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.
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.
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.
| FirstEnergy
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.
FirstEnergy CEO Chuck Jones | First Energy
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.”
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.
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.”
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.
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).
