response to stakeholder suggestions. (See MISO Outlines Electrifying Tx Planning Fut u res.)

Future I — formerly Announced Plans — assumes an 85% probability that corporations will realize their renewable growth and carbon-cutting goals and full certainty that states will fulfill their clean energy plans. It also includes a 40% reduction in carbon emissions from 2005 levels by 2040.

Future II — previously Accelerated Fleet Change — assumes MISO members will meet or exceed decarbonization plans while carbon emissions drop 60% from 2005 levels. Electric vehicle adoption stimulates demand, while residential and commercial electrification reaches 39% of its technical potential, representing a 30% energy growth footprint-wide by 2040.

Future III — Advanced Electrification — also assumes members fulfill their renewable plans and consumers adopt EVs. It foresees a sharp increase in demand from residential and commercial electrification, representing 50% energy growth. The RTO also experiences a minimum 50% renewable penetration level as carbon emissions dip 80% below 2005 levels.

MISO originally predicted a 60% energy growth in the electrification future but backed down on the estimate after pushback from stakeholders. The RTO plans to include more detailed time-of-use charging patterns for the 2022 MTEP cycle.

Calls for Fourth Future

Hunziker said stakeholders sought more data and justification for MISO’s electrification predictions. He also said some stakeholders asked whether the RTO would update economic assumptions based on the devastating impact of the coronavirus pandemic.

Hunziker said it’s simply “too early to tell” the pandemic’s long-term effects on the energy industry.

MISO Director of Economic and Policy Planning Jesse Moser said the RTO continues to believe it doesn’t need to develop a fourth future that models a major economic slowdown despite the pandemic.

“Our view today is that this appears to be a shorter-term impact,” Moser said. “We think we’re in a good place right now … We’ll come back and see what happens.”

Hunziker said any lasting effects on MISO load depend on how long shelter-in-place directives remain in place and whether the virus resurges in the fall. He also reminded stakeholders that it’s an election year and challengers to incumbent candidates have extensive energy policy plans.

Moser said the RTO will specifically review electrification assumptions next year. But by summer it will have spent “pretty close to a year” defining the futures and must lock down its assumptions.

“No future is going to be perfect. If we do our job, they will land somewhere in this range of scenarios,” Moser told stakeholders.

But some stakeholders disagree, maintaining that MISO should consider stagnant economic conditions and stationary load growth in the scenarios — or develop a fourth future dedicated entirely to the possibility.

Mississippi Public Service Commission’s David Carr said the RTO’s electrification and demand predictions are simply too high, especially considering the pandemic’s side effect of paralyzing economies.

“There is in fact significant uncertainty on near- and long-term energy demand,” Carr said during an April 15 Planning Advisory Committee teleconference. He added that resource retirements and additions will increasingly be thrown into upheaval. He reminded stakeholders that economists predict that the crisis is triggering the worst recession since the Great Depression.

Carr asked MISO to take an extra “three to six months” to reevaluate the futures and make sure they account for the possibility of a lower end of decarbonization and load growth.

But Sam Gomberg of the Union of Concerned Scientists pointed to the decade following 2008’s Great Recession “as a reminder that there are two sides of the coin to this uncertainty.” He said renewable generation expansion and technological advancements gained steam over the last economic downturn and recovery.

Some stakeholders countered that this slump is shaping up to eclipse all other downturns in magnitude. Others pointed out that projects approved in MTEP 21 won’t go into service until several years after 2021, safely outside of the current pandemic. Still others said it isn’t realistic to expect that the depressed load seen in the months with social distancing will reverberate 20 years into the future.

WEC Energy Group’s Chris Plante said the RTO is still in need of a fourth future that contains more conservative electrification estimates to serve as a foil for Future III.

Others said a fourth future could serve to temper load forecasts in a post-COVID-19 world.

But Xcel Energy’s Carolyn Wetterlin said Future I does represent the low end — and even dips lower — than what her company expects in terms of renewable buildout.

During MISO’s April 21 Informational Forum, CEO John Bear held firm that the RTO will not add a fourth future and reminded stakeholders that the futures are meant to bookend a range of future possibilities. In MISO, large economic transmission projects that show benefits under all three futures are selected for inclusion in annual transmission plans.

“These are not meant to be deterministic … or spot-on 20 years into the future,” Bear said. “It’s easy to lose sight of that.”

Bear said the RTO “simply doesn’t know” what, if any, long-term impacts the pandemic could introduce in the energy industry. He also reminded stakeholders that futures capture 20 years, not just the immediate future.

“We do plan on looking at the state of the world a year from now” to study any lasting load impacts in annual planning, Bear said.

April 29, 2020

PJM CEO Introduces Himself

Manu Asthana was 17 when he arrived in Philadelphia as an undergraduate at the University of Pennsylvania’s Wharton School in 1991. Born in India, he had grown up in the Middle East, where his parents moved for work. The U.S., he said, was “quite a culture shock.”

New PJM CEO Manu Asthana introduced himself via teleconference at the Energy Policy Roundtable in the PJM Footprint.

Nearly 25 years after his graduation, Asthana returned to the Philadelphia area as CEO of PJM.

“It was quite an interesting completion of the circle for me,” Asthana, who joined the RTO in January, told the Raab Associates Energy Policy Roundtable in the PJM Footprint via webinar Tuesday.

He returned, no longer a wide-eyed teenager, but an experienced energy executive looking for a new challenge.

After only four months on the job, he’s already had several: Responding to FERC’s controversial expansion of PJM’s minimum offer price rule (MOPR), winning stakeholder approval of tougher credit requirements in its markets and — unexpectedly — figuring out how to prevent the coronavirus pandemic from disrupting PJM’s 24/7 operations.

“It has been humbling to be reminded that we don’t get to write the script,” he smiled.

Chicago and Houston

Asthana graduated Wharton with concentrations in finance and entrepreneurial management. After learning to trade Treasury bond options at the Chicago Board of Trade for Swiss Bank Corp., he moved to Texas in 1997 to work for a company that was acquired by TXU Energy.

He held a number of roles in his 12 years at TXU, including chief risk officer. “When I left the company, I was running their trading business, running their commercial market operations and asset management … all of the commitment, dispatch and economic analysis and market-related decision-making around what was at that time one of the largest fleets of generators in the state of Texas.”

Asthana remained with TXU for about two years after it was taken private in 2007 — in what was the biggest leveraged buyout in history — but grew restless. “I had done everything I came there to do; learned everything I came there to learn. It was time to leave.”

He joined Direct Energy in 2010 and began “running their trading business, then took on their power generation operation.” After the company sold its power plants, he was “tasked with turning around the performance of” Direct’s retail energy business. Two years later, he “was tasked with also turning around the performance of the home services business.”

He resigned as president of Direct Energy Home in December 2018 after almost nine years. “I had gotten to the same point I did with TXU, where I accomplished more or less everything I came to do,” he explained.

Asthana previously told RTO Insider that he continued working with Direct through April to “ensure a successful leadership transition” and spent much of the rest of the year doing charity work before being tapped by PJM.

Direct, like some other retail electricity suppliers, has had a series of well-publicized regulatory scrapes. “I’m very proud that my team’s efforts to continuously improve in these areas led to customer complaints falling by two-thirds during my tenure,” he told RTO Insider after his hiring was announced in November. (See New PJM CEO Defends Direct Energy Stewardship.)

After his Texas experience at TXU and Direct, Asthana said, he was looking “to do something that had an impact beyond just the organization that I worked for. I wanted to have a broader impact. And I thought that PJM was uniquely positioned in the energy transformation that’s happening.”

3 Priorities

Asthana said he came to PJM with three priorities. The most important: ensuring the grid’s reliability.

He also places a premium on personnel development. “I believe strongly that leaders grow people,” he said.

His other priority is working with PJM’s stakeholders — “including, very importantly, our states” — “to solve difficult problems and try to get our markets to a stable place where they can continue to deliver the efficiencies and the reliability that is required.”

“A lot of people tell me, ‘Hey, can you find a way to make the stakeholder process more efficient, more effective, to get things done through the process?’” he said. “I’d like to reframe for all of us our stakeholder process. I don’t see it as a problem to be navigated. I see it as a significant strength of the organization.

“We have tremendous capabilities, tremendous passion to do the right thing and to get the market structure right and to get the rules right for the long term. I think there is disagreement on what the right actions are depending on what the topic of discussion is. But the diversity of thought and the amount of passion and energy that our stakeholders bring to our process I think is a significant asset for PJM.”

Moderator Jonathan Raab — who helped facilitate the creation of PJM’s current Consensus-Based Issues Resolution (CBIR) process a decade ago — asked Asthana if he thought additional changes were needed in stakeholder rules.

The stakeholder process works well for many routine issues, but it has shown an inability to reach consensus on major contentious issues, according to a May 2017 study by Christina Simeone, director of policy and external affairs for the Kleinman Center for Energy Policy at the University of Pennsylvania. Simeone said some of the problems are the result of compromises made under the Governance Assessment Special Team (GAST) process that led to CBIR. (See Can RTO Stakeholders Find Consensus on Big Issues?)

“I’m hearing a range of things,” Asthana said. “Some people are satisfied; some people are not satisfied” with the effectiveness and efficiency of the process.

“I think since I’ve been here, I do think that the process … our stakeholders together are very capable of solving difficult problems. And I think we are starting to do that.”

As an example, he pointed to the approval in March of tougher credit rules, which cleared the Markets and Reliability Committee with a 90% sector-weighted vote. (See PJM Members OK Tighter Credit Rules.)

Finding the Balance on MOPR

Such consensus was not possible, he acknowledged, on one of the first issues he had to consider after starting work in January: PJM’s response to FERC’s December order expanding the MOPR to new state-subsidized resources.

Asthana said PJM’s Jan. 21 rehearing request and March 18 compliance filing sought to support states’ rights to choose their generation mix while also recognizing the reliance resource providers and investors have on a “stable, predictable” capacity market (EL16-49, ER18-1314, EL18-178).

The RTO held 10 meetings with stakeholders to gain feedback on how it should proceed.

“One of the points of feedback I had coming in the door was, ‘Hey, it would be really nice if PJM were to listen more,’” he said.

He noted the “very, very, disparate sets of inputs” on issues such as the timing of the first auction under the new rules and the flexibility that should be afforded individual units.

“I’m sure there are … a number of opinions on how we did, but I really hope that our stakeholders feel that they were listened to and that their thoughts were reasonably considered, and we took a balanced approach.”

The wind and solar industry trade groups said they were relieved that PJM’s interpretation of the order would allow new renewable generation to clear the capacity market in the short term. PJM’s conclusion that voluntary renewable energy credits are not state subsidies and its decision to allow an asset life of up to 35 years means that new wind and solar projects will be able to bid below the default MOPR floor values and clear the market, officials for the organizations said. (See MOPR May Not be Death Knell for Renewables in PJM.)

Maryland Public Service Commission Chair Jason Stanek, who spoke later in the forum Tuesday, said he was grateful for PJM’s efforts, although he would have liked more time to plan for the next Base Residual Auction. (PJM said it will hold the next auction within six-and-a-half months after the commission’s acceptance of the compliance filing.) “Under the circumstances … I don’t believe PJM could have done a better job in balancing the interests of a very disparate group of parties,” he said.

2035 and Beyond

The MOPR battle, Asthana said, has “unfortunately overtaken the discussion” on how the RTO can help the states plan for the future. He said he has asked his staff to envision what market rules and transmission planning will be needed in 2035 and beyond if states achieve their decarbonization targets, including large offshore wind projects planned off of Virginia, Delaware and New Jersey.

“I think PJM can play a large role in helping think through the most efficient way to plan the transmission grid to facilitate that offshore wind,” he said. “I think it’s very inefficient if we try to plan one project at a time or even one state at a time.”

April 29, 2020

DTE to Cut Spending in Response to Pandemic

DTE Energy said Tuesday that it will cut $60 million in operations and maintenance expenses to counteract sagging energy sales caused by social distancing measures in Michigan.

CEO Jerry Norcia said he expects lower electricity sales from the state’s COVID-19 pandemic shutdown to shave anywhere from $30 million to $50 million off DTE’s 2020 operating earnings. The company’s estimates are based on Michigan starting to return to work in mid-May.

“We have spent a lot of time over the last few weeks understanding the potential financial impacts of the pandemic [and] building and implementing a plan to react to these challenges,” Norcia said during an earnings call.

CFO Peter Oleksiak said operating earnings for the first quarter were $320 million ($1.66/share) compared to the $374 million ($2.05/share) earned in the first quarter of 2019.

The lower earnings were also attributable to a mild winter in the utility’s territory.

“Overall, this quarter was warmer than normal and was the sixth warmest on record. DTE Electric earnings were $94 million for the quarter, which was $53 million lower than in 2019,” Oleksiak said.

Norcia said that while DTE’s financial team was updating its year-end forecast, it found that higher winter temperatures along with “potential sales impacts and additional costs associated with COVID-19” dashed its 2020 financial plan.

“These changes are larger than the contingency that we normally carry in our annual plan. When we rolled all of this up, we saw $60 million of earnings pressure that we needed to offset,” he said.

The $60 million reduction in spending will involve “a list of one-time items to reduce cost in the near term that are not sustainable over the long-term.” DTE will freeze hiring, minimize overtime, tap its own employees for some consultancy and contract work, and cut business travel, Norcia said.

DTE Energy spending — A DTE Energy essential employee during the pandemic | *DTE*

He also said DTE will “postpone nonessential work, always with maintaining safety as our highest priority.”

“With all these lean actions, I am confident we will achieve our financial goals for the year without sacrificing safety or customer service,” Norcia said.

Residential load has “been stronger with more people at home,” increasing 10 to 11%, while commercial has dropped by 16 to 18% and industrial has fallen 40 to 46%, according to the CEO.

“We believe we have seen the bottom for our load at this point. Michigan remains under the stay-at-home order with only essential businesses operating, and our load has been pretty consistent over the last several weeks,” Norcia said.

For the entire year, Norcia said DTE projects a 3 to 4% increase ($40 million to $50 million) in residential electricity sales, a 6 to 9% decline ($50 million $75 million) in commercial sales and an 18 to 22% decline ($20 million to $25 million) in industrial sales.

“Under a less favorable scenario, we would have to reassess our economic recovery plans,” Norcia said. “The pace at which load returns is one of the largest variables of our economic recovery plan.”

Spending Plans

Norcia also said DTE is prepared to cut more spending, should it come to that.

“We have over $2.5 billion in operations and maintenance to manage through lean times, as well as the benefit of investing in incremental operations and maintenance ahead of schedule in previous years,” he said.

“We faced recessionary pressures before in 2008 and 2009, and we came through that time stronger than ever. … We are facing similar pressures, and I am confident that we have built a robust plan to respond to these challenges.”

DTE itself implemented a work-from-home edict in mid-March, with more than half of its employees commuting virtually.

Norcia said the company will restart “construction and maintenance activities in early May and ramp up through the month.” However, he said he expects office employees will remain working from home into summer.

DTE has also recently promised Michigan regulators additional work on its integrated resource plan. Early this year, the Public Service Commission blocked the company’s first 15-year IRP, finding that the utility didn’t adequately factor in the benefits of renewable energy. (See Michigan PSC Orders DTE to Redo IRP.)

The commission approved a revised IRP in April. This time around, DTE promised energy-efficiency programs, more ambitious energy savings goals and cutting some proposed demand response pilot programs until more is known about them (U-20471).

The PSC also ordered DTE to conduct further analysis of its proposed 2029/2030 retirement of the coal-fired Belle River power plant, saying the first analysis was “inadequately justified because the avoidance of new environmental upgrade costs was not considered in the analysis.”

Finally, DTE committed to filing its next IRP by Sept. 21, 2023, two years sooner than required by state law.

The company on April 23 commissioned its 168-MW Polaris Wind park, currently the largest operating wind facility in Michigan. The facility is the first of four new wind farms DTE plans to bring online in 2020.

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, 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.)