Page 974 – RTO Insider

February 26, 2021February 2, 2024

RIPUC Rejects Program for Low-income Customers

The Rhode Island Public Utilities Commission last week unanimously rejected a proposal from National Grid to remove barriers for low-income customers to access the benefits of clean energy.

“At best, this is a poorly developed concept, and taken at its worst, it’s a gimmick and a thinly veiled attempt by the utility to increase their profits from the Renewable Energy Growth Program, while claiming to be doing it in the name of equity,” Commissioner Abigail Anthony said at a Feb. 18 PUC meeting.

National Grid proposed to expand on the state’s Community Remote Distributed Generation (CRDG) incentive program.

“Developers enrolled in the [existing] program get paid by ratepayers an amount that is up to 15% higher than the price needed to build a similarly sized solar facility without the CRDG special features,” PUC Chairman Ronald Gerwatowksi said during the meeting. The project owner would then enroll National Grid’s customers for that facility’s incentive and distributes the extra funds as a bill credit.

Solar facility in Middletown, R.I. | Newport Renewables

National Grid, according to its filing on the proposed program changes, found that low-income customers were underrepresented in the existing program. The utility proposed an increase in the existing rate enhancement by an additional 3 cents/kWh. To qualify for that adder, project owners would have had to subscribe at least 20% of the project’s capacity to low-income customers.

“The purpose of the proposed adder was to increase enrollment of low-income customers in CRDG solar projects in a manner similar to other states’ renewable energy programs,” a National Grid spokesperson told RTO Insider in an email. “The company is committed to addressing low-income customer issues in fulfilling its clean energy goals and will consider alternatives, as the commission recommends.”

Low-income customers enrolled in the proposed program would realize an average annual bill savings of $200, according to National Grid’s filing.

Gerwatowksi said that the intentions of the proposal were good, but the means for accomplishing its objectives “raised questions.”

“We have tens of thousands of customers struggling to pay their bills, and we’re going to be facing mountains of debt when the [pandemic-related] moratorium ends and efforts to increase affordability need to meet the scale of the problem,” Anthony said. “This proposal was a distraction from the work the company should be doing to identify and eliminate all of the inconsistencies in their programs and policies that are causing the electric system to cost more than it needs to.”

The commissioners said they were open to discussing ways to improve on the proposal.

“I think this proposal did identify an opportunity to deliver the benefits of enrolling low-income customers in CRDG but … in a way that doesn’t have added costs,” Anthony said.

February 26, 2021

Calif. Worries High Rates Could Hurt Climate Efforts

California’s energy policy leaders came together Wednesday to weigh the potential impact of the state’s sharply rising electricity rates on its carbon reduction and electrification goals.

The heads of CAISO, the state Public Utilities and Energy commissions, and the legislative committees that oversee energy heard from CPUC staff and academic experts in a virtual hearing on how escalating rates could exacerbate the state’s division between rich and poor and undermine its ambitious programs to fight climate change.

“We begin this work because we understand that meeting our state’s decarbonization and electrification goals will depend on maintaining electricity rates that are affordable for customers,” CPUC President Marybel Batjer said.

Those goals include serving retail customers with 100% carbon-free energy by 2045 and requiring that all new cars sold in the state be zero-emissions vehicles by 2035. (See Calif. Governor Proposes $1.5 Billion for ZEVs.)

In the next decade, however, rates charged by the state’s three big investor-owned utilities will outstrip inflation by a wide margin, CPUC staff said. Ratepayers will have to cover the costs of billions of dollars in wildfire mitigation strategies and transmission and distribution upgrades.

The result: Southern California Edison’s rates will rise by 3.5% annually through 2030; Pacific Gas and Electric’s rates are projected to climb by 3.7% a year; and San Diego Gas and Electric’s rates will increase 4.7% every year for the next decade. Annual inflation, meanwhile, is anticipated to be about 1.9%. And PG&E and SDG&E’s annual rate increases have been twice the rate of inflation since 2013, commissioners said.

California Electricity Rates — Projections show PG&E rates compared with inflation through 2030 | *CPUC*

Electricity costs outpacing inflation by such a wide margin is a “very troubling finding,” Batjer said. Though not as dramatic as some had feared, the increases are more likely to hurt lower-income households that are sensitive to even small increases in monthly bills, she added.

The state must figure out how to maintain affordability and reliability while continuing to fight climate change, she said.

Batjer and the other CPUC commissioners were joined on the virtual dais by CAISO CEO Elliot Mainzer and members of CAISO’s Board of Governors, the state’s energy commissioners, and the chairs of the Senate and Assembly energy committees.

CPUC Commissioner Genevieve Shiroma called the unusual gathering a “who’s who of California energy.”

Shiroma led the effort that produced the draft white paper that formed the basis for the hearing and future efforts. She said it wasn’t fair to keep saddling ratepayers, regardless of income, with fixed costs for infrastructure upgrades.

“We as a commission cannot continue to approve larger and larger revenue requirements,” she said. “We need to do a better job of considering the cumulative impact of the rate increases we approve … and we need to be diligent in ensuring that … we approve [increases] only for programs where we have strong evidence that the benefits will outweigh the costs.”

A primary concern is that rising electricity rates will prevent the adoption of electric vehicles and the replacement of gas furnaces and water heaters with electric units.

California is among the states with the highest retail electricity prices , averaging 20.45 cents/kWh in December versus the national average of 12.8 cents/kWh, according to the U.S. Energy Information Administration.

That could thwart the electrification of transportation, a major policy goal in California, with about 800,000 electric vehicles currently on the road and millions more anticipated. The movement to electrify buildings has been rapidly gaining momentum, with dozens of cities and counties adopting electrification ordinances that exceed state building codes in recent years.

“Higher bills make meeting our policy goals much harder,” CPUC Energy Division Director Ed Randolph said.

The white paper describes the problem but does not provide immediate solutions, Randolph said. Among the issues lacking ready alternatives is the state’s need to prevent catastrophic wildfires sparked by utility equipment, such as those in 2017-2020, and rolling blackouts like those in August.

“Once we looked at the drivers of the increases and the ways we could reduce utility costs, it was hard to pinpoint places where we should cut back on spending,” he said. “The biggest drivers of bill increases are wildfire mitigation spending and transmission buildout. While we can look at ways to be more efficient in these investments, I don’t believe we can recommend not making [them]. They are critical to reducing wildfires, maintaining reliability and avoiding outages such as the ones that happened last summer in California and just happened in Texas.

“We also know that investments in clean energy infrastructure are absolutely necessary to meet our state policies, and analysis shows that these investments have minimal impact on bills or could even save Californians money over time” by reducing rates because of increased demand, he said.

The CPUC and its sister agencies, utilities and stakeholders must find ways to minimize costs and keep electricity affordable, Randolph said.

“Hopefully this en banc [hearing] is a start of that joint effort,” he said.

‘A Tale of Two States’

Paul Phillips, CPUC manager of retail rates, said the rate dilemma highlighted the often extreme income equality in California.

“It really has become a tale of two states,” Phillips said, while presenting the white paper’s findings. “We have wealthier coastal homeowners who tend to invest in distributed energy resources,” mainly rooftop solar, and have a better sense of how to lower their own electric costs. Inland communities of lower-income workers don’t have those resources, he said.

In an afternoon session, Severin Borenstein, a CAISO board member and University of California, Berkeley professor, echoed the theme. He presented the results of a study he and two colleagues from the Energy Institute at UC Berkeley’s Haas School of Business authored, titled, “Designing Electricity Rates for An Equitable Energy Transition.” Nonprofit think tank Next 10 commissioned the study.

The report said California’s strategy of recovering fixed utility and social program costs from lower-income ratepayers is “a headwind in the state’s efforts to combat climate change through electrifying transportation and buildings, which many see as critical steps to a low-carbon future.”

“The state’s three large investor-owned electric utilities recover substantial fixed costs through increased per-kilowatt hour (‘volumetric’) prices,” it said. “With nearly all fixed and sunk costs recovered through such volumetric prices, the price customers pay when they turn their lights on for an extra hour is now two to three times what it actually costs to provide that extra electricity — even when including the societal cost of pollution.

“This massive gap between retail price and marginal cost creates incentives that inefficiently discourage electricity consumption, even though greater electrification will reduce pollution and greenhouse gas emissions,” the report said.

Between 66 and 77% of the costs that California IOUs recover from ratepayers are “associated with fixed costs of operation that do not change when a customer increases consumption,” it said. “This includes much of the costs of generation, transmission and distribution of electricity, as well as subsidies for low-income household and public purpose programs, such as energy efficiency assistance.”

The shift to behind-the-meter solar generation has disproportionately shifted cost recovery onto customers who do not have rooftop solar, the report said. More affluent homeowners now consume “modestly” more energy than low-income households, it said.

The study recommended changing the way utility infrastructure and social programs are financed. One approach, it said, would be to raise revenue from sales or income taxes, “ensuring that higher-income households pay a higher share of the costs.”

That might not sit well with voters, it acknowledged.

“A more politically feasible option could be rate reform — moving utilities to an income-based fixed charge that would allow recovery of long-term capital costs, while ensuring all those who use the system contribute to it,” the report said.

“In this model, wealthier households would pay a higher monthly fee in line with their income.”

In his presentation, Borenstein said the state’s Franchise Tax Board could either provide refunds to low-income ratepayers or disclose customers’ income brackets to the utilities that collect the fees.

“We’ve thought about enforcement issues, and we think there are ways to do it,” Borenstein said. “It would be a lift, but the alternative is not only, I think, going to undermine decarbonization but, also, we’re basically balancing the costs of all of the carbon-reduction programs on the backs of the people who are least able to pay for it.”

February 26, 2021

Cold Weather Standards Team Sticking to Year-end Target

The team modifying NERC’s standards for cold weather preparedness confirmed in a webinar Thursday that the joint inquiry by the ERO and FERC into the recent power outages in Texas and neighboring states will not affect its schedule for completing Project 2019-06, which remains on track to be finished “by the end of the year.” (See Anger Rises over Texas Power Restoration.)

However, NERC Senior Standards Developer Jordan Mallory also acknowledged that the effort “is a high-priority project” for the organization. She said the standard drafting team (SDT) has been actively conducting industry outreach and is confident that “we will only need one more ballot” after the current formal comment period, which ends on March 3.

NERC Panel Delays Action on Cold Weather Prep.)

Team Credits Industry Feedback for Improved Product

Industry reaction to previous postings have been lukewarm at best, as noted at September’s meeting of NERC’s Standards Committee, where the standard authorization request (SAR) was approved. (See “Cold Weather SAR Approved,” Gen Operators Cool to Winter Preparedness Standard.)

cold weather preparedness standards — NERC’s Jordan Mallory (left) and SPP’s Matthew Harward | © *ERO Insider*

SPP’s Matthew Harward, chair of the SDT, said at Thursday’s webinar that the constructive criticism had helped the team create a proposal that would be acceptable to more stakeholders. He emphasized that the team is aware that “a one-size-fits-all approach will not be the most efficient way” to address the issue, and that it had focused on giving generator owners “flexibility … to make many determinations based on their own situations.”

The proposal currently out for comment involves three updated standards: EOP-011-2 (Emergency preparedness), IRO-010-4 (Reliability coordinator data specification and collection) and TOP-003-5 (Operational reliability data).

Changes to EOP-011-2 include adding new requirements for cold weather preparedness plans on the part of generator owners, along with data specifications and collections for balancing authorities and annual maintenance and inspection requirements. IRO-010-4 would be modified to include data specification requirements and cold weather parameters for reliability coordinators, while updates to TOP-003-5 would include those requirements for transmission operators.

The team is also seeking comment on the implementation plan, which would see all new requirements take effect one year after the new standards are accepted by FERC. Harward emphasized that despite the team’s confidence in their work, they still welcome feedback from stakeholders to make sure they are on the right track.

If “you have a suggestion — another standard or new standard … where these requirements should go — please submit comments, because those are very valuable to the drafting team to help us navigate where to place the standards,” Harward said.

February 26, 2021

Biden Targets Energy Sector in Supply Chain Order

In an executive order issued Wednesday, President Joe Biden ordered a review of a number of critical sectors — including energy — in order to “strengthen the resilience of America’s supply chains” ahead of future national emergencies.

The most immediate consequence of the order is a 100-day review of vulnerabilities in the supply chains of four products, to be spearheaded by relevant department heads in consultation with appropriate agencies:

high-capacity batteries, including for electric vehicles, led by the secretary of energy;
semiconductor manufacturing and advanced packaging, led by the secretary of commerce;
critical minerals and “other identified strategic materials,” led by the secretary of defense; and
pharmaceuticals and active pharmaceutical ingredients, led by the secretary of health and human services.

Additional reports are due within one year of the date of the order. Energy Secretary Jennifer Granholm’s report is to cover “supply chains for the energy sector industrial base,” as she defines it. Similar mandates were given to the secretaries of defense, health and human services, commerce, homeland security, transportation and agriculture.

Biden Supply Chain Order — President Joe Biden and Vice President Kamala Harris meet with governors and mayors in the Oval Office. | *The White House*

Both the 100-day and the one-year reports are to include reviews of:

critical goods and materials underlying the supply chain in question;
other essential goods and materials, including digital products;
prioritization of such materials based on statutory or regulatory requirements, importance to national security, and emergency preparedness;
manufacturing and other capabilities needed to produce critical and essential goods and materials;
contingencies that may disrupt, strain or compromise the supply chain — including the failure or exploitation of digital products and services, and reliance on foreign suppliers;
the resilience and capacity of U.S. manufacturing supply chains, as well as its industrial and agricultural base, to support national and economic security in the event of such contingencies;
primary causes of risks for the U.S. industrial base and supply chains;
specific policy recommendations for ensuring resilient supply chains for the relevant sector; and
prior actions by allies and partners in this regard.

In a signing ceremony for the order, Biden emphasized that “even small failures at one point in the supply chain can cause outsize impacts further up the chain.” He specifically noted the shortages of personal protective equipment that many hospitals have faced as a result of the COVID-19 pandemic, as well as the current scarcity of semiconductors that has led to slowdowns in production of cars and electronics. Biden called the semiconductor “a 21st century horseshoe nail,” referencing the proverb about a missing nail leading to the loss of a kingdom.

“While we cannot predict what crisis will hit us, we should have the capacity to respond quickly in the face of challenges,” the White House said in a statement. “The United States must ensure that production shortages, trade disruptions, natural disasters and potential actions by foreign competitors and adversaries never leave the [U.S.] vulnerable again.”

Biden’s order follows one issued by former president Trump last year that declared a national emergency related to the bulk power system supply chain and aimed to remove foreign-manufactured BPS equipment from certain utilities. (See Trump Declares BPS Supply Chain Emergency.) However, that order is currently suspended, pending the result of a 90-day review initiated by Biden as one of his first actions upon taking office last month. (See Biden Suspends Trump’s BPS Supply Chain Order.)

February 25, 2021

Vote Delayed on PJM SATA Proposal

Stakeholders voted Wednesday to delay endorsement of PJM’s proposal to develop rules for how storage should be considered in the Regional Transmission Expansion Plan (RTEP) process, electing to wait until further work is done on the issue.

A vote on the storage as a transmission asset (SATA) proposal was set for Wednesday’s Markets and Reliability Committee meeting after receiving 58% support at the Planning Committee meeting Dec. 1. (See PJM PC OKs RTEP Rules for SATA.)

But members decided to delay endorsement with a sector-weighted vote of 4.33 (86.6%), surpassing the 66% threshold to support the motion to defer the issue.

PJM SATA Proposal — Paul Sotkiewicz, E-Cubed Policy Associates | © *RTO Insider*

Paul Sotkiewicz of E-Cubed Policy Associates made the motion to defer the SATA issue until the conclusion of Phase 2 of work planned by PJM. He said he wanted to see more done to address the points of operations, markets and planning as stated in the original issue charge approved at the May 2020 PC meeting and worked on at special sessions since June. (See SATA Issue Charge Moves Forward in PJM.)

Sotkiewicz said the issue charge was “ambiguous” about what is included in the scope for Phase 1 of SATA. Having a “comprehensive proposal” addressing concerns about SATA competition and energy capacity ancillary services market issues would provide a more complete proposal for stakeholders to vote on, he said.

“We can come back and have a discussion and vote on the comprehensive proposal after addressing all of these issues,” Sotkiewicz said. “As it stands, I think it’s pretty clear this is not ready for prime time.”

Sharon Segner, vice president at LS Power, asked if there were specifics on when PJM would begin work on Phase 2 and what would be discussed among stakeholders.

Stu Bresler, PJM senior vice president of market services, said the RTO originally intended to wait until FERC ruled on the Phase 1 proposal before taking up work on Phase 2. He said the grid operator would introduce an issue charge at the appropriate committees to initiate Phase 2 “as soon as possible.”

Bresler said PJM will have to decide which committees should take up the Phase 2 issue because it potentially touches on aspects of the Planning, Market Implementation and Operating committees.

PJM Proposal

Michele Greening of PJM stakeholder affairs discussed the work conducted on SATA, saying the Phase 1 effort was designed to explore existing transmission planning criteria, including performance measurement methodology. She said additional criteria were developed for evaluating SATA, addressing reliability, market efficiency, operational performance and public policy.

Greening said PJM specifically avoided examining SATA participating in the energy or ancillary services markets, deferring both measures to Phase 2.

Jeff Goldberg, a PJM senior engineer, said the proposal would establish RTEP requirements to ensure that SATA implementation maintains system reliability consistent with NERC standards. He said PJM’s SATA evaluation approach also seeks to prevent adverse impacts to the generation interconnection queue.

The proposal’s guiding principles state that Phase 1 reliability requirements be established to ensure that any Phase 2 dual use of SATA does not adversely impact reliability requirements, Greening said, and that SATA must remain connected to the transmission system while operating to address the system needs for which it was planned.

Amendments Proposed

Segner presented a friendly amendment to the PJM proposal, saying that developers should be included for consideration in the RTEP. She said LS Power takes the position that SATA is a better product for the market, where it should derive its revenues, but when it’s important for SATA to be transmission, storage developers of all types should be included in competition.

Segner said SATA competition is consistent with language in both the problem statement and issue charge, along with the proposal matrix developed and endorsed by the PC. She added that competition was anticipated throughout the stakeholder process.

“The stakes are very high for getting this issue wrong,” Segner said. “This is an infant market, and if it’s not done correctly, there will be consequences and a very significant impact.”

Market Monitor Joe Bowring said there is “absolutely no reason why” SATA shouldn’t be open to competition, which would ensure the least-cost application.

“Competition is core to the way PJM markets function,” Bowring said.

Segner’s friendly amendment raised objections, even while several stakeholders agreed that competition was an important point to include in the PJM proposal. Stakeholders objected to the timing of the amendment, saying it should have been discussed more thoroughly at the PC rather than being introduced before the final vote at the MRC.

A second friendly amendment, brought forward by Tonja Wicks of Duquesne Light Co., was prompted by objections. Wicks proposed a change in the Operating Agreement language from “net” charge/discharge costs to “settle” charge/discharge costs for a SATA receiving cost-based rate recovery.

February 25, 2021November 2, 2023

Experts Urge Grid Hardening amid Decarbonization Push

With Texas still reeling from the impact of widespread power failures, electricity industry experts this week discussed how the Midwest’s grid can fully decarbonize while dodging the worst effects of increasingly common extreme weather events.

The Smart Electric Power Alliance’s Grid Evolution Midwest virtual conference Feb. 22-23 focused on the path to a carbon-free power system in the Midwest. Panelists zeroed in on how intensifying climate events can complicate the process.

Worsening Weather

Michigan Public Service Commission Chair Dan Scripps said the Midwest energy transition is being driven by forces that are “difficult to put back in the bottle,” including technological advancements, declining energy prices and increased customer participation. The realities of climate change in the South in the last few weeks are rightly causing increased scrutiny on the “core functions of the grid,” he said.

“This winter’s been tough,” he said.

Texas’ prolonged blackouts following a massive winter storm were top of mind for other panelists. (See With Crisis Behind it, ERCOT Now Faces the Music.)

“As we see the grid stressed by weather, these extreme weather events, it heightens our focus … on the need to transition more fully to two-way power flows on this grid that was designed to be a one-way power flow grid,” said Veronica Gomez, senior vice president and general counsel at Commonwealth Edison.

Carlos Restrepo, chief technical officer and managing director at Sonnen Inc., said the Midwest’s renewable changeover is happening alongside new weather patterns, neglected infrastructure and increasing load from electrification.

“It’s putting us in a position where we have to figure out what do we do,” Restrepo said. “Our infrastructure is not getting any younger.”

Restrepo said solar and wind generation paired with storage will create a more balanced grid, where energy is available when extreme weather events “fracture” the grid and its ability to distribute power.

He said the Midwest needs new, forward-thinking regulations that are technology “enablers” instead of “stoppers.”

Basic Fixes First

Gomez said the grid is in need of “nuts and bolts, meat and potatoes” investments like swapping wooden poles for steel ones. Sometimes policymakers fixate on the grid of the future, she said, and forget about “old-fashioned” improvements.

“You can’t forget about the basics either,” she said.

Great Plains Institute CEO Rolf Nordstrom said grid modernization is a “prerequisite” to reach a decarbonized system.

“The system is very, very old. People joke that it’s recognizable by Edison, at least in parts. If we’re going to transition this legacy system from one-way flow and one-way movement of information to a multidirectional flow of both data and electricity, and we’re going to deploy all these distributed resources, from electric vehicles, to storage, to you-name-it … you don’t get to do that without modernizing the system,” he said.

However, he said he is now hopeful for a “bipartisan push” from the federal government to invest in grid infrastructure.

“The kind of extreme weather that we were just witnessing in this past week. I mean, everything we see suggests that this is going to become more common. And you know, that’s on both ends. It’s wildfires in California and floods in other parts of the country like the Midwest,” Nordstrom said. “We can expect it to be more chaotic. … It’s clearly playing out this way in Texas.”

He said the warming climate puts pressure on utilities’ core responsibilities, where “safety, reliability and affordability” are all under threat.

Nordstrom said in the aftermath of the Texas event, some have “played fast and loose” with the facts and blamed renewable generation.

“The vast majority of the challenges were actually with thermal plants and much more conventional forms of energy. … The mischief with the facts just complicates taking an evidence-based approach,” he said.

Minnesota Power Manager of Regulatory Strategy and Policy Jennifer Peterson pointed out that her service territory in early 2019 recorded a punishing -56 degrees Fahrenheit temperature.

Peterson said navigating the chill involved all the demand response her utility could muster, ranging from curtailing industrial iron mines to residential customers switching from furnaces to their woodburning stoves for heat.

“I think the key going forward is to have a number of tools, whether that’s dynamic pricing to send the right signals [or] emergency curtailable products like demand response. I think the utility will need flexibility on a number of fronts to manage the system as it becomes more dynamic and we experience more pressure from increasing weather events,” she said. She added that the grid is no longer going to revolve around “large capital investments” resulting in “large kilowatt-hours.”

Reinforcements at What Cost?

Nordstrom said while grid planners can design the system to withstand a host of weather challenges, that can get expensive. It remains to be seen how much companies are willing to invest in resilience and how much consumers are willing to pay for electricity with more built-in risk management, he said.

“I think it’s challenging,” he said. “If you’re used to a world where the future is predicated on the past, we’ve left that world. Just how much do you invest to protect against the extremes, knowing that they’re going to be more frequent?”

Nordstrom said the industry has left unanswered how it plans to decarbonize its natural gas sector.

“We’ve spent so much time on the electric sector and thinking about what decarbonizing that looks like. We’ve spent really relatively little time thinking about how you decarbonize natural gas and how you decarbonize heating,” he said. “I’m not saying it’s easy in electricity, but I think we at least have a line of sight for what it looks like to decarbonize the system at least 80% or more. We don’t have the same clarity or line of sight for what it looks like to decarbonize natural gas. Yet.”

Nordstrom said the natural gas sector so far only offers partial decarbonization solutions like renewable natural gas and hydrogen technologies. He said part of the problem is that some stakeholders want a full decarbonization policy instead of supporting “cul-de-sacs” that help but aren’t 100% effective.

Xcel Energy’s 2050 decarbonization goal doesn’t include its natural gas system, according to Sydnie Lieb, the utility’s energy and environmental policy manager. But the utility is taking steps to address natural gas, filing with Minnesota state regulators to introduce an electric water heater flexible load pilot project, she said.

Lieb also said customers will inevitably see increased bills in the clean energy transition.

But Fresh Energy Lead Director of Energy Transition Margaret Cherne-Hendrick said utilities and regulators should work to keep bills affordable in the throes of a clean energy conversion.

“We don’t think this transition will be on the backs of individual ratepayers, individual businesses,” she said. “This transition will be done through regulations and financing.”

Audrey Partridge, regulatory policy manager at the Center for Energy and Environment, said it’s unrealistic to stay with a regulatory style that pits renewable resources against “$2[/MMBtu] natural gas.”

“As long as we have that framework, there’s going to be a challenge,” she said.

Partridge said the pandemic offers an opportunity to create a more equitable decarbonization and rethink rate structures. “We’ve seen it at the end of economic downturns,” she said. “I believe we’ll see it at the end of COVID-19.”

Wisconsin Public Service Commission Chair Rebecca Cameron Valcq said the situation in ERCOT lays bare the importance of the deceptively simple task of balancing load and generation at all times.

“For the last 100-plus years, we all got really comfortable with a very, very set way of generating, transmitting and consuming our energy,” Cameron Valcq said. “And those three things are in a period of such rapid change that I think all of us as regulators have to keep reminding ourselves that as the technology is advancing, as the way energy is consumed is changing, we have to make sure what we’re always keeping an eye on is: are the load and generation continuing to be in balance?”

“We can all see to 80% reduction,” Cameron Valcq said, but it’s the last 20% increment that will be the largest challenge and require the most technology and innovation.

Cameron Valcq said regulators should send signals to utilities that cost recovery will be possible for technologies to facilitate the transition to zero carbon.

She also said doubling down on energy efficiency will help the industry inch toward full decarbonization more quickly.

“We only need to see what’s happening in Texas to understand that we cannot afford to put all of our eggs in one basket,” she said. “We have to remember this is an ‘all of the above’ situation.”

Gomez said ComEd’s power supply is already carbon-free 94% of the hours of the year. She acknowledged that much of the clean power is sourced from nuclear plants. ComEd’s challenge is getting that “last, difficult 6%” obtained from clean resources, she said.

February 25, 2021

ERCOT Provides ‘Explanations, not Excuses’

Saying ERCOT wanted to “provide explanations, not excuses,” CEO Bill Magness on Wednesday detailed for the Board of Directors the events that led up to last week’s near collapse of the grid that left millions of Texans in the cold and dark for abnormally long periods of time.

Dozens of deaths and disrupted water supplies have been attributed to the outages. The financial losses are expected to exceed even those of Hurricane Harvey in 2017.

“This was a devastating event for those of us who make our living in the power industry, but especially devastating to the people we work for,” Magness told the board during an emergency teleconference. “There’s no question there were tremendous, terrible impacts, including loss of life, that affected so many Texans. We regret the time it took to resolve this event.”

ERCOT Blackouts — CEO Bill Magness and board members hailed ERCOT operators Wednesday for their prompt actions in avoiding a total grid collapse. | © *RTO Insider*

Magness’ presentation will likely serve as the basis of the grid operator’s appearance Thursday before a joint meeting of the Texas House of Representatives’ State Affairs and Energy Resources committees.

“We don’t want to see this happen again. We want to be part of that review,” Magness said. “We stand behind the actions we took during this event. We believe they’re very solid.”

ERCOT was “riding along fairly steady” on Feb. 14, Magness said, setting a new winter-peak demand record of 69.2 GW at 7:06 p.m. But as load began to drop off, generation did so even more quickly.

The operations center called its first energy emergency alert (EEA) at 12:15 a.m. Feb. 15, then elevated the EEA to Level 2 at 1:07 a.m. Thirteen minutes later, with generation continuing to fall off the system — 35.3 GW at that point — staff declared an EEA Level 3 and ordered its first load shed.

The operators continued to drop load to try and stay ahead of the generation losses. Magness said at its peak, ERCOT had to do without 48.6% of its installed capacity (52.3 GW of 107.5 GW).

By 1:50 a.m., the grid’s frequency level had dropped to 59.4 Hz, where it stayed for four minutes and 26 seconds. If the frequency had stayed at that level for a total of nine minutes, spinning turbines would have been involuntarily shut down and damaged, Magness said, leading to a complete blackout.

“We were definitely in a dangerous situation, and one we had to respond to,” Magness said. “The steps we took are outlined in federal NERC standards, actions you have to take to maintain frequency. You could have a situation where it’s out of the grid operators’ control, and we can’t have that happen.”

Staff called for another 6.5 GW of load shed before the grid returned to some semblance of normality at 1:55 a.m., but not before hitting a frequency low of 59.302 Hz.

“The only way to get back to 60 Hz effectively was to institute the amount of load shed we were instituting,” Magness said.

ERCOT eventually called for 20 GW of load shed on Feb. 15. Without almost half of the grid’s generating capacity, some local transmission providers were unable to effectively rotate their outages, leaving customers without power for more than two or three days.

Still, that was better than the alternative, as a complete blackout would have taken an “indeterminate amount” of time and been “extraordinarily difficult” to recover from, Magness said.

ERCOT operators called for repeated load sheds as the grid’s frequency dropped. | *ERCOT*

Further complicating matters: Of the 13 primary generating units ERCOT contracts with to restart the system during a black start, six were in outages that ranged from four to 127 hours. Two of those units’ alternate generators also experienced outages.

“We might still be talking today about bringing the system back,” Magness said.

Peter Cramton, one of five directors who announced Tuesday they would be resigning from the board, lauded ERCOT’s operators for their work during the crisis and referenced the oft used description of grid operators as being air traffic controllers. (See related story, ERCOT Chair, 4 Directors to Resign.)

“I think it’s important the public understand ERCOT was flying a 747,” he said. “It had not one, but two engines experience catastrophic failure, then flew the damaged plane for 103 hours before safely landing in the Hudson. In my mind, the men and women in the air traffic control room are heroes.”

ERCOT declared an operating condition notice Feb. 8 in advance of the extreme cold weather, which Magness said was expected to bring the coldest weather that Texas has seen in decades. Director Jackie Sargent, general manager of Austin Energy, said staff should have been more upfront with their concerns during a board meeting the following day. (See ERCOT Bracing for Winter Storm, Record Demand.)

“I certainly could have done a better job of emphasizing what was coming,” Magness said in apologizing. “I certainly could have covered that with the board in more depth as well.”

Market Issues Rise

Attention has also begun to focus on liquidity issues within ERCOT’s retail market, where real-time prices averaged $6,579.59/MWh Feb. 14-19 and spent days at the $9,000/MWh cap. In January, prices averaged $20.79/MWh.

Kenan Ögelman, vice president of commercial operations, said the prices have driven “extremely high collateral requirements” for all market participants. Those participants will begin to see their bills and revenue this week.

“The financial stress continues this week,” he said, noting staff, the Public Utility Commission and participants are working to address the market issues.

“We’ve have been authorized [by the PUC] to use additional discretion [in settling market transactions]. We are being judicious in applying that discretion,” Ögelman said. “The invoice process is there to ensure we bill folks and collect that money, so we can pay folks that incurred costs. Disrupting that process has a lot of liquidity risk. If I were not able to collect dollars, I would not be able to pay money, and that would have chilling downstream consequences.”

CFO Sean Taylor was unable to give a “solid answer” as to whether ERCOT has sufficient funds to cover market shortfalls. He said it has a “significant amount” of collateral on hand (about $2 billion) and access to $1 billion in congestion revenue rights funds.

“We do anticipate the major players paying us the money they owe us,” he said. “That mitigates a lot of concern if that does happen.”

Texas Gov. Greg Abbott has asked the legislature to look at shielding customers from high bills. Also Wednesday, the PUC announced it has open an investigation into retail electric providers’ (REPs) pricing plans that are indexed to wholesale rates and have led to four- and five-figure bills.

“An influx of complaints into our Customer Protection Division has caused concerns that questionable business practices might be exacerbating the situation,” PUC Executive Director Thomas Gleeson said.

Talberg Steps Down as Chair

The meeting marked the end of Sally Talberg’s short tenure as board chair. She, Cramton and two other independent directors, who have been criticized by Texas politicians for living out of state, announced their resignations Tuesday. Also resigning Tuesday was Just Energy’s Vanessa Anesetti-Parra, a Canadian who represented the independent REP market segment. The nominee for the last of its five independent director positions also withdrew his application.

“This discussion has been really helpful,” Talberg said. “I want to acknowledge the ERCOT staff and what they did over the past 10 days. They were not immune to the loss of heat. My heart goes out to all of you. This is not what anyone wanted.”

Talberg said as the meeting began that Southern Federal Power’s Randall Miller resigned as the alternate representative for the board’s independent REP segment.

February 25, 2021

Report: US Needs Grid-enhancing Technologies Now

While the advanced macrogrid required for the U.S. clean energy future is years and billions of dollars away, a new report from the WATT Coalition argues that currently available grid-enhancing technologies (GETs) could help optimize the grid and unlock gigawatts of renewables in interconnection queues.

The study, conducted by the Brattle Group, focused on transmission constraints in Kansas and Oklahoma, where, it says, more than 9 GW of wind and solar projects with interconnection agreements are sitting in the SPP queue. Under a business-as-usual base case, the study estimates that by 2025, about 2.6 GW of this new generation could be interconnected; but with dynamic line ratings, advanced power flow control and advanced topology control, more than 5.2 GW of mostly wind energy could be brought online.

Grid-enhancing Technologies — | *WATT Coalition*

Speaking at a media briefing on the report Wednesday, Rodica Donaldson, senior director of transmission strategy at EDF Renewables North America, said that GETs are urgently needed to mitigate both “chronically delayed or even dysfunctional” interconnection processes and existing constraints on the grid. GETs can “become either a bridge to address congestion, until a permanent fix is there, or it can be coupled with more effective solutions,” she said.

“There’s a huge timing gap,” said Jay Caspary, former director of transmission development at SPP and now vice president at Grid Strategies. “Renewables could be developed in 12 to 18 months, much faster than transmission lines, which take five to 10 to 15-plus years.”

Noting that wind energy was the leading generation resource for SPP last year, Caspary said, “We’re going to see more and more renewables trying to get on the system, and the way we think we can do this quickly and cost-effectively is through grid-enhancing technologies.”

SPP did not respond to requests for comment.

The report focused on:

DLRs, which set a transmission line’s load limit based on monitored conditions rather than using a fixed limit based on the heat tolerance of equipment and conservative assumptions about ambient conditions on the line. By monitoring ambient conditions, DLRs generally allow more flow over the course of a year but also detect when flow should be reduced to ensure safety and reliability in extreme conditions.
advanced power flow controls, which expand on the capabilities of traditional controls that push or pull power away from overloaded lines and onto underutilized ones. Advanced controls can be deployed faster, scale to meet the size of the need and can also be redeployed to other areas of the grid.
advanced topology control software, which finds ways to reroute power flows around congested or overloaded areas on the grid by switching existing high-voltage circuit breakers on or off.

In the WATT study, the total cost for deploying the technologies at strategic locations on the system in Kansas and Oklahoma would be about $90 million, but they would generate $175 million per year in production cost savings, providing a six-month return on investment. Other benefits would include thousands of short- and long-term jobs and a drop in carbon emissions of 3 million tons a year.

Efficiency Before Infrastructure

All three technologies have been around and talked about at industry meetings for years. As far back as 2016, SPP was showing off its own power flow control technology and inviting vendors to share information on the GETs, like DLR, that they were developing. (See SPP Gathers Technology Vendors to Share Wares.)

The problem, Caspary said, is they have not been used in a systematic way or been incorporated into grid planning, and the reason for that is also well known: regulation and utility business models. (See How Utility Conservatism is Hampering Tx Innovation.)

“Today’s incentive structure means that U.S. utilities are disincentivized from first optimizing their infrastructure before investing in new infrastructure,” said Jenny Erwin, director of strategic marketing at Smart Wires, a WATT member. “The traditional cost-plus approach to capital investment means that today’s rules benefit transmission owners who invest in infrastructure, not efficiency.”

But, Erwin said, industry thinking on GETs is starting to shift. “Optimizing first actually helps justify additional large-scale investments,” she said. In the past year, National Grid has begun deploying DLRs and advanced power flow controls in its service territory and is looking at advanced topology optimization, said Rudolph Wynter, the utility’s COO for wholesale networks and capital delivery.

GETs are, he said, “another set of tools. We have to show we are good stewards and good asset owners. One really good way to do that is to show that we’re doing as much as we can to optimize existing assets before we have to build new assets.”

While not providing any detail, Rep. Kathy Castor (D), chair of the House Select Committee on the Climate Crisis, is hopeful that Congress can provide some policy support for GETs. “The fact that these grid-enhancing technologies can provide short-term relief from grid congestion shouldn’t be an issue that gets bogged down in partisan politics,” Castor said.

Action by FERC could also help overcome the barriers of traditional utility business models, specifically by putting new incentives in place and incorporating GETS into discussions about planning, former FERC Commissioner Nora Mead Brownell said. Both she and Castor were optimistic about the possibilities for movement on the issue under the leadership of new Chair Richard Glick.

FERC “should hold the RTOs accountable,” Brownell said. “RTOs should stand up in a technical conference and talk about what they’re doing to provide the leadership that is necessary to get these [technologies] deployed quickly.”

February 25, 2021

Entergy Profits Unscathed by Storms, Virus

Vicious storms and an ongoing pandemic failed to hobble year-over-year profit growth, Entergy executives said Wednesday.

Entergy CEO Leo Denault began the company’s year-end earnings call by addressing severe winter weather that overwhelmed ERCOT, MISO and SPP last week. Entergy carried out MISO’s orders to perform rolling blackouts in order to balance the system. (See ERCOT, MISO, SPP Slough Load in Wintry Blast.)

“Our system is back to normal operations,” Denault announced.

Denault said employees “worked around the clock in difficult conditions” to complete restoration the morning of the earnings release. The winter storm caused a peak of about 90,000 outages in Entergy’s service territory.

Entergy estimated that the event caused $400 million worth of incremental fuel costs and another $125 million to $140 million to mobilize crews and restore power. Denault said the utility will work with regulators to recover costs in a way that mitigates impacts on customer bills.

Entergy Profits — Entergy winter storm restoration last week | *Entergy*

CFO Drew Marsh said Entergy is still “unpacking” the events of last week. While it does, it will file with regulators in Texas, Louisiana and New Orleans to recover costs from last summer’s back-to-back hurricanes that rocked those service territories. Denault said Entergy would seek to securitize the costs to shield ratepayers. (See MISO Looks Back on Turbulent Summer.)

The recent winter storm coupled with the active hurricane season means Entergy has followed MISO load-shed orders twice in fewer than six months.

In spite of the storms, Entergy managed year-end earnings of almost $1.4 billion ($6.90/share), compared to 2019’s $1.2 billion ($6.30/share). For the quarter, Entergy said it earned $388 million ($1.93/share), better than last year’s fourth-quarter performance of $385 million ($1.92/share).

The financial performance shows that Entergy can “achieve goals regardless of circumstances,” Denault said.

Entergy’s $800 million in transmission investments in 2020 helped it weather Hurricane Laura, Denault said. He said some new structures “withstood record winds” and “were critical in restoring power after the storm.”

Marsh said the utility implemented $150 million in cost-cutting measures in 2020, eclipsing an original $100 million cost savings target for the year. The savings offset lower retail sales volume, including COVID-19 impacts and storms, Entergy said.

Denault said Entergy created “sustainable value for all our stakeholders, even in extraordinary times.”

“This past year, our employees demonstrated once again why Entergy is best-in-class in storm response,” he said.

Embracing Solar

Denault said renewable energy — particularly solar generation — will be a key player in Entergy’s strategy.

“We have approximately 450 MW of solar projects currently being installed. We have another 880 MW of solar resources either in regulatory review or [requests for proposals]. We plan to solicit another 800 MW of solar this year,” Denault said. “This is only the beginning. And we will continue to grow the number of renewable energy facilities across our region.”

Entergy currently has about 500 MW of renewable resources in operation.

By 2030, Denault said Entergy’s generation portfolio will contain 5 GW of renewable generation “with the potential for more.” He said that over the next decade, the utility will retire about 4 GW of legacy natural gas plants “along with the remainder of our coal assets.”

Denault said going forward, Entergy won’t build any large-scale generation that isn’t at least partially hydrogen capable. He said that while the company’s near-term carbon reductions goal doesn’t include a hydrogen strategy, he believes it will be essential in reaching net-zero emissions.

Entergy in fall said it would achieve net-zero carbon emissions by 2050. To date, the company’s carbon emissions have fallen about 40% from 2000 levels.

Arkansas Rate Case Unfinished

Finally, Denault said Entergy Arkansas’ 2021 annual formula rate plan (FRP) continues to be a point of contention between it and state regulators.

The Arkansas Public Service Commission in December blocked Entergy’s request for a statewide rate increase of about 4%, raising the average residential bill by about $4/month. Entergy has sought rehearing on the order, claiming the price hike is justified. The PSC is expected to rule on the rehearing request in mid-March

Denault said the commission’s order “falls short of our expectations” and is unreasonable. The commission wrote in the order that it “expects all utilities to control their costs in a prudent and reasonable manner and not utilize the FRP as an automatic yearly 4% rate increase.”

February 25, 2021

Exelon to Split Tx, Generation Businesses

Exelon announced a major restructuring Wednesday, saying it will separate into two publicly traded companies, one for its regulated transmission and distribution business and the other for its merchant power generation.

Expectations were widespread that Exelon would announce a major restructuring coincident with its fourth quarter 2020 earnings release. It had announced it was considering the separation in November. (See Exelon Discusses Potential Generation Spinoff.)

The company’s stock rose in pre-market action, trading as high as $42.34 after closing at $40.80 Tuesday. It closed Wednesday at $40.19.

Exelon reported higher than expected Q4 earnings but said it may have lost as much as $950 million because of outages at three Texas natural gas plants idled during the arctic blast that left much of the state in the dark for days.

Restructuring

Exelon said the restructuring will create the nation’s “largest fully regulated transmission and distribution utility,” with six utilities in five states and D.C., and the largest producer of carbon-free power — thanks mostly to its 18.7 GW nuclear fleet. It also owns 12 GW of hydropower, solar, wind, gas and oil generation.

The company said the separation “better positions each company within its comparable peer set” and will allow them to pursue business strategies tailored to their sectors. It “aligns our business mix with investor preferences and overall market trends,” it said.

“These are two strong, distinct businesses that will benefit from the strategic flexibility to focus on their unique customer, market and community priorities,” CEO Chris Crane said in a statement.

Exelon Restructure — Exelon plans to separate it regulated transmission and distribution utilities from its merchant generation unit. | *Exelon*

The company hopes to complete the transition, which will require approvals by FERC, the Nuclear Regulatory Commission and the New York Public Service Commission, by the first quarter of 2022.

One spinoff company, temporarily named RemainCo, will hold the assets in Exelon’s six regulated service areas. Another new company called SpinCo will hold the merchant generation assets.

Questions on Ill. Nuclear Plants

Exelon, by far the largest nuclear generator in the U.S., reported that its fleet’s capacity factor was 95.4% in 2020, the second highest ever for its owned and operated units. But nuclear power has been a troubled part of Exelon. The company said last year it may be forced to shut down its Illinois nuclear plants without state legislation to subsidize the units, which have been pinched as natural gas and renewables have depressed wholesale power prices.

The company is hoping to win relief as part of sweeping Illinois energy legislation expected to be considered this year.

Crane asserted that Illinois Gov. JB Pritzker “has called for passing an energy bill this session that protects our nuclear fleet, grows renewable energy and supports customers and job creation.”

But Illinois industry observers say that the governor remains undecided on his exact stance.

Gov. Pritzker has said only that he supports the principles behind the Clean Energy Jobs Act, which is supported by many legislators in the both the state Assembly and Senate. It does not provide for the nuclear bailout that Exelon seeks.

There is much debate about the profitability of Exelon’s Illinois nuclear plants. The company says they are not profitable and need state support. But Pritzker is skeptical and has hired a consultant to dig into the company’s financials.

In response to an analyst question in the conference call, Crane admitted the company faces “a cloud” in Illinois, its reputation badly tarnished in the wake of a $200 million bribery scandal that resulted in the indictment of former ComEd CEO Anne Pramaggiore. (See Ex-ComEd CEO, Officials Charged in Ill. Bribery Scheme.) Federal officials said ComEd sought favorable legislation by giving jobs and contracts to allies of Assembly Speaker Michael Madigan, who resigned Feb. 18.

Illinois PIRG Director Abe Scarr said the company’s separation plans will reduce, but not eliminate, conflicts of interests that harm consumers.

“Every year, Exelon bills hundreds of millions of dollars of services to ComEd, a subsidiary it controls, a subsidiary which can fully recover those costs from its captured customers,” Scarr said. “The Illinois General Assembly has the opportunity this spring to begin undoing the policy harms of the ComEd bribery scandal. That means winning restitution for ComEd customers, restoring effective utility regulation by ending automatic rate hikes through formula rates, and reforming utility political influence by no longer allowing utilities to charge their customers for charitable contributions. Addressing the conflicts of interest that persist beyond an Exelon breakup should remain on the General Assembly’s agenda.”

Texas Losses

The company estimates pre-tax losses of $750 million to $950 million because its Colorado Bend, Wolf Hollow and Handley plants in ERCOT were unable to operate when prices hit the $9,000/MWh price cap during the cold front.

Crane said the range “includes our best estimate for load obligations, ancillary charges and bad debt,” but cautioned that the estimate was preliminary and would be updated in Exelon’s Q1 conference call in the spring.

“As you know, last week’s events have raised many questions about Texas market design and associated risks,” Crane said. “And this has not been a new conversation. It’s been one that’s been around for a while. And we hope that through this that the proper actions can be taken on the design. As a result, we are evaluating all our options with respect to our ERCOT business.”

Laura Starks, CEO of Texas-based energy consultancy Starks Energy Economics, said it’s difficult to forecast the losses to utilities from the Texas fiasco, especially after five ERCOT board members resigned in the wake of the outages.

Earnings

Continuing a streak of quarterly results that have beaten market expectations, Exelon announced adjusted Q4 earnings and revenues that outperformed market estimates. Other major utilities have also been beating Q4 expectations, including NextEra, Dominion and Xcel.

Exelon reported adjusted (non-GAAP) earnings of $0.76/share, beating analyst expectations by $0.06. But GAAP EPS significantly underperformed expectations at $0.37, $0.60 lower than the market was anticipating. One-time plant retirement costs accounted for much of the difference, totaling $0.38/share.

Revenues for the quarter were $210 million higher than estimates at $8.12 billion.

Full year GAAP 2020 results took a major hit compared to 2019; GAAP EPS was $2.01 versus $3.01 for 2019. Adjusted operating earnings were steady in 2020 at $3.22/share.

Exelon gave adjusted (non-GAAP) operating earnings full-year guidance for 2021 of between $2.60 and $3/share. In the conference call the company said it expects to grow its rate base about 7% per year through 2024.