The U.S. Department of Energy said Monday it will award Pacific Gas and Electric’s Diablo Canyon nuclear power plant $1.1 billion in first-round funding from the Civil Nuclear Credit Program, established last year to support the continued operation of nuclear plants at risk of closing for economic reasons.
Diablo Canyon, the last nuclear plant in California, had been scheduled to close in stages in 2024 and 2025, but this year the state deemed its 2.2 GW of baseline power essential for reliability as CAISO faces continuing summer shortfalls.
“This investment creates a path forward for a limited-term extension of the Diablo Canyon Power Plant to support reliability statewide and provide an onramp for more clean energy projects to come online,” Gov. Gavin Newsom said in a news release. “I thank the Biden-Harris Administration for this critical support.”
Newsom’s office had asked DOE in May to change the eligibility criteria for the Civil Nuclear Credit Program, or CNC, which was created last year as part of the $1.2 trillion Infrastructure Investment and Jobs Act.
The department said in April that CNC funding was only for nuclear plants that do not recover more than half their costs from ratepayers. PG&E recovers nearly all its Diablo Canyon costs from customers under rate cases approved by the California Public Utilities Commission.
Newsom’s office asked DOE to exclude the cost-of-service requirement to allow Diablo Canyon to qualify for the federal funds. The plant provides 8.5% of in-state generation, which will be needed as the state tries to switch to 100% clean energy by 2045, the governor’s office said.
The transition to renewables has exacerbated strained grid conditions in California. CAISO declared energy emergencies during heatwaves the past three summers, as solar power ramped down in the evenings, but air conditioning demand remained high. It said it could face similar shortfalls this summer and beyond.
On June 30, DOE announced it was making the changes requested by Newsom’s office “given the request’s potential applicability to reactors nationwide.”
“This change affects the eligibility of reactors who may apply in the first round of awards,” the department’s Office of Nuclear Energy said in a statement.
Newsom signed a budget trailer bill in June that allocated $75 million toward keeping the plant open, and in September he signed a bill granting PG&E a $1.4 billion forgivable loan to keep Diablo Canyon operating five years beyond its scheduled retirement. The measure, Senate Bill 846, told PG&E to seek federal funds to offset the loan and lower customer costs if Diablo Canyon’s license was renewed.
PG&E filed its application for federal funding on Sept. 2. On Oct. 31, the utility said it had formally applied to the Nuclear Regulatory Commission to renew the plant’s license and postpone its decommissioning.
The moves reversed courses for the state and PG&E.
The utility had been planning to shut down Diablo Canyon since 2016, when it signed an agreement with environmental, labor and anti-nuclear groups to close the plant on the state’s Central Coast rather than invest billions of dollars in environmental and safety upgrades.
On Monday, PG&E CEO Patti Poppe called DOE’s funding decision “another very positive step forward to extend the operating life of Diablo Canyon Power Plant to ensure electrical reliability for all Californians.”
“While there are key federal and state approvals remaining before us in this multiyear process, we remain focused on continuing to provide reliable, low-cost, carbon-free energy to the people of California, while safely operating one of the top performing plants in the country,” Poppe said in a news release.
The $1.1 billion in funding is conditional, PG&E said.
“Final award amounts will be determined following completion of each year of the award period, and amounts awarded will be based on actual costs,” it said in the news release.
Energy Secretary Jennifer Granholm said in a statement Monday that DOE’s Diablo Canyon funding decision was “a critical step toward ensuring that our domestic nuclear fleet will continue providing reliable and affordable power to Americans as the nation’s largest source of clean electricity. Nuclear energy will help us meet President Biden’s climate goals, and with these historic investments in clean energy, we can protect these facilities and the communities they serve.”
The California Air Resources Board last week approved $2.6 billion in incentives for clean cars and trucks, the agency’s largest budget yet for the incentive programs.
The budget includes $2.2 billion for clean trucks, buses and off-road equipment. Another $326 million will go toward incentives for the purchase of clean light-duty vehicles, and $55 million is earmarked for clean mobility projects, such as community shuttles and bike share programs.
Along with the funding package, the CARB board on Thursday approved several changes to the agency’s incentive programs, including the Clean Vehicle Rebate Project, Clean Cars for All, and the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project.
“These incentives provide important steps to accelerate the transformation of the transportation sector to zero tailpipe emissions, powered by the lowest carbon energy sources,” CARB Executive Officer Steven Cliff said.
Cliff said the incentive programs will complement CARB regulations. Advanced Clean Cars II, which the board approved in August, will require all new cars sold in the state to be zero-emission or plug-in hybrid by 2035. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)
And Advanced Clean Fleets, which the board is expected to adopt early next year, aims to achieve a zero-emission truck and bus fleet in California by 2045 where feasible and even sooner for vehicles such as last-mile delivery and drayage trucks.
CARB estimates that more than 70% of the $2.6 billion will benefit priority populations, including low-income neighborhoods and areas hit hard by air pollution.
“This is a really historic day,” said CARB board member Diane Takvorian. “The key thing is not the amount of money, although that’s awesome. It’s really because it pulls together so many of the priorities that CARB has been working so hard for, for so long.”
Light-duty Incentives
Electric car sales have grown substantially in California, hitting 1.3 million vehicles at the end of the third quarter of 2022. The EV market share was 17.7% during the first nine months of the year, according to the California Energy Commission’s ZEV dashboard.
But EV prices have skyrocketed, CARB said, averaging $63,821 at the end of 2021 compared to $47,000 for a gasoline-powered car.
“In addition to ongoing supply chain issues, inflation and rising interest rates have made both new and used vehicles more expensive,” CARB said.
As a result, car buyers — especially those with lower incomes — are having a hard time finding an electric vehicle they can afford, even with CARB’s incentives.
Under the Clean Vehicle Rebate Project (CVRP), rebates for low-income buyers will increase to $7,500 for a fuel cell car (FCEV) or a battery-electric vehicle (BEV), and $6,500 for a plug-in hybrid (PHEV). That compares to current low-income rebates of $7,000 for an FCEV, $4,500 for a BEV and $3,500 for a PHEV.
Car buyers with annual incomes exceeding 400% of the federal poverty level but below the CVRP income cap may be eligible for the program’s standard rebate: $4,500 for an FCEV, $2,000 for a BEV and $1,000 for a PHEV.
Rebates are also increasing in the Clean Cars for All (CC4A) program, which is for low-income drivers scrapping an old vehicle. Participants can receive up to $10,000 for a new or used BEV or FCEV, $9,500 for a plug-in hybrid, or $7,000 for a conventional hybrid. An additional $2,000 will be available for residents of disadvantaged communities who are buying a plug-in hybrid or zero-emission vehicle.
Current incentive amounts under CC4A are up to $9,500 for a new or used BEV, FCEV or PHEV.
Low-income buyers can stack the CVRP and CC4A rebates to receive as much as $19,500 in incentives. A low-interest financing program is also available to low-income drivers, as is a $2,000 prepaid card for public EV charging.
Plug-in hybrids will no longer be eligible for CVRP as of Jan. 1, 2025, and conventional hybrids will lose CC4A eligibility by November 2024.
CC4A is currently available in five of the state’s air districts, but a statewide expansion of the program is underway.
Heavy-duty Incentives
The Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP), which CARB considers “the cornerstone of advanced technology heavy-duty incentives,” will receive $1.8 billion in the 2022/23 funding plan.
Of that amount, $157 million is set aside for drayage trucks, $70 million for transit buses, $135 million for zero-emission public school buses, and $1.1 billion for school bus replacement grants to local agencies.
CARB had previously proposed limiting the HVIP incentive to fleets with 100 vehicles or fewer starting in 2023. But the agency decided to postpone the fleet-size restriction until 2024, when fleets with 50 vehicles or fewer will be eligible.
In another new restriction, fleets of more than 500 trucks are required to buy 30 zero-emission vehicles without the HVIP incentive before being eligible for HVIP funds.
“Large purchases of ZEVs encourage manufacturers to scale up their assembly lines and support economies of scale,” CARB said in its funding plan.
The CARB board heard from several members of the public who are opposed to the fleet-size limit for HVIP.
“Large fleets play a pivotal role in proving out new technologies and driving scale, while small fleets rely on purchasing these trucks from large fleets,” said Madison Vander Klay, a senior associate with the Silicon Valley Leadership Group (SVLG).
SVLG also opposes the bulk purchase requirement for fleets larger than 500 trucks, which Vander Klay called “unreasonable.”
CARB staff noted that if smaller fleets aren’t using up all the HVIP funding, money would be released for larger fleets.
HVIP incentives are based on the type of vehicle being purchased. For heavy-duty buses, for example, the incentive ranges from $85,000 to $240,000, depending on the model. Another change to the HVIP program will increase the base incentive for fleets of 10 vehicles or fewer and decrease the incentive for fleets larger than 100 vehicles.
In addition to HVIP, the CARB funding plan allocates money to other heavy-duty vehicle programs, including $273 million for the Clean Off-Road Equipment voucher program (CORE); $60 million for commercial harbor craft pilot projects; and $29 million for truck loan assistance for small businesses.
The Biden administration last week invited applications for more than $6 billion in funding to expand and modernize the U.S. electric grid, opening the first round of transmission loans and grants under the Infrastructure Investment and Jobs Act (IIJA).
The Grid Resilience Innovative Partnership (GRIP) and Transmission Facilitation Program represent the largest single direct federal investment in transmission and distribution, according to the Department of Energy.
All told, the administration plans to invest more than $20 billion under its Building a Better Grid Initiative, which seeks to identify national transmission needs to reach President Biden’s goal of 100% clean electricity by 2035 and a zero-emissions economy by 2050. DOE cited estimates that the U.S. needs to expand the grid by 60% by 2030 and may need to triple capacity by 2050 to decarbonize the economy. (See Industry Welcomes DOE’s Better Grid Initiative.)
GRIP
Under GRIP, DOE opened applications for $3.8 billion for fiscal years 2022 and 2023 to improve grid flexibility and resilience against extreme weather and climate change. The IIJA allocated $10.5 billion in total for:
Grid Resilience Utility and Industry Grants ($2.5 billion), to fund transmission and distribution technology solutions against wildfires, floods, hurricanes, extreme heat, extreme cold, storms and other hazards to the power system. Among those eligible to apply are “electric grid operators, storage operators, generators, transmission owners or operators, distribution providers and fuel suppliers.”
Smart Grid Grants ($3 billion), intended to increase the “flexibility, efficiency, reliability and resilience” of the power system, with particular focus on increasing transmission capacity, preventing faults that can cause wildfires and integrating renewable energy, electric vehicles and electrified buildings. DOE will accept applications from state and local governments, tribal nations, universities, and for-profit and nonprofit entities.
the Grid Innovation Program ($5 billion), which will provide financial assistance to states, tribes, local governments and public utility commissions to “collaborate with electric grid owners and operators to deploy projects that use innovative approaches to transmission, storage and distribution infrastructure” to improve resilience and reliability.
“DOE believes there are significant benefits to be realized by coordinating the implementation of the three [IIJA] programs focused on power sector infrastructure, grid reliability and resilience,” it said.
Applicants must submit “concept papers” for the Grid Resilience Utility and Industry Grants and Smart Grid Grants by Dec. 16, with concept papers for the Grid Innovation Program due Jan. 13, 2023. A public webinar to provide more information will be held on Nov. 29.
Transmission Facilitation Program
The Transmission Facilitation Program is a revolving fund to help attract private investments into large-scale new transmission, upgrades of existing transmission lines and microgrids.
The Biden administration is hoping to encourage more large-scale transmission like the 5,000-MW Greenlink West project, a 525-kV line that would run 350 miles from Las Vegas to Yerington, Nev. | NV Energy
The IIJA authorized DOE to borrow up to $2.5 billion to prime the pump for new transmission and expansions that otherwise would not get built.
DOE will purchase up to 50% of the capacity of such projects, serving as an anchor tenant to attract other customers. “By initially offering capacity contracts to late-stage projects, DOE will increase the confidence of additional investors and customers and reduce the risk of project developers under-building or under-sizing needed transmission capacity projects,” DOE said.
Applications for the first phase are due Feb. 1, 2023. A public webinar will be held on Nov. 30.
Applications will be judged based on two equally weighted criteria: that a project is “unlikely to be constructed in as timely a manner or with as much transmission capacity” without the capacity contract and that DOE’s proceeds from capacity sales will recover the cost of its contracts.
The IIJA funding is in addition to the Inflation Reduction Act’s $3 billion in transmission funding, including $2 billion that DOE said “will unlock additional billions in federal lending for projects designated by the secretary of energy to be in the national interest.”
MISO, SPP Eye JTIQ Projects
Marcus Hawkins, executive director of the Organization of MISO States, said OMS is discussing with the SPP Regional State Committee seeking funding for the Joint Targeted Interconnection Queue (JTIQ) projects, a $1 billion portfolio of transmission between MISO and SPP.
“I’m sure individual PUCs will also apply for funding for other types of projects, but the JTIQ projects are the only ones I have direct knowledge of,” Hawkins said in an email.
MISO spokesman Brandon D. Morris confirmed the RTO’s interest in the funding, saying five projects in the JTIQ portfolio may be candidates. “These projects span seven states (Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota and South Dakota) and seem to align with DOE’s priorities,” Morris said.
CAISO spokeswoman Anne F. Gonzales said the RTO cannot accept the federal funding but will consult with organizations that can. “CAISO supports research and development efforts that enable innovative and comprehensive grid resilience solutions. The ISO provides support letters and serves as a member on many projects’ Advisory Boards,” she said. “In this advisory role, the ISO provides the system operator perspective and informed contribution to the role of grid operators in managing grid reliability as the complexity of the grid infrastructure and grid operational scenarios evolve.
SPP, NYISO and ISO-NE said they were reviewing the funding opportunity but otherwise declined to comment. The Organization of PJM States Inc. and the New England Power Generators Association also declined to comment. PJM and ERCOT did not respond to requests for comment. The Edison Electric Institute, the Independent Power Producers of New York and the Electric Power Supply Association also did not respond to queries.
“While each of these programs is targeted to address specific problems and solutions, I think the biggest benefit from these programs is that collectively they reduce the overall cost to consumers of getting needed transmission infrastructure built and put into service and ultimately will lower the impact on individual customer bills,” said Larry Gasteiger, executive director of transmission trade group WIRES.
Beyond the federal funding, Gasteiger said, “we need a moonshot effort to build more transmission on a faster timetable than we have ever built before at all levels, including interregional, regional and local transmission.”
About 70% of the grid is more than 25 years old, according to DOE. Gasteiger said much of the nation’s aging transmission is at the local level. “Yet there seems to be a glaring disconnect between the White House and DOE on the one hand and FERC on the other as to the importance of addressing those local transmission needs. Too much of FERC’s focus is on efforts that are likely to discourage or inhibit the development of needed local transmission.” (See Transmission Owners, RTOs Defend Planning, Cost Control Practices.)
DOE Criteria
DOE laid out the priorities for GRIP in its 140-page funding opportunity announcement, citing “insufficient development of projects” to increase transfer capacity between regions, reduce increasing interconnection queue times or increase the supply of “geographically and technologically diverse” resources to improve resource adequacy and reduce correlated generation outages.
It noted that the U.S.’ largest electric utilities have been investing more than twice as much in their distribution systems as in their transmission systems.
“Investments should prioritize driving innovative approaches to achieving grid infrastructure deployment at scale where significant economic benefits to mitigate threats and impacts of disruptive events to communities can be attained,” it added. “DOE is looking for proposals that will leverage private sector and non-federal public capital to advance deployment goals. These efforts will be aligned with state, regional or other planning activities and goals. As state resilience plans continue to be updated annually and evaluate future risks, DOE is interested in how federal funds will leverage industry investments towards hardening their system and/or advancing innovative solutions to enhance system resilience.”
Among the technologies it cited as candidates were “adaptive storage deployment, microgrid deployment, and the undergrounding of distribution and transmission lines.”
It also made a plug for grid-enhancing technologies (GETs), noting real-time congestion costs in CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM totaled $4.8 billion in 2016. Deploying three GETs nationally — advanced power flow control, dynamic line ratings and topology optimization — could save $5 billion in annual energy production costs, “with upfront investment paid back in just six months, and double the amount of renewables that can be integrated into the electricity grid prior to building new large-scale transmission lines,” it said.
DOE also said it would welcome applications to help grid operators quickly rebalance the electrical system with autonomous controls through data analytics, software and sensors.
Funding also will be available to appliance manufacturers who spend money on giving their products the ability to engage in smart grid functions and utilities that install smart grid monitoring and communication devices.
DOE urged applicants to team up with a wide range of stakeholders, including grid operators, technology vendors, system integrators and community leaders.
And in case there was any question, DOE said it will reject applications “for proposed technologies that are not based on sound scientific principles (e.g., violates the laws of thermodynamics).”
Federal buildings in Arkansas could, in the near future, be running on 100% carbon-free electricity (CFE), at least half of which would match the facilities’ demand hour for hour, 24/7, according to a new memorandum of understanding signed by the U.S. General Services Administration and Entergy, the state’s largest investor-owned utility.
The MOU was announced Tuesday at the 27th Conference of the Parties (COP27) in Sharm el-Sheikh, Egypt, in line with a new U.S.-led Net Zero Government initiative, with 18 other countries signing on to cut greenhouse gas emissions from their national government operations to net zero by 2050.
Brenda Mallory, Council on Environmental Quality | U.S. Department of State
The countries have also each agreed to develop a roadmap for achieving their net-zero goals, including interim targets, and to publish this plan all before COP28 next year in the United Arab Emirates, according to Brenda Mallory, chair of the White House Council on Environmental Quality (CEQ). Australia, Austria, Belgium, Canada, Cyprus, Finland, France, Germany, Ireland, Israel, Japan, Korea, Lithuania, the Netherlands, New Zealand, Singapore, Switzerland and the U.K. are the founding members of the initiative, along with the U.S., Mallory said at a launch event on Thursday in Sharm el-Sheikh.
“By joining this initiative, countries are — for the first time on a global stage, in a unified fashion — explicitly articulating the leadership role of government in catalyzing economywide climate actions and supporting their countries’ achievement of broader climate targets,” she said.
“We know that national governments are frequently the largest employers, electricity consumers, vehicle fleet owners, real estate holders and purchasers of goods and services in their countries,” Mallory said. “As a result, efforts to green our government operations can spur demand for clean industries and technologies, accelerate innovation … and lower decarbonization costs across all sectors.”
Entergy is one of the federal government’s top 10 electricity suppliers, serving a federal load in Arkansas of about 241,000 MWh per year, spread over 3,485 federal facilities in the state, according to a GSA spokesperson.
The MOU calls for the GSA and Entergy to collaborate on a plan that would provide all the utility’s federal customers 100% renewable power or CFE by 2030, with 50% matching demand 24/7. Entergy’s existing nuclear plants — one each in Arkansas and Mississippi, and two in Louisiana — will be part of the mix, along with “regionally sourced” renewables, including solar, wind and hydropower, the agreement says.
Entergy and the federal government will also pick up all costs of developing and delivering the clean power, with no cost-shifting to other customers, who may eventually have access to the 100% clean power. The MOU specifically calls for the utility to design and file a CFE rate by the end of 2022, which “would provide the appropriate pricing and other terms” needed to meet the 100% clean electricity target.
According to a GSA press release, “once [the plan is] fully developed and approved, it is anticipated that Entergy Arkansas customers in both the public and private sector will have a cost-competitive and reliable option for CFE that matches their electricity consumption for all hours of the day.”
GSA Administrator Robin Carnahan said the MOU is a potential model for similar utility-government partnerships that will “spur demand for carbon pollution-free electricity — when and where people need it.” Other benefits include “helping to promote local, clean energy sources and catalyze utility-scale energy storage, and create a more resilient grid,” she said.
Entergy has not commented on the MOU.
Close of the COP
COP27 closed in the early hours of Sunday, with exhausted delegates approving a historic agreement establishing a structure and process for creating a fund to help developing nations build back from the loss and damage they have already experienced from extreme weather caused by climate change.
After years of opposing any action on loss and damage, the U.S. signaled it would sign on to the agreement, which also calls for developing a range of financing options for addressing loss and damage, for example, climate risk insurance. The agreement also does not set any targets or call for any commitments for funding from developed countries.
With the Republicans taking control of the House of Representatives in January, it is unlikely that President Biden would be able to get additional climate funding for loss and damage approved.
In a statement posted to Twitter, U.N. Secretary-General Antonio Guterres said the agreement in and of itself “would not be enough, but it is a much needed political signal to rebuild broken trust.”
At the same time, the lack of a strong commitments on accelerated emission reductions and the phasedown of fossil fuels in the final conference decision at COP27 left the goal of limiting global warming to 1.5 degrees Celsius still on “on life support,” according to COP26 President Alok Sharma, speaking at the closing plenary.
Measures that would have contributed to “emissions peaking before 2025 as science tells us is necessary, not in this text; clear follow-through on the phasedown of coal, not in this text; a clear commitment to phaseout of all fossil fuels, not in this text,” Sharma said.
These and other issues left unsettled in Sharm el-Sheikh underline the importance of international efforts like the Net Zero Government initiative.
‘Show It’s Doable’
Both the initiative and the GSA-Entergy MOU build on Biden’s own plan for cutting U.S. government emissions, as laid out in an executive order issued in December 2021. The order first set the 2030 target for all 300,000 federal buildings to run on 100% clean power, matching demand 24/7 50% of the time. (See Biden Calls for Federal Procurement of 100% Clean Energy by 2030.)
The order also spelled out Biden’s intention for the federal government to “lead by example” and catalyze both technological innovation and economic and job growth. In addition to its clean power target, the order also requires that all new light-duty vehicles bought for the federal fleet to be zero-emission by 2027, with zero-emission procurement for all new vehicles in the fleet by 2035. The federal fleet currently has about 600,000 vehicles.
Other emission0reduction goals in the order include
for all federal government buildings: net-zero emissions by 2045, with an interim goal of a 50% reduction by 2032;
for all federal government operations: net-zero by 2050, with an interim target of a 65% reduction by 2030; and
for federal procurement: net-zero by 2050, via a “Buy Clean” policy that will promote the use of low-carbon construction materials and other low-carbon materials across the supply chain.
Other governments in the initiative are adopting similar goals and using their purchasing power to set examples and develop best practices for businesses, cities and schools.
Australia has adopted a stretch goal for its government operations to be net zero by 2030, said Christopher Bowen, the country’s minister for climate change and energy.
“I think it’s more important in terms of the example we set,” Bowen said during a panel at Thursday’s launch event. “If we’re asking companies to drive lower emissions; if we’re asking households to drive lower emissions, we have to set the example; … show it’s doable, show it’s possible.”
The Australian roadmap includes installing solar panels on all government buildings and converting existing power purchase agreements to renewable energy, he said.
From Ireland to Singapore
Eamon Ryan, Ireland’s minister for the environment, climate and communications, also pointed to governments’ ability to set budgets and policy as key drivers for emission reductions. An Post, Ireland’s state-owned postal service, started electrifying its vehicle fleet in 2019, beginning with delivery vehicles serving Dublin’s city center and then expanding to other cities across the country.
“Everyone thought that was crazy, but it actually worked,” Ryan said. More than half of the company’s fleet is now electric, according to the An Post website.
Grace Fu, Singapore | U.S. Department of State
Responding to the current energy crisis, the government has also decided to install solar panels on every school building in the country, he said. In addition to cutting the schools’ electric bills, the panels also can be used for “education, for each school to be able to monitor and see how this works,” Ryan said.
“Schools are the center of community, so if we can get it working there, we can spread this to the local shops, the local housing and so on,” he said.
Similarly, Grace Fu, Singapore’s minister for sustainability and the environment, said that while net-zero government initiatives are important, they can not only be top down. Singapore’s all-of-government approach includes “encouraging all our ministries in their outreach to the community to build in that [net zero] shift in mindset,” Fu said.
“We like every one of [our] employees to be our champion; to be a sustainability champion,” she said. “If every public sector employee is really going out there to lead the charge, I think we can really cause a wave of movement in Singapore.”
At its open meeting on Thursday, FERC significantly advanced NERC’s remit to address the challenges posed by the growth of solar and wind generation on the bulk electric system, directing the organization to develop new reliability standards for inverter-based resources (IBRs) (RM22-12) and create a plan for registering entities that own IBRs (RD22-4). The commission also approved two new reliability standards involving IBRs.
In a presentation on the two orders to NERC, Leigh Faugust of FERC’s Office of General Counsel told commissioners that the moves are necessary because of the rapidly changing nature of the BES’ generation mix. Existing regulations standards were designed for an electric grid where energy primarily came through synchronous generation resources like coal, nuclear and hydropower; however, new generation types like wind and solar — as well as battery energy storage systems — connect to the grid through inverters.
“According to NERC, the rapid integration of IBRs is the most significant driver of grid transformation on the bulk power system,” Faugust said. “NERC has reported that solar and wind IBR projects in all stages of development may total upwards of 860 GW of added nameplate capacity over the next decade.”
Although IBRs “are being increasingly incorporated into the bulk power system and distribution grids,” reliability standards largely have not yet been updated to reflect the new normal, Faugust said. In addition, current rules defining which resources qualify as part of the BES — and thus have to register with NERC, follow its reliability standards and respond to NERC alerts — do not apply to many smaller IBRs that are connected to the transmission system.
Registration Criteria, Standards up for Revision
The first of the commission’s orders concerns these registration criteria. It directs NERC to submit a work plan within 90 days detailing how it will identify and register owners and operators of IBRs that are connected to the BPS and “in the aggregate have a material impact” on reliable operation, but are not currently required to register with NERC.
Under the draft order, NERC will be required to complete modifications to its registration processes no later than 12 months after the commission approves its work plan. The organization will have to identify all relevant IBR owners and operators within 24 months after approval, and register them no later than 36 months after approval.
FERC’s order provides some flexibility to NERC by allowing it to decide which of the reliability standards’ requirements IBR owners and operators will have to comply with upon registration; the commission gave the example that new registrants might be required only to comply with “provisions pertaining to facility interconnections and studies, protection systems, modeling, voltage support and frequency response,” along with newly passed standards. NERC’s decisions in this regard will be subject to the commission’s approval.
In its second order, FERC issued a draft Notice of Proposed Rulemaking intended to deal with “the impacts of IBRs on the reliable operation of the” BPS, which the commission said are not adequately addressed by current reliability standards.
Four specific perceived gaps in the current standards are targeted by the draft NOPR. First, the commission said that IBR owners and operators “do not consistently share IBR planning and operational data”; when they do share such data, they are “often inaccurate or incomplete.” Data that should be shared, according to FERC, include location, capacity, telemetry, control setting, ramp rates and a wide range of additional information.
The commission quoted a report from NERC’s Inverter-based Resource Performance Subcommittee (IRPS) that found that NERC’s current standards are at least in part to blame for the situation. According to the report, MOD-032-1 (Data for power system modeling and analysis) leaves “the level of detail and data formats up to each [transmission planner] and [planning coordinator] to define.”
The next gap in the standards is in the validation of data and creation of system models. FERC’s NOPR said that no current standard includes “unregistered IBR modeling data and parameters and IBR-DER [distributed energy resource] aggregate modeling data and parameters to ensure reliability.” While NERC has recommended on several occasions that stakeholders coordinate on providing accurate modeling data, the lack of a mandatory standard means that it is difficult to ensure such collaboration happens.
Another shortcoming in NERC’s current set of standards is planning and operational studies, which Faugust pointed out are not currently required to include models with validated IBR data. Finally, FERC pointed to a lack of IBR performance requirements, such as ride-through capability, that are not currently covered by reliability standards.
FERC’s draft NOPR would direct NERC to submit a compliance filing within 90 days of the effective date of the final rule; the filing would outline a comprehensive standards development and implementation plan for new or modified reliability standards to address the reliability gaps. Comments in response to the draft NOPR are due 60 days after its publication in the Federal Register, with reply comments due 30 days later.
The commission’s third IBR-related action in Thursday’s meeting was the approval of two new reliability standards: FAC-001-4 (Facility interconnection requirements) and FAC-002-4 (Facility interconnection studies). Proposed by the IRPS in a March 2020 white paper, the new standards add requirements that interconnection requirements and studies “evaluate the reliability impacts of newly interconnecting facilities and changes at existing facilities.”
In a statement, NERC said it “appreciates FERC’s focus on reliability matters and will continue to work with FERC and stakeholders toward assuring the reliability of the North American bulk power system.”
WESTMINSTER, Colo. — Steve Wright, a newly minted member of SPP’s Board of Directors who has promised to “strengthen the bridge” to the grid operator’s potential members in the Western Interconnection, put his words into action last week during a two-day development session for its RTO-light Markets+ service offering.
Stepping to the podium Wednesday to help open the meeting’s second day, Wright fondly recalled his time in the Pacific Northwest, where he served as the Bonneville Power Administration’s CEO before retiring last year as general manager of Washington’s Chelan Public Utility District.
“I was always very proud of the collaboration work we did at Bonneville. We did a lot of really important stuff,” Wright told stakeholders.
But that experience did little to prepare him for SPP’s bottom-up, stakeholder-driven governance structure.
“Just in my short time at SPP, I see collaboration on steroids. In fact, it’s almost collaboration to the point of deference to stakeholders and what they want,” said Wright, who joined the board in October. (See “Membership Elects 2 New Directors,” SPP Board/Members Committee Briefs: Oct. 25, 2022.)
Collaboration is also important to Arizona Public Service (APS), said Aly Koslow, the utility’s director of federal regulatory affairs and compliance.
“We are really keenly focused on some of the collaboration benefits that we see [in Markets+],” she told RTO Insider. “The fact that we haven’t had a more organized day-ahead market to join for a long time has made reaching our individual clean-energy goals a little bit less clear.”
APS has a target of delivering 100% carbon-free energy by 2050. Koslow said the utility has a “good idea” about how it will reach 80% of that goal but said, “That last 20% is much more difficult to achieve. It’s going to be new technology, and it’s going to be collaboration.”
“That is a big part of why we are looking to potentially join a market,” she added.
Koslow was joined by dozens of other representatives from Western utilities at Tri-State Generation and Transmission’s headquarters outside of Denver. Like APS, the potential RTO stakeholders are comparing SPP’s Markets+ offering with CAISO’s Western Energy Imbalance Market (EIM) and its extended day-ahead market (EDAM).
CAISO has a head start, but SPP is attempting to close the gap with a transitional real-time balancing market similar to its Western Energy Imbalance Service (WEIS). (See SPP Briefs: Week of Nov. 7, 2022.)
“That is a part of the dynamic out here,” Garrison Marr, senior manager of power supply for Washington’s Snohomish Public Utility District, said Friday of the ongoing RTO evaluation. “The value proposition is really relative to our counterfactual today of an unorganized bilateral market that can be pretty inefficient as we move through the trading trajectory.”
If SPP has a leg up in the competition with CAISO, it’s the RTO’s governance model that gives stakeholders an enormous say over policies and processes. The grid operator says it gets that Western utilities place “high value” on having a voice in shaping the “ever-changing energy landscape” and that the “Western utility landscape represents many diverse interests that must be balanced in every decision.”
“These objectives are at the heart of who SPP is and how we do what we do,” SPP says in its draft Markets+ service offering. “Our customer-driven approach will ensure Western customers get the products and services they need at affordable rates they help control.”
“This whole voting system is designed to give you power, and the board sees itself as primarily managing process to make sure we get the process that leads to the decisions that lead to as much consensus as possible,” Wright said.
SPP’s potential market participants have responded positively. Mark Holman, managing director of Canadian power marketer Powerex and a vocal supporter of Markets+, said governance is one of two pillars of a successful market, along with resource adequacy.
“What we want to see happen in any governance framework is that we never end up with a situation where a minority of participants that are very large can drive decisions, but also that we end up with a situation where a majority of participants, but a very small share of the footprint, can drive decisions,” Holman said.
SPP has proposed a five-member Markets+ Independent Panel (MIP), unaffiliated from market participants and stakeholders, that reports to the RTO’s Board of Directors and oversees a Markets+ Participants Executive Committee (MPEC). The MPEC would direct the market’s working groups — likely focused on operations reliability, seams and market design — and task forces; an ad hoc settlements group has already been proposed.
The grid operator’s staff have recommended a two-tiered voting structure, with the first tier requiring a 67% approval threshold from three sectors (investor-owned utilities, public power, and public interest organizations and independents). The second tier would be a regional vote with a 51% approval threshold.
Staff hope to have the structure in place when Markets+’s first development phase begins in April. If the Phase 1 participants are unable to agree on the MIP’s representation, SPP has proposed that a subcommittee of its board be used in the interim, with one of the directors staying on the MIP to smooth the transition.
Paul Suskie, the RTO’s general counsel, conducted a straw poll on governance preferences by asking for a show of hands. By a 17-13 margin, stakeholders indicated they would like to stand up an MIP before Phase 1 but were not opposed to the board subcommittee structure.
SPP plans to add a Markets+ State Committee (MSC), like the Regional State Committee in the Eastern Interconnection. The Western states will determine their level of involvement and the MSC’s composition during Phase 1.
Suskie told his audience that while in New Orleans earlier in the week for the National Association of Regulatory Utility Commissioners’ annual meeting, a FERC commissioner told him, “You have the fewest protests at FERC because you work it out with the stakeholder process.”
Staff said they have received a large set of comments supporting the proposal that a common resource adequacy program be a prerequisite for Market+ participation. The Western Power Pool is several steps ahead there, having begun a Western Resource Adequacy Program (WRAP), the West’s first regional reliability planning and compliance program, at the request of regional utilities. The WPP has filed a tariff at FERC and has asked for a response by mid-December.
“We plan to respond to whatever may come, and I’m very confident that we will resolve the process in a positive manner. We’re very confident that we will be operating under the tariffs shortly,” WPP CEO Sarah Edmonds said, asking that those in the region “come forward” with contractual and financial commitments.
Fortunately for SPP, its staff have been working closely with WPP since 2019 in helping set up and manage the WRAP. A joint task force will be established early in Phase 1 to determine how the program will interact with Markets+.
Unlike CAISO’s EDAM, the WRAP will not have a separate, binding resource-sufficiency test.
“A lot of us are at this table for that reason,” Koslow said during the meeting. “If resource adequacy was great in CAISO, this conversation would not be happening. I’m really worried about what that might look like in EDAM.”
Referring to the “challenges we’ve had with resource adequacy in the EIM,” Russ Mantifel, Bonneville’s EIM program manager, said, “It would be great … if the best landing spot for everybody was as a member of WRAP.”
SPP plans to release the final service offering in late November after it addresses the comments received in Westminster and on the draft offering. It will engage through March with the entities who have committed to funding Phase 1; staff have projected that will cost $9.7 million and take about 21 months.
Those entities that commit to the funding will be eligible to vote on design decisions and ensure Markets+ keeps moving forward, staff said. During the phase, staff and stakeholders will work on the protocols and tariff language that will be filed at FERC. At the same time, staff will explore an opportunity to add Markets+’s energy imbalance market, with a target implementation date of June 2024.
SPP has assumed that by Phase 2, when the day-ahead market is designed, Markets+ will be about a 50-GW system with up to 30 balancing authorities and 90 market participants. The phase is estimated to take three years and cost about $130 million, staff said, based on their experience with the day-ahead Integrated Marketplace they launched in 2014.
Staff said they will look for ways to minimize costs for entities who choose to transition from Markets+ to SPP’s RTO West. They said seven parties are expected to decide whether to become RTO members by March.
FERC last week approved the surrender of the license for the 163-MW Lower Klamath hydroelectric project straddling the California-Oregon border, setting the stage for the largest dam removal and salmon restoration effort in U.S. history.
The commission’s decision marks a major victory for local tribes and environmental groups in the region, who for years have sought the breaching of the dams to restore salmon runs to an area of the Klamath River that saw fish populations decline dramatically with the completion of the first dam in 1918. For Northwest tribes, salmon represent a traditional source of food and a vital component of cultural identity.
During the commission’s open meeting on Thursday, Chair Richard Glick said some people might wonder why a hydro plant licensee would agree to remove dams “in this time for great need for zero-emissions energy.”
“First of all, we have to understand that this doesn’t happen every day. The last time there was approval for decommissioning dams was about 10 years ago,” Glick said.
The FERC chair pointed out that the dams were built during a time “when there wasn’t as much focus on environmental issues.”
“Some of these projects have a significant impact on the environment and a significant impact on fish and other wildlife, so when companies are contemplating going through the relicensing process, people recognize that now we have new information and different laws, and so on, and sometimes these relicensing processes can be rather expensive,” he said.
Glick added that, while the Klamath dam removals “make sense” from the perspective of wildlife protection, tribal concerns weighed heavily as well.
“I think it’s a very important issue,” Glick said. “A number of years back, I don’t think the commission necessarily spent a lot of time in thinking about the impact of our decisions on tribes, and I think that’s an important element that I think is in today’s order and a number of orders recently. And I think for [the] good we’re making progress on that front. Still a ways to go, but I think we’re making the right progress there.”
A Model for Other Removals?
Culminating a process that began more than 15 years ago, last Thursday’s 174-page order authorizes Klamath River Renewal Corporation (KRRC) and PacifiCorp — the dams’ previous owner — to remove four hydroelectric developments along the river, including the J.C. Boyle Dam in Oregon and the Copco No. 1, Copco No. 2 and Iron Gate dams in California (P-2082-063).
“Never before have so many large dams been removed from a single river at one time in the U.S.,” the Congressional Research Service said in a report last March, noting that the project could become a “proof-of-concept for other major dam removals.”
The Lower Klamath Project was originally part of the 169-MW, seven-dam Klamath Hydroelectric Project, built between 1918 and the early 1960s. In 2007, PacifiCorp decided not to seek relicensing of the four lower dams following a long-running dispute over water rights and the health of salmon runs in the Klamath Basin. The utility determined that new mitigation measures that would have been required under renewed licenses for the four aging structures would be too costly to implement.
For years the dams operated under a series of interim licenses, until FERC in June 2021 approved transfer of their licenses to the KRRC, a group comprising the Yurok and Karuk tribes, area farmers, ranchers, fishermen and environmental groups. The states of California and Oregon assumed roles of co-licensees to ensure that KRRC’s decommissioning and restoration efforts had sufficient backing. (See Klamath Hydro License Transfer Approved.)
Under the terms of the transfer, PacifiCorp has continued to operate the dams until decommissioning. Three dams further upstream, which have been modernized with fish ladders to facilitate salmon runs, will remain in service.
Opponents of the dam’s removal said the reservoirs created by the projects play an important role in irrigation, flood control and wildfire protection, as well as recreation and hydroelectric production. While acknowledging those concerns in its order, the commission noted that California, Oregon and the KRRC have committed to addressing many of them, including monitoring wells currently located near the reservoirs for declines in water levels and modifying the region’s fire management plans to account for the loss of a ready water supply, including an increase in storage tanks and installation of remote, camera-monitored fire-detection systems to allow for “precise triangulation” of wildfires.
The commission acknowledged that dam removal could have mixed effects on property values, with the loss of value for formerly waterfront properties potentially offset by increased values because of improved water quality and “an enhancement of the natural riparian environment.”
The commission also noted that commenters such as Siskiyou County, Calif. — home to the three of the dams — raised concerns that removal could result in a significant reduction in their tax revenue. “While it is possible that revenues related to the presence of the project will be lost, we have previously stated that the termination of any business venture reduces tax revenues to governments but is not a reason to deny a surrender application,” FERC wrote.
Terms of Surrender
FERC’s order requires the Lower Klamath co-licensees to submit an owner’s dam safety program within 30 days, which will be effective from the termination date for each facility until removal. And, at least 60 days prior to any construction activities, the licensees must provide the secretary of the commission with final decommissioning design documents and an independent board of consultants’ review of those documents.
Within 30 days of completing decommissioning, the licensees must submit to the secretary a final decommissioning report, with photographs, which documents that the dams have been decommissioned in accordance with FERC’s order.
“The surrender of the license for the Lower Klamath Project shall not be effective until the commission’s Division of Dam Safety and Inspections – Portland Regional Engineer has issued a letter stating that the project’s facilities have been decommissioned in accordance with this surrender order and the commission’s Division of Hydropower Administration and Compliance is satisfied with the required monitoring in accordance with this surrender order,” the commission wrote.
FERC approved 11 settlements last fiscal year that resulted in market participants paying a total of about $57.52 million in penalties and disgorgements for alleged violations, Office of Enforcement staff told commissioners at their open meeting Thursday.
The amount represented more than a sevenfold increase over the previous fiscal year’s $7.9 million, though the bulk of the money came from a massive settlement with Salem Harbor Power Development, which in June agreed to pay nearly $43.8 million in penalties and disgorgement (IN18-8). Enforcement had alleged that the company behind the Salem Harbor gas plant in Massachusetts misled ISO-NE about the construction timeline of the project and took more than $100 million in capacity payments before it was in operation. (See Developer in ISO-NE Hit with FERC Fine for Capacity Market Fraud.) The case also cost ISO-NE $500,000 for mishandling the project’s delays. (See FERC Investigation Faults ISO-NE in Capacity Market Fraud.)
The details of the case were included in Enforcement’s annual report for fiscal year 2022 (Oct. 1, 2021, to Sept. 30). Even without the Salem Harbor settlement, Enforcement still collected about $5.8 million more than it did in FY21, when FERC Chair Richard Glick lauded the office for its aggressiveness. (See FERC Enforcement Rebounds from COVID Slowdown.)
“I think the office is back in terms of being active [and] making sure it fulfills its responsibilities that the commission gives it,” Glick said Thursday, using similar rhetoric as he did last year. “It’s important to have the cop on the street so that people … think twice before they engage in market manipulation, before they try to evade a commission rule.”
Glick highlighted the fact that, of the total amount, about $34 million were returned to customers through disgorgement. But Enforcement’s Division of Audits and Accounting, he noted, also directed about $158 million to be refunded or prevented from being collected as a result of 51 findings of noncompliance. This amount was also up significantly over FY21, when it directed $18.5 million.
New investigations were also up, with the office’s Division of Investigations opening 21, compared to 12 in FY21. According to the report, “12 involved potential market manipulation, nine involved potential tariff violations and seven involved potential misrepresentations prohibited by the commission’s Duty of Candor rule. The 21 investigations involved a wide range of additional issues, including NERC’s Rules of Procedure, ISO/RTO must-offer requirements and Section 205 of the” Federal Power Act.
While it does not disclose the specifics of these investigations, the report provides some examples of those that were closed without enforcement action. Five of these were based on 10 referrals from RTO market monitors, and often the office could not find sufficient evidence any rules were broken, or it found minor, unintentional rule violations that it determined did not cause any substantial harm to the markets. The other five referrals that resulted in new investigations remain open.
“Ensuring that our energy markets are free from manipulation so that they can continue to serve consumers is a top priority at FERC, and it requires vigorous oversight and enforcement efforts,” Glick said.
Sen. Joe Manchin (D-W. Va.) opened the Thursday confirmation hearing for three key posts at the Department of Energy by asking the nominees “a pretty simple, yes or no” question.
“Do any of you believe that the United States of America can be energy independent within the next 10 years without a robust clean fossil [fuel] energy program?”
And one after the other, David Crane, Jeffrey
Marootian and Gene Rodrigues all answered “no,” during the hearing of the Energy and Natural Resources Committee.
The question was particularly pointed for Crane, the controversial former CEO of independent power producer NRG, who was recently named to lead DOE’s new Office of Clean Energy Demonstrations (OCED), where he will oversee the development of both carbon capture and hydrogen hubs funded by the Infrastructure Investment and Jobs Act.
Marootian, who previously was head of the District of Columbia’s Department of Transportation, has been tapped as assistant secretary for energy efficiency and renewable energy, while Rodrigues, a former executive at Southern California Edison, will be assistant secretary for electricity delivery and energy reliability.
Sen. John Barrasso
| Senate ENR Committee
Both Manchin, committee chair, and Sen. John Barrasso (R-Wyo.), the committee’s ranking member, had tough questions for Crane, who was infamously fired from NRG in December 2015 after the company’s stock fell 63% in 11 months. He has also been outspoken on the need for utilities and corporate America to move faster on decarbonization and during his tenure at NRG closed several of the company’s coal plants.
Given the financial losses at NRG, Barrasso asked Crane, “Why should we believe that you’re going to manage the American people’s money better than you managed the NRG money?”
While dramatic, the losses at NRG were “actually consistent with [losses at] other companies in the industry” at that time, Crane said. According to a 2016 article in Greentech Media, Dynegy, an NRG competitor, saw its stock’s value tumble 50% in the same time period.
Crane also countered that his long experience “at the intersection of big capital and big energy projects” gives him the skillset needed at the OCED. He also pledged to Manchin that he would implement the carbon capture and hydrogen provisions of the IIJA “with the same vigor that I implement every other provision.”
Those provisions, along with the Inflation Reduction Act’s expansion of the 45Q tax credits for carbon capture “are catalyzing a response that I think is going to be very good for the industry,” he said.
Similarly, Crane said the response to DOE’s call for initial proposals for $7 billion in hydrogen hub funding, which closed on Nov. 7, was “extremely enthusiastic,” ensuring that the projects chosen will meet the IIJA’s requirements that hubs be located in different regions and use different fuel stocks, including fossil fuels. (See DOE Opens Solicitation for $7B in Hydrogen Hubs Funding.)
Sen. Martin Heinrich (D-N.M.) also quizzed Crane on what metrics the OCED would use “to ensure that those large demonstrations are truly addressing the key risks, to be able to move those things towards adoption [and] deployment scale?”
Crane said his office would be focusing not only on the technical side of the demonstration projects but “more on the commercial offtake. These projects not only have to operate within their ring fence, but they have to be commercially sound. …
“The Department of Energy has a lot of negotiating influence in these public-private partnerships” for demonstration projects, Crane said. “But what we can’t do is structure projects that the private sector would never replicate. I will tell you, in my two months at the DOE, the word ‘replicability’ has passed my lips more often than it has in my previous 63 years.”
From Baseload to Grid-edge
Thursday’s hearing was the first meeting of the Energy and Natural Resources Committee since last week’s midterm elections, which left Democrats in control of the Senate, and Manchin likely to retain leadership of the committee.
The hearing also underlined other key trends in energy policy in Congress and at DOE. First, the administration continues to promote its commitment to an all-of-the-above approach to decarbonization, which includes at least the potential for carbon capture and sequestration and green hydrogen to provide economic growth for the struggling fossil fuel communities Manchin and Barrasso represent.
DOE is also focused on making the projects it funds with IIJA dollars commercially viable, which has resulted in the agency recruiting industry leaders like Crane and Rodrigues.
By contrast, Marootian, whose most recent position was as a special adviser to the Office of Energy Efficiency and Renewable Energy, clearly does not have the depth or breadth of experience of Crane or Rodrigues. For example, when Heinrich asked him if DOE would help to set standards to accelerate the deployment of advanced conductors and other grid-enhancing technologies, he said only that he would be “delighted” to work on the issue.
Rodrigues, on the other hand, smoothly navigated grid-related questions from Republicans and Democrats. Responding to a query about baseload power from Sen. John Hoeven (R-N.D.), Rodrigues said that the complexity of ensuring the reliability of the U.S. electric grid means “we need a mix of resources that can be used in different ways. Baseload energy is critically important.”
A top priority for the Office of Electricity, he said, will be “ensuring that each and every state’s policy decisions, policy preferences and decisions made around the resource mix that they want to serve their constituents — that the grid is enabled to take those resources and affordably get them to the American people.”
At the same time, Rodrigues also stressed the importance of developing grid-edge resources, like vehicle-to-grid technologies, to increase reliability.
While technological barriers still need to be overcome, Rodrigues said, “if and to the extent the grid is able to accept [grid-edge] resources, to integrate them, then we will have ways to increase reliability, increase affordability.”
The Office of Electricity will work to advance these technologies, Rodrigues said, “to ensure that the visibility of these resources, the controllability of these resources and … [the] policies are in place to ensure that consumers recognize the value of being a beneficial part of how we control our grid.”
NERC staff called the organization’s 2022-2023 Winter Reliability Assessment, issued on Thursday, a “serious warning” that highlighted the possibility of “bigger problems” compared to last winter in several regions, with extreme weather once again posing a major risk to grid reliability.
“When we look at events over the last several years, it’s really clear that the bulk power system is impacted by extreme weather more than it’s ever been,” said John Moura, NERC’s director of reliability assessment and system analysis, in a media call on Thursday. “And so, as we transition our system rapidly, it’s vitally important that we’re planning and operating a bulk power system that is resilient to … the extreme weather we’re seeing, which includes both generation and transmission solutions.”
The regions where NERC identified potential for insufficient electricity supplies during peak winter conditions are MISO; ERCOT; Alberta; the Maritimes region, which contain parts of Canada and the U.S.; and SERC-East, which includes North and South Carolina. In addition, the assessment marked New England as at risk of constraints to the natural gas transportation infrastructure during cold weather, which could lead to outages of gas-fueled generation sources.
Demand Rising as Capacity Falls
NERC’s winter assessments are released each year and cover the months of December through February, based on demand and generation availability forecasts provided by regional entities, utilities and other stakeholders. In Thursday’s call Mark Olson, NERC’s manager for reliability assessments, emphasized that “almost all areas are well prepared for … average winter years” and observed that some regions do, in fact, appear to be in a better position than they were last year.
For example, the WECC-Western Power Pool assessment area had a lower risk of supply shortfall based on its improved hydropower outlook from last year, while SPP was assessed at lower risk because of added natural gas and wind generation since last winter.
However, for a significant fraction of the North American electric grid, questions exist about the ability to maintain needed levels of service in the face of extreme conditions that might affect the functioning of generators while driving up demand for electricity for heating. ERCOT faces the biggest potential shortfall, with NERC calculating that under the region’s projected reserve margin could fall as much as 21% below demand in the most severe scenario.
Left: NERC’s risk-period scenario for MISO, showing a potential for load shedding under extreme conditions; Right: the same projection for ERCOT. | NERC
No other region approaches ERCOT’s assessed risk: The closest is the Maritimes — comprising the Canadian provinces of New Brunswick, Nova Scotia and Prince Edward Island; and Northern Maine, which is not part of ISO-NE — which has a potential 8.6% shortfall. MISO could come short by as much as 7.6%, while Alberta, which is in WECC’s footprint, has a potential 1.1% deficit.
John Moura, NERC | NERC
One reason the possible shortfall in Texas is so high, Olson said, is that unlike other regions, ERCOT has “very little transfers that can come help in the event that they do [have] energy emergencies.” Demand in Texas is also very sensitive to cold weather because of electric heating demand, which “significantly uses more electricity” as the temperature drops.
On the other hand, Olson pointed out that ERCOT has implemented a number of improvements to cold weather performance since the winter storms of February 2021 that “also should improve the fuel availability to the natural gas-fired generators.” Moura added that while NERC only assesses the readiness of the bulk electric system, he was “sure” that those responsible for regulating the natural gas supply “have made strides” in preparing their system.
For MISO, reserve margins have fallen by more than 5% since last winter, largely because of more than 4.2 GW in nuclear and coal-fired generation retirements. While 2.25 GW of demand response and wind generation with nameplate capacity of 3.2 GW have been added, Olson reminded listeners that the inherent uncertainty around the weather impacts the availability of these resources.
“If wind comes in below projections … that can drive whether there is an energy emergency or not in MISO,” Olson said. “If it’s low, it’s more likely to have emergencies, and if it’s high, it can alleviate some of those concerns.”
Coordination Recommended
NERC’s assessment includes several recommendations to utilities to lower the risk of energy shortfalls this winter. The first is for balancing authorities and reliability coordinators to work with generator owners to ensure adequate fuel supplies both for normal and extreme conditions; this includes filling storage capacity, preparing fuel delivery systems, and coordinating with fuel providers to make sure additional fuel can be secured when needed. GOs should keep BAs and RCs apprised of their fuel levels and readiness as well, while RCs and BAs should actively monitor fuel adequacy and be prepared to step in with “proactive steps” to assist if needed.
The ERO also said policymakers at the state and provincial levels should be aware of energy risks for the winter season as well, and delay generation retirements if they are likely to negatively impact reliability. State regulators can also support environmental and transportation waivers requested by grid operators (GOPs) in the event of cold weather, in addition to issuing public appeals for electricity and gas conservation.
Finally, the assessment recommends that grid operators, GOs and GOPs implement the mitigations in NERC’s recent Level 2 alert related to cold weather preparations, as well as any additional recommended winterization steps for their facilities.
