SPP Takes Next Step in Expansion Of its Wholesale Market

December 12, 2022

by Peter Maloney
APPA News
December 12, 2022

The Southwest Power Pool (SPP) has taken the next step toward the centralization of day-ahead and real-time unit commitment and dispatch that the wholesale grid operator said would pave the way for the reliable integration of a rapidly growing fleet of renewable generation.

The Nov. 30 release of SPP’s detailed proposal for its Markets+ service provides the basis for stakeholders that expressed an interest in committing to Markets+ in December to formalize contractual commitments for phase one of the service.

Stakeholders interested in committing to funding further market development must sign a Markets+ Market Participant Phase One Funding Agreement by April 1, 2023, SPP said.

SPP has been working with western stakeholders since December 2021 to understand the features they would want in the grid operator’s proposed day-ahead and real-time market.

SPP describes Markets+ as “a conceptual bundle of services” that would centralize day-ahead and real-time dispatch using a hurdle-free transmission service across SPP’s footprint. “For utilities that see value in these services but who aren’t ready to pursue full membership in a regional transmission organization (RTO) at this time, Markets+ provides a voluntary, incremental opportunity to realize significant benefits,” SPP said.

SPP said it envisions a two-phase process for the continuing development of Markets+. In phase one, potential participants and stakeholders will financially commit to design the market protocols, tariff and governing documents. Phase two begins upon Federal Energy Regulatory Commission (FERC) approval. At that point, SPP would acquire necessary software and hardware while participating entities fully commit to fund and are integrated into the system.

Earlier in November, SPP announced the 2023 implementation of major components of the Markets+ governance structure and the exploration of a transitional real-time balancing market in 2024.

In August 2022, the Bonneville Power Administration became the first western utility to formally commit to funding further development of Markets+.

In September, Washington State’s Chelan County Public Utility District, Grant County Public Utility District, and Tacoma Power committed to Markets+. Arizona utilities, including Salt River Power also committed to Markets+ in September.

ERCOT Creates Curtailment Program for Large Flexible Customers during Peak Demand Periods

December 10, 2022

by Paul Ciampoli
APPA News Director
December 10, 2022

The Electric Reliability Council of Texas (ERCOT) is implementing a voluntary curtailment program allowing large flexible customers, such as bitcoin mining facilities, to reduce their power use during periods of high demand, it said on Dec. 6.

“Our goal with this program is to work with large customers in supporting the reliability of the Texas power grid,” said Woody Rickerson, ERCOT Vice President of System Planning, in a statement. “These customers are large power users but have the flexibility and willingness to reduce their energy use quickly, if needed. By working with these large loads during peak demand periods, we will better serve all Texans while keeping the grid reliable and resilient.”

The program is primarily intended for large flexible customers, but any large customer directly connected to a transmission service provider’s facility can participate, subject to approval by ERCOT.

The program is temporary and completely voluntary until ERCOT establishes a long-term set of rules.

Registration for the program began on Dec. 6 and ERCOT anticipates the program going live in January 2023.

More information can be found in our Market Notice, including the registration form to participate.

APPA Says FERC Communications Proposal is Overly Broad, Should be Withdrawn

December 5, 2022

by Paul Ciampoli
APPA News Director
December 5, 2022

A proposal by the Federal Energy Regulatory Commission (FERC) to add a new provision to its regulations that would impose a “duty of candor” on any entity communicating with the Commission, its staff, or certain other entities is overly broad and would likely chill communications while presenting significant enforcement challenges for the Commission, the American Public Power Association (APPA) said in urging FERC to withdraw the proposal.

APPA submitted comments on Nov. 10 to FERC in response to a FERC Notice of Proposed Rulemaking (NOPR) that would amend the Commission’s regulations to add the new provision.

APPA noted that it has long been a proponent of Commission rules that guard against market manipulation and that promote just and reasonable market outcomes for consumers, consistent with the Commission’s obligations under the Federal Power Act (FPA).  “APPA also recognizes the need for the Commission to be able to rely on accurate information in executing its duties under the FPA and other statutes it is tasked with administering.”

APPA “can understand the appeal of trying to ensure this goal by adopting a generic requirement simply ‘to tell the truth,’” it added.

“APPA is compelled, however, to express serious concerns with the NOPR and the Proposed Regulation.  The proposed rule would be exceptionally broad – both in terms of the entities to which it would apply and the scope of communications it would cover.” 

There is no intent element, nor is there any materiality requirement — except as to factual omissions, which the Proposed Regulation would also encompass, it said.

“The rule would apply to unintentional and immaterial mistakes, subject only to the ability of a target of an investigation to demonstrate that it exercised ‘due diligence’ to assure the accuracy of the communication.”

APPA said it concurs in FERC Commissioner James Danly’s assessment “that the breadth of the proposed rule would likely chill communications while presenting significant enforcement challenges for the Commission.”

APPA said it is particularly concerned by the NOPR as it relates to communications with entities other than the Commission and its staff. 

The Proposed Regulation would likely apply to essentially all communications with Regional Transmission Organizations (RTOs), Independent System Operators (ISOs), market monitors, the Electric Reliability Organization (ERO) and its Regional Entities, as well as a sweeping array of communications with utilities.

The NOPR “does not provide a reasoned basis for such an expansive candor regulation,” APPA argued. It said there is no discussion of any specific instances where the lack of a general duty of candor obligation has undermined the Commission’s ability to carry out its obligations. Moreover, the NOPR’s description of the existing statutory, regulatory, and ethical requirements for honest communications “tends to show that any problem the Commission is attempting to solve is a narrow one that would be better addressed through a more targeted response.”

Even if there were a clearly identified need for the rule, the NOPR fails to establish the legal authority for adopting the Proposed Regulation or for enforcing it against entities that are not generally subject to the Commission’s jurisdiction, such as APPA’s public power utility members, the trade group said.

The NOPR indicates, for example, that authority to adopt the duty of candor is grounded, at least in part, in section 206 of the FPA.

The Commission’s authority under section 206 is limited to “public utilities,” however, and the NOPR does not explain how it could extend liability to a non-public utility for a violation of a rule based on FPA section 206.

Public utilities refers to those entities regulated by FERC, not non-jurisdictional utilities such as public power utilities.

“Nor do the other FPA provisions cited in the NOPR provide a basis for the generically applicable duty of candor. In addition to these problems with the statutory underpinnings of the proposed rule, the rule is overly broad and presents significant due process concerns, particularly in the context of communications with jurisdictional transmission or transportation providers.”  

APPA urged the Commission to withdraw the NOPR. “Any specific gaps in the coverage of existing candor requirements should be addressed by more targeted proposed rules to address those particular circumstances,” it said.

If the Commission proceeds, however, “APPA recommends that the proposed duty of candor be limited to written or recorded communications of factual information to the Commission or its staff, and that the rule include a materiality requirement.”

Regardless of the scope of any final rule, the Commission should, at a minimum, specify that non-public utilities would generally not be subject to enforcement for violation of the duty of candor under FPA section 316A, APPA said.  Section 316A of the FPA allows FERC to assess significant financial penalties against entities that violate certain FPA provisions or FERC rules or orders issued under those provisions.

N.Y. Governor Signs Bill Placing Two-Year Moratorium on Certain Types of Cryptocurrency Mining

November 28, 2022

by Paul Ciampoli
APPA News Director
November 28, 2022

New York Gov. Kathy Hochul on Nov. 22 signed a bill into law that places a two-year moratorium for certain types of cryptocurrency mining operations.

In a memorandum related to her signing the bill, Hochul said that the law will prohibit Environmental Conservation Law permits from being issued for two years to proof-of-work cryptocurrency mining operations that are operated through electric generating facilities that use a carbon-based fuel.

New York is the first state to take such action, Hochul said.

The law also requires the state’s Department of Environmental Conservation (DEC) to prepare a generic environmental impact statement on cryptocurrency mining operations that use proof-of-work-authentication methods to validate blockchain transactions.

The law still allows for the issuance of permits for generating facilities that “use alternatives to carbon-based fuel, such as hydropower, which would permit growth and business development in this industry,” the memorandum said.

Cryptocurrency and other trade groups expressed disappointment in Hochul’s action.

The Chamber of Digital Commerce, a blockchain trade association, said that to date, “no other industry in the state has been sidelined like this for its energy usage. This is a dangerous precedent to set in determining who may or may not use power.”

“The Business Council does not believe the legislature should seek to categorically limit the growth and expansion of any business or sector in New York,” said Heather Briccetti Mulligan, President & CEO of the New York Business Council. “We plan to further engage and help educate them regarding this industry and the benefits it provides to the local, regional, and state economy.”

Click here for additional details on the bill that Hochul signed into law.

New York DEC Denies Air Permit Renewal To Cryptocurrency Mining Power Plant

In July, the DEC denied renewal of an air permit to a 107-megawatt (MW) power plant in Yates County that is used to power computer operations for proof-of-work cryptocurrency mining.

In denying a Title V air permit renewal for Greenidge Generation in the town of Torrey, the DEC cited the dramatic increase in greenhouse gas emissions from the facility since the passage of the state’s Climate Leadership and Community Protection Act driven by “the change in the primary purpose of its operations.”

Comment Period Opens on Proposal to Add Reliability Mechanism to Texas Market

November 17, 2022

by Peter Maloney
APPA News
November 17, 2022

The Public Utility Commission of Texas (PUCT) is seeking comment on a report on reforms aimed at bolstering the reliability of the state’s wholesale electric market.

The report, Assessment of Market Reform Options to Enhance Reliability of the ERCOT System, includes “novel hybrid designs that maintain the unique” energy-only wholesale power market of the Electric Reliability Council of Texas (ERCOT). The study was done by Energy+Environmental Economics (E3).

The PUCT developed a Blueprint for Wholesale Market Design in response to legislation passed by Texas’ 87th Legislature, SB 3, calling for electric market reforms in the wake of the widespread outages and hundreds of deaths caused by Winter Storm Uri in February 2021.

The objective of the law, as regards generation reliability during extreme weather, is to set a reliability standard of a 1-in-10 loss of load expectation (LOLE) in order to establish sufficient reserves at all times and to provide a means of providing incentives for building new dispatchable generation.

Pursuant to the law, the PUCT agreed to develop tools to meet reliability needs not met by ERCOT’s real-time and ancillary services market. Phase II of the Market Design Blueprint adopted by the PUCT last December called for the commission to study hybrid designs that would maintain ERCOT’s energy-only energy market while providing incentives to ensure sufficient generation resources to meet reliability needs.

The recently released E3 report analyzed six proposed market design modifications and incorporated the results of over 35 hours of testimony and more than 300 written submissions received during the PUCT’s public comment period.

The PUCT was not, however, able to open for comment one design, the Performance Credit Mechanism (PCM), that emerged from the review and analysis process. The PUCT, therefore, opened a public comment period on the PCM option (Project 54335). The public comment period closes at noon on Dec. 15.

In addition to a status quo option, the reviewed market modification options included a Load Serving Entity Reliability Obligation (LSERO) that would require load serving entities to acquire reliability credits bilaterally from generators based on forward forecasts, a Forward Reliability Market (FRM) that would create a mandated, centrally cleared reliability market administered by ERCOT, a Backstop Reliability Service (BRS) that would authorize ERCOT to procure resources sufficient to meet reliability needs, and a Dispatchable Energy Credit (DEC) that would require load serving entities to procure credits equal to 2 percent of their annual load. The PCM would establish a process in which credits are awarded based on historic generation during periods of high stress on the grid.

The energy-only status quo scenario would result in a 2026 loss of load expectation of 1.25 days per year, far above the common industry standard of 0.1 days per year, and the exit of 11,260 megawatts (MW) of coal- and gas-fired generation capacity at a customer cost of $22.3 billion per year, according the E3’s analysis in the report.

The LSERO, FRM and PCM designs would result in the addition of 5,630 MW of incremental gas-fired capacity with a LOLE of 0.1 days per year and an annual cost of $460 million per year.

The BRS design would result in the addition of 5,620 MW and a LOLE of 0.1 days per year at an annual cost of $360 million. The DEC design would lead to an aggregate reduction in natural gas-fired generation, resulting in an LOLE of 2.03 days per year at an annual cost of $490 million, according to E3’s analysis.

The PCM design is similar to the LSERO and FRM designs but is less complex and avoids the need for forward looking accreditation, but generator revenues would be less stable under PCM and the design would be less able to less able to reflect infrequent extreme weather conditions, E3 said.

Multiple market designs in the report appear capable of improving market signals to ensure reliability, E3 said, but in the end the report’s authors recommended the FRM design as a “more suitable fit” for the ERCOT market that would “provide more natural year-to-year stability over market outcomes.” The PCM design, E3 said, would “entail significant risk because of its novelty.”

The PCM design has elements similar to the LSERO but “introduces features that may be more consistent with ERCOT market principles such as earned accreditation rather than an upfront administrative process,” PUCT staff said in the filing releasing the report and recommending the opening of the comment period on the PCM design.

Southeast Energy Exchange Market Begins Operations

November 16, 2022

by Paul Ciampoli
APPA News Director
November 16, 2022

The Southeast Energy Exchange Market (SEEM) on Nov. 9 announced that it has initiated operations.

The new SEEM platform will facilitate automated, sub-hourly trading, allowing participants to buy and sell power close to the time the energy is consumed, utilizing available unreserved transmission. Participation in SEEM is open to any entity that meet qualifying requirements. 

Founding members of SEEM include Associated Electric Cooperative, Dalton Utilities, Dominion Energy South Carolina, Duke Energy Carolinas, Duke Energy Progress, Georgia System Operations Corporation, Georgia Transmission Corporation, LG&E and KU Energy, MEAG Power, N.C. Municipal Power Agency No. 1, NCEMC, Oglethorpe Power Corp., PowerSouth, Santee Cooper, Southern Company, and TVA. 

Four Florida energy companies – Duke Energy Florida, JEA, Seminole Electric Cooperative and Tampa Electric Company – have signed agreements to join as members of SEEM effective Jan. 1, 2023 and expect to initiate active energy trading in mid-2023. 

With their addition, the SEEM footprint would include 23 entities in parts of 12 states with more than 180,000 MW (summer capacity; winter capacity is nearly 200,000 MW) across two time zones.

CAISO Touts Successes During Heat Wave, Details Areas For Improvement

November 6, 2022

by Peter Maloney
APPA News
November 6, 2022

A new report from the California Independent System Operator (CAISO) details the successes and failures of the system’s electric grid during the record heat wave at the end of the summer.

From Aug. 31 through Sept. 9, California, and much of the West, experienced 10 days of triple-digit heat with only minimal nighttime cooling and record electricity use. On Sept. 6, record temperatures were set all over California and the West and demand on the CAISO system reached a record peak of 52,061 megawatts (MW). During that time, CAISO issued Flex Alerts calling for voluntary consumer conservation for a record 10 consecutive days.

During the heat wave event, CAISO’s daily average prices rose to $600 per megawatt hour (MWh) with maximum prices reaching $2,000/MWh in the real-time market. Day-ahead average prices reached $300/MWh.

Despite the intense heat, CAISO “was able to keep electricity flowing without interruption thanks to increased capacity added under California’s resource adequacy program, new state programs that provided non-market resources to address extreme events, enhanced collaboration with state and federal agencies and significant conservation by commercial and residential electricity customers,” the ISO said in its Summer Market Performance Report Sept 2022.

The report also cited needed market enhancements to improve how increasingly frequent, extreme, and long heat events are managed, including the clearing of energy exports in the market and real-time testing for resource sufficiency. In particular, the report identified needed software improvements, especially for the clearing of exports and the resource sufficiency test used in the Western Energy Imbalance Market (WEIM).

CAISO credited several factors to the fact that electricity kept flowing during the heat wave and it did not have to call for rotating outages, including increased capacity through resource adequacy procurement since summer 2020, including more than 3,500 MW of lithium-ion battery storage.

CAISO also credited market enhancements, including clarification of scheduling priorities, enhancements to resource sufficiency evaluations and electricity market pricing designed to incentivize generation during periods of high demand.

CAISO noted, however, that demand during the heat wave “far exceeded” the 49,748 MW of resource adequacy shown to the ISO and, thus, was “insufficient” to cover peak demand during some periods.

To fill the gap, CAISO called on up 1,300 MW of demand response, comprised of 500 MW of voluntary demand response bid in the market and 800 MW of emergency demand response.

Regional resources and coordination were also a factor. CAISO called on 6,500 MW of imports from outside its system during the height of the heat wave, as well as 1,000 MW from WEIM.

Among the non-market resources that helped keep the lights on during the heat wave, CAISO said they ranged from non-market demand response, to behind-the-meter backup diesel generators, and temporary grid-side natural gas-fired resources that were deployed by utilities and state agencies with coordination from a wide variety of government, utility, and customer and business groups.

In terms of improvements, CAISO recommended changes that would ensure that energy storage resources are appropriately charged and accounted for in ISO systems to avoid manual corrective action, which happened during the event.

CAISO identified a software issue that resulted in storage resources not charging sufficiently early in the day. Specifically, storage resources that bid above $150/MWh to charge were not charged by the market. “The high prices experienced during the heat wave presented new scenarios for the ISO to learn about the complexities and challenges of managing battery state of charge,” the report said.

During the stresses created by the heat wave, CAISO also discovered there was both over- and under-counting of capacity available to the ISO in the WEIM resource sufficiency evaluation.

If a balancing authority fails the resource sufficiency evaluation, transfers into it from other WEIM participants are limited until the insufficiency is resolved.

On Sept. 6, the ISO failed the resource sufficiency evaluation in two instances, and transfers into the ISO were limited, but not material because the limits were well above the actual available transfers of 1,000 MW from the WEIM.

Upon further investigation, CAISO found that there was both over- and under-counting of capacity, the net impact of which would have potentially led the ISO to fail the resource sufficiency evaluation up to an additional four instances.

CAISO said it has “already addressed some of these issues” and is “evaluating fixes or potential enhancements for the others.”

CAISO has scheduled a stakeholder call for Nov. 17 to review details of the analysis and answer stakeholder questions.

CMUA Responds to Report’s Findings

In response to the report’s findings, Barry Moline, executive director of the California Municipal Utilities Association (CMUA), said that “Preparing for such an event this summer, publicly owned electric utilities and water agencies coordinated closely with the Governor’s Office, California Energy Commission, and the California Independent System Operator. We worked diligently to locate, confirm and generate firm power with every available back-up generator; facilitated customer conservation at key times; and pushed existing power supply to its limit. Only by working together did we avoid major disruption.”

Moline said that going forward, “publicly owned electric utility and water and wastewater agencies will continue to coordinate closely with the Administration and CAISO to decarbonize while assuring that California has the infrastructure and power supply it needs to provide affordable and continuous power.”

California Grid Operator’s Board OKs Proposal to Improve Interconnection Process

November 3, 2022

by Paul Ciampoli
APPA News Director
November 3, 2022

The California Independent System Operator (ISO) Board of Governors recently adopted a proposal aimed at improving the grid operator’s interconnection process.

Over the past decade, the ISO received an average of 113 interconnection proposals per year. But last year, as the state accelerated the pace of procurement for renewable and storage resources, applications for new projects more than tripled to 373 projects.

To mitigate the potential for processing delays due to the high number of requests, the ISO began meeting with stakeholders in 2021 to find ways to streamline the interconnection process.

CAISO said the items that received Board approval within the Interconnection Process Enhancement (IPE) Phase 2 proposal help move projects forward more efficiently, enabling the ISO to better manage the queue by:

• Changing how projects are evaluated so the most viable and ready projects have highest priority;
• Appropriately balancing cost responsibility between developers and consumers for network upgrades to local transmission systems; and
• Providing developers of projects located outside of the ISO footprint with a better-defined process which will include reimbursement of their cost for network upgrades that is consistent with projects in the ISO’s balancing area.

Other improvements in the IPE Phase 2 proposal that do not require Board approval include making more non-confidential information available and easier to access to help developers determine the best location to connect new capacity and enabling developers to provide more input during the interconnection planning process on required network upgrades.

Additionally, the Western Energy Imbalance Market (WEIM) Governing Body and the ISO Board of Governors at their joint meeting in October approved a proposal to recognize the Washington State-specific greenhouse gas emission reference levels in the WEIM under Washington State’s recently revised Clean Air Act.

The proposal also includes an approach for supporting certain reporting obligations under Washington’s Climate Commitment Act, which created a cap-and-invest program starting in 2023.

ISO New England Stakeholders Outline Steps In Case of Extreme Winter Weather

October 27, 2022

by Peter Maloney
APPA News
October 27, 2022

ISO New England stakeholders outlined the steps they would take to work together to navigate potential energy shortages this winter.

The stakeholders discussed scenarios and strategies during a tabletop exercise in Westborough, Massachusetts. Participating in the workshop were operations and communications personnel from the ISO and the its regional utilities: Central Maine Power, Eversource, National Grid, Rhode Island Energy, United Illuminating, Unitil, and VELCO. Officials from all six New England states, as well as federal and regional agencies were also present to observe the exercise.

The stakeholders explored a scenario similar to the winter of 2017-2018, when two weeks of extreme cold strained the supply of fuels used to generate New England’s electricity.

In the past two years, four out of seven ISOs and RTOs in the U.S. have resorted to controlled outages because extreme weather led to limited energy supplies. In New England, however, a winter energy shortfall that involves several days of inadequate fuel supplies, would present “different operational challenges than capacity deficiencies that have been more common historically and typically involve just peak hours,” ISO New England said in ISO Newswire.

ISO New England released a report in August at the request of New England Power Pool stakeholders that evaluated how the region’s grid would perform under the double burden of increased levels of renewable generation sources and higher demand. “The region may struggle to maintain necessary operating reserves in scenarios of high electrification and more aggressive retirements of existing resources,” the report found.

“While this type of emergency is unlikely, it would be profoundly impactful and close coordination between all involved entities is paramount,” Peter Brandien, ISO New England’s vice president of system operations and market administration, said in a statement. “Through exercises like this tabletop, ISO New England and the region’s utilities can work together to better understand how to best respond if these conditions materialize.”

During the tabletop exercise representatives of ISO New England, transmission owners, and local distribution companies described steps they would take to:

• Forecast a possible energy shortfall using the ISO’s 21-Day Energy Assessment Forecast and Report;
• Mitigate the impact of the shortfall by urging generators to stock up on stored fuels, making public appeals for energy conservation, and other measures;
• Protect against widespread and long-lasting damage to the regional electric grid by conducting controlled outages if other efforts are unsuccessful; and
• Keep the public, government, and energy industry informed at each stage of the emergency.

Despite Possible Fuel Constraints, FERC Sees Sufficient Supplies For This Winter

October 27, 2022

by Peter Maloney
APPA News
October 27, 2022

Despite some possible regional fuel constraints, electricity markets will have sufficient capacity to maintain reliable operations this winter, under normal winter conditions, according to a report from staff at the Federal Energy Regulatory Commission (FERC).

“All regions anticipate adequate reserve margins, although extreme winter events may stress operations,” the authors of the report, Winter Energy Market and Reliability Assessment 2022-2023, wrote.

Extreme weather events aside, this winter could be mild for much of the country, implying lower-than-average electric and natural gas demand, the report said citing data from the National Oceanic and Atmospheric Administration (NOAA).

Although prolonged cold weather could cause disruptions and price impacts, the long-term NOAA data suggests a 50 percent to 80 percent likelihood of higher-than-average temperatures in Southern California, the Desert Southwest, Texas, and the Eastern Seaboard, with lower-than-average temperatures expected for the Northwest and the West North Central regions.

Natural gas prices, which set the marginal cost of wholesale electric power for much of the country, are expected to remain higher than they have been in recent years, the report said.

Despite the expectation that natural gas production will be 3.2 percent above last winter and will outpace the expected 2.4 percent increase in domestic natural gas demand growth, forecasts anticipate that continued growth in net exports, including from liquified natural gas (LNG) export facilities, that will place additional upward pressure on natural gas prices this winter. The Henry Hub natural gas futures contract price is averaging $6.82 per million British Thermal Units (MMBtu) for winter 2022-2023, up 30 percent from last winter’s settled price, the report said.

Natural gas supplies will continue to experience constraints in New England and California may also face constraints this winter due to ongoing pipeline outages, which could lead to higher natural gas and electricity prices, the report said. The authors, however, added that ISO-NE expects to maintain reliability this winter under mild and moderate winter conditions and has concluded it does not need a dedicated winter reliability program, unlike in past years.

The report also noted that supply constraints may affect coal deliveries and coal stockpiles this winter across regions that have relied on increased coal-fired generation during recent stress periods, including the Southwest Power Pool, the Midcontinent ISO (MISO), the Electric Reliability Council of Texas, the SERC Reliability Corp. in the Southeast, and the PJM Interconnection.

Meanwhile, the generation addition and retirement patterns that have prevailed for the past several years will continue through the winter.

The U.S. will add 43 gigawatts (GW) of net winter capacity between March 2022 and February 2023, mostly from wind and solar power, while 15 GW of net winter capacity, mostly coal-fired plants, are expected to retire during the same period, the report said.

Nearly 6,700 line-miles of new transmission lines and transmission upgrades are expected to have come online through this winter, mostly in the MISO, PJM, and Southeast regions, the report said.

Forecast generation and transmission additions could change or be delayed, however, as regions are reporting some projects are being impacted by component unavailability, shipping delays, and labor shortages, the report said.