President Trump last week declared a national emergency regarding foreign threats to the bulk power system, issuing new restrictions on the purchase of BPS equipment by federal agencies, citizens and companies from suppliers suspected of connections with foreign adversaries.
In an executive order issued Friday, Trump said “the unrestricted acquisition or use” of BPS equipment developed, manufactured or supplied by entities connected to “foreign adversaries” — defined as any foreign government or nongovernment person engaged in long-term or serious instances of conduct threatening the security of the U.S., its allies or its citizens — could help malicious actors to identify and exploit vulnerabilities in the North American power grid.
“Although maintaining an open investment climate in bulk power system electric equipment, and in the United States economy more generally, is important for the overall growth and prosperity of the United States, such openness must be balanced with the need to protect our nation against a critical national security threat,” the order said. Transactions banned under the order include those involving BPS equipment developed or manufactured by an entity connected with a foreign adversary that:
poses a danger to the U.S. electric grid;
creates a risk of catastrophic effects to U.S. critical infrastructure; or
otherwise threatens the national security of the U.S. or the safety of its citizens.
Authority for determining such transactions will reside with the secretary of energy, in coordination with the director of the Office of Management and Budget and in consultation with the secretary of defense, the secretary of homeland security, the director of national intelligence and heads of other agencies as appropriate.
The energy secretary may also approve exceptions to the prohibition, either on a case-by-case basis or by designating particular products or vendors as prequalified for future transactions. In addition, the order directs the energy secretary to identify BPS equipment meeting these requirements that is already in place and work with utilities to develop plans for isolating, monitoring or replacing such items “as soon as practicable.”
Brouillette to Head Procurement Task Force
In a press release, the Department of Energy said the order will help to close a loophole in government procurement rules that “often result in contracts being awarded to the lowest-cost bids,” which it said could be exploited by malicious actors.
“It is imperative the bulk power system be secured against exploitation and attacks by foreign threats. This executive order will greatly diminish the ability of foreign adversaries to target our critical electric infrastructure,” Secretary Dan Brouillette said.
The order also creates a Task Force on Federal Energy Infrastructure Procurement Policies Related to National Security, to be chaired by Brouillette with participation by the secretaries of defense, the interior, commerce and homeland security; the director of national intelligence; and the director of the Office of Management and Budget. The task force is mandated to develop unified energy infrastructure procurement policies in coordination with the Electricity, Oil and Natural Gas Subsector Coordinating Councils.
In a separate release, NERC said the order would “help support activities already underway in NERC’s supply chain standards and other work” to provide security to the BPS. The organization said it “looks forward to working with industry and government stakeholders toward effective implementation of the executive order.”
Reps. Greg Walden (R-Ore.), Fred Upton (R-Mich.) and John Shimkus (R-Ill.) also spoke in support of the order. The congressmen serve as the ranking members of the House Energy and Commerce Committee and its Energy Subcommittee and Environment and Climate Change Subcommittee, respectively.
“We commend President Trump for taking action today, directing the secretary of energy to take additional steps to enhance the security of our nation’s bulk power system,” they said in a joint release. “We look forward to working with Secretary Brouillette to ensure the department has the resources and authorities it needs to carry out this important mission.”
The COVID-19 pandemic has helped shine an unexpected spotlight on the need for cybersecurity best practices, but maintaining that awareness once the crisis has passed could be a challenge, according to members of the government-sponsored Cyberspace Solarium Commission.
Speaking to state utility commissioners in a webinar April 24, two members of the commission — Southern Co. CEO Tom Fanning and former National Security Agency Deputy Director Chris Inglis — shared several recommendations from the group’s report issued earlier this year. Participants told ERO Insider that while the report itself focused primarily on the federal government’s role in cybersecurity preparedness, the industry representatives on the commission felt its recommendations should be shared with a wider range of players.
“I asked Chris and Tom, what [would they] want the state commissioners to be doing with this?” said Richard Mroz, a senior adviser to Protect Our Power and former president of the New Jersey Board of Public Utilities, who moderated the webinar. “And it was, first and foremost, to … go to the companies they regulate and ask them what they think of those recommendations, whether it’s an identification of those systemic, critical infrastructure operations, or … certifying all the way up to the C-suite that there’s responsibility and oversight of [their] cybersecurity practices.”
Multiple Avenues for Defense
Congress last year formed the Solarium Commission — a bipartisan group of members of Congress, former government officials and industry representatives — to “develop a consensus on a strategic approach to defending the United States in cyberspace.” The report returned more than 75 recommendations oriented around a strategy of “layered cyber deterrence” designed to “reduce the probability and impact of cyberattacks of significant consequence.”
Layered deterrence is a three-step process consisting of:
Shaping behavior — working with allies and partners to promote responsible behavior in cyberspace;
Denying benefits — securing critical networks so that attackers who gain access will be unable to cause damage; and
Imposing costs — maintaining the ability to retaliate against actors targeting the U.S.
To meet these broad goals, the commission identified six key pillars for the federal government: reforming the government’s structure and organization for cyberspace; strengthening norms and nonmilitary tools; promoting national resilience; reshaping the cyber ecosystem toward greater security; stepping up collaboration with the private sector on cybersecurity; and developing the military’s cybersecurity capabilities.
Electric utilities are identified in the report through recommendations centered on “critical functions” that depend on a reliable power supply. The commission called for Congress to consult with the private sector on how to ensure continuous operation of such functions, while also identifying entities responsible for systemically critical systems and assets — to ensure both that they have the full support of the U.S. government and that they meet a satisfactory level of security performance.
COVID-19 Presents Cyber Challenges
While the report was drafted before the emergence of the coronavirus as a national threat, commission members believe the current crisis may help to drive home the importance of cybersecurity in critical infrastructure sectors, as well as to state and federal officials.
“The commission’s report makes clear the need for the federal government to invest more in private sector resilience in order to prevent or mitigate a potential disruption,” said John Costello, a senior director with the commission. “I think it’s validated by the COVID crisis in terms of highlighting how a systemic disruption to our economy could unfold, and the need for the government and private sector to be prepared to meet it.”
Cybersecurity has been identified as a significant concern for a number of industries, including electricity, because of the larger-than-usual number of people using online services to work from home. NERC’s Pandemic Preparedness and Operational Assessment — Spring 2020, issued last week, reminded industry that the remote work force represented a “new attack vector” and to be “hyper vigilant.” (See PPE, Testing Top Coronavirus Concerns for NERC.)
Solarium team members hope that as utilities work to address these near-term concerns, government can build a national foundation to develop and spread cybersecurity best practices. The commission’s recommendations in this regard revolve around the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA), which it urged Congress to empower as the lead agency for federal cybersecurity efforts.
“We want working at CISA to become so appealing to young professionals interested in national service that it competes with the NSA, the FBI, Google and Facebook for top-level talent (and wins),” the Solarium Commission’s co-chairs, Sen. Angus King (I-Maine) and Rep. Mike Gallagher (R-Wis.), said in the report.
Push for Public Utilities
Another area of focus for the commission was assisting utilities that understand the need for cybersecurity but may lack the financial flexibility for the major, ongoing efforts needed in a quickly changing threat landscape. Federal agencies can play an important role in establishing shared resources and other tools for these entities to draw on, as well as helping them build their internal capabilities.
“For the most part, utility companies run on small margins. A lot of them are publicly owned. That means they don’t have much wiggle room in terms of their budget and investments in cybersecurity,” Costello said. “There’s a few things that the government can do to help. … One would be to augment and subsidize their security operations through programs and funding, and the report really tried to strengthen those areas of government assistance.”
While participants in last week’s briefing were optimistic about the determination of government and industry leaders to strengthen their cyber defenses, they warned against becoming complacent once the immediate danger has passed and utilities are able to move toward normal operations. Ironically, the industry’s success in keeping vital electricity systems running even in crisis conditions could lead members of the public to conclude that no changes are needed, in turn reducing the likelihood of political pressure forcing utilities to stay on top of their security practices.
“We can still teach and learn online; you can do your banking online; you can even get to your supermarket, and the refrigeration systems are still working,” Mroz said. “But that’s what I hope people don’t take for granted. And I think exactly what the commission was saying is that we need to be vigilant … and keep the focus on how you ensure that those threats aren’t realized and take down our way of life.”
The judge in charge of Pacific Gas and Electric’s criminal probation, stemming from the 2010 San Bruno pipeline explosion, found the utility was failing in its inspection and maintenance of power lines and ordered it to improve its performance to avoid starting wildfires.
U.S. District Judge William Alsup imposed new probation conditions Wednesday, saying PG&E must hire its own cadre of inspectors to make sure vegetation clearance meets state standards after outside contractors failed to identify or fix urgent problems last year.
He also required the utility to adopt a new regimen of inspection and reporting of transmission towers after it failed to spot worn equipment, including the “ancient C-hook” that broke, dropping a line and starting the November 2018 Camp Fire, the deadliest and most destructive wildfire in California history. (See PG&E to Plead Guilty to Killing 84 in Camp Fire.)
“A fundamental concern in this criminal probation remains the fact that Pacific Gas and Electric Co., though the single largest privately owned utility in America, cannot safely deliver power to California,” Alsup said. “This failure is upon us because for years, in order to enlarge dividends, bonuses and political contributions, PG&E cheated on maintenance of its grid — to the point that the grid became unsafe to operate during our annual high winds, so unsafe that the grid itself failed and ignited many catastrophic wildfires.
“In the past three years alone, PG&E wildfires killed at least 108 and burned 22,049 structures,” the judge said. “It will take years, now, for PG&E to catch up on maintenance so that the grid can safely supply power at all times. The conditions of probation herein have been aimed at requiring PG&E to do so.”
Distribution Line Shortcomings
PG&E’s vegetation clearance around power lines has been stepped up but still lags years behind, the judge said. The company contracts out its line inspections and tree-trimming work, which has proven problematic, he said.
“PG&E is fond of handing up records indicating completed work,” Alsup said, but spot-checks performed by a court-appointed monitor showed the records were untrustworthy.
A worn C-hook, like the one pictured here, broke on Nov. 8, 2018, dropping a high-voltage line and sparking California’s deadliest wildfire. | PG&E
In 2019, the monitor “checked the work, putting boots to the ground and independently inspecting over 550 miles of lines in high fire-threat districts,” the judge said. The monitor found 3,280 “risk” trees that PG&E’s contractors hadn’t identified, including 15 instances of urgent conditions that could have resulted in harm to people or property if left unfixed, the judge said.
“In one instance, PG&E contractors had recently marked an urgent condition — where a tree was 1 foot away from a primary conductor — as ‘tree work complete,’” Alsup said. “Similarly, a tree touched a primary conductor right outside the driveway of a home.
“In another case, the monitor identified a tree within inches of a primary conductor. The leaves of the tree bore burn marks from the ongoing intermittent contact,” the judge said. “That tree had been identified for routine compliance work in November 2018, and tree-trimming contractors reported they had completed the work in February 2019, although clearly they had not.”
To remedy the deficiencies, Alsup ordered PG&E to hire, on its own payroll, inspectors to examine power lines before and after vegetation-clearance work.
“PG&E shall employ a sufficient number of inspectors to manage the outsourced tree-trimming work,” Alsup wrote as a new term of the company’s San Bruno probation. “The pre-inspectors must identify trees and limbs in violation of California clearance laws that require trimming. Post-inspectors must spot-check the work of the contracted tree-trimmers to ensure that no hazard trees or limbs were missed.”
He instructed the utility to prepare a detailed plan by May 28.
Transmission Line Problems
The judge set the same date for PG&E to offer a new transmission inspection plan.
“For transmission towers, the problem is defective and worn-out hardware on the towers themselves,” Alsup wrote. “The Butte County [Camp] Fire, for example, started because an old C-hook had become so deeply gouged from decades of swaying against the plate on which it hung that the C-hook simply broke and fell, causing the attached power line to fall onto the metal tower, spewing sparks onto the wind-blown dry grass below.”
The transmission tower, part of PG&E’s century-old Caribou-Palermo line, had “supposedly been assessed just days before the fire … [the subject of an unusual] nonroutine enhanced inspection,” Alsup said.
“PG&E refused to say why it sent contractors to inspect the line but conceded that the line’s age was a factor,” he said. “Inspectors climbed the 100-foot-tall towers, presumably searching for equipment deficiencies, yet reported zero instances of cold-end hardware issues such as worn-out C-hooks.”
In last November’s Kincade Fire in Sonoma County, state investigators have focused on a broken jumper cable found hanging from a transmission tower where the fire started, the judge noted. Yet months earlier, “three separate inspections — via tower climbers in February, high-resolution drone imaging in May and ground inspectors with binoculars in July — had all failed to identify the problematic jumper cable,” he said.
A public safety power shutoff last fall may have prevented a downed tree on a PG&E distribution line from starting a fire. | PG&E
“Like a broken record, PG&E routinely excuses itself by insisting that all towers had been inspected and any noted faults were addressed, at least according to its paperwork,” Alsup said. “But these transmission tower inspections failed to spot dangerous conditions.
“Was this because the inspections were poorly designed, or was it because they were poorly executed? Had someone falsified inspection reports? It is hard to get a straight answer from PG&E,” the judge said. “The offender is masterful at falling back on the inspection reports and saying, ‘See, judge, we had that very line inspected and all was well,’ or, ‘We fixed whatever they found wrong. We did our part.’ The reports, however, are a mere courtroom prop.”
The judge said that under its current protocol, PG&E contractors don’t “accurately assess the degree of corrosion on the type of hardware that broke and caused the Butte County fire. For example, contracted inspectors could not agree on the amount of wear of a deeply gouged C-hook on a line parallel to Butte County’s Caribou-Palermo line.”
Three inspectors said it was 5 to 30% worn, but an expert witness rated the wear at 30 to 50%, which would require immediate replacement, he said. “And, because PG&E’s inspection forms only ask inspectors to check ‘yes’ or ‘no’ to the prompt ‘cold-end hardware in poor condition,’ any degree of wear simply went unmarked,” he said.
Alsup ordered the company to start keeping records identifying the age of all transmission equipment, including every piece of hardware on every line, and its recorded date of installation.
“In consultation with the monitor, PG&E shall design a new inspection system for assessing every item of equipment on all transmission towers,” the new probation conditions say. “Forms shall be precise enough to track what inspectors actually do, such as whether they touch or tug on equipment. Videos must be taken of every inspection.”
‘PG&E Struck Again’
Since August 2017, Alsup has overseen PG&E’s probation resulting from its conviction of six felonies related to the San Bruno explosion, in which “eight people burned to death or died from wounds. Fifty-eight survived with injuries, and over 100 homes burned,” the judge recounted in his latest order.
The catastrophe occurred when a 30-inch gas pipeline ruptured and exploded under a suburban San Francisco neighborhood, sending up flames hundreds of feet high and shaking the ground to the point that residents and emergency crews thought it was an earthquake.
A federal jury in August 2016 convicted PG&E of five felony counts of “knowingly and willfully” violating federal pipeline safety standards and one felony count of obstructing a government investigator.
Then, “one year into its probation, PG&E struck again,” Alsup wrote. The company was deemed responsible for at least 17 of the 21 major Northern California wine country fires of October 2017, in which 22 people died and more than 3,256 structures were destroyed.
The California Department of Forestry and Fire Protection found at least three of the fires were caused by PG&E’s failure to maintain specified clearances required by state law between its power lines and nearby trees or limbs.
In November 2018, the Camp Fire tore through the rugged foothills of Butte County and leveled much of the town of Paradise, killing 85 people and destroying nearly 19,000 structures in a single morning. It was the deadliest and most destructive wildfire in state history, and PG&E acknowledged its equipment was likely responsible.
Fire investigators eventually determined that the worn C-hook on a 100-year-old transmission tower had failed.
PG&E recently said it would plead guilty to 84 counts of involuntary manslaughter in the Camp Fire and pay $4 million in fines and costs. (One death was deemed a suicide as the flames approached.) The corporation is scheduled to be sentenced May 26 in Butte County Superior Court.
After the Camp Fire, Alsup held hearings to determine what new safety measures were needed to prevent PG&E from starting conflagrations.
The judge said in Wednesday’s order that PG&E’s probation for the San Bruno convictions ends in early 2022 and cannot be extended. He urged the California Public Utilities Commission to penalize investor-owned utilities for failing to meet vegetation-clearance regulations and to link executive bonuses to safety performance.
He also said that until PG&E can assure the state its grid can be operated safely, the controversial public safety power shutoffs (PSPSs) that plagued the state last year should be continued. There were no major fires in 2019, when close to a million customers were blacked out purposefully, he noted. (See California Officials Hammer PG&E over Power Shutoffs.)
“During the high-wind events, we must continue to tolerate PSPSs as the lesser evil until PG&E has come into compliance with state law and the grid is safe to operate in high winds,” the judge said.
PJM’s Independent Market Monitor on Tuesday defended its conclusion that ratepayers are likely to see cost increases in jurisdictions that exit the RTO’s capacity market and adopt the fixed resource requirement (FRR) option.
“Based on conversations I’ve have had — both public and private — with those who are pursuing FRRs, they’re increasingly recognizing … that the costs are likely to be higher under an FRR than under the competitive market,” Monitor Joe Bowring said during Raab Associates’ Energy Policy Roundtable in the PJM Footprint webinar Tuesday.
States can require their utilities to make the FRR election. The FRR entity must provide adequate capacity for all load-serving entities in its territory regardless of the existence of retail choice, Bowring said. LSEs are required to pay the FRR entity based on either a state-mandated compensation mechanism or — in the absence of a mechanism — on the Rest of RTO capacity price, he said.
The Monitor issued an analysis on the impact of Exelon’s Commonwealth Edison leaving the capacity market for an FRR in December and one on Maryland’s options April 17.
The ComEd report’s first scenario concluded net load charges would increase 23.6% if ComEd procured all of its capacity obligations outside of the BRA at the offer cap — $254.40/MW-day — rather than the $195.55/MW-day clearing price in the 2021/22 Base Residual Auction.
Maryland Public Service Commission Chair Jason Stanek | Md. PSC
In a second scenario, the Monitor calculated that ComEd’s load charges would decrease 5% if the price negotiated for its capacity were equal to the locational deliverability area’s (LDA) clearing price. The report contended the first scenario was more plausible, “given Exelon’s assertions that the current total revenue from energy, ancillary and capacity markets is not adequate for its nuclear plants.”
Only one of six scenarios in the Maryland analysis showed possible cost savings for Maryland ratepayers (5.4%), while the other scenarios saw increases of 5 to 43%. (See “Monitor: Maryland FRR Likely to Increase Capacity Costs,” FERC: RGGI, Voluntary RECs Exempt from MOPR.)
FRR “is not an easy exit ramp to choose,” said Maryland Public Service Commission Chair Jason Stanek, who also appeared on the panel on pursuing state clean energy policies under the expanded MOPR.
Lower Reserve Margin
But Rob Gramlich, president of Grid Strategies, said FRRs won’t necessarily raise costs. “The cost-reducing effect of FRR is known — the lower reserve margin. All other things [being] equal, that clearly has the effect of reducing prices,” he said. The FRR unforced capacity (UCAP) obligation for the ComEd zone is 23,385 MW — about 2,700 MW (10.4%) less than ComEd’s requirement of 26,112 MW under the BRA.
Gramlich said the Monitor’s analyses are based on improper assumptions, including that generators outside the LDA would be paid more under FRR than what they would earn in the PJM auction. Half the scenarios assumed prices at the offer cap for the applicable LDA. The $254.40/MW-day in the ComEd LDA is 30% above the $195.55/MW-day clearing price in the 2021/22 BRA.
He said the analyses only look at the next BRA and assumed “MOPR has no cost impact going forward, thus finds no savings” under FRR.
Gramlich also said the Monitor ignores the flexibility in FRR for portfolio-based penalties. Four-hour storage, which gets little capacity value in the BRA, can be included in FRR entities’ portfolios to avoid performance penalties, he said.
“I’m not necessarily advocating for FRR,” Gramlich said. “There are good and bad FRR approaches. … My point is nobody should be surprised that states are trying to accomplish their own objectives, and I think the rhetoric around FRR meaning a retreat from markets is not accurate. And studies saying FRR necessarily raises costs [are] also not accurate.”
Exelon also has challenged the Monitor’s analysis. Exelon’s Jason Barker told PJM stakeholders in February that the ComEd analysis was not “a credible or useful tool for understanding the value of an FRR for Illinois customers.” (See Exelon Challenges PJM Monitor’s ComEd FRR Analysis.)
Bowring was unyielding Tuesday. He said his firm’s reports are not attempting to predict what the final capacity prices would be under FRR but to give low and high price estimates of the economic impacts on consumers. He said the reports are conducted with detailed analysis using defined input assumptions so others can evaluate the results.
He said the increase in costs under FRR would be even larger once state subsidies to nuclear and renewable resources are factored in. “It appears to be demonstrably cheaper to stay with the markets, and if you need to do additional subsidies on the side, you can do that” for a lower total cost than FRR, Bowring said.
Market Power
Bowring said FRR would be a weaker variant of cost-of-service regulation and noted that imports into capacity market delivery areas are limited by capacity emergency transfer limits, which he said are relatively low compared to capacity requirements. The concentrated ownership of capacity that can meet the state’s capacity requirements gives local generation owners market power.
“It’s the state bargaining with monopolists who have better information [and] more knowledge about the cost of the resource and the nature of the resource,” Bowring said. “It’s not an equal negotiation. So basically, you’re giving market power to the generators in the FRR, and that’s the really critical point.”
He noted that generators within an FRR area are not required to participate, giving them leverage over pricing. “If you don’t think you’re going to get a fair price — a price equivalent to what other people are being paid for capacity — then you don’t have to participate and the FRR can’t occur,” he said.
Capacity Transfer Rights
Bowring said that while Gramlich pointed out that the reliability requirement would be lower in an FRR, he ignored that capacity transfer right (CTR) payments would go down significantly, causing prices for consumers to rise.
Gramlich insisted the CTR payments are “not a factor.”
“That number is identical to the … excess payments [the Monitor] assumes for that external generator to sell into a constrained area. … That’s not the case if you pay that external generator a competitive price.”
Gramlich said the Monitor’s market power concerns are “partially contrived by the assumption that states would prefer to choose resources that are internal to their state. Well, the state doesn’t have to do that. … In some ways the analysis assumes bad FRR design by choosing the generators, thereby conferring market power to them rather than competitively soliciting power from internal and external generators.”
New Jersey
Gramlich said the expanded MOPR has been “the worst thing since the California flawed initial market design [to] the cause of RTOs and competition,” saying it will result in almost 32 GW of unmet state renewable portfolio standard demand by subjecting almost 8,800 MW (UCAP) of nuclear and renewable resources to the rule.
The shortfall will increase by 2035 with the addition of 7,500 MW of offshore wind from New Jersey and again with Virginia’s adoption of a 100% clean energy standard, he said. (See Va. 1st Southern State with 100% Clean Energy Target.)
The New Jersey Board of Public Utilities is accepting comments until May 20 on alternatives to the state’s participation in the capacity market, with reply comments due June 24 (Docket EO20030203).
Bowring said a report on New Jersey’s FRR options should be released in a few weeks. He declined to speculate on its findings, saying it would be market-sensitive information. “I doubt it would be very different” from the previous analyses, he added.
New Jersey’s contract for offshore wind — a long-term contract with built-in escalators — “sounds a lot like some of the old PURPA [Public Utility Regulatory Policies Act] contracts that were signed that ended up costing New Jersey customers billions of dollars in excess of market value,” Bowring said.
Maryland’s Approach
Maryland zones and modeled locational deliverability areas | Monitoring Analytics
Stanek said the Maryland PSC has been reviewing the Monitor’s analysis for the state and is working with its legislators in Annapolis to determine its best move. He said it is also closely looking to see what actions Illinois and New Jersey take.
“We’re taking a slower approach,” he said. “We would like to see what the next BRA auction results are. One thing we can agree on is that they’re not going to be terribly out of line compared to the last auction.”
Beyond that, he said, there are no guarantees.
“I don’t believe that we’ve made a good use out of the past two years fighting FERC, working on this MOPR. I think all parties — whether you’re [the] renewable sector, you’re a state regulator, you’re a … merchant generator — I don’t foresee that this current capacity market … is going to continue in the current state. So, we need to use our resources to figure out what comes next. True, we’ll have a few more BRAs in the coming future. But we need to plan for the next phase so that states can pursue their public policies.”
Returning to the Bargaining Table
Sarah Novosel, managing counsel and senior vice president for government affairs for Calpine, said she was grateful that FERC acted on rehearing only four months after its December order, allowing those who oppose it to make their case before the appellate courts.
“I’m hopeful that it’s now going to allow the legal issues to be put into the courts where they belong — they need to be sorted out by the court — and really allow FERC and parties to focus on the compliance process. Because that’s really what we need to do, is … get the compliance order issued and get the auctions started again.”
Novosel said her company — which filed the FERC complaint that resulted in the December order — is open to additional negotiations to address concerns over renewables.
“Calpine, and I think other generators, are open to coming back to the bargaining table,” she said. “We’ve got the order now, and we’ve gotten to the point where we really do need to get some data from the auctions. … Let’s see where the prices are heading.”
One way for offshore wind to participate under MOPR, she said, would be for PJM to adopt something similar to New England’s Competitive Auctions with Sponsored Policy Resources (CASPR) two-stage construct. Under CASPR, ISO-NE will clear the Forward Capacity Auction after applying the MOPR to new capacity offers to prevent price suppression. In the second Substitution Auction, generators nearing retirement that cleared in the primary auction could transfer their obligations to subsidized new resources that did not clear because of the MOPR.
Carbon Pricing
Bowring, Gramlich and Novosel all expressed support for carbon pricing, which was the subject of a second panel.
Susan Tierney, senior adviser for the Analysis Group, discussed her analysis on NYISO’s carbon pricing proposal, which she said could be only one of the many tools the state will need to meet its ambitious goals under the 2019 Climate Leadership and Community Protection Act: 70% of electric supply from renewables by 2030 and 100% from zero-carbon resources by 2040.
Solar will have to triple in five years, and energy storage will have to grow tenfold in the next decade, she said. Meanwhile, the state expects to lose two of its nuclear generators in the next few years.
“It took 60 years to get to 28% renewables [penetration]. So, this is a huge lift that is going to have to take place,” she said. “New York should really [use] every tool under the sun. … No one knows how they will accomplish these goals, so innovation is absolutely critical.”
Tierney said passage of the law “changed the tone of [NYISO’s] stakeholder discussions in a very big way,” broadening support.
“The NYISO has always said that … taking a proposal to FERC would really require some signal from the state — the politicians — that there was interest in having FERC entertain this,” she said.
Discussions with New York Gov. Andrew Cuomo’s office have been derailed by the coronavirus pandemic, leaving timing uncertain.
“What’s going to happen may also be timed to the next elections and new appointments to FERC,” she said.
Emanuel Bernabeu, PJM’s director of applied innovation and analysis, discussed the RTO’s efforts to model carbon pricing in parts of its footprint and ways to limit leakage, which it shared with stakeholders in February. (See PJM Panel Weighs Impact of Pa., Va. Joining RGGI.)
Bernabeu said the PJM’s next steps will be to model RTO-wide carbon pricing and higher prices — $25/ton and $50/ton, compared with the $7/ton and $15/ton modeled previously. He cautioned that the previous results cannot be extrapolated. “Everything is very highly nonlinear,” he said.
Karen Palmer, director of Resources for the Future’s (RFF) Future of Power Initiative, noted that Virginia is planning to join the Regional Greenhouse Gas Initiative in 2021. “That’s a big addition,” she said. “It’s going to substantially increase the number of emitting generators under the RGGI cap.”
Pennsylvania Gov. Tom Wolf has said he wants the state to join RGGI also, but he is facing opposition from the Republican-controlled legislature. (See Critics: Pa. RGGI Hearing Stacked with Detractors.)
“We’ve done some modeling showing that if Pennsylvania wants to do a cap and trade, joining RGGI is a good idea because it’s going to be cheaper than going it alone. And also … there are ways you can target revenues from the allowance auctions that could help reduce emissions leakage.”
ERCOT’s Technical Advisory Committee on Wednesday unanimously approved a change to the Retail Market Guide by email vote after it canceled its previously scheduled meeting because of a limited number of items to consider.
RMGRR163 removes a reference to a couple of legacy reports that will no longer be created. The committee’s Retail Market Subcommittee approved the change on March 5.
ERCOT has released its 2019 State of the Grid report.
The 15-page documents lays out the issues facing ERCOT in 2020 and beyond. It also recaps 2019, when the grid operator was able to maintain system reliability, despite peak electricity demand exceeding 74 GW and low power reserves forcing it to declare two energy emergency alerts.
Annual energy usage was up 2%. It has increased 20% over the past decade. ERCOT’s latest forecast indicates load will continue to increase.
The organizers of an effort to create a resource adequacy program in the West updated their progress and raised vital issues, including potential FERC oversight and the need to hire professionals to develop and manage the program, during a webinar Friday.
The Northwest Power Pool (NWPP), a voluntary organization of utilities based in Portland, Ore., is heading the effort. Its members cover eight Western states and two Canadian provinces, making it possible for the proposed RA program eventually to include most of the Western Interconnection. (See Western Resource Adequacy Program in the Works.)
NWPP President Frank Afranji said one pressing matter now is hiring a program developer to help bring the project to fruition now that it’s well along in the preliminary planning phase.
“Even though a lot of the work has been done [including the program’s basic design], the steering committee has decided that in order for us to move up to the next level, we really need to get an experienced program developer,” Afranji said.
A search is underway for an individual or organization with experience designing multistate RA programs to deal with governance details, cost estimates and regulatory and stakeholder outreach, he said.
“We have the initial, conceptual design … [but] the next stage is going to require a lot more sophisticated work,” Afranji said.
Later, NWPP members will hire an administrator to run the RA program – a distinct role from the program developer, he explained.
Planners expect the RA program to move to a more detailed design phase later this year and begin implementation work in 2021.
Afranji thanked the many participants who tuned into the webinar. “It’s a tribute to the very high interest in the resource adequacy issue,” he said.
A Two-Part Approach
Mark Holman, managing director for power at Powerex, the electricity marketing and trading subsidiary of BC Hydro, described the program’s design, which includes two time horizons.
One horizon will be “forward showing,” Holman said. Member entities will have to show seven months prior to the summer and winter seasons of peak demand that they have enough contracted or installed resources to meet their obligations to the program.
“We’re trying to ensure that each entity comes to the table with sufficient installed available committed capacity to meet their share of the reliability needs,” he said.
The effort will involve establishing common metrics to measure capacity across the vast Western region with its many separate entities and ways of working, Holman said.
| NWPP
The second “operational” time horizon of the program will focus on real-time and day-ahead time frames.
“That’s how we access pooled regional resources,” Holman said. “By having an operational module, it enables us to lower or right-size the amount of resources that are needed … This function is usually provided by an ISO or RTO. In our case, of course, we don’t have an ISO or RTO, so this is a module we’re looking to develop.”
With variable wind and power resources becoming a larger part of the energy mix in the West, the real-time component would allow resources to be adjusted and shared among the RA program’s members as needed, he said.
Planners have been considering whether the program should be binding on members and whether failures to meet resource obligations should be punished with fines, Holman said.
‘The Land of FERC’
Sarah Edmonds, director of transmission services at Portland General Electric, talked about whether the RA program will fall under FERC jurisdiction.
That’s a potentially touchy topic in the Pacific Northwest where many entities — including the Bonneville Power Administration, public utility districts and irrigation districts — aren’t overseen by FERC and don’t want to be.
“We know that’s an important element to some of our members,” she said.
Edmonds said a working group within the NWPP RA program effort has been researching the regulatory landscape and making preliminary assessments.
“Jurisdiction is going to depend on the scope of the program, what functions we want to have in the program and also the timing on when we want to implement these functions,” she said.
One conclusion so far is that parts of the RA program will almost certainly be FERC jurisdictional if the program is going to have any real benefits for participants.
“This is intended to be a regional program, so by its very nature it will be multi-state,” Edmonds said.
Common planning reserve metrics, and a decision to make the program binding on participants with fines for non-compliance, would subject the program to federal oversight, she said. “It’s those functions … that put us in the land of FERC.”
States traditionally have authority over generation facilities and resource planning and adequacy, while FERC oversees interstate transmission and sale of electricity under the Federal Power Act, Edmonds noted. The program will probably be subject in its different respects to state and federal authority.
“We’re dealing with something called cooperative federalism,” Edmonds said. “When it comes to resource adequacy across a regional program, we are likely living in a world where both FERC and the states play a role … Unfortunately, there is no bright line here. There’s no specific delineation of what would be FERC, necessarily. This is something we will have to work out as we work through the details of what we want in this program and when.”
Currently all RA programs operate within ISOs and RTOs and are “part and parcel of all the FERC jurisdictional services provided by the operators.”
“We’re in a really unique position as far as this program” because it would operate outside an RTO or ISO, she said.
The RA program could be constructed in a way — without binding commitments or financial penalties, for instance — to avoid FERC oversight, Edmonds said. Such a program would likely result in information sharing only.
“If we just made this an informational, nonbinding program, it would be more than we have today, but I don’t think it delivers what we want in terms of the end result for reliability for the region,” she said.
ERCOT is working with federal officials to investigate a cybersecurity incident that resulted in the ISO sending a number of wire transfers to a fraudulent bank account last week.
In a market notice issued Friday, ERCOT said the incident began when an attacker compromised a Microsoft Office 365 account belonging to one of its market participants, who was not named in the report. Using the compromised account, the attacker gained access to the email address of the market participant’s authorized representative. It then created several additional email accounts that appeared nearly identical to those of officers and employees at the market participant (a technique known as “domain typo-squatting”).
ERCOT became involved on April 20, when the attacker used the authorized representative’s email account to request the ISO modify the market participant’s banking information. After ERCOT granted the request, a number of wire transfers intended for the market participant were sent to the new bank account from April 21 to 23, when the market participant notified ERCOT that its registration information may have been compromised.
Working with federal authorities, ERCOT was able to recover “a majority” of the transfers sent to the fraudulent account and is still attempting to recover the remaining funds. The identity of the attacker has not been determined. According to the ISO, several IP addresses in Germany and Ghana were used in the attack.
ERCOT last year began using domain-based message authentication reporting and conformance (DMARC) practice to ensure only legitimate emails reach their intended recipients. In 2018, it said, several million fraudulent or deceptive emails were sent using the @ercot.com domain. | DMARC.org
ERCOT’s Computers Not Compromised
ERCOT defines a cybersecurity incident as “a malicious or suspicious act that compromises or disrupts a computer network or system that could foreseeably jeopardize the reliability or integrity of the ERCOT system or ERCOT’s ability to perform the functions of an independent organization.” While the attack meets this definition because it impacted ERCOT’s ability to perform certain registration functions, at this time the ISO has found no evidence that its computer networks or systems were compromised as a result of the attack.
The only computer or network to be compromised appears to be the single Office 365 account belonging to the affected market participant, who ERCOT said had not enabled multi-factor authentication (MFA). ERCOT recommends all participants use MFA to help prevent unauthorized individuals from accessing sensitive information.
It also suggested other protective methods, such as pre-registering email domains similar to those used by market participants and using a domain-based message authentication reporting and conformance (DMARC) practice to ensure only legitimate emails reach their intended recipients.
ERCOT began using DMARC last year. It said that in 2018 several million fraudulent or deceptive emails were sent using the @ercot.com domain. ERCOT’s practice authenticates outgoing emails from the @ercot.com domain and prevents any that fail the DMARC test from reaching any recipient that has a DMARC practice in place.
The ISO is implementing “additional levels of control” for changes to banking information and plans to discuss in future stakeholder meetings additional controls on updates to market participants’ registration information.
ERCOT said the incident seems to be unconnected to a data breach at JPMorgan Chase Bank in March that inadvertently disclosed account information for some ERCOT counterparties.
Cybersecurity has been identified as a significant concern for the electrical industry, due to the large number of people using online services, including Office 365, Slack, and others, to work from home. In a recent report NERC recommended industry be “hyper vigilant” because “a distracted workforce and remote working arrangements open up new attack vectors.” The organization urged utilities to use the E-ISAC and the Cybersecurity Risk Information Sharing Program to stay abreast of the latest threats. (See PPE, Testing Top Coronavirus Concerns for NERC.)
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 futures 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 Futures.)
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.
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.”
PJM CEO Manu Asthana (bottom left) and Moderator Jonathan Raab at the Energy Policy Roundtable in the PJM Footprint.
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.”
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.
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.
