FirstEnergy on Sunday released its top lawyer and chief ethics officer in the aftermath of the alleged $61 million bribery scheme resulting in the passage of Ohio House Bill 6.
Chief Legal Officer Robert Reffner and Chief Ethics Officer Ebony Yeboah-Amankwah “separated” from the company, according to a filing with the U.S. Securities and Exchange Commission.
Robert Reffner, chief legal officer (left), and Ebony Yeboah-Amankwah, chief ethics officer, “separated” from FirstEnergy on Nov. 8. | FirstEnergy
The moves came before a Monday announcement in which FirstEnergy pledged to achieve carbon neutrality by 2050. The company issued a climate position and strategy statement to go along with the announcement.
Acting CEO Steven Strah — who received a pay raise to $950,000 per year, according to the SEC filing — said FirstEnergy was dedicating itself to achieve ambitious environmental goals.
“We believe climate change is among the most important issues of our time,” Strah said. “We will help address this challenge by building a more climate-resilient energy system and supporting the transition to a carbon-neutral economy.”
Internal Moves
FirstEnergy did not provide a reason for the departures of Reffner and Yeboah-Amankwah. A company spokesperson said there would be no further comments on the leadership changes.
Reffner was appointed to his position in May when the company announced other major changes to its management, including Strah as president. Yeboah-Amankwah was also appointed to her position in the same round of changes, reporting to Reffner. (See Strah Named New President of FirstEnergy.)
FirstEnergy President Steven Strah | FirstEnergy
In a press release issued Oct. 29, FirstEnergy announced the termination of CEO Charles Jones, along with two other executives: Dennis Chack, senior vice president of product development, marketing and branding; and Michael Dowling, senior vice president of external affairs. Officials said an internal review related to “government investigations” determined the executives “violated certain FirstEnergy policies and its code of conduct.” (See FirstEnergy Fires Jones over Bribe Probe.)
FirstEnergy is alleged to have supported the election of former Ohio House Speaker Larry Householder (R) and his associates in a three-year scheme that resulted in the approval of zero-emission credits for the company’s money-losing Perry and Davis-Besse nuclear plants.
More Compensation
Also included in the new SEC filing was a salary of $75,000 a month for Director Christopher Pappas, who was named executive director of the board in the aftermath of the termination of Jones and the promotion of Strah. Pappas will receive three months advanced payment, the filing said.
Non-executive board Chairman Donald Misheff will be paid a cash stipend of $62,500 a month, with three months advanced payment.
And Leslie Turner, a former executive with The Hershey Co. who was named chair of a new subcommittee set to review FirstEnergy’s compliance programs, will receive $3,750 a quarter in her new role and a pro-rated amount of $2,500 for November and December, according to the filing.
In a second filing Monday, FirstEnergy told the SEC it cannot file its latest 10-Q on time because of the ongoing criminal investigations. The utility released financial results for the third quarter on Nov. 2. (See FirstEnergy Earnings Call Overshadowed by Probes.)
“In connection with the ongoing government investigations, the company’s re-evaluation of its controls framework, which could include identifying one or more material weaknesses, the company requires additional time to complete its quarterly review and closing procedures and to provide appropriate disclosure in the Form 10-Q,” FirstEnergy said.
Environmental Goals
Besides the management moves, FirstEnergy said it was busy moving forward with its carbon-neutrality plan. The company set an interim goal of a 30% reduction in greenhouse gas emissions within its direct operational control by 2030, based on 2019 levels, and full carbon neutrality by 2050.
FirstEnergy’s strategy calls for several environmental initiatives to reach the goals, including:
hardening transmission and distribution systems to reduce physical risks of climate change;
replacing conventional utility trucks with electric and hybrid vehicles;
preparing for a transition away from coal-fired power in West Virginia by 2050;
seeking approval next year to construct a solar generation source of at least 50 MW in West Virginia;
utilizing advanced technology to allow customers to manage their energy use; and
integrating carbon pricing into financial forecasting.
The company also plans on creating an executive steering committee partnering with the board and leadership for “oversight, accountability and risk mitigation for the climate policy.”
“Our ambitious new carbon goal and comprehensive climate strategy are fully aligned with our regulated business strategy and support our commitments to our customers, communities and investors, as well as environmental stewardship,” Strah said.
Without the blue wave forecast by some pollsters, the Biden administration will likely go for moderate, incremental change to federal energy policy rather than large, ambitious packages, National Association of Regulatory Utility Commissioners’ Energy Resources and the Environment (ERE) Committee heard on Tuesday.
“It’s really about the art of the possible, given the divided government at the national level, assuming Republicans hold the Senate,” said Emily Duncan, director of federal government relations for National Grid, who presented a brief post-election assessment for the committee.
Two runoff elections in Georgia scheduled for Jan. 5 will determine which party controls the Senate: If the two parties are tied, effective control would go to the Democrats, as Vice President-elect Kamala Harris would have the tie-breaking vote.
Democrats flipped two Senate seats (Arizona and Colorado), while Republicans flipped one (Alabama). Two runoff elections in Georgia on Jan. 5, both with GOP incumbents, will decide control of the chamber during the first two years of the Biden administration.
President-elect Joe Biden has said his top four priorities are the coronavirus, the economic recession, systemic racism and climate change.
“We could see the Democratic-controlled House put together packages on each of those issues; however, I think it’s highly unlikely that a Republican-controlled Senate would take any of those up,” Duncan said. “The real question is what is Majority Leader [Mitch] McConnell [R-Ky.] willing to negotiate with a President-elect Biden?” (See GOP Senate May Limit Biden Climate Ambitions.)
Path of Least Resistance
The new administration will likely pursue regulatory action under existing statutory authorities rather than legislative wins, Duncan said. Biden spent 40 years of his career in the Senate and knows the people and the rules, so “if there is going to be any bipartisanship, Biden is the one to get it done,” she said.
Emily Duncan, National Grid | NARUC
McConnell has called for a COVID relief package to be passed during the lame-duck session of Congress, and if that happens, there may not be another in the first 100 days of the new administration, she said.
“I think we will continue to see pressure at the federal level on energy items related to COVID, in particular federal efforts to implement moratoriums on utility shutoffs and disconnections,” Duncan said. “Obviously as an industry, we work very hard with you, our state regulators, on those issues and would prefer to keep that at the state level, so we’ll be following that closely.”
There also is the possibility for increased funding for the Low Income Home Energy Assistance Program, and technology R&D has always enjoyed bipartisan support, she said.
But there will also be increased conservative judicial scrutiny of any regulations that the administration issues, and a Republican Senate will moderate Biden’s cabinet nominations, and more moderate cabinet secretaries will likely moderate regulations that come out of those agencies, she said.
On FERC
President Trump last week replaced FERC Chairman Neil Chatterjee with fellow Republican Commissioner James Danly. (See Trump Names Danly FERC Chair.)
“We are hearing that [the] Senate Energy [and Natural Resources Committee] may vote as early as next week to advance the two FERC nominees,” Democrat Allison Clements and Republican Mark Christie, Duncan said. With Danly becoming chair, “it will be interesting to see what happens over the next two and a half months” at FERC.
Emily Duncan of National Grid on Nov. 10 presented an outlook on post-election federal energy policy to NARUC’s Energy Resources and the Environment Committee. | NARUC
Duncan said that Biden would very quickly move to name Commissioner Richard Glick as chairman, even though Democrats would remain in the minority if the full Senate confirms Clements and Christie.
While Danly has not been supportive of carbon pricing, there is even a question as to whether Glick would be supportive or choose another path, she said.
“However, as chairman, Glick will set the agenda and determine what items are voted on, so it will be interesting to see if the Senate moves to confirm the two commissioners and bring FERC to its full quorum,” she said. “Certainly most in the regulating community would like to see five commissioners at FERC, so we’re hopeful that that will happen.”
Under Glick, the commission is likely to revisit its policies on certifying new natural gas infrastructure projects and probably revise how it conducts environmental assessments under the National Environmental Policy Act, Duncan said.
Colorado Public Utilities Commission Chairman Jeffrey Ackermann, who also chairs the ERE Committee, asked how the Energy Department and EPA might differ under Biden.
Duncan listed an expanded definition of “Waters of the United States” under the Clean Water Act, “fuel economy standards for model years beyond what the original California waiver was for … new source performance standards on methane on private lands … [and] methane flaring controls on public lands as well.”
Nonetheless, with the federal government still divided, states will remain in the driver’s seat in terms of transitioning away from fossil fuels and toward renewable energy resources, she said.
As his path to re-election narrowed late Thursday, President Trump demoted FERC Chairman Neil Chatterjee, replacing him with fellow Republican James Danly.
Trump’s move — which came as his electoral leads in Georgia and Pennsylvania appeared at risk of evaporating as vote counting continued — could be just the first of a series of personnel changes the president has contemplated, according to The Washington Post, which reported that he was considering sacking infectious disease expert Anthony Fauci, FBI Director Christopher Wray and Defense Secretary Mark T. Esper. (On Monday, Trump announced via Twitter that he had fired Esper.)
Chatterjee likely became a target after joining with Democratic Commissioner Richard Glick on Oct. 15 in supporting a proposed policy statement inviting states to introduce carbon pricing in wholesale electricity markets to address climate change. (See FERC: Send Us Your Carbon Pricing Plans.) Trump’s action came a day after the president, who had promised to restore the coal industry, formally withdrew the U.S. from the Paris Agreement on climate change.
Chatterjee’s willingness to address climate policies got the attention of the Washington Examiner, which published an article describing him, “a Kentucky Republican, [who] used to be known as [Senate Majority Leader] Mitch McConnell’s coal guy, eager to advance President Trump’s pro-fossil fuel agenda” as “staking a claim as one of the government’s leading problem solvers on addressing climate change.”
The author of the Examiner article, Joshua Siegel, tweeted that the policy statement and Order 2222 — which directed RTOs and ISOs to make their markets accessible to distributed energy resource aggregations — “was a clear driver in this decision by the White House.”
Danly dissented on both issues.
In an interview with RTO Insider, Chatterjee said he was informed of the decision around 6 p.m. Thursday. He said was given no reason for the move and could only speculate that it had to do with his “promoting market-based solutions to climate change,” citing the commission’s policy statement on carbon pricing.
“Perhaps folks [at the White House] weren’t in favor of that, and I think that validates my independence,” he said.
Although he said he was given no earlier indication that the move was coming, Chatterjee said he was not surprised. “I knew I was taking a risk when I was pursued these policies.”
Chatterjee also confirmed to E&E News that he had refused to follow Trump’s executive order in September prohibiting diversity training at federal agencies.
Former FERC Chairman Neil Chatterjee photographed General Counsel James Danly (right) as he watched the Senate confirm him to be a commissioner March 12. | Neil Chatterjee
FERC announced Danly’s promotion in a statement at 9:05 p.m. Thursday night that provided no reason as to why Trump made the decision to switch chairs. Danly only became a commissioner in March after serving as general counsel since 2017.
Glick tweeted: “Although we haven’t always agreed, I know that Chairman Chatterjee arrived at his views honestly and independently. And I appreciate his willingness to ignore party affiliation and work with me on several key initiatives that will prove beneficial to this nation.”
Chatterjee served as chair August to December 2017 while Trump’s pick for chair, Kevin McIntyre, went through the Senate confirmation process. The president made Chatterjee chair again in October 2018 when McIntyre resigned from the position, ailing with brain cancer that would claim his life. (See McIntyre Steps Down; Chatterjee Named FERC Chair.)
In the statement and on Twitter, Chatterjee congratulated Danly on the promotion and said he was proud of his time as chair. “It’s been the honor of a lifetime to serve as the chairman of FERC alongside my colleagues and staff, who represent some of the most talented and hardworking professionals in the U.S. government,” he said.
Chatterjee also indicated he would complete his term, which ends at the end of June 2021. “Our work — my work — at the commission isn’t over. I look forward to working with my friend, Chairman Danly, as well as the next administration to continue to carry out our important mission.”
He posted a more emotional statement on his personal Facebook page early Saturday morning, saying that he didn’t “give a f@&! what people think of me. I will be judged by my grandchildren. And as of this moment I am confident that I will be able to look them in the eyes when they ask me where I stood on the most significant issues of this time and be proud.”
Though he told RTO Insider he was “at peace” with the move and sounded upbeat, he admitted on Facebook that “it’s been a difficult few days. I have dedicated almost the entirety of my professional career to public service. I am a deeply flawed person. I know for certain I have not always made the right decision. But I can honestly say that I tried to get it right to the best of my limited abilities.”
“It has been my utmost pleasure to have served under Neil Chatterjee, both as general counsel and alongside him as commissioner,” Danly said via FERC’s statement. “I have learned a tremendous amount from his expertise and insight, and I am proud of the work we’ve been able to accomplish under his thoughtful watch.
“Neil has truly left his mark on FERC and the energy sector by brokering a significant agreement allowing us to move forward with liquefied natural gas terminals, which helped secure our American energy independence,” he added. “He also made a lasting impact through his commitment to protecting competitive markets, modernizing our policies under [the Public Utility Regulatory Policies Act], expediting the approvals of much needed critical energy infrastructure and so much more. I thank Neil for his leadership, and I look forward to continuing to work with him in this new role.”
Up in the Air
The president cannot fire members of FERC without cause, but he can name any sitting member that is also a member of his party as the chair. Given former Vice President Joe Biden’s election as president Saturday, Danly’s time as chair will be limited to little more than two months.
Biden and Senate Democrats will also have control over three of FERC’s five commission seats once Chatterjee’s term expires. Though Biden will ultimately be able to nominate at least four commissioners during his term, only three of them may be Democrats.
In July, Trump nominated Democrat Allison Clements, energy policy adviser for the Energy Foundation, and Republican Mark Christie, chair of the Virginia State Corporation Commission, to fill FERC’s two current vacancies. (See FERC Nominees Bob and Weave Through Senate Hearing.)
ClearView Energy Partners noted that “it is customary but not required that a chairman appointed by an outgoing administration to tender his resignation to allow a new president to fill the seat and change the majority.” It is unclear at this point whether the Senate will vote on Clements’ and Christie’s nominations during Trump’s lame duck period. If it doesn’t, Biden will be able to nominate two Democrats to fill the vacancies.
While Chatterjee has said he intends to complete his term, Danly’s intentions are unknown. His term ends June 30, 2023.
“We don’t have anything on that right now,” Mercedes Kearney, Danly’s executive coordinator, said Friday when asked whether Danly would give up his seat if Biden wins. “So much is going on right now.”
Benefits for participants in CAISO’s Western Energy Imbalance Market surged past $119 million in the third quarter of 2020 — a record amount driven by savings during the heat waves of August and September, the ISO told the EIM’s Governing Body on Wednesday.
“We saw a higher level of benefits in this quarter than we normally have seen because of those conditions and the resultant high prices, especially in the Southwest,” CAISO COO Mark Rothleder said.
EIM benefits topped a record high of $119 million in the third quarter. | CAISO
The benefits were mainly from savings; utilities paid less for electricity in EIM transfers than they would have otherwise paid during times of tight supply and soaring prices, the ISO reported.
Load-serving entities in the Southwest and California were pressed to meet high demand during the heat events in mid-August and over Labor Day weekend. CAISO ordered rolling blackouts for two days in August and barely avoided additional outages in September. (See CAISO Avoids Blackouts amid Brutal Heat, Fires.)
More than half the third-quarter benefits, $66 million, came in August.
The Western EIM has 11 active participants and 11 pending participants. | CAISO
Of the 11 active EIM participants, CAISO said it saved the most, reaping $23.7 million in benefits. Arizona Public Service was able to avoid $22.6 million in additional costs by procuring electricity through the EIM, and the Salt River Project, also in Arizona, saw $17.4 million in savings, CAISO reported.
“The quarterly benefits have grown over time as a result of the participation of new balancing authority areas in the market, which results in additional benefits for both the individual BAAs but also compounds the benefits to adjacent BAAs by enabling further transfers,” CAISO said in its third-quarter report.
The savings bring the EIM’s total benefits to $1.1 billion since it started operating in November 2014.
Current EIM entities also include NV Energy, PacifiCorp and Seattle City Light. Eleven more entities are scheduled to join in 2021 and 2022, including the Bonneville Power Administration, the Los Angeles Department of Power and Water, and Public Service Company of New Mexico.
ISO-NE CEO Gordon van Welie last week shared the RTO’s “vision for the future” with the NEPOOL Participants Committee, which he presented as “our long-term intent” that “guides the formulation of our strategic goals.”
The RTO included a forward-looking statement that van Welie said seeks “to harness the power of competition and advanced technologies to reliably plan and operate the grid as the region transitions to clean energy.”
Publication of ISO-NE’s vision comes on the heels of recent calls for reform by the New England States Committee on Electricity (NESCOE), which wants increased transparency from the RTO and a more prominent role in the decision-making process. (See States Demand ‘Central Role’ in ISO-NE Market Design.)
The RTO’s five “strategic goals” are responsive market designs; progress and innovation; operational excellence; stakeholder engagement; and attracting, developing and retaining talent.
When it comes to the first goal, van Welie said ISO-NE wants to improve the current market structure and continue to evolve and reposition its design to accommodate the states’ transition to high levels of renewable and distributed resources. The RTO also wants to maintain a robust fleet of balancing resources and preserve the market’s ability to attract new entry.
The progress and innovation goal includes a push to evolve capabilities to support the grid as the region transitions to clean energy. It also includes improving power system and market modeling and supporting investments in transmission infrastructure to enable renewable energy, as well as a call for integrating distributed energy resources and providing data and information-based services.
According to van Welie, stakeholder engagement requires collaboratively understanding and anticipating needs, thought leadership through high-quality analysis and communication, and nurturing productive relationships with FERC, the states and market participants.
Amended DDBT Passes
The committee voted to support an amended proposal from ISO-NE to recalculate the dynamic delist bid threshold (DDBT) for Forward Capacity Auction 16.
Calpine, NESCOE and Vistra’s Dynegy offered a combined amendment to the RTO’s proposal to lower the DDBT upper bound to 75% of the net cost of new entry (CONE) and set the DDBT at the RTO’s estimated clearing price plus a margin adder calculated using 75% of net CONE.
NESCOE said it remains concerned that the ISO-NE proposal does not balance design objectives and can result in the DDBT being set too high when capacity prices increase. The organization added that the risk of the DDBT being higher, especially as it approaches net CONE, could have cost implications for consumers.
Calpine and Dynegy said the RTO’s design interferes with competitive price formation, adds significant administrative burden and risks to existing suppliers, and creates an unnecessary barrier to market exit. The amendment allows a modest margin adder to low prices when supply curves are typically flat, with the adder diminishing as expected prices increase, which preserves at least some of the benefit of the DDBT.
Previously, NESCOE presented two amendments at the Markets Committee meeting in October. One would have lowered the upper bound to 85% of net CONE and add an upper bound set at 125% of the prior auction clearing price. The second would have limited the maximum rate of change in the DDBT from auction to auction to 30% of net CONE.
Calpine and Dynegy also presented amendments at the MC that would set the DDBT at ISO-NE’s estimated clearing price plus a scaled margin that starts 75 cents above the RTO’s estimated cost of $2/MWh, decreasing to $0/MWh at net CONE, or, as an alternative, from a fixed bid to a cap price.
At the RTO’s request, the committee considered, but did not approve, the unamended DDBT proposal. The vote failed to pass with none in favor and noted abstentions.
Pathways Process Continues
Frank Felder and Frank Wolak each made presentations on “Potential Pathways to the Future Grid,” with Felder returning for “Focus on Energy Only Market and Alternative Resource Adequacy Constructs” and Wolak discussing “Long-Term Resource Adequacy with Significant Intermittent Renewables.”
Felder, a professor at Rutgers University and an expert in energy policy and electricity markets, told the committee that whether the minimum offer price rule (MOPR) applies to a forward clean energy market or integrated clean capacity market determines the potential for “double payment” for clean energy and price suppression. He said an energy-only market addresses the double payment issue and maintains a regional market, even more so with added carbon pricing. Additional changes to the ancillary services markets may be needed, however, to ensure sufficient balancing resources.
According to Felder, some alternative resource adequacy constructs could address the MOPR issue. He added that anticipated replacement of large generating resources throughout New England with new capacity with very different operating characteristics suggests the region will need to strongly consider changes to transmission planning and cost allocation to avoid costly investment decisions.
Wolak, a Stanford University economics professor and director of its program on energy and sustainable development, said that in a low-carbon world, the electricity supply sector would consist of more than 50% intermittent renewables.
Wolak said the growing share of renewables will also require investments in both grid-scale and distributed storage and active demand-side participation by customers with interval meters using dynamic retail electricity prices, in addition to automated distribution network monitoring and on-site load-shifting technologies. He added that market design should support business models that lead to efficient investments in those technologies.
Winter is Coming
In his report to the committee, ISO-NE COO Vamsi Chadalavada said that the energy market’s value was $193 million in October, down $14 million from revised September figures and $9 million from October 2019.
Chadalavada also delivered the winter outlook, including a 40% probability of above-normal temperatures for New England from December through February. There is also an equal chance for above- or below-average precipitation in the region.
In terms of winter capacity, Chadalavada said ISO-NE is projecting the lowest 50/50 operable capacity margin of 2,574 MW and a 90/10 capacity margin of 1,232 MW for the week beginning Jan. 2, 2021. The capacity outlook will be adjusted if there are extended periods of cold weather.
The 50/50 winter peak demand forecast of 20,166 MW is 310 MW lower than the 2019/20 forecast, while the 90/10 winter peak demand forecast of 20,806 MW is down by 367 MW.
Chadalavada added that unknown societal factors would likely continue to impact demand throughout the season. He said forecasting staff are continuously evaluating load trends and frequently retraining forecasting models.
The RTO also recently hosted a Generator Winter Readiness Seminar and distributed a survey to all regional generating resources. It said survey results will enhance its understanding of winter preparations across the region, temperature-specific limitations on real-time capabilities and specific protocols followed during extreme cold-weather events.
ISO-NE will continue to perform a weekly 21-day look-ahead of forecasted conditions, which provides an opportunity for generators to act in advance of an energy emergency. In addition to the Winter Generator Readiness Survey, the annual natural gas critical infrastructure survey process has been incorporated into Operating Procedure 21 before winter.
Other Action
The committee also acted on consent agenda items.
Without objection, the PC removed sunset of the forward reserve market (FRM) from the consent agenda following FERC’s Oct. 30 order rejecting the Energy Security Improvements (ESI) proposal on which the FRM sunset was contingent. (See FERC Rejects ESI Proposal from ISO-NE.)
The remainder of the consent agenda was approved with two abstentions and two oppositions because of concerns about the installed capacity requirement (ICR) and related values for Forward Capacity Auction 12’s three annual reconfiguration auctions (ARAs) set for 2021.
The PC approved net ICRs of 32,925 MW for ARA 3, 32,765 MW for ARA 2 and 32,980 MW for ARA 1. The HQICC value is 958 MW for ARA 3, with the amount rising to 969 MW for ARA 2 and down to 941 MW for ARA 1.
Research scientist Andy Satchwell of Lawrence Berkeley National Lab had a caveat for the audience at the beginning of his presentation last week on electric vehicle rate designs and utility programs.
“The questions about what rate design and utility programs will drive EV adoption are unanswered,” he told the National Association of Regulatory Utility Commissioners’ Annual Meeting and Education Conference. But as a researcher, this does not make him unhappy. “This is an emerging and dynamic — and therefore really exciting — topic,” he enthused.
Satchwell was joined by Patty Durand, CEO of the Smart Energy Consumer Collaborative, which has been asking consumers the same questions annually for more than seven years. “We have probably the longest longitudinal study of residential consumers in the nation,” she said.
Clockwise from top left: Andy Satchwell, Lawrence Berkeley National Lab; moderator Zeryai Hagos, New York Department of Public Service; and Patty Durand, Smart Energy Consumer Collaborative | NARUC
In a second panel, Chris Budzynski, director of utility policy for Exelon; Lydia Krefta, Pacific Gas and Electric’s manager of regulatory, compliance and pilots for clean energy transportation; and Kelli Newman, senior marketing analyst for Georgia Power, discussed their utilities’ EV programs.
Durand said her group uses customer segmentation as the “backbone” of its research, breaking residential consumers into four groups. The “most engaged” segments are the Green Innovators, who care about sustainability, and the Tech Savvy Proteges, who embrace the “cool” factor of new technology, Durand said.
Next comes the Movable Middle: “They care a little bit about sustainability; they care a little bit about technology. They’re probably not going to do anything unless there’s an incentive, a program, marketing — some kind of thing that hooks them and gets them engaged. They will engage with the right program and messaging.”
Last, Durand said, are the Energy Indifferent. “They’re probably not going to engage. They generally are not interested in anything to do with energy. … We recommend just leaving them alone and focusing on the majority of consumers who do care or would engage.”
Clockwise from top left: Kelli Newman, Georgia Power; moderator Jamie Barber, Georgia Public Service Commission; Lydia Krefta, Pacific Gas and Electric; and Chris Budzynski, Exelon | NARUC
While only 1% of consumers currently own an EV, about 16% report they are very interested in acquiring one, and 29% are somewhat interested, Durand said. The numbers are higher for Green Innovators (29% very interested, 33% somewhat interested) and Tech Savvy Proteges (25/37%).
The segments are reflected in consumers’ willingness to pay more for an EV: A 10% increase in cost reduces interest among Green Innovators by 4 percentage points — from 51% to 47%. Interest from Tech-savvy Proteges also drops by 4 percentage points, from 40% to 37%. Interest among the Movable Middle drops 3 points from 27% to 24%.
EV Rate Design
Awareness of EV-specific rates is “extremely low” between 5 and 6% of the whole population, with even 91% of Green Innovators unaware, Durand said.
“We asked consumers, ‘If you have an EV, are you on an [EV] rate plan or would you sign up for a rate plan?’ And most consumers either didn’t answer the question or said ‘no,’” she said. “So, these are really terrible numbers for those who want EVs to be more common [and] want beneficial electrification to include transportation.”
She added: “It’s an easy-to-overcome barrier. Education is one of the easiest things to do. But this does show a problem with residential consumer awareness.”
Satchwell said some states have adopted “advanced” rate designs, including the unbundling of service costs (e.g., energy, capacity and ancillary services); hourly or sub-hourly marginal prices (vs. average utility costs); and include feeder-level or more granular marginal prices (vs. rates applied regardless of grid-specific locations).
The major debate in designing EV rates is whether they should be based on demand charges or time-of-use (TOU) rates, he said. “Demand charges can impact public charging by penalizing fast chargers, but they may, arguably, better match cost causation depending on how they’re designed,” he said. “EV supporters believe time-of-use rates are better for customer economics and better reflect that hourly marginal value.”
There are also multiple flavors of TOU rates, with some utilities offering multiple rate periods with mid-peaks and some offering super off-peak periods with significant discounts. The latter “sometimes have been referred to as matinee pricing — the same way that theaters … used to try and fill seats during the middle of the day with a huge discount,” he said.
Utilities have multiple flavors of time-of-use rates, with some offering super off-peak periods or “matinee” pricing. | Lawrence Berkeley National Lab
Some utilities offer flat “all-you-can-charge” monthly fees, such as Austin Energy, which charges $30/month but prohibits charging during peak hours.
There are also differences in metering requirements for home EV chargers. For example, Georgia Power’s whole home rate applies to all household electricity usage, which eliminates the need for additional equipment or changes to data collection and billing systems. But it can be a disincentive to EV charging if the rate is tiered with inclining block rates.
In contrast, Austin Energy’s EV-only rate requires a separate sub-meter and dedicated circuit, adding costs, but can allow clearer cost-based price signals.
Rates for commercial customers — such as fleet owners and public charging stations — are more likely to include locational and temporal specificity. San Diego Gas & Electric’s Power Your Drive program charges customers based on the CAISO day-ahead market price, with an adder for the top 200 distribution feeder load hours.
San Diego Gas & Electric’s Power Your Drive program for commercial customers is based on the CAISO day-ahead market price, with an adder for top distribution feeders. | San Diego Gas & Electric
PG&E’s Business EV rate, which took effect Oct. 1, replaced demand charges with a monthly subscription charge, which the company said lowers charging costs by 40% on average. The subscription fee, based on whether consumption is above or below 100 kW, is combined with TOU rates.
PG&E also is seeking regulators’ approval for a pilot project using dynamic hourly rates for commercial customers, also based on CAISO day-ahead prices.
The company powers more than 303,000 EVs in its service territory and offers $800 rebates. EVs’ share of new vehicle sales in the territory peaked at 14% in 2018 before the federal Tesla tax rebate expired. It dropped to 12% in the first quarter of 2020 before falling to 6% in the second, when the coronavirus pandemic hit the state.
In Georgia, EVs’ share of new car sales peaked at 3% in 2015, when the state offered a $5,000 tax credit. After the credit expired, the share dropped to less than 0.5% but has neared 1.5% since mid-2019. “We’ve now started to see more organic growth, and we attribute this to the affordability of some Tesla models now,” Newman said. “People who got familiar and comfortable with EV driving back in 2015 are now starting to buy electric vehicles again.”
Georgia Power’s rates range from 1 cent/kWh for super off-peak charging (11 p.m.-7 a.m.), 7 cents for off-peak (which varies by month and weekdays vs. weekends) and 20 cents for on-peak (2-7 p.m. June through September). It said drivers that spend $170/month on gasoline would pay only $19/month in charging fees if they limited their charging to the super off-peak period.
Satchwell discussed how customers respond to EV rates, based on a review of 11 evaluation reports of offerings published between 2013 and 2020, most of them short-term pilots. Most of the pilots had at least a 2:1 peak-to-off-peak price ratio, with a small number having a ratio of 4:1 or greater. Not surprisingly, higher peak-to-off-peak ratios result in more off-peak charging, he said.
PVs and EVs
But customers who owned a PV system were significantly less responsive to prices than their non-PV counterparts, according to a review of an SDG&E residential EV rate pilot. “This maybe suggests that PV customers place a higher value on [selling PV electricity back to the grid] than the increased electric costs for EV charging,” he said. “Certainly, there’s more here to unpack.”
Durand said she was shocked by her group’s finding that 50% of those with rooftop solar also own an EV.
“The interest was very high,” she said. “If as a stakeholder, you’re interested in more EV purchasing or finding customers interested in EVs, pursuing the consumers who have solar … or having policies that help consumers get solar, is a way to accelerate the transition to EV ownership.”
Government, Utility Incentives
Satchwell said that although some utilities encourage adoption of EVs through small rebates in partnerships with car dealers, federal and state tax credits have been the primary financial incentive to reduce that upfront cost of EVs to customers.
Satchwell’s review of 30 proceedings in 19 states found that about 85% of capitalized utility costs are for EV charging infrastructure on the customer-side of the meter, which addresses “range anxiety” and allows customers to participate in retail and wholesale market opportunities to sell power back to the grid, where available.
Some utilities’ investments have been to modernize their distribution grid, which can provide benefits for all customers, not just EV owners, he added.
Georgia Power is offering business customers $500 rebates on Level 2 chargers on 240-V circuits for workplace and customer charging. It is offering residential customers $250 rebates on Level 2 chargers and offering builders $100 rebates for installing 240-V garage outlets in EV-ready homes.
Car Dealers’ Lackluster Support
Durand said car dealers could encourage EV sales by pointing out that while their purchase price is higher than gasoline vehicles, they are cheaper over the long-term due to lower maintenance and fuel costs.
Dealers “don’t know enough about [EVs]; I usually come in knowing more than they do,” she said. “They are underwhelming in their endorsement of an EV. The total cost of ownership (TCO) is something that consumers don’t understand. Utilities could work with dealers and have TCO stickers on the cars so that customers can browse the lot and see: ‘Oh, this costs a little more upfront but then by year two I’m really saving money. Or the stickers could include state and federal incentives, which consumers don’t understand or know much about.”
PJM stakeholders last week endorsed the RTO’s package of updates to real-time value (RTV) market rules that call for additional penalties for generation operators that abuse the rules.
The RTO’s package was endorsed with 73% support at last week’s Market Implementation Committee meeting. In a nonbinding poll, the package received 55% support over maintaining the status quo.
Laura Walter, senior lead economist for PJM, provided an update on the work completed during the MIC’s special sessions on the rules and reviewed the proposed packages from the solutions matrix.
The special sessions have been taking place since January, after stakeholders endorsed an issue charge at the Markets and Reliability Committee’s meeting in December. (See “Real-time Values,” PJM MRC Briefs: Dec. 19, 2019.) The problem statement said observations indicated RTVs were being used to consistently override unit-specific parameter limits or parameter-limited exceptions.
The original intent of RTVs was to provide a way for generation operators to communicate current operating capability to PJM if their resources could not meet their unit-specific parameter limits or exceptions, Walter said. Generators opting to use RTVs forfeit operating reserve credits and make-whole payments.
The PJM package would require that market participants repeatedly failing to reflect actual operating conditions in their submitted operating parameters could be referred to FERC for enforcement. A market participant would be required to enter a forced outage ticket into PJM’s Generator Availability Data System (eGADS) for the period of increased notification, start-up time and/or minimum downtime.
For the timeline of an RTV submittal, Walter said, the package would require that the requested time period not exceed one market day. She said that when an RTV is requested, it would be available for that one day; then the entire schedule would revert to the previous day’s values.
The package also calls for adding RTVs to the Tariff. Currently, RTVs are mentioned only in the manual, Walter said.
In a nonbinding poll conducted in August, 55% of stakeholders said they supported the PJM package, and 10% gave support for a package by the Independent Market Monitor, while 71% said they were satisfied with the status quo.
Details of the Monitor’s package were also presented. In a vote held after the PJM package, the Monitor’s only garnered 8% support.
The Monitor’s proposal included removing minimum run time from the list of eligible parameters with RTV submissions. It also said units that choose to run longer could self-schedule beyond the minimum run time, with PJM operator notification.
The proposal also would have aimed to prevent withholding by using longer minimum run times. Any penalties collected would have been allocated to daily real-time load.
The PJM package will now move on to the MRC in December for a first read.
Manual 11 Revisions Endorsed
Stakeholders unanimously endorsed updates to Manual 11 designed to increase transparency and conform to the current PJM process for calculating LMPs as part of the problem statement regarding five-minute dispatch and pricing.
Vijay Shah, senior engineer in real-time market operations for PJM, reviewed the proposed updates to Manual 11: Energy & Ancillary Services Market Operations. The changes include an added reference to the day-ahead and real-time sections in section 2.2: Definition of Locational Marginal Price and change “LMP verification” to “price verification” throughout section 2.10: Verification Procedure, as verification includes review of real-time and ancillary service prices.
In section 2.11: Price-Bounding Violations, language was updated to state that all interval prices will be posted, Shah said, and any intervals that do not pass an output consistency check will be indicated on PJM’s website. The section was not included in the first read of the changes at the MIC meeting in October.
Shah said the changes are not related to the five-minute dispatch and pricing short-term changes that were filed with FERC in July. (See PJM Stakeholders OK 5-Minute Dispatch Proposal.)
Tacka said work on the issue first began last year in the former Distributed Energy Resources Subcommittee (DERS) and has continued into the new DER and Inverter-Based Resources Subcommittee (DIRS).
A microgrid is defined as a system of generating facilities and load that can operate both while connected to and off the main grid, Tacka said. PJM is looking to define a public distribution microgrid as a microgrid that contains a PJM generating facility that can generate while connected to and “islanded” from the broader grid and uses public utility distribution wires.
PJM’s public distribution microgrid concept | PJM
Tacka said a public distribution microgrid would not include any NERC bulk electric or transmission facilities. The electric distribution company will determine if the public distribution microgrid is wholesale or retail when islanded.
The Manual 11 language includes provisions for reflecting islanded conditions in a resource’s availability for energy and ancillary services, Tacka said, while Manual 18 language adds clarification for performance assessment interval treatment of public distribution microgrids serving as generation capacity resources.
The committee will be asked to endorse the manual changes at the MIC meeting in December.
UTC Uplift Changes
Ray Fernandez, manager of market settlements development for PJM, provided a first read of updates to Manual 28: Operating Agreement Accounting to conform with changes ordered by FERC regarding uplift charges on up-to-congestion (UTC) transactions (EL14-37).
In its order issued in July, FERC determined that PJM’s current uplift allocation rules are unjust, unreasonable and unduly preferential because they do not allocate uplift to UTCs. (See FERC Orders Uplift Charges on PJM UTCs.)
PJM was directed by the commission to submit a replacement rate that revises the RTO’s current uplift allocation rules to allocate uplift to UTCs “in a manner that treats a UTC, for uplift allocation purposes, as if the UTC were equivalent to a [decrement bid] at the sink point of the UTC.”
Fernandez said UTCs will now be allocated in both real-time and day-ahead uplift.
PJM is seeking stakeholder endorsement of the manual changes at the December MIC meeting.
PJM stakeholders last week unanimously endorsed proposed changes to the 2021 day-ahead scheduling reserve (DASR) requirement that saw small changes from last year.
David Kimmel, PJM senior engineer of performance compliance, reviewed the preliminary proposed changes at last week’s Operating Committee meeting, along with updates to Manual 13.
The DASR is the sum of the requirements for all zones within PJM and any additional reserves scheduled in response to a weather alert or other conservative operations. It is the sum of the three-year averages of both the under-forecasted load forecast error (LFE) and eDART forced outages.
DASR requirement components | PJM
Kimmel said the final 2021 DASR requirement is 4.74%, slightly lower than the 2020 requirement of 5.07%. He said the number comes from the LFE component of 2.16%, which is up 0.01% from last year, and the forced outage component of 2.59%, down 0.33% from last year.
The final 2021 DASR value will be incorporated into Manual 13 changes and be implemented in January.
Winter Weekly Reserve Target
The committee also unanimously endorsed changes to the 2020/21 winter weekly reserve target, which changed slightly from last year’s.
2020/21 winter weekly reserve targets | PJM
Patricio Rocha Garrido of PJM reviewed the results of the winter weekly reserve target analysis. The targets for December, January and February are 23%, 27% and 23%, respectively, compared to 22%, 28% and 24% last year.
“These increases and decreases are based on the load uncertainty we have in our most recent reserve requirement study case,” Rocha Garrido said. “However, the values are very close, so it doesn’t make much of an impact.”
Part of the reserve requirement study, the targets help staff coordinate planned generator maintenance scheduling and cover against uncertainties by ensuring that the loss-of-load expectation (LOLE) for winter is “practically zero,” Rocha Garrido said. For the entire year, PJM sets the LOLE at one occurrence in 10 years.
The winter weekly reserve target for each month is the highest weekly reserve percentage, Rocha Garrido said, rounded up to the next integer value.
Manual Endorsements
Stakeholders also unanimously endorsed several minor manual changes.
Lagy Mathew of PJM reviewed updates to Manual 3: Transmission Operations. Mathew said the changes featured minor clarifications, including defining extra-high voltage lines as those equal to or greater than 345 kV.
Kevin Hatch of PJM reviewed updates to Manual 12: Balancing Operations to address changes from the Market Implementation Committee’s special sessions on five-minute pricing and dispatch. Hatch said the RTO has been working with the Independent Market Monitor to identify sections of Manual 12 to be updated and to improve transparency on the dispatch process. Hatch said the changes include updated terminology for “day-ahead market” instead of the outdated “two-pass system.”
Texas regulators last week approved the election of Michigan Public Service Commissioner Sally Talberg and two others to three-year terms on ERCOT’s Board of Directors.
“I’m not trying to pick favorites, but I’m so excited to have Sally Talberg back,” Texas Public Utility Commission Chair DeAnn Walker said during the commission’s open meeting Thursday. “I’m glad to have her back in the ERCOT group.”
Walker said that Talberg approached her recently and asked her advice about joining the ERCOT board.
“I said absolutely,” Walker said. “I’m glad to have her back in the ERCOT group.”
Talberg advised the PUC from 2000 to 2004 during Texas’ transition to retail competition. Pat Wood III chaired the PUC at the time and would go on to also chair FERC under President George W. Bush. Judy Walsh, due to cycle off ERCOT’s board after this year, also served on the commission then.
While working on a master’s degree in public affairs from the University of Texas at Austin, Talberg also worked at the nearby Lower Colorado River Authority.
Talberg told RTO Insider she had expressed her interest in joining the ERCOT board some time ago, “initially thinking it would be some far-off prospect after serving on the MPSC.”
“But these spots were opening, so it happened earlier than I anticipated,” she said.
Talberg was first appointed to the PSC in 2013, serving as chairman from January 2016 to July 2020. Her term expires next July, but she has said she will step down from the commission once her appointment to the ERCOT board is official. (See “Michigan PSC’s Talberg Among Director Nominees,” ERCOT Board of Directors Briefs: June 9, 2020.)
The PUC also approved the elections of retired ISO-NE General Counsel Raymond Hepper and incumbent Director Terry Bulger to the ERCOT board. All three will serve as unaffiliated directors.
The board’s Nominating Committee has put forward former Consolidated Edison CEO Craig Ivey for the final vacant seat. Ivey will be presented to members during their virtual annual meeting in December.
D’Andrea Jumps the Gun
During the PUC’s open meetings, Walker typically opens discussion of a docket by saying she has written a memo with suggested changes. Commissioners Arthur D’Andrea and Shelly Botkin then usually express their agreement and approve the order.
The practice caught D’Andrea off-guard last week as Walker opened discussion of Oncor’s request for a limited code-of-conduct waiver from the commission’s affiliate reporting and affiliate transaction rules (50893).
Commissioner Arthur D’Andrea agrees with Chair DeAnn Walker’s nonexistent memo. | Texas PUC
“I agreed with your memo…” D’Andrea began.
“I didn’t have a memo. Arthur, why are you making it harder?” Walker responded, teasing D’Andrea. The few staffers in the socially distanced hearing room erupted in peals of laughter.
The commissioners agreed they had no concerns with the affiliate issue and approved the order.
Nuke Decommission Fund Remanded
The commission remanded back to docket management the Comanche Peak nuclear power plant’s requested review of its decommissioning cost study and funding analysis, finding that they do not include evidence required by Texas’ administrative code (50945).
Walker noted in a memo that the study and analysis were not accompanied by a report or supporting testimony and the requested annual funding amount; the decommissioning trust fund’s administrator did not demonstrate the funds are being invested prudently and in compliance with their investment guidelines; and the administrator did not demonstrate efforts to achieve “optimum tax efficiency.”
Comanche Peak Power Co. (CPPC) administers the decommissioning fund. It wants to continue the fund’s annual contribution of nearly $20.1 million through 2025, split between the plant’s two units on a 72.3/27.7% basis. The current approved allocation amount is on a 57.1/42.9% split.
The Comanche Peak Nuclear Power Plant’s two units | The Nuclear Decommissioning Collaborative
CPPC said the two units have a net after-tax value of $1.32 billion. It says according to a May decommissioning cost analysis, it will cost $1.73 billion in 2019 dollars to decommission and completely dismantle Comanche Peak. The analysis shows about a -2.5% difference between the $19.4 million required funding levels and the five-year average decommissioning-fund collections of $19.9 million annually from 2015 to 2019.
In other actions, the PUC:
authorized Southwestern Electric Power Co.’s (SWEPCO) and El Paso Electric’s (EPE) adjustments to their energy efficiency cost recovery factors. SWEPCO will be allowed to recover $5.2 million (50805) and EPE $5.9 million during the 2021 program year (50806).
allowed EPE and Entergy Texas to issue fuel refunds following settlement agreements. EPE will refund $9.4 million (50940) and Entergy $25.5 million (51037) to ratepayers.
Replacing the fossil-fueled energy supply with renewable energy requires unusual focus and substantial investment in the electricity sector. Our ability to meet these needs — elevated by climate change and the COVID-19 crisis — depends on the success of RTOs and ISOs. We at the Union of Concerned Scientists work to make these institutions more transparent, understood and responsive to science and democratically established laws.
The RTOs/ISOs evolved over decades and matured in the 1990s through a combination of electric utility industry and government regulatory desire for cooperation and efficiency. Coordination in the utility industry through competition and innovation becomes harder when the RTOs/ISOs ignore the public interest in further decarbonizing energy. The conflict between an energy market system that ignores external costs and a society and its policymakers that see the health and climate impacts of pollution from energy can’t be ignored.
These organizations have demonstrated they can deliver savings and integration of high levels of renewables.
Utilities are Different
The difference between RTOs/ISOs and better known trading platforms, such as Lyft, Uber, eBay and Amazon, is that the grid operators were established by existing monopolies. But those monopolies did not anticipate renewable energy growth driven by policy, economics or carbon limits. The influence of the incumbent players in making the rules is not found in the better known platforms. How much do the existing asset owners influence new energy technologies in the market? We can take a look at how open, transparent and interested in emissions these grid operators are.
We Have Work to Do
The RTOs/ISOs are at varied and different places on transparency and consideration of climate impacts. Broadly, the RTOs/ISOs provide regional coordination and sharing reserves through power pools that benefit consumers, allow competition and further cost savings and technology innovation. But how well does this structure, set up with advantages for the owners of existing power plants, serve to protect the climate and implement state carbon-reduction policies? When policymakers push the external costs of carbon and health into decisions that can lower carbon emissions, RTOs/ISOs should not counteract those policies and raise costs to consumers.
Transparent and Open?
Transparency builds trust. Stakeholders have to know how decisions are influenced. The public needs to know what decisions are being made.
How well members, stakeholders or even the public follow the decision-making depends in large part on the posting of meetings scheduled, agendas and the minutes of what was discussed. UCS was quick to support press access to NEPOOL when access was denied. But a wider look at the mere posting of meeting dates and agendas for the RTOs/ISOs’ governing boards differ sharply from one regional grid to the next.
In PJM, there is no schedule of board meetings available and no minutes, leaving stakeholders unsure of discussions or changes to items on which members had voted. The ISO-NE board’s meeting dates and bare agenda are available, but minutes are not. At NYISO, board meetings can be open to regulators upon request, and minutes and future dates are published. MISO mails out notices of board meetings, and even the committees of the board hold open meetings. SPP posts meeting notices and extensive minutes and materials. CAISO holds open meetings with video recordings posted on YouTube!
Carbon-aware?
The RTOs/ISOs operate in parallel (and lately in conflict) with state laws that regulate utilities and provide consumer protections, as well as with health and safety protections that address environmental externalities. The New England States Committee on Electricity’s recent vision for the grid connected the lack of transparency in stakeholder and ISO-NE board processes with the need for market reforms suited to “the New England states’ legal requirements, policy imperatives and associated consumer interests.”
New York state CO2 emissions by sector | NYISO, using U.S. EIA data
There is a wide range in how the RTOs/ISOs keep informed and share data about emissions from power plants. Ten to 15 years ago, some ISOs developed a report of average marginal emissions for the evaluation of pollution savings from state energy-efficiency programs. Today, climate change driven by accumulated greenhouse gas is a bigger concern. Reporting totals of emissions over a year and by month or season will help decision-makers facing a wider variety of options to change fossil fuel use and cumulative emissions.
NYISO established an Environmental Advisory Council in 2004 that provides it with reports that include average marginal emission rates from its generation, as well as the cumulative CO2 emissions in New York from all sectors (drawing data from the U.S. Energy Information Administration). PJM reports only the average marginal rate of emissions, released each spring, and it is impossible to determine if this report is shared with the RTO’s board because there is no transparency. ISO-NE has, since 1993, made a similar annual report of marginal rates of emissions, though with an 18-month delay from the end of the year. CAISO makes monthly reports of emissions. SPP makes none.
Changed Energy Mix
Reporting on the energy mix is another measure of improvement on climate-harming emissions. SPP does post data showing enormous use of wind energy. In the spring and fall, SPP’s energy supply mix is routinely as high as 50% wind. All the other RTOs/ISOs also display their current energy mixes on their websites. These kind of data on the resources meeting electricity demand are fundamental to the RTO/ISO function. Such displaying and archiving of energy data is a minimal level of transparency not found from utilities outside the RTOs/ISOs.
The accumulation of CO2 in the atmosphere comes from the cumulative emissions from combustion (and other biological sources). A decent comparison and metric for RTO/ISO boards to monitor would show total greenhouse gas emissions from power plant operations, along with the sort of data EIA provides on fuel-burning emissions in other sectors of the economy in their regions. That reporting would allow RTO/ISO boards to monitor changes as members and utilities pursue electrification and electricity replaces fossil fuel in building and transportation. RTO/ISO boards should receive a report annually on how the grids they manage are affecting the climate.
What We Need from RTOs
Regional cooperation to meet energy demand requires transparency and openness now, as the public, leaders and utility industry members meet the challenge of climate change and decarbonize energy. Leaders of all these organizations need metrics reflecting their own operations and markets, both for daily business and for addressing climate-damaging emissions of carbon and methane.
People in government need the informed cooperation of citizens and corporations to implement policy on climate. With all the decision-making ahead, the RTOs/ISOs are going to be key for people, their polices and utilities to work together in new ways to move off climate-damaging fuels.
The New England states are asking for change from their RTO. The Mid-Atlantic states are in court over their RTO’s objection to renewable energy policy. We have to decide: Are these organizations up to the task?
Mike Jacobs is a senior energy analyst for the Union of Concerned Scientists with expertise in electricity markets, transmission and renewables integration work.
