Page 974 – RTO Insider

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.

February 25, 2021November 26, 2023

Study: CREZ an Option to Meet 2030 Maine RPS

Maine could benefit from the designation of Competitive Renewable Energy Zones (CREZ) for building onshore wind to meet its 2030 renewable portfolio standard of 80%, according to a study released last week by Gov. Janet Mills’ Energy Office.

By following the example of Texas’ CREZ process, the state could unlock the potential of significant remote wind resources that are inaccessible absent investments in transmission, according to the “Renewable Energy Goals Market Assessment.” A 2019 law that updated the state’s RPS called for the study, which was sponsored by the Energy Office and conducted by Energy & Environmental Economics (E3) and Applied Economics Clinic.

The designation of two CREZ, one in the western part of the state and one in the north, would send a signal to developers that certain wind resources are critical to meeting the RPS, the study said. Under the CREZ approach, the state could reduce developer uncertainty by completing transmission upgrades in the designated zones in advance of wind farm construction, it said.

The study suggested that the state issue two requests for proposals for each zone, with one proposal targeting transmission development and another targeting resource development.

A new study from the Maine Energy Office said the state could meet its 2030 RPS by establishing CREZ, in which wind farms like the 42-MW Mars Hill project, seen here in Northern Maine, could be developed. | CC BY-SA 2.0, via Wikimedia Commons

A CREZ approach in Maine, however, would require an additional study of population and environmental barriers to land development, the study said.

The purpose of the market assessment is to support policymaking on the path to achieving the state’s renewable portfolio standard. The Energy Office is accepting comments on the study through Friday.

Finding 800 MW

The study determined that Maine already has either built or procured enough resources to meet its renewables standard through 2026. After that, the state will need to bring online at least 800 MW of new resources to meet the 80% requirement in 2030. Wind resources in western and northern Maine, according to the study, would provide a low-cost option for compliance.

Six scenarios in the study show pathways for meeting the 2030 requirement. Under a least-cost scenario, for example, new onshore wind development would fulfill the 800-MW need. That development, however, would only be possible with transmission upgrades.

The study’s review of transmission constraints in the western and northern regions showed that, with grid upgrades, the two zones could support 360 and 498 MW, respectively, of new onshore wind capacity in 2030.

Offshore Wind Scenario

Maine could turn entirely to offshore wind as an alternative to onshore wind and transmission development to meet the 80% requirement.

Under the study’s high OSW scenario, up to 1 GW of offshore capacity would be interconnected to Maine’s grid by 2030. The need for new onshore wind capacity would be pushed out to 2035, and the first transmission upgrades would not need to be completed until 2040. A high offshore wind option would require additional analysis of Maine’s grid to understand the implications of adding offshore capacity, the study said.

Existing Transmission

To understand how Maine could meet its 80% requirement without grid upgrades and with a mix of resources, the study identified three resources that could be brought online by 2030 with existing infrastructure. Under a no-grid-upgrades scenario, Maine could bring online 500 MW of offshore wind, 260 MW of distributed generation and 200 MW of onshore wind.

The 200 MW of onshore wind would need to be developed in southern Maine, where the study determined the existing transmission system has available capacity.

February 24, 2021

Blueprint Frames Carbon Capture as Critical for Climate

The Carbon Capture Coalition has two top priorities for the current session of Congress: providing a direct-pay option for the 45Q tax credit and expanding project eligibility for the credit via a multiyear extension of the deadline for beginning construction.

And the most likely vehicle for passage of one or both policies could be a bipartisan infrastructure bill, said Sen. Tina Smith (D-Minn.), speaking at a media preview of the coalition’s 2021-2022 Federal Policy Blueprint on Tuesday.

“My hope and, I think, the hope of many of us is that that big infrastructure package can address directly the needs we have to move toward a clean energy future, including technology-neutral tax credits and other infrastructure,” Smith said. “We are hoping to get to work on this in real time after we move through and get this COVID relief package done.”

Originally passed in 2018, 45Q is a tax credit specifically for carbon-capture technologies: $50/ton for carbon stored in underground saline formations, and $35/ton for carbon used to make other products. The credit got a two-year extension in the year-end omnibus legislation passed by Congress, and the IRS released final rules on it earlier this year.

But, the coalition argues in the blueprint, “direct pay is a more cost-effective and efficient way of incentivizing carbon-capture projects,” attracting more investment and increased deployment of projects. Similarly, according to the blueprint, the deadline extension is needed because “complex and capital-intensive carbon-capture projects can have lead times of several years before beginning construction” and still might not be able to qualify for the credit.

Smith and other speakers at the briefing focused on framing carbon capture as an essential tool for cutting emissions and addressing climate change across the economy, as well as a job creator and an issue that could garner strong bipartisan support.

“It isn’t a substitute for sharply reducing emissions; it’s a partner. We need to do both,” Smith said.

“Economy-wide and accelerated deployment of carbon capture is critical to achieve midcentury global temperature targets,” said Jessie Stolark, the coalition’s public policy and member relations manager. She pointed to a recent analysis from the International Energy Agency showing that carbon capture could provide up to 15% of emission reductions needed to get to net zero by 2070.

Anna Fendley, director of regulatory and state policy for the United Steelworkers, said the technology will be crucial in the industrial sector “where process emissions can’t be eliminated. We don’t have carbon-capture technology on our blast furnaces yet,” Fendley said. “The blueprint really speaks to some of the challenges in the industrial sector; namely that it’s so capital-intensive and trade-exposed.”

Fendley was referring to the coalition’s portfolio of other options for expanding the 45Q tax credit, such as eliminating thresholds for the amount of carbon a project must capture per year to qualify and upping the credit value for sectors in which the technology will have a higher cost.

The coalition is also backing the Storing CO2 and Lowering Emissions (SCALE) Act, which would provide low-interest loans and grants to help finance CO2 pipelines and other transport and storage infrastructure. Introduced in the House of Representatives last year, it would provide financial support for developing commercial-scale saline storage — large underground sediment formations containing brine and porous rock — and extra funding to EPA to speed up federal and state permitting of such sites.

“The federal government has a long-established role in transportation: automobiles, public transit and water,” said Charles Hernick, vice president of policy and advocacy at Citizens for a Responsible Energy Future, a conservative clean energy lobbying group. “When we think about the carbon-managed economy of the future, we need to think of CO2 pipelines as well. This is going to be an area that is important for investment, and there’s a unique role for the federal government to really make a difference and kick open the door for this growing economy.”

Big Coalition, Broad Goals

Founded in 2018, the Carbon Capture Coalition and its 80 members are themselves a reflection of the bipartisan, industry and federal support that have coalesced around carbon-capture technologies in recent years.

Last September, the Department of Energy announced $72 million in research and development funding for 27 carbon-capture projects, and the year-end energy legislation passed by Congress included a recommendation for an additional $1 billion in R&D funding.

At present, the U.S. has about a dozen commercial-scale carbon capture facilities in operation, Stolark said, and 30 more are in development across the country. Sen. Smith talked about a recently announced project billed as the world’s largest carbon capture and storage system, taking CO2 from ethanol plants in Minnesota and Iowa and shipping them via a proposed pipeline to saline storage sites in North Dakota. When fully built out, the project could capture and store up to 10 million tons of CO2 per year and “deliver truly low-carbon liquid fuels,” Smith said.

Carbon capture is also an integral part of President Biden’s plan to decarbonize the U.S economy and reassert the nation’s leadership in global efforts to tackle climate change, said Shuchi Talati, chief of staff of DOE’s Office of Fossil Energy.

“To reach our goal, we have to manage the carbon that comes from all sectors, including power and industry,” Talati said. “We want to leverage the work already done by the carbon management team in the Office of Fossil Energy and consider ways we can apply technologies to develop low-carbon cement and concrete, low-carbon steel, low-carbon paper and so many other important products.”

Hernick said increased R&D funding for carbon capture is also needed to keep the U.S. competitive in global markets. While older coal plants are closing in the U.S., newer, more efficient plants will stay online here and around the world. “There are still a lot of folks that need electricity and are looking to those coal assets in their country,” Hernick said. “The goal here is not just about U.S. emissions but really global technology and U.S. leadership to address a global issue.”

Talati also stressed that environmental justice will be a central part of the administration’s approach to carbon capture R&D. “It’s not just determining what technologies we need, but also we need to choose carefully where to site these projects,” she said. “They must be in locations where there is support for these projects, where there’s community involvement and benefits for the surrounding populations, including jobs.”

The challenge for the coalition and lawmakers like Smith is finding the most effective route to pass carbon capture-friendly policies — piecemeal or as a package. Smith is for a “holistic” approach, putting together “a broad coalition that can come together to support technology innovations that are going to create jobs and opportunities for people regardless of whether you live in a red state or a blue state.”

“Now is the moment for us to be thinking in bold ways, to be thinking bigger about what we can accomplish,” she said. “It will be easier to put together that big coalition if we are thinking broadly about what we need to do.”

February 24, 2021

Wis. Gov. Seeks Progress on Climate Agenda

Wisconsin Gov. Tony Evers’ (D) second state budget seeks millions in funding to make good on the commitment he made a year ago to address climate change. However, the policy measures he proposed to put the state on a path to 100% carbon-free electricity by 2050 will likely meet the same fate as his 2019 climate agenda, which was cut out of the budget by the Republican-controlled legislature.

Evers joined the U.S. Climate Alliance of governors pledging to support the carbon reduction goals of the Paris climate accord shortly after taking office in 2019. He narrowly defeated Republican Gov. Scott Walker, ending an eight-year administration which rarely mentioned “climate change” except to deny its existence.

“We made a commitment to make Wisconsin 100% carbon-free by 2050, and we’re going to keep it,” Evers said in his budget address Feb. 16. “Our utility partners have made great strides this year toward reducing emissions, but we still have a long way to go. … It is critical that we take necessary and immediate steps to address energy production and efficiency.”

Wisconsin Climate Agenda — Wisconsin Gov. Tony Evers, shown giving his budget address, is attempting to make progress on his climate agenda despite Republican opposition. | *Gov. Tony Evers*

The commitment to a carbon-free future was stripped from the governor’s proposed 2019-2021 state budget by the Republican leadership of the Joint Finance Committee. Also nixed was the creation of an Office of Sustainability and Clean Energy within the Department of Administration.

And Evers’ chances don’t look much better this year. Republican Assembly Speaker Robin Vos dismissed his climate agenda and other budget proposals as “nothing more than a liberal Democrat from Madison’s wish list to his donors.” The budget must be approved by July 1.

Evers has attempted to advance his agenda through executive actions, such as an Oct. 2019 executive order creating the Governor’s Task Force on Climate Change.

After a series of public meetings, the 32-member task force, chaired by Lt. Gov. Mandela Barnes, issued a 120-page report in December offering 55 recommendations related to energy, transportation, agriculture, education, forestry, food, jobs and environmental justice.

All but 10 of the proposals would require legislative approval or inclusion in the state budget.

“We’re excited about Gov. Evers’ budget proposal. It has a lot of really ambitious agenda items that reflect what people have been asking for,” said Heather Allen, executive director of RENEW Wisconsin, a nonprofit promoter of renewable energy. “There are areas of compromise that recognize the economic benefits of renewable energy for the state.”

Allen said there is support across the aisle for some aspects of the governor’s climate change agenda — such as funding for job training in the fields of renewable energy and energy efficiency through the Wisconsin Fast Forward grant program.

“We need to increase the number of Wisconsinites trained in those jobs,” she said. “We’re optimistic there’s bipartisan support for this.”

Allen is also hopeful Evers will win support for his proposal to double utility companies’ funding of the Focus on Energy program, which has been frozen since 2010. Doubling the funding from 1.2% to 2.4% of annual operating revenues would generate an additional $100 million for energy programs for low-income residents and investments in renewable energy.

“This program is actually where Wisconsin is a leader. Focus on Energy has proven very effective in funding energy efficiency and renewables,” Allen said. “We would love to see deeper investment there and an expansion of the program into new areas like electric vehicles and beneficial electrification. These are definitely things we think both parties can get behind.”

One recommendation not requiring legislative approval is having the state lead by example: committing agencies and buildings to switch to clean energy use. The University of Wisconsin-Platteville, for instance, won approval in early February to build a 2.4-MW solar array. The infrastructure could save the campus $200,000 annually after it is built later this year.

“More and more projects like that coming online through the governor’s leadership will demonstrate the value of renewable projects for the state just from the bottom-line perspective,” Allen said.

The governor also doesn’t need the legislature to endorse the carbon-reduction goals of the state’s utility companies. Alliant Energy, WEC Energy Group and Xcel Energy have all made public their significant plans to shift away from coal and gas for generating electricity over the next couple decades. Alliant is investing $900 million in clean energy production, including the purchase of several solar farms.

Another move Evers could make unilaterally is to compel the Public Service Commission to modernize and standardize the rates paid to customers who generate renewable energy — everyone from homeowners with rooftop solar panels to manufacturers and institutions which can independently produce several megawatts of clean energy. Many renewable energy generators are competitively disadvantaged by the current system that allows individual utilities to set rates that should be uniform across the state, RENEW says.

Evers’ budget includes the task force’s call for funding of a statewide climate risk assessment and resilience plan and technical assistance for municipalities and tribal communities to plan to be carbon-free by 2050. Evers would also fund a new Office of Environmental Justice with $200,000 over its first two years.

The governor’s wish list includes $100 million in bonds for energy conservation projects on state property, such as the University of Wisconsin System; $30 million spent on flood prevention measures and infrastructure; $10 million from the state’s portion of the Volkswagen emissions settlement to reinstate an electric vehicle charging station grant program; and $700,000 to replace aging state vehicles with electric ones.

“The climate crisis is taking an undeniable toll on folks across our state,” Evers said in his budget address. “Every Wisconsinite — whether they live in the Driftless, the Central Sands, or the Northwoods, or in the heart of our urban areas — has experienced the effects of climate change. And communities of color, low-income Wisconsinites, and our farmers have been among those most disproportionately affected.”