Reliability risks from the addition of variable resources to the Western grid will continue to grow, requiring greater planning reserve margins to mitigate the unpredictability of wind and solar generation, WECC said Wednesday in its third annual Western Assessment of Resource Adequacy.
Last year’s Western assessment showed a planning reserve margin indicator (PRMI) for the Western Interconnection of 16.9%. The 2023 PRMI increased to 18.3% in WECC’s latest assessment.
“Additional [variable energy resources] will cause the PRMI to increase further,” WECC said. “If nothing is done to mitigate the long-term risks within the Western Interconnection, by 2025 we anticipate severe risks to the reliability and security of the interconnection.”
Power producers plan to retire 26 GW of resources, mostly coal and natural gas plants, during the next decade and to add 80 GW of new resources, most of which will be solar and wind generation and battery storage.
“The resource mix in 2032 will look different than it does today, with much higher levels of variability,” the assessment said. “This is because resources like solar and wind are variable, meaning their energy output changes constantly and there is limited dispatchability.”
Severe weather events and rising temperatures add to the uncertainty, as do electrification, energy efficiency and emerging technologies, WECC said.
All “will affect how demand looks and behaves over the next decade,” it said. “This added uncertainty exacerbates the challenges facing planners and operators.”
WECC’s other measure of resource adequacy, its demand-at-risk indicator (DRI), showed fewer hours at risk of electricity shortfalls in the next few years. WECC measures DRI for every hour of the year for five subregions: California and Mexico, the Desert Southwest and three regions — central, northwest and northeast — of the Western Power Pool (shown as NWPP in the report).
“Compared to the 2021 assessment, the DRI for the Western Interconnection decreases through 2025 due in part to reductions in the load forecasts in the Pacific Northwest and northern Rocky Mountains, and in part to actions taken after the 2020 heat wave to strengthen resource adequacy,” it said.
“These actions include the addition of almost 3,000 MW of new or expedited resources, the vast majority of which is battery storage, and the delayed retirement of generator resources,” WECC said.
The delayed retirements included the 2,300-MW coal-fired Jim Bridger Power Plant in Wyoming, the 1,600-MW gas-fired Haynes Generating Station in Long Beach, Calif., and the 830-MW gas-fired Scattergood Generating Station in Los Angeles.
“Once these plants are retired, the risk returns and will need to be mitigated,” WECC said. “Delaying the retirements provides entities more time to determine how to mitigate the risks once these plants retire.”
After 2025, each WECC subregion shows an increase in DRI because of retirements in the next decade, the reliability organization said.
WECC introduced its Western RA assessment in 2020 to supplement NERC’s Long-Term Reliability Assessment because Western stakeholders were concerned that NERC’s analysis did not capture all the risks the Western Interconnection faces.
Like the NERC assessment, WECC’s Western assessment attempts to identify the biggest threats to the bulk power system over the next 10 years.
WECC has scheduled two webinars to discuss its findings, a high-level policy overview on Nov. 9 and a “deep-dive technical review” on Nov. 16.
WASHINGTON — The nuclear industry is out to change the conventional wisdom on building new nukes — specifically that such projects are always late, over budget and do not perform as expected.
The way forward, according to a panel of nuclear safety regulators at the International Atomic Energy Agency’s Ministerial Conference last week, will require harmonization of standards, international collaboration and a strong sense of urgency.
“Regulators are often perceived as barriers to efficient deployment of new-build [projects] and the adoption of new technologies and innovation,” said Mark Foy, chief executive and chief nuclear inspector of the UK Office for Nuclear Regulation. “I think it’s time for regulators to actually bust that myth.”
Rumina Velshi, Canadian Nuclear Safety Commission | IAEA
With the U.K. targeting 24 GW of new nuclear by 2050, “the future will see innovative technologies, innovative operating regimes and new organizational designs,” Foy said in his opening remarks as both panel moderator and participant. “As [regulators], we welcome these and are beginning to look at our approach and criteria for assessment and for licensing, and how they need to evolve in this new world.”
“A global industry will require global solutions,” he said, with alignment — or “harmonization” — of standards between countries a major topic of discussion within the industry.
Rumina Velshi, CEO of Canada’s Nuclear Safety Commission, agreed that as new technologies such as small modular reactors (SMRs) are rolled out, countries will need to develop a common framework that is technology-inclusive, performance-based and risk-informed. Achieving the scale and speed needed to meet climate goals will also mean short-term standardization of SMR design, Velshi said.
“SMRs will only work if we’ve got a reasonable number of technologies, not the more than 80 or 90 being considered,” she said. “Governments and industry [must] come together with a reasonable set of technologies … and standard designs that can deploy globally.”
Christopher T. Hanson, NRC | IAEA
While agreeing with Velshi on the need for whittling down the “plethora of new designs,” Christopher T. Hanson, chair of the U.S. Nuclear Regulatory Commission, argued for striking “a balance between harmonization and sovereign, national responsibilities. After all, each of us regulators will be regulating the reactors within our own borders and are responsible to our citizens.”
The NRC in August issued a design certification for the NuScale SMR to be built at the Idaho National Laboratory and is now reviewing the Kairos Hermes advanced reactor planned for Tennessee, Hanson said. He also stressed the need for “the continued and ongoing safe operation of the current fleet, overseen by strong, technically competent and independent regulators.”
Liisa Heikinheimo, deputy director general of Finland’s Ministry of Economic Affairs and Employment, also talked about the need for speed and flexibility in permitting processes as nuclear technologies continue to evolve.
Finland has set an aggressive goal of 2035 for carbon neutrality, Heikinheimo said, and SMRs will be needed “not only for electricity production but also to produce heat. This is a new feature, and it should be understood well from different angles. We need to build, most probably, units closer to cities and to be more flexible in operations to be compatible with renewables.”
Lisa Heikinheimo, Finland | IAEA
Representing the industry voice on the panel, Jay Wileman, CEO of GE Hitachi Nuclear Energy, also called for a new narrative for nuclear, saying that the industry must counter its late and over-budget profile. The only new reactors built in the U.S. in three decades, Georgia Power’s Vogtle plants, are years late, with an estimated cost of $30 billon, more than double the original cost estimate of $14 billion. The utility announced that one of the reactors started to load fuel in October and could begin operation in the first quarter of 2023.
Moving forward, the industry must be more competitive, Wileman said. “We have to come in with a design that’s at the right cost. To do that, you have to have a standard plant, a repeatable one that can be taken globally from one country to another, one regulatory overview to another, without redesigning every time.”
“You have to design to cost,” and deliver both on time and on performance, he said.
GE Hitachi is working with regulators in the U.S. and Canada on the permitting for its BWRX-300 SMR, which has been chosen for projects by TVA, Ontario Power Generation and SaskPower in Saskatchewan.
Clean, Firm, Dispatchable
The emerging international footprint for nuclear is now, at least within the industry, a given. According to multiple speakers at the IAEA conference, keeping climate change to 1.5 degrees Celsius and achieving worldwide carbon neutrality by 2050 will not be possible without the clean, firm, dispatchable power nuclear can provide.
The change in attitudes toward nuclear around the world “is palpable,” said Rafael Mariano Grossi, director general of the IAEA, in his opening remarks at the event on Wednesday. “Countries, important countries, at some point in their contemporary history thought nuclear energy would no longer be part of their energy mix, and we see countries reversing those decisions or decisively moving into nuclear because we have to be led by science, by economically feasible decisions and not by ideology.”
With nations in Africa and Latin America increasingly looking at nuclear, Grossi said, governments must “choose the right technologies, the right partners and provide the right framework for nuclear expansion.”
William D. Magwood IV, director general of the Nuclear Energy Agency of the Organization for Economic Cooperation and Development (OECD), said nuclear generation — both for electricity and process heat for heavy industry — will have to triple by 2050.
Announcements during and following the conference add to a growing narrative around nuclear as a core technology for energy security and economic development in the U.S. and worldwide.
Energy Secretary Jennifer Granholm closed the conference on Friday with an announcement that Poland had selected a U.S. bid from Westinghouse for the country’s first nuclear reactor. The decision, Granholm said, “sends a clear message to Russia that the Atlantic alliance stands together to diversify our energy supply to strengthen climate cooperation and resist Russian weaponization of energy.”
On Thursday, TerraPower, the advanced nuclear company founded by Bill Gates, and PacifiCorp announced their plans to explore deploying TerraPower’s Natrium advanced reactor to five sites in the utility’s service territory by 2035. The two companies are collaborating on the federally funded Natrium demonstration plant being planned for Kemmerer, Wyoming, at the site of a coal plant slated for closure.
The White House on Monday also announced a new clean energy partnership with the United Arab Emirates, with the “full-scale implementation” of civil nuclear technology called out as a key provision of the partnership framework.
‘High-quality Inputs’
While the U.S. continues to lead the world in nuclear power generation, China has moved into second place with 54 reactors currently in operation and another 22 under construction, according to the World Nuclear Association. As with other clean technologies, China has also developed a strong domestic supply chain, putting pressure on U.S. competitiveness in international markets.
Regulators at the IAEA conference faced questions about how long safety permitting should take and what companies and regulators need to do to keep projects on track.
Hanson said the length of the permitting cycle “depends on the quality of the input — if we have substantive pre-application engagement, if we get high-quality inputs. What does ‘high-quality inputs’ mean? It means show your work. Don’t just assert safety, show us; prove it in your application.”
Complexity and maturity of technology are other key factors, he said. One recent application, for a low-power reactor used to produce isotopes at a medical facility in Wisconsin, was reviewed in 24 months, Hanson said,
The NRC also recently released the draft environmental impact statement for the Kairos Hermes advanced reactor, 12 months after the project was first submitted. A final EIS is scheduled for the end of September 2023, according to the NRC website.
Velshi said Canada is also aiming for a 24-month turnaround for new advanced reactors.
At the same time, license extensions have become a major focus for U.S. and Canadian regulators, with projects in both countries looking to extend plant life to 60 or even 80 years. In the U.S., the NRC looks for “a rigorous and data-focused aging management plan … to ensure that as that plant proceeds into its longer life, it is doing so safety,” Hanson said.
The refurbishments needed for relicensing are often “massive projects that are probably equivalent to new-build projects,” Velshi said. The nuclear sector’s ability to deliver these projects on time and safely can provide “remarkable value in building confidence” for the public, investors and policy makers, she said.
Wileman agreed with the regulators on the need for high-quality applications, but he said, companies like GE Hitachi need “very good pre-submission discussions … really being able to go shoulder-to-shoulder and work the process collaboratively and make sure the dialogue is there; make sure everyone has a sense of urgency.”
“It’s important that the regulators and the industry understand the ambitions of one another and perhaps the challenges that each [faces],” Foy said. “But you can’t do it in isolation. You do have to come together and work on that end solution.”
PROVIDENCE, R.I. — ISO-NE’s Board of Directors had the rare experience of staring public criticism in the face on Tuesday as the grid operator held its first open board meeting at a Renaissance Hotel in downtown Providence, R.I.
A series of speakers offering public comments came up one by one, addressed the board and told them what they think ISO-NE is doing wrong.
Most of the roughly 15 commenters were there to push ISO-NE to transition more quickly off fossil fuels and take the climate crisis seriously.
The meeting came about as part of a set of governance changes the grid operator is making to appease the New England states, which have been pushing for it to become more transparent and accessible. (See ISO-NE Offers up Governance Tweaks)
One of the most attention-grabbing comments came from Kendra Ford, a Unitarian Universalist minister from Exeter, N.H., who walked to the microphone and looked into the eyes of each of the board members before speaking.
“We are in an emergency, and you are not acting like this is an emergency. We have to rearrange and reorganize the way we think about everything. Energy is at the leading edge of that,” Ford told the board.
“You have done some things, but you need to do so much more, and you need to do it immediately to save lives,” she said.
Later, as the board continued its largely standard business with an update from ISO-NE CEO Gordon van Welie, Ford stood up again and cut in.
“You’re describing a carefully measured, convenient transition that doesn’t inconvenience anyone and doesn’t cause anyone to lose money. That can no longer be the way,” she said. “I am begging you to respond to the emergency. It may not be affecting you personally in this moment, but it is coming to all of us.”
Another commenter, Jonas Kaplan-Bucciarelli, a Boston University student from Amherst, Mass., asked the board to walk a mile in his shoes.
“I think that you don’t understand the level of urgency and despair around the climate crisis, especially that my generation is experiencing as we’re growing up in this world, and grew up having climate change on the radar as we were going through middle school and elementary school,” he said.
Many of the commenters spoke out against the region’s minimum offer price rule, which ISO-NE is phasing out instead of immediately removing, to the frustration of climate advocates in the region.
They also took ISO-NE to task for a stakeholder process that’s widely seen as the least accessible of any grid operator in the country.
“It’s been a struggle to engage with you all,” said Amanda Nash, an activist with No Coal No Gas and 350 Massachusetts.
“You are all well trained and paid to create and administrate these procedures, but for the vast majority of us, this is work we do on top of our jobs and other responsibilities,” Nash said. “It seems like obfuscation is the name of the game.”
ISO-NE COO Vamsi Chadalavada offered a response to the commenters later in the meeting.
“The passion and urgency that we heard is unmistakable,” he said. “But I also wanted to offer some comfort that that’s the same level of urgency that all of us at the ISO feel in making sure we get through the clean energy transition.”
“I didn’t want to leave you with an impression that we are pro-fossil. … We are equally motivated to move towards the future,” Chadalavada said.
And he urged people to reach out to the ISO for information and to answer questions, technical or otherwise.
At the meeting, van Welie gave a presentation on the organization’s strategic plan, and the grid operator’s managers also updated the board on market projects, energy adequacy and winter planning. And MIT Energy Initiative director Robert Armstrong gave a presentation to the board on the future of energy storage.
Champlain Hudson Power Express said Tuesday it has closed on the financing needed to build its roughly $6 billion underground transmission line linking Quebec and New York City.
All major permits for the 340-mile U.S. portion of the 1,250-MW transmission line are in place, and construction will begin this fall in New York, CHPE said. Government permits for the 36-mile Canadian portion of the project are anticipated in summer 2023, and completion is projected in spring 2026.
Along with construction costs, the project price tag includes tens of millions of dollars for community benefit projects over the next several decades.
“The project financing announced today is an important step toward starting construction and beginning to realize the tremendous economic and environmental benefits this project will provide to residents, organizations and municipalities throughout the state,” Donald Jessome, CEO of TDI-USA Holdings, CHPE’s parent, said in a news release Tuesday. “We look forward to watching our community partners move forward with vital projects that will improve the communities they live and work in, and to soon begin delivering clean, renewable energy to New York City.”
CHPE has been in the works for more than a decade: It was first proposed in 2010, and it received approval from the New York Public Service Commission in 2013.
It is an important part of the state’s decarbonization strategy, as it will bring more than 1 GW of zero-emission hydroelectric power to a region that now relies heavily on fossil-generated electricity.
Dominion Energy (NYSE:D) on Friday filed a settlement agreement with the Virginia attorney general and other stakeholders that proposes an alternative to the performance requirement ordered by the State Corporation Commission (SCC) for the company’s $9.8 billion Coastal Virginia Offshore Wind (CVOW) project.
The group proposes to replace a 42% capacity performance guarantee, imposed by the SCC as a condition of its approval of the project, with a process through which the company explains any capacity shortfalls and the commission determines remedies. The company would be required to “provide a detailed explanation of the factors contributing to any deficiency” causing the project’s net capacity factor to fall below 42% on a three-year rolling average. The commission would then determine whether the shortfall “resulted from the unreasonable or imprudent actions of the company” and could impose a remedy addressing incremental energy or other costs.
Dominion CEO Robert Blue had called the performance mandate “untenable” and said it would require the company “to financially guarantee the weather, among other factors beyond its control, for the life of the project.” In an Aug. 22 petition for reconsideration, the company said it could be forced to terminate all development of the project if the requirement was not lifted. (See Dominion CEO: SCC Order for OSW Performance Guarantee ‘Untenable’.)
“Given the now significantly de-risked status of the project’s development, and given its continued ‘on-budget’ status, we feel that this settlement reflects a balanced sharing of financial impacts in what we currently see as unlikely scenarios of material delays or cost overruns,” Blue said in a statement on the agreement, which included the Sierra Club, Walmart (NYSE:WMT)
and environmental advocacy organization Appalachian Voices.
University of Virginia environmental law professor Cale Jaffe, who worked with Sierra on the settlement, said the proposed agreement addresses their concerns with the performance guarantee by leaving the door open to a precedent being set for fossil fuel generators being subject to the same requirements that offshore wind may be held to. He noted that Dominion’s Wise County coal plant has been operating well below its estimated capacity factor and has been steadily declining, leaving ratepayers with a large capital cost.
“We were very concerned about asymmetric treatment between new renewable energy … and older fossil fuel generation. … So one point we wanted to make sure was to raise concerns of any asymmetric treatment of renewable resources as compared to fossil,” he said.
The proposal would also avoid the possibility of making the project so onerous as to make development impossible, he said, which would come into conflict with the statutory demands of the Virginia Clean Economy Act, which is explicit in designating that CVOW is in the public interest.
The agreement, however, would not resolve Sierra’s original concern in the project: ensuring that the development considers the historically disadvantaged communities of Hampton Roads. Jaffe said the club will continue pushing for those interests to be included in Dominion’s economic plan, in the form of considering local and minority-owned businesses for hiring employees.
“There would be roughly 900 construction jobs, another 1,100 operation jobs … and we wanted to make sure diversity, equity, and inclusion was a part of that,” Jaffe said.
Agreement Includes ‘Unprecedented Consumer Protections’
In a statement on the filing, Attorney General Jason Miyares said the agreement includes “unprecedented consumer protections for Virginians” with cost sharing on project overruns and a cost cap on construction expenses.
“I am pleased that we have achieved consumer protections never seen before in modern Virginia history. For the first time, Dominion has significant skin in the game to ensure that the project is delivered on budget. Should the project run materially overbudget, it will come out of Dominion’s pocket, not consumers’,” Miyares said.
Under the proposed cost-sharing arrangement, customers would pay the first $500 million of costs above $9.8 billion, followed by an even split for the following $1 billion. Any costs above $11.3 billion will be paid entirely by Dominion; though if the project rises above $13.7 billion, it would go before the SCC to make a determination of viability and potential further cost allocation.
“This cost-sharing and cost-cap agreement means that Dominion will potentially have to pay almost $3 billion if the project runs over budget. Ensuring that the project remains on budget is crucial to ensuring it is also built on time,” Miyares said.
The agreement also states that Dominion “shall take all reasonable steps to ensure that customers receive the full and complete benefits of the Inflation Reduction Act of 2022” and not make any elections under the legislation that would reduce the benefit to customers. It also stipulates that if the completed project produces less than 2,587 MW, the cost-sharing schedule would also decrease on a per-megawatt prorated basis.
Dominion said work has continued to keep the project on schedule, which calls for construction to be complete in late 2026, and 90% of costs are expected to be fixed by the end of the first quarter of next year, up from 75% currently.
“The settlement agreement provides a balanced and reasonable approach that supports continued investment in CVOW to meet the commonwealth’s public policy and economic development priorities and the needs of Dominion Energy Virginia’s 2.7 million customers representing more than 5 million people and businesses,” the company said.
Appalachian Voices Virginia Policy Director Peter Anderson said the proposal creates an alternative to the SCC order for controlling the project’s construction risks and bringing down the presumption of reasonable costs ratepayers could be responsible for in the event of overruns. He also believes the agreement balances the interests of all the parties involved in the development, particularly by ensuring that the company bears some risk alongside customers.
“At this point it’s up to the commission as to whether they think it’s in the best interests of ratepayers,” he said.
California’s statewide greenhouse gas emissions dropped 8.7% in 2020, a “historic” decline that’s largely due to the impact of the COVID-19 pandemic, according to a new report.
The data are included in “California Greenhouse Gas Emissions for 2000 to 2020,” a greenhouse gas inventory released last week by the California Air Resources Board (CARB).
CARB said the drop in GHG emissions in 2020 was the largest percentage decrease in the more than two decades that the state has been tracking GHG emissions. Previously, the largest decline occurred between 2008 and 2009, when GHG emissions fell 6% during the Great Recession.
In 2019, the state’s GHG emissions fell 1.7%, following an increase of less than 1% in 2018. (SeeCalif. GHGs Decline 1.7% in 2019.)
The “historic plummet in emissions” in 2020 was due to the pandemic, according to CARB, which cautioned the public to view the results as an outlier.
“Economic recovery from the pandemic may result in emissions increases over the next few years,” CARB said in its report. “As such, the total 2020 reported emissions are likely an anomaly, and any near-term increases in annual emissions should be considered in the context of the pandemic.”
Transportation Emissions
California’s 2020 GHG emissions totaled 369.2 million metric tons (MMT) of CO2 equivalent (CO2e), 35.3 MMT less than 2019 levels.
When analyzed by sector, the largest decline was in transportation, which saw a 16% decrease in GHG emissions or a drop of 27 MMT of CO2e. Transportation remained the largest contributor to the state’s GHG inventory, accounting for 37% of the total.
CARB said the 16% decrease in transportation emissions was likely due to shelter-in-place orders issued in 2020 and an associated decrease in driving.
Other factors are the 18% growth during 2020 in the number of battery electric vehicles in the state and increases in fuel-efficiency of vehicles. In addition, heavy-duty trucks are using an increasing percentage of bio- and renewable diesel fuel, which accounted for 21% of diesel fuel sold in the state in 2020.
GHG emissions also decreased in the industrial sector, with a drop of 7 MMT of CO2e, or 9%. Decreased emissions from oil and gas production, as well as refining and hydrogen production, contributed to the sector’s results.
In the commercial and residential sector, GHG emissions fell by 1.7 MMT, which CARB attributed to a relatively warm winter and a slowdown in commercial activity due to the pandemic.
Electricity Sector
One sector that did not see a substantial drop in GHG emissions in 2020 was electricity, which remained near 2019 levels of about 60 MMT of CO2e. That’s 16% of the state’s total emissions.
GHG emissions from California’s electricity sector. | CARB
Emissions from in-state generation increased in 2020, CARB said, as more natural gas was used to make up for reduced availability of hydropower. But emissions from electricity imported from outside of California fell in 2020, as the state continued a trend of importing a greater share of low-GHG electricity.
In another likely impact of the pandemic, the state’s gross domestic product (GDP) fell by about 2.8% during 2020. But GHG emissions per GDP unit decreased in California that year by 6.1%, which CARB said “demonstrat[es] the effectiveness of California’s long-term climate programs to decarbonize industry, energy and transportation.”
The state’s GHG emissions per capita also fell in 2020, dropping to 9.3 metric tons of CO2e per person compared to 13.1 metric tons per person in 2006.
California Assembly Bill 32 of 2006 set a target of reducing the state’s GHG emissions to 1990 levels by 2020. The state previously reported meeting that goal four years early, in 2016. GHG emissions in 1990 were 431 MMT.
But while preparing the latest edition of the GHG inventory, CARB discovered and corrected a “data discrepancy” that affected past years’ figures, the agency said. The revised data show that the state hit the AB 32 target in 2014 rather than 2016, according to CARB.
California still must meet a more stringent target set by Senate Bill 32 of 2016. The bill requires a reduction of GHG emissions to 40% below 1990 levels by 2030.
In addition, a draft climate change scoping plan that CARB released this year sets a statewide goal of carbon-neutrality by 2045. (See Critics Tear into CARB Draft Climate Change Plan.) The agency expects to finalize the plan by the end of the year.
The clean energy industry experienced its slowest quarter in three years this summer, an industry group reported Wednesday.
The American Clean Power Association said the federal Inflation Reduction Act — passed in August — holds promise for future growth. But the industry was held back in the third quarter by supply chain constraints, trade and tariff issues, and uncertainty over tax policy.
Clean power projects totaling 14.2 GW capacity were delayed in the third quarter, and more than half of them had been delayed in the second quarter, as well. ACP said it is aware of 36.2 GW of delayed projects and 3.5 GW of terminated or canceled projects.
For the quarter, new utility-scale projects totaling 3.4 GW were installed, 22% less than in the third quarter of 2021.
Wind power installations were down 78% and solar down 23%. The exception was battery storage, which is having its best year on record.
JC Sandberg, interim CEO of ACP, said policy and regulatory issues continue to hamper growth.
“The solar market has faced repeated delays as companies struggle to obtain panels as a result of an opaque and slow-moving process at U.S. Customs and Border Protection,” Sandberg said in a news release. “Policy uncertainty around tax incentives constrained wind development, underscoring the near-term need for clear guidance from the Treasury Department so the industry can deliver on the promise of the IRA. Storage was the one bright spot for the industry and had its second-best quarter on record. The aggressive deployment of storage continues to drive down consumer energy costs and enhance grid reliability.”
Sandberg said the Inflation Reduction Act should be a major catalyst for the clean energy industry.
“ACP anticipates that the IRA will give industry the tools it needs to more than triple annual installations of wind, solar, and battery storage by the end of the decade. We expect the IRA to deliver 550 GW of new capacity by 2030, representing $600 billion in capital investment and growing the clean power workforce to nearly a million strong by 2030.”
Some highlights of the report:
Between July and September, 4.6 GW of clean energy projects entered advanced development and 2.5 GW began construction. In total, 93 GW was in advanced development and 39 GW was under construction by the end of the quarter.
Solar accounts for 63% of delays, wind 23% and battery storage 14%. Detained panel shipments are the biggest cause of delays for solar projects, and wind installations are most frequently hampered by supply chain disruptions and grid interconnection delays.
Power purchase agreements for green energy totaled 7.2 GW for the third quarter, and the wind and solar market-averaged national price index reached a new high: $45.93 per MWh, 10% more than the previous quarter and 34% higher than a year earlier.
Texas remains the leader in clean power, with 149.39 GW operational, 11.2 GW under construction, and 12.6 GW in advanced development, each metric the highest among the 50 states. Its third quarter installation total was 1.27 GW, second only to California’s 1.4 GW.
Xcel Energy said Monday that it intends to retire its Tolk Generating Station in West Texas four years ahead of schedule, clearing the way to exit coal usage by the end of 2030.
Xcel said winding down Tolk’s operations at its two units, with a combined capacity of 1,067 MW, early will save ratepayers more than $70 million. Tolk supplies parts of Texas and New Mexico with power. The plant faces a rapidly depleting supply of groundwater for its operations.
Xcel originally agreed to cut the operating life of Tolk from 2037 to 2032 in a 2020 stipulation over a rate increase with the New Mexico Public Regulation Commission. Under the agreement, Xcel also committed to studying at least one scenario where it would retire the plant before 2030. New Mexico has a goal to reach 100% carbon-free electricity by 2045.
The utility said it will soon file a revised retirement date with New Mexico regulators and put the plan to Texas regulators in February.
Xcel said it will continue flexible operations at Tolk, running the plant “when natural gas prices are high while managing limited remaining water resources.” It also said it will run Tolk’s currently installed synchronous condensers beyond 2028 to help ensure grid reliability.
The utility said it will substitute Tolk’s output with a “diverse mix of replacement generation, including wind and solar.”
“For more than 40 years, the dedicated employees at Tolk Generating Station have provided reliable and safe service to our Texas and New Mexico customers and communities,” said Adrian Rodriguez, president of Xcel Energy New Mexico and Texas. “While we maximize replacement generation in the region, we’re also committed to transition our employees into new roles as needed, something we’ve done successfully at other Xcel Energy plants.”
Xcel said Tolk’s accelerated retirement will help meet its goal to reduce carbon emissions 80% by 2030, when its Comanche 3 coal unit, its last coal burner is retired. The company plans to generate 100% carbon-free electricity by midcentury.
“As the first energy provider in the nation to set ambitious goals for addressing all the ways our customers use energy — electricity, heating and transportation — we are always striving to provide our customers cleaner energy resources, while saving them money,” Xcel Energy CEO Bob Frenzel said in a statement. “Advancing the retirement of coal operations at Tolk Station demonstrates our commitment to our clean energy strategy, while ensuring our customers and communities have reliable, affordable and safe service.”
MISO plans to spend $364.2 million throughout 2023, a 3.2% decrease from this year’s budget.
The RTO plans to spend $310.5 million in base operating expenses, $18.2 million in other operating expenses and $35.5 million in project investments, which include its ongoing effort to replace its market platform.
The Audit and Finance Committee of the MISO Board of Directors gave the preliminary budget unanimous support during a Tuesday teleconference. The full board will hold a vote on the proposed budget in early December.
The grid operator remains concerned about employee salary hikes it might have to institute. It intends to spend about $28 million in base operating expenses, a 10% increase over 2022 and said the increase is necessary to onboard more staff to safeguard reliability.
“A lot of these are intellectual efforts,” CFO Melissa Brown explained to board members. She said “wage pressures to attract the talent we need” remain a risk to staying within next year’s budget confines, noting “ripples” from upping salaries caused the most disruption to the 2022 budget. (See “High employee turnover concerns leadership,” MISO Board Week Briefs: Sept. 12-15, 2022.)
However, MISO said it can more than offset the additional spending with a 68% ($38.5 million) decrease in its other expenses category because of higher rates earning more interest income. Other operating expenses includes capital labor, capital interest and other income losses.
Brown said overall, the grid operator expects to collect a $0.44/MWh tariff rate from its members in 2023, lower than its $0.45/MWh rate in 2022.
Alliant Energy’s Mitch Myhre, who chairs the stakeholder-led Finance Subcommittee, said members are concerned over real-world pressures that could impact the 2023 budget. He said MISO could find itself spending $8 million more than expected if it continues to have difficulties maintaining its talent pool and called for staff to “actively manage” the situation.
“It is important that MISO is a judicious and conscientious steward of funds received from its members and remain vigilant against material budget increases or overages,” Myhre said.
Entergy will have to pay SERC Reliability $60,000 in penalties for violating NERC’s reliability standards, according to NERC’s Spreadsheet Notice of Penalty for September approved by FERC last week (NP22-32).
NERC submitted the Spreadsheet NOP on Sept. 29; in addition to the sanctions against Entergy, the document also details a settlement between ReliabilityFirst and American Electric Power (AEP) carrying no monetary penalty. The commission said on Friday that it would not further review the settlements, leaving the Entergy penalties intact.
Also approved on Friday was a separate settlement involving violations of NERC’s Critical Infrastructure Protection (CIP) standards (NP22-34) for which details have not been released in accordance with FERC’s policy on critical energy infrastructure information, along with a settlement between National Grid USA and the Northeast Power Coordinating Council (NP22-33). (See National Grid to Pay $512k for Standards Violations.)
Entergy Faulted for Maintenance, Ratings Mishaps
SERC’s settlement with Entergy concerns infringements of PRC-005-6 (Protection system, automatic reclosing, and sudden pressure relaying maintenance) and FAC-008-3 (Facility ratings). The entity self-reported both violations after discovering them in 2019, though they began in 2016 and 2017 respectively.
The relevant portion of PRC-005-6 lays out the schedule by which transmission owners, generator owners and distribution providers must maintain the equipment to which the standard applies. Entergy disclosed to SERC that it had missed the mandatory maintenance times on several components.
Among the facilities affected was the underfrequency panel at Entergy’s Turnerville substation near Plaquemine, La. Installed in 2010, the panel should have undergone maintenance on its protective relay within six years, according to the standard, but Entergy said that during an internal audit staff discovered this had not been done because the flag for the panel in its automated maintenance tracking system had been deactivated by an unidentified person.
Similarly, the utility failed to perform maintenance on batteries at the McAdams and Cleveland substations in Mississippi that was required within 18 months of their activation in June 2016 and June 2017, respectively. Again, in both cases the maintenance was skipped because the flag in Entergy’s automated system was disabled.
SERC attributed all three instances to “ineffective internal controls,” blaming Entergy for failing to “require approval for disabling maintenance tasks” in its substation work management system (SWMS). Following the discovery of the issues, Entergy performed an extent of condition review on the SWMS to find any other disabled maintenance flags that might develop into noncompliance; none were revealed. The regional entity said no harm is known to have occurred as a result of the violation.
Entergy’s FAC-008-3 violations were also discovered in 2019 but were unrelated to the PRC-005-6 violations. They concern requirement R6 of the standard, which requires that each TO and GO have facility ratings for their solely- and jointly-owned facilities that are “consistent with the associated facility ratings methodology.”
In August 2019, Entergy discovered an active alarm at its Hartburg substation in east Texas, caused by a failure of a cooling system. The failure had begun in March of that year, but operational personnel failed to schedule maintenance or to lower the rating of the substation — even though the cooling failure required a 20.5% derate.
Following this discovery, Entergy performed an extent of condition review to find any other conditions on the system requiring a temporary rerating. Five more were found; in each case personnel at the utility received alarms of the problems, but “the alarms were set as a low priority and personnel failed to update the facility ratings.” Entergy admitted it was “unaware as to why the alarms were originally set to low priority.”
According to SERC, the root cause of the issue was “inadequate training,” particularly on the part of the Entergy personnel that set alarm priorities, who had not been trained on the importance of the cooling systems and their role in facility ratings. This led other personnel to dismiss the alarms and focus on other tasks that seemed more important. Entergy responded to the issue by updating all alarms to the correct priority and establishing annual training to ensure staff are aware of the components that affect rating of transformers.
In both the PRC-005-6 and the FAC-008-3 violations SERC noted prior noncompliance history. The RE considered the PRC-005-6 history to be an aggravating factor in the penalty determination because the extent of condition review conducted in that case should have revealed the violations covered in this settlement. SERC said these issues also call into question the effectiveness of the mitigation plan of the previous violation, which focused heavily on the ability to disable maintenance flags in the SWMS.
ReliabilityFirst’s settlement with AEP (acting as an agent for several utilities including Appalachian Power Company, Ohio Power Company, Wheeling Power Company and others) concerns violations of COM-002-4 (Operating personnel communications protocols).
The entity reported to RF in October 2020 that it was in noncompliance with requirement R6 of the standard, which details the appropriate response to an operating instruction during an emergency. Specifically, utilities that receive oral two-party, person-to-person operating instructions during an emergency must either repeat the instruction and receive confirmation from the issuer that they understood it, or request that the issuer repeat the instruction.
According to the Spreadsheet NOP, two of AEP’s internal communications during a system event in 2019 were found to be noncompliant with the requirement because operators had “failed to execute three-part communication,” referring to the prescribed responses. RF identified the root case as “lack of process adherence and discipline,” and described the risk posed as moderate.
While the RE noted that failure to communicate properly increases the risk of failure to understand the instruction, it also acknowledged that these were the only two instances of improper communication out of 25 communications that occurred during the event.
RF said it processed the violation as a Spreadsheet NOP instead of a lower-level infraction in order to highlight the importance of proper communication procedure during an emergency. The RE pointed out that unclear communication “has contributed to significant events … that led to instability and cascading outages, including the 2003 Northeast Blackout and the Florida Blackout of 2008.” However, based on AEP’s self-reporting and cooperation in this incident, RF decided not to levy a monetary penalty for its infraction of the standard.
