August-like weather that one weatherman called “categorically insane” has settled over Texas, leading to ERCOT calling on generators to postpone planned outages or return to service in advance of the heat.
Peak demand hit 70.6 GW late Monday afternoon, breaking Sunday’s short-lived record of 67.5 GW, as well as the previous peak demand mark for June. The previous high for May was set in 2018.
ERCOT’s all-time record for peak demand is 74.8 GW, set in August 2019. The Texas grid operator said last week that it expected to have sufficient generation to meet the above-normal demand from “unseasonably” hot weather.
The problem is that about 15 to 20 GW of thermal generation, approximately a third of the fleet, has been offline in recent days during what is normally maintenance outage season. Generators have until May 15 to complete their outages. Renewables have helped pick up the slack, providing nearly 30 GW of energy, or close to 45% of total generation.
ERCOT said in an emailed statement that it is “coordinating closely” with the Public Utility Commission, generation owners and transmission utilities to ensure “they are prepared for the extreme heat.”
“ERCOT will deploy all the tools available to us to manage the grid reliably,” a spokesperson said. “At this time, ERCOT projects there will be sufficient generation to meet this high demand for electricity.”
As demand approached another record peak for May on Monday, ERCOT had plenty of capacity in reserve. | ERCOT
The grid operator on May 3 issued an operating condition notice (OCN), its lowest-level communication in anticipation of a possible emergency condition. On Friday, ERCOT extended the OCN until Thursday because of forecasted temperatures above 94 degrees Fahrenheit in its North Central and South Central zones.
The National Weather Service said heat and humidity will result in heat indexes in the low 100s in the Houston area. Highs in the state are expected to stay in the 90s through the rest of the week.
Prices briefly hit $2,183 in the Houston area early Monday afternoon. At the same time, prices were as low as -$849 in nearby Calhoun County, where renewable generation was trapped behind transmission constraints.
ERCOT and the PUC have yet to issue press releases or use social media to urge conservation or warn about the unseasonable heat; nor has Texas Gov. Greg Abbott, who continues to focus his Twitter account on Operation Lone Star, his costly effort that he says is securing the southern border with Mexico.
However, the Texas Division of Energy Management tweeted about the excessive heat, urging Texans to “spend time in air conditioning.”
Stoic Energy President Doug Lewin attributed the high demand to a combination of extreme heat, poor energy efficiency and population growth: Texas’ 15.9% population growth rate between 2010 and 2020 was more than double the U.S.’ and will help the state hit 30 million residents this year, according to the U.S. Census Bureau.
“Texas gets 80% less energy reduction from efficiency than the ‘average’ state,” Lewin said. “This particularly hurts us in extreme temperatures.”
SAN DIEGO — The West’s potential to regionalize transmission planning and participate in organized markets occupied much of the discussion at the three-day meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body (CREPC-WIRAB) in San Diego last week.
A prime topic was FERC’s recent Notice of Proposed Rulemaking (NOPR) on transmission, which, if adopted, would require long-term regional transmission planning and increased state involvement in transmission cost allocation, among many other changes.
Western utility commissioners also discussed the work of the Joint Federal-State Task Force on Electric Transmission, convened by FERC and the National Association of Regulatory Utility Commissioners (NARUC) to spur transmission development as a means to deliver renewable power, reduce congestion and improve reliability. (The task force met virtually on Friday to discuss challenges related to clogged generator interconnection queues and cost allocation for transmission network upgrades.) (See FERC-State Task Force Considers Clustering and ‘Fast Track’ to Clear Queues and Task Force Seeks ‘Right Balance’ in Spreading Tx Upgrade Costs.)
Utah Public Service Commission Chair Thad LeVar told the audience of state regulators and others that two questions guide his work on the task force.
“The first question is, ‘Will any specific proposal or rulemaking either encourage or chill development of regional transmission coordination in the West?’” LeVar said. The second question is whether any proposal will fail to “respect and recognize the diverse carbon policies” of Western states, he said.
“To me, those are the two most important things because everybody agrees we need to move toward more regional transmission coordination … but we need to do that in a way that respects and recognizes” state policies, he said.
Those policies range from California’s drive to supply retail customers with 100% clean energy by 2045 to the plans of states of the interior West to continue relying on a mix of renewable energy and fossil fuels for the foreseeable future.
The uneasy relationship between more progressive and more conservative states in the West is likely to remain a sticking point to greater grid integration, stakeholders at the meeting said.
Even so, “there’s a lot of momentum toward regional coordination,” LeVar said.
Moves Toward Western Markets
The push toward Western coordination now extends to a major resource planning program and the possibility of participation in organized markets.
The Western Power Pool’s Western Resource Adequacy Program (WRAP), which WPP President Sarah Edmonds described in a presentation, is poised to be a West-wide effort to ensure reliable energy supply as coal plants retire and weather-dependent wind and solar resources proliferate during a time of climate change and extreme weather events. (See Western Power Pool Names New CEO.)
“This planning framework establishes a common planning reserve margin for the entire footprint … and it arrives at common counting rules across the entire footprint for the resources that we use,” Edmonds said on the meeting’s first day, May 2.
“The region has never had a West-wide view of what it needs to meet the needs of the future and how to count resources consistently across the footprint,” she said. “There’s a real value proposition in what we can do when we work together and … [leverage] our community as a whole.”
The WRAP, scheduled to enter a nonbinding phase later this year, has attracted participants in an area that stretches from British Columbia to Arizona and east to South Dakota. Stage 1 of the WRAP will include 26 participants that together represent a summer peak load of about 67,000 MW and a winter peak of more than 65,000 MW.
CAISO’s Western Energy Imbalance Market (WEIM), an interstate real-time trading platform, recently surpassed $2 billion in cumulative benefits for its participants since its founding in 2014. The WEIM has 17 members and is expected to grow to 22 participants by 2023, its benefits keeping pace with participation. (See Western EIM Tops $2B in Benefits.)
The ISO issued a straw proposal April 28 to add an extended day-ahead market (EDAM) to WEIM’s real-time market, potentially attracting even more of the Western market to its regional offerings. (See CAISO Issues EDAM Straw Proposal for the West.)
In addition, several Western entities have joined SPP’s Western Energy Imbalance Service and could eventually become members of SPP’s planned RTO West or its Markets+ program, which offers an array of RTO-like services but stops short of a full RTO.
A panel of stakeholders discussed the challenges of day-ahead market design on day two of the CREPC-WIRAB meeting.
“When you think about how unique a day-ahead market will be, especially in the West — where we have different [open access transmission tariffs] that we have to deal with, with regards to transmission utilization in the market, as well as potentially different resource adequacy programs — we have to think about how we create equity with those different constructs, and so that’ll be important as these designs continue to evolve,” Scott Kinney, director of power supply with Avista Corp., said.
Avista, based in Spokane, Wash., is a new participant in the WEIM and recently signed a letter with 14 other Western utilities saying it plans to support SPP’s efforts to develop a regional day-ahead energy market to evaluate against CAISO’s proposed day-ahead market. (See Western Utilities to Support SPP Market Development.)
A day-ahead market is “something that I think we should pursue as a region, but there’s no crisis behind it,” Kinney said. “So, let’s take the time to make sure that we fully flesh out all the options that are in front of us from a day-ahead market construct so that we can compare them equitably and make sure that they’re providing benefits to our customers.”
In the past year, FERC commissioners have urged the formation of one or more RTOs in the West, which remains balkanized with 38 separate balancing authority areas, while much of the rest of the nation is organized into RTOs or ISOs. (See Glick Says West Should ‘Finish the Job’ on RTO.)
In all the regionalization efforts, “the one area that hasn’t been tackled is transmission operation, transmission planning and transmission cost allocation,” LeVar said. The joint task force is intended to further regional transmission cooperation, he said.
FERC Transmission NOPR
FERC’s transmission NOPR (RM21-17) is separate from the work of the task force but shares its aims.
In one of its more controversial provisions, however, the NOPR would retreat from Order 1000’s effort to open transmission development to competition by giving incumbent transmission owners a federal right of first refusal (ROFR) on regional projects, provided they partner with an unaffiliated company with a “meaningful level of participation and investment” in the project.
The commission found in Order 1000 that federal ROFRs create “a barrier to entry,” discouraging nonincumbent transmission developers from proposing alternative solutions that could be more efficient or cost-effective. But the commission said it was changing course in its April 21 NOPR because it feared that Order 1000’s removal of the federal ROFR may be “inadvertently discouraging investment” in regional transmission.
Incumbent transmission providers “may be presented with perverse investment incentives” to instead engineer local transmission projects for which they retain development control, FERC said.
The NOPR troubles independent transmission developers.
Sharon Segner, senior vice president for transmission policy at developer LS Power, said the NOPR raised concerns about transmission competition in the Western Interconnection. She spoke as part of a panel on barriers to transmission development in the West, which largely focused on the NOPR’s pros and cons.
“As we look at the NOPR from a Western perspective, the first question that has to be asked is, ‘Does the rule usher in a cost-effective, clean energy transition?’” she said. “And while there are certainly areas of progress from a Western standpoint, in my company’s view we certainly see some yellow lights and red lights in terms of the proposals.”
Among the problems is that the NOPR “took meaningful steps backward on the notion of transmission competition across the country,” Segner said. “It’s a proposal that my company will rigorously object to.”
The proposal runs counter to President Biden’s July 2021 executive order aimed at promoting competition in the American economy,” she said. The order names FERC as a federal entity responsible for administering statutes protecting fair competition.
If an incumbent transmission provider has a partner, “then the competitive process could go away,” Segner said. “Having a partner in a transmission line does not necessarily mean that the consumers will have lower rates, and that doesn’t provide the benefits of a competitive process.”
“We don’t believe that FERC can substitute competition for cartels, and that’s essentially what we believe the end result of FERC’s proposal is — that if the transmission owner finds one partner then they have the ability to shut out competitive pressures and have the ability to stop competition,” she said.
Some panelists and audience members supported FERC’s goal of enhancing regional transmission planning to incorporate renewable resources.
“I was very pleased to see it,” Rob Gramlich, president of consulting firm Grid Strategies said.
An “open, transparent regional planning process,” will be more likely to get transmission built, Gramlich said. The NOPR could require planners to proactively examine the future resource mix and take a more holistic approach to balancing costs and benefits, he said.
Fred Heutte, senior policy associate with the Northwest Energy Coalition, said the co-optimization of new generation and transmission, rare in the West, is “implicit in where the NOPR is going.”
Gramlich agreed “that co-optimization is extremely important for consumers to save on generation costs and [to see an] overall delivered cost of generation plus transmission.”
A big question, he said, is who will coordinate those activities.
“I think the NOPR, first of all, requires a mindset shift” in the West toward regional generation and transmission planning, more like processes followed by Eastern RTOs and ISOs, Gramlich said.
“You can clearly envision a role for WECC and for [regional planners] WestConnect and Northern Tier [Transmission Group] and CAISO,” Gramlich said.
In January, CAISO published a first-of-its-kind 20-year transmission outlook intended to promote regional efforts to move renewable energy across the West. (See CAISO Sees $30B Need for Tx Development.)
“I don’t know exactly where the boundaries should fall, but I think that somebody needs to proactively [coordinate transmission planning], and I agree with Sharon [Segner] that, to some extent, this shouldn’t just be utility driven,” he said.
“I think there’s a lot of deference to just sort of taking what the individual utilities put together in this region … rather than an actual ‘let’s take the data and come up with an optimal configuration and then work with policymakers on an acceptable regional plan,’ Gramlich said. “I’d love to see a shift toward that latter framework.”
As Russian tanks and infantry massed on the border with Ukraine last year, U.S. government officials began reaching out to owners and operators of the nation’s critical infrastructure, including the electric grid.
Russia’s willingness to wage electronic warfare was well known, and any attack on Ukraine was sure to be accompanied by a cyber offensive that could easily spill across the borders and affect the country’s allies.
While nobody could be sure just what cyber capabilities Russia’s military had in reserve, the government’s hackers had attacked Ukraine’s power grid on multiple occasions; doing the same to the U.S. could cripple Russia’s strongest rival. Manny Cancel, CEO of the Electricity Information Sharing and Analysis Center (E-ISAC), told ERO Insider it took little effort for everyone to realize the shared vulnerability.
Manny Cancel, NERC | NERC
“One of the guiding principles that we all agreed to was sort of lowering the barrier for information-sharing on both sides of the fence, that the government needed to share information, and maybe declassify intelligence, as quickly as they could,” Cancel said. “And vice versa — it’s very important for the utility industry or the energy sector to share information back with the government to provide context [and] situational awareness.”
The result has been what Cancel called an “unprecedented level of engagement” between the government and private sector, both in the U.S. and Canada. Through both classified and unclassified briefings, as well as online alerts, public officials have made regular sharing of threat data a staple of the Cybersecurity and Infrastructure Security Agency’s Shields Up program; the E-ISAC has done its part by holding regular webinars open to the entire electric industry, not just its own members.
Cancel said a top priority has been including other critical infrastructure sectors, such as the telecommunications, finance and natural gas industries. This way all participants can benefit from each other’s work.
“The electricity sector has been operating with shields up for probably a decade — I can’t think of a day when we didn’t,” Cancel said. “But I still think the guidance was very relevant, just to sensitize people that this is really serious. We’ve got to up our game from a vigilance perspective [and] from an information-sharing perspective because that’s the only way we’re going to be able to protect and respond to a potential attack on critical infrastructure here in the United States.”
The response has also expanded beyond the U.S. and Canada, with officials in Europe reaching out to their counterparts in North America to discuss how to build a united front to the fighting in Ukraine. Cancel mentioned that NERC, the E-ISAC, and the U.S. Energy Association have had conversations with European regulators about their biannual GridEx security exercise, and how similar events could be staged in their countries.
However, he emphasized that while the E-ISAC actively works with European partners in “a number of forums,” U.S. officials are mindful that their role is collaborative rather than leading, and that every nation has its own challenges to deal with.
“There’s always an opportunity to share, not only … threat intelligence and information, but [also] risk mitigation activities and best practices,” Cancel said. “We do demonstrate a leadership role, but … our colleagues overseas … have some very robust risk mitigation programs and cyber programs.”
While Cancel praised the performance of the nation’s frontline cybersecurity defenders, he warned that utilities cannot let themselves become complacent. The current geopolitical tensions may have inspired the industry to its best efforts, but leaders must ensure their focus remains on proactive defense against any potential threats rather than returning to a compliance mentality.
“The minute you talk about standards, people generally — and I did this myself when I was at a utility — talk about, what do I need [in order] to comply, and what happens when I don’t comply?” Cancel said. “That conversation needs to change. I’m not saying you throw the compliance angle, [but] how can … industry and regulatory entities like NERC and FERC, and the rest of the federal government work to … better protect things.”
Higher operating costs tied to an increase in winter storms drove down Duke Energy’s first-quarter earnings despite an uptick in revenues from increased demand for both power and natural gas.
Duke on Monday reported first-quarter earnings of $1.08/share compared with first-quarter 2021 earnings of $1.25/share. Total revenues for the quarter were $7.1 billion, a 16% increase from $6.1 billion in the first three months of 2021.
The cost of coal ash cleanup in Indiana cost the company about $250 million. Severe winter storms in the Carolinas were the primary expense drivers. The storms alone reduced earnings per share by 7 cents, the company said.
Duke fielded crews of nearly 19,000 employees to restore power to more than 1 million customers after a series of winter storms, the highest number in eight years, swept through the region.
Duke Energy CEO Lynn Good | Duke Energy
CEO Lynn Good said despite the increase in expenses for storm restoration operations in the first quarter, the company is reaffirming its full-year earnings guidance range of $5.30 to $5.60/share, with a midpoint of $5.45.
“We’re also reaffirming our long-term EPS growth rate of 5 to 7% through 2026, at the midpoint of our original 2021 guidance range,” Good told analysts at the start of the company’s earnings call. “We’re monitoring economic trends and will take action if necessary as we continue to execute the important strategic work we have underway in the Carolinas, Indiana and Florida.”
Good said the company will file its long-term carbon-reduction emissions plan with the North Carolina Utilities Commission on May 16.
The plan, in accordance with legislation (H.B. 951) passed a year ago, will lay out how Duke will lower carbon emissions by 70% by 2030 compared to 2005 levels and achieve net-zero emissions by 2050. Once approved, the plan must be updated every two years.
“The plan will outline multiple portfolios to achieve the 70% carbon-reduction target, including proposals around timing of coal plant retirements and resource additions,” Good said.
“We expect substantial solar and battery additions, demand-side management and energy efficiency opportunities in every pathway. Onshore and offshore wind will be presented for consideration, as well as small modular nuclear reactors. Each portfolio has been rigorously tested for reliability and affordability for our customers.”
The company is planning to file a rate case in North Carolina, as permitted by H.B. 951.
Duke Energy provided investors with a summation of upcoming regulatory issues, including a long-term $7 billion “grid hardening” investment in Florida and up to 2,400 MW of new generation in Indiana. | Duke Energy
In Florida, Duke is committed to spending $7 billion over the next 10 years, including measures to harden the grid to resist storm damage.
And in Indiana, the company has proposed building 2,400 MW of new generation, including 1,100 MW of renewables and 1,300 MW of “dispatchable generation,” including new gas turbine power plants and batteries, before it can close its remaining coal plants.
The California Air Resources Board is searching for a new chief executive following the announcement that current Executive Officer Richard Corey will retire at the end of June.
Corey has worked for the agency for 37 years and served as executive officer since 2013. In that role, Corey oversees a staff of about 1,700 employees and an annual budget of more than $2 billion.
The executive officer is appointed by the CARB board. The agency issued a recruitment announcement for the position last week.
During a ceremonial presentation at the end of CARB’s April 28 board meeting, Chair Liane Randolph detailed Corey’s accomplishments.
Corey joined CARB after receiving a bachelor’s degree in environmental toxicology in 1984 from the University of California, Davis. He later received an MBA from the same university.
By 1997, Corey was grants chief in CARB’s research division
When CARB adopted first-in-the-nation limits on tailpipe greenhouse gas emissions in 2004, Corey “played a key role in developing, communicating and defending staff’s findings on the need to address climate change and the economic impacts of the regulation,” Randolph said. “This set the course for CARB’s further initiatives on climate change.”
Later, as stationary source division chief, Corey oversaw the adoption and implementation of the agency’s low-carbon fuel standard. And as a deputy executive officer, he supervised CARB’s first cap-and-trade auction.
He was named executive officer in 2013, succeeding James Goldstene.
Board members expressed appreciation to Corey for his work ethic, thorough knowledge of the agency’s work and his availability to the board.
“You’re herding cats all the time,” board member Hector De La Torre said. “It’s really hard to do.”
De La Torre, who served in the California Assembly from 2004 to 2010, called Corey’s work with the state legislature “tremendous.” The board never had to worry that there would be “blowback” from lawmakers over something the executive officer said.
“That’s really, really important … to know that we’re not going to mistakenly get into fights with the legislature,” De La Torre said. “Because that can happen. There’s egos over there.”
Although Corey’s retirement is effective June 30, the April 28 board meeting is expected to be the last he attends as executive officer.
In its recruitment announcement, the agency said the ideal candidate to replace Corey would be an air quality and climate expert with “a commitment to clean air for all Californians and a focus on priority communities that are overburdened by air pollution.”
Salary for the Sacramento-based position is listed at $17,349 to $18,850 per month. The application deadline is May 24.
New Mexico has become the latest state to adopt California’s Advanced Clean Cars regulation, which sets tailpipe emission standards and requires automakers to supply a certain percentage of zero-emission vehicles in the state each year.
The New Mexico Environmental Improvement Board (EIB) and the Albuquerque-Bernalillo County Air Quality Control Board (AQCB) each approved the rule on Thursday, at the end of a two-day joint hearing.
The rule will apply to new light- and medium-duty passenger cars and trucks starting with model year 2026.
The decision came after proponents told the boards that finding an EV to buy at New Mexico car dealerships was difficult, if not impossible.
“Automakers will prioritize electric vehicles to the jurisdictions that require them,” said Kathy Harris, a clean vehicles and fuels advocate with the Natural Resources Defense Council (NRDC). “So having New Mexico adopt the Advanced Clean Cars standard will ensure that the types of clean vehicles that drivers want will be available to them.”
Tammy Fiebelkorn, an Albuquerque city councilor, said she drives an EV that she bought used. She said she bought the car out-of-state because she couldn’t find one in New Mexico.
Fiebelkorn said that when she went shopping for a new EV last year, she visited every car dealer in Albuquerque looking for one.
“There were none to be found,” she said. “Literally none.”
And when dealers were asked if they could order an EV, they either said “no” or that they couldn’t guarantee the car would be received in less than a year, Fiebelkorn said.
Growing List of States
New Mexico joins 17 other states that have adopted California’s Advanced Clean Cars regulation in whole or in part.
Under the federal Clean Air Act, states have an option to follow federal vehicle emission standards or to adopt California’s more ambitious standards.
California’s Advanced Clean Cars regulation has two parts. A low-emission vehicle (LEV) program sets tailpipe emission standards, while the zero-emission vehicle (ZEV) program requires automakers to supply a certain number of EVs each year.
Sixteen states have adopted the LEV and ZEV components, while Delaware and Pennsylvania adopted the LEV program only, according to NRDC. The 18 states combined account for more than 40% of the U.S. vehicle market, the group said.
The ZEV program uses a system of ZEV credits, which are based on factors including the type of EV provided for sale and its all-electric range. The 22% ZEV credit requirement will work out to about 7% of new cars delivered for sale, according to written testimony on the rule from Claudia Borchert, climate change policy coordinator in the New Mexico Environment Department.
The current rate of ZEV sales in New Mexico is about 1% to 2%, Borchert said. By comparison, ZEVs accounted for more than 12% of California light-duty vehicle sales last year, according to the California Energy Commission.
Automakers will be able to earn early action credits for delivering ZEVs to New Mexico starting with model year 2023. And to further smooth the way to the 22% credit requirement, car manufacturers may receive a one-time credit for model year 2027, based on their ZEV credit balance in California for model year 2025.
Borchert described the one-time credit as the same compromise that environmental advocates and auto manufacturers reached during the clean car rulemaking in Nevada last year. (See Nev. Adopts Clean Cars Rule, Allows Early Credits.)
Although some stakeholders oppose the one-time credit because it could reduce the number of ZEVs delivered for sale, “this concern must be balanced against the need to provide a smooth, feasible ramp for manufacturer compliance,” Borchert said.
Agency Coordination
Last week’s joint hearing included the Albuquerque-Bernalillo County Air Quality Control Board, as well as the state EIB, because the city of Albuquerque has jurisdiction over its own air quality regulations. The two entities worked together on the clean cars rulemaking process.
Both boards unanimously approved the regulation on Thursday.
EIB Vice Chair Amanda Trujillo Davis noted the “overwhelming support” for the rule expressed during the hearing. In response to concerns about the fate of the lithium-ion batteries used in EVs, Trujillo Davis said she hoped New Mexico could become a leader in EV battery recycling.
EIB member Karen Garcia responded to comments from auto industry representatives who said EV adoption should be left to the free market.
“Sometimes the market needs a little push in the right direction,” Garcia said. “And I think this rule would provide that.”
The clean car rule is part of Gov. Michelle Lujan Grisham’s and Albuquerque Mayor Tim Keller’s efforts to reduce greenhouse gas emissions responsible for climate change, the city and state said in a joint release after the boards’ votes. In a 2019 executive order, Lujan Grisham directed the state to join the U.S. Climate Alliance and set a statewide GHG emissions reduction goal of at least 45% below 2005 levels by 2030.
The clean car rule will also help the city and state with their respective ozone attainment initiatives, the release said.
Concerns Expressed
Not all stakeholders supported the Advanced Clean Cars rule.
Benjamin Segovia, regional director for the New Mexico Farm and Livestock Bureau, said the group supports incentive-based approaches to clean vehicle adoption rather than mandates.
New Mexico is “vastly different” from California, he said.
“A California standard is not the right fit for a poor state like New Mexico, where many struggle to find affordable means of transportation,” Segovia said.
In her written testimony, Borchert responded to other concerns about the clean car regulations.
One concern is that New Mexico’s EV charging infrastructure is not adequate to support the rule’s ZEV requirement. Borchert said about 80% of EV owners charge their vehicle at home.
As of April, New Mexico had 180 charging stations with 437 ports, and more charging stations are on the way, she said. About 115 EV charging stations are being funded by $4.6 million in Volkswagen settlement funds. And the state will have additional money for charging infrastructure from the American Rescue Plan Act and the Infrastructure Investment and Jobs Act.
Some car dealers in rural areas questioned whether automakers would send them EVs that they won’t be able to sell. Borchert said manufacturers are expected to send more ZEVs to dealers “with demonstrated consumer demand,” such as in urban areas.
Some commenters were concerned about the impact of increased EV adoption on the state’s road construction and maintenance fund.
The New Mexico Department of Transportation has been working with RUC-West, a group that researches and shares best practices on road usage charges, to study other ways to collect the road maintenance funds. Options include an additional annual registration fee for ZEVs or a road usage charge.
Exelon (NASDAQ:EXC) reported a positive first quarter to investors and analysts Monday, its first earnings report since it completed the separation of its former power generation and competitive energy business, Constellation Energy, in February.
Net income from continuing operations for the first quarter of 2022 decreased to $481 million ($0.49/share), compared to $525 million ($0.53/share) for the same period in 2021. Adjusted to exclude the costs of the Constellation separation, however, earnings increased to $634 million ($0.64/share) from $542 million ($0.55/share).
Company officials said the results reflected higher earnings from Commonwealth Edison, resulting from an increased rate base, and increased returns on equity for PECO Energy, Baltimore Gas and Electric and Pepco Holdings Inc.
Exelon CFO Joe Nigro said the earnings were “driven in part by the recovery of costs associated with ongoing infrastructure investments to improve reliability and resiliency, enhance service for our customers and prepare the grid for a clean energy future.” Exelon reaffirmed its full-year adjusted operating earnings guidance range of $2.18 to $2.32/share and a long-term operating earnings growth target of 6 to 8% through 2025.
“Our grid modernization investments, enabled by constructive regulatory relationships, continue to drive solid operational results and stable earnings across our utilities,” Nigro said.
CEO Chris Crane said the separation of Constellation “really unlocked significant value” for shareholders, with a total return of 76% through the time of the announced deal more than a year ago through mid-April of this year.
“The first quarter was a milestone for Exelon as we successfully completed our separation of the generation business and embarked on our path as the nation’s premier transmission and distribution utility company,” Crane said.
Electric Vehicle Initiative
Nigro spoke about the adoption of electric vehicles and Exelon’s strategy in helping in the transition to EVs, saying they are “unquestionably a key enabler for reducing emissions.”
Jurisdictions in which Exelon operates are targeting 4.2 million EVs on the road over the next 25 years, a twentyfold increase from the end of 2021, he said.
“As our states make this transition over the coming decades, Exelon is poised to support our customers through investments such as upgraded distribution circuitry, substations and ultimately transmission,” Nigro said. “Transforming the grid over this period to meet the increased standards required by EVs, along with other expanded and innovative uses of the grid, will require significant investment.”
COO Calvin Butler said Maryland wants 300,000 EVs on the road by 2025, while New Jersey wants 330,000 by 2025 and 2 million by 2035. Current Illinois law requires 1 million EVs by 2030, and Delaware is looking for 20% of its registered vehicles to be electric by 2025.
“That just goes to show you the opportunity,” Butler said. “And when you look at the infrastructure that is going to be required to meet that and all of our capital plan, we see the opportunity across the Exelon utilities. It’s all different but significant opportunity for us to be partners in building out that infrastructure and preparing the grid.”
Massachusetts Gov. Charlie Baker on Friday swore in Beth Card as the new Energy and Environmental Affairs secretary.
Card replaces Kathleen Theoharides, who announced her departure from the role at the end of April.
“Beth Card has a deep knowledge of environmental policy and a wealth of experience in leading climate resiliency efforts in state government, and we are glad to appoint her as Secretary,” Baker said in a statement.
Card joined the Baker administration last year as undersecretary of environmental policy and climate resilience. She worked previously as the director of environmental and regulatory affairs for the Massachusetts Water Resources Authority and at the Massachusetts Department of Environmental Protection as deputy commissioner for policy and planning and assistant commissioner, Bureau of Water Resources.
“The tireless efforts of Secretary Theoharides have resulted in the creation of critical climate change programs, investment in the commonwealth’s renewable energy portfolio, and the advancement of the administration’s decarbonization goals,” Card said.
Former Mass. EEA Secretary Kathleen Theoharides will join RWE Renewables in June as head of offshore development-east. | RWE Renewables
Theoharides oversaw initiatives in Massachusetts that led to the development of the first U.S. utility-scale offshore wind farm, new procurements for 3.6 GW of offshore wind energy and a statewide mandate to reach net-zero emissions by 2050.
On Thursday, RWE Renewables announced that Theoharides will join the company’s offshore wind team June 1 as head of offshore development-East.
“Katie has been a visionary for Massachusetts whilst driving the state’s clean energy ambitions and will further RWE’s … strategy to rapidly invest €50 billion in clean energy technologies,” said Sam Eaton, executive vice president of offshore wind development, RWE Renewables Americas.
Theoharides will be responsible for development activities along the East Coast, including RWE’s floating wind research array in the Gulf of Maine and the company’s lease area in the New York Bight with partners Diamond Offshore Wind and National Grid Ventures, respectively.
“I’m thrilled to be joining the RWE team to help accelerate the pace of offshore wind deployment in the U.S., and to create clean, renewable energy that will help us achieve our urgent climate goals,” Theoharides said.
The NY Green Bank is starting a $250 million Community Decarbonization Fund this year and increasing its own capitalization by nearly a third to address stakeholder requests for the state-owned bank to improve how it serves disadvantaged communities (DAC), feedback it detailed in a revised annual plan filed May 2 (13-M-0412).
The NY Green Bank in 2021 raised $300 million in private funds to increase its capitalization by nearly a third. | NYGB
The bank raised $300 million from private sources to leverage the nearly $1 billion in ratepayer funding that supported its existing commitments, namely to invest $150 million in affordable housing projects by 2025 and $100 million in building electrification and energy efficiency in disadvantaged communities by 2025.
New York’s Climate Leadership and Community Protection Act (CLCPA) requires that 35% to 40% of all state spending related to clean energy go to DACs, which the NY Green Bank calculates from its total investments planned through Dec. 31, 2025, the end of the current Clean Energy Fund term.
NY Green Bank requested from the Public Service Commission an extension from the original filing deadline in March to more fully gather stakeholder comment, which it summarized in this month’s amended annual report without identifying any commenters.
Noted Comment
Some stakeholders complained of “cumbersome and lengthy” project financing processes, while others noted the increased capital needed to meet state environmental goals across building typologies, including affordable multifamily housing, or to comply with New York City’s Local Law 97, under which most buildings over 25,000 square feet will be required to meet new energy efficiency and greenhouse gas emissions limits by 2024.
One environmental justice advocate involved in those discussions with the NY Green Bank, Clarke Gocker, director of policy and strategy for PUSH Buffalo, told NetZero Insider he is “guardedly optimistic” about the bank’s move toward greater focus on serving DACs.
“If the state’s going to meet its climate goals, there really has to be a sea-change and a revolution in how existing funds are mobilized, and there needs to be a dramatic scaling up of investment that comes first from the public sector,” Gocker said.
PUSH Buffalo is a member of NY ReNews and is on the steering committee, and it has “been calling in the past 18 months, in particular after the passage of the CLCPA, for massive investments to implement the climate law really in line with even [New York State Energy Research and Development Authority’s] own projections released last fall, which are on the order of $10 billion a year,” Gocker said.
The state’s Climate Action Council has estimated a minimum of $1 billion in annual grants and incentives will be required through 2050 to green the affordable housing market, which would require a quadrupling of current funding. The council’s Climate Justice Working Group is helping define DACs, with draft criteria encompassing 35% of the population and households in the state, and it is holding public hearings on the topic through June 30.
Specific census tracts and low-income individuals are included in the draft definition as DACs that bear negative public health burdens or as individuals earning less than 60% of the state median income or participate in assistance programs, regardless of where they live.
NY Green Bank also is committed through 2025 to provide $100 million in financing to help clean transportation businesses locate or expand in New York and up to $100 million toward port infrastructure projects.
Reasonable Terms
“A theme repeated by developers, lenders and community-based organizations related to a lack of capital available to support building decarbonization or ambitious energy efficiency,” the amended plan said. “Owners and operators of regulated multi-family affordable housing properties commented that their properties had no excess cashflow or balance sheet resources to cover the cost of energy-related building upgrades.”
In 2021, NY Green Bank launched two financing channels, which included a request for proposal (RFP) for financing high-performance affordable housing, and another on “mandatorily redeemable preferred equity for disadvantaged community lenders.”
Stakeholders urged the bank to consider replacing the broad pathway for building decarbonization with focused RFPs addressing predevelopment loans, incentive bridge loans and permanent debt, and to publish indicative terms to align with “off-the-shelf” products offered by other real estate project lenders. Specialty lenders, they said, do not necessarily need preferred equity infusion to facilitate the expansion of their lending activities.
Environmental justice advocates pointed out that community-owned solar projects offer greater energy bill savings than those available to subscribers of privately-owned ones, but that lending institutions lack interest in such small, complex projects, the bank said.
One perspective among environmental justice advocates was that NY Green Bank currently charges higher interest rates than the private sector lenders to low-income New Yorkers, Eddie Bautista, executive director of the New York City Environmental Justice Alliance and a member of the state’s Climate Justice Working Group, told NetZero Insider.
The state in 2013 chartered NY Green Bank, which operates as a division of NYSERDA, to work with the private sector to increase investments in the state’s clean energy markets.
SPP Takes AECI Dispute over Winter Storm Charges to FERC
SPP has filed a request with FERC that the commission take immediate action in a dispute between the grid operator and Associated Electric Cooperative Inc. (AECI).
The RTO filed its Section 207 request on April 20, asking FERC to assert its exclusive or primary jurisdiction and determine that it properly compensated AECI for emergency power provided during the February 2021 winter storm as it scrounged for power from its neighbors to meet demand.
It also asked the commission to find that:
the transactions in question are governed by SPP’s tariff;
AECI is entitled only to the compensation provided for under the tariff under federal law; and
the RTO correctly calculated payments and paid the cooperative all the compensation owed as an SPP market participant.
SPP requested the commission act expeditiously to preserve its exclusive jurisdiction over the issues in dispute. AECI has taken its complaint to the U.S. District Court for Western Missouri, where it filed in February (6:22cv3030).
AECI is seeking to recover $37.64 million from SPP for the emergency power it provided during the storm. That includes $29.4 million for the costs to provide the power and $8.24 million in day-ahead residual unit commitment (DARUC) make whole payments SPP has charged the cooperative.
AECI said it was obligated to reimburse the market for other resources that were committed during the emergency events, but did not itself receive any such payments for its resources. It said SPP has not reimbursed the cooperative for any of the make whole payments.
The organization’s representatives discussed the dispute several times last year and this year, SPP said. It said AECI did not follow all of the JOA’s dispute-resolution’s formal steps and that no mutual resolution was reached through the informal discussions.
SPP has filed a motion to dismiss the lawsuit. An RTO spokesperson said the grid operator is waiting on orders from FERC and the court and is unable to provide further comment.
MMU Releases Winter Market Report
Wind energy grabbed a 42% share of SPP’s generation mix during the winter, a 35.5% increase from the previous winter, according to the Market Monitoring Unit’s (MMU) quarterly State of the Market report.
The MMU said wind generation was the primary fuel type during the most recent winter, an increase from 31% the prior winter. Coal and natural gas thermal generation decreased between the two winters, from 38% to 33% and from 21% to 16%, respectively.
Other highlights from the report, which covered December 2021 to February 2022:
Day-ahead prices increased from an average of $18.18/MWh during the 2020 winter to $27.95/MWh in the most recent winter, a 54% increase. Real-time prices increased from an average of $16.93/MWh two years ago to $24.32/MWh in 2022, a 44% increase.
Average winter monthly outages and derates returned to normal after the 2021 winter storm, totaling 29,100 GWh.
Overall, real-time market congestion for intervals with breached flowgates increased to 82% of all intervals, a substantial increase from 2021 (59%) and 2020 (34%). Analysis indicates that over the last three winters, the percentage of intervals with breached market-to-market (M2M) flowgates has increased from 33% of all intervals to 82%, indicating M2M flowgates are a large factor in increased flowgate breaches.
Transmission congestion rights (TCR) funding during the winter came in at 84%, down from 98% the winter before. The MMU partially attributed the low funding levels to significant outages not found in the TCR model as underfunding worsened to $101 million, up $93 million from the previous year.
The 2021 frequently constrained area (FCA) study had similar congestion patterns as previous years, but with more frequent and higher congestion costs. The study identified the southwest Missouri and southeast Oklahoma areas to be added as FCAs.
The MMU will host a webinar to discuss the report on a to be determined date.
Competitive Tx Process Improvements
The Transmission Owner Selection Process Task Force is soliciting stakeholder feedback as it works to improve the RTO’s competitive transmission project selection process. The feedback is due this Wednesday.
SPP has conducted a similar process after each of the four competitive projects it has awarded. The most recent came last month when the grid operator’s board approved NextEra Energy Transmission Southwest’s selection to build a 48-mile, 345-kV transmission line in Oklahoma. (See SPP Board of Directors/Markets Committee Briefs: April 26, 2022.)
The task force is conducting its work even as FERC has backed off some of its Order 1000 requirements. The commission last month issued a transmission planning rules proposal that would offer incumbent TOs a federal right of first refusal on certain regional projects. (See ANALYSIS: FERC Giving up on Transmission Competition?)
As demand approached another record peak for May on Monday, ERCOT had plenty of capacity in reserve. | ERCOT
