Page 1049 – RTO Insider

September 4, 2020

CAISO Readies for Weekend Heat Wave

CAISO called for extra capacity and conservation Thursday and put grid maintenance on hold as it faces a Labor Day weekend heat wave like the one that caused rolling blackouts and strained its system in mid-August.

“We’re lining up everything we can to be prepared for this as best we can,” said John Phipps, the ISO’s director of real-time operations.

In market notices Thursday, CAISO said it is “seeking any available capacity the ISO can procure under its Capacity Procurement Mechanism (CPM) or under section 42.1.5 of the ISO Tariff” from Saturday through Monday. It restricted maintenance operations, urged coordinators to schedule their load in the day-ahead market “considering anticipated high loads” and issued a statewide flex alert calling for voluntary electricity conservation. (The ISO has not yet suspended convergence bidding, as it did during the August heat wave.)

Much of the West will experience triple-digit temperatures during the holiday weekend — similar to the “heat storm” that engulfed many Western states Aug. 13-18 and forced CAISO to order rotating outages Aug. 14-15, an emergency step it hadn’t taken in nearly 20 years. (See Theories Abound over California Blackouts Cause.)

On Sunday, Las Vegas and Phoenix are expected to hit highs of 112 and 111 degrees Fahrenheit, respectively, the National Weather Service forecasted. NWS issued an excessive heat warning for Los Angeles and most of inland California. Even normally cool cities such as San Francisco and Portland, Ore., are expected to reach 90 F.

CAISO heat wave — This Labor Day weekend will see triple-digit temperatures across much of the West.

“A strong ridge will develop over much of the Western U.S.,” NWS said. “This will set the stage for … very hot temperatures, including a likelihood of seeing record-high temperatures. In some cases, the high temperatures are forecast to be as much as 20 to 25 degrees above normal, which will lead to many areas across the Great Basin and especially the Desert Southwest seeing temperatures well over 100 degrees.”

As in mid-August, California could run into a situation in which it is unable to draw on imported energy from neighboring states to meet its evening net peak demand, after the sun sets and solar power shuts down but air conditioning use remains high, CAISO officials said.

“The entire West is competing for supply going into this hot period,” said Mark Rothleder, vice president of market policy and performance. “We rely on what is a limited set of capacity in California and the West, and when you get to these high load levels, it’s stretching that capacity.”

Phipps said CAISO predicts peak demand of 44,237 MW on Saturday, 46,636 MW on Sunday and 45,060 MW on Monday. Those figures are typical of summer peak loads in California and fall far short of the ISO’s peak of 50,116 MW on Sept. 1, 2017, and 50,270 MW on July 24, 2006, both of which it met without resorting to rolling blackouts.

But CAISO’s supply-and-demand has changed dramatically in recent years, said Rothleder and Vice President of Operations Eric Schmitt during a press briefing Tuesday.

Fossil fuel plants, particularly coal-fired plants, have retired across the West. Neighboring states are serving higher demand from population growth while their own ramping capacity diminishes, leaving less for California to import during West-wide heat waves, Rothleder said.

Schmitt said 10,000 to 12,000 MW of solar, including 7,000 to 8,000 MW of behind-the-meter solar, now ramp down at sunset. Compared with the past, “it’s really apples and oranges,” Schmitt said.

September 4, 2020

ISO-NE Sees 722-MW ICR Jump for FCA 15

ISO-NE is proposing an installed capacity requirement (ICR) of 34,153 MW for Forward Capacity Auction 15, a 722-MW (2%) increase over FCA 14, in part because of reduced expectations of assistance from its neighbors in an emergency.

The RTO presented its ICR proposal and tie line calculations to the New England Power Pool Reliability Committee on Tuesday. The committee will vote on the ICR and related values on Sept. 23.

ISO-NE calculates the ICR — the minimum system capacity needed to meet Northeast Power Coordinating Council reliability criteria — based on sequential Monte Carlo simulations to probabilistically compute the behavior of loads and resources.

The RTO’s annual calculations also account for operators’ ability to purchase energy from neighboring balancing authority areas during a capacity deficiency under Emergency Operating Procedure No. 4.

The RTO’s Fei Zeng told the committee that the Maritimes, Hydro-Québec Phase II, Québec Highgate, New York AC and Cross Sound Cable ties will provide a combined 1,735 MW of tie line benefits for FCA 15 (2024/25), a 205-MW (11%) reduction from FCA 14 (2023/24).

Benefits from the New York AC ties showed the biggest reduction, a drop of 104 MW (29%), followed by a 47-MW reduction for the Maritimes (9%).

ISO-NE ICR — ISO-NE is proposing a net installed capacity requirement of 33,270 MW, a 2% increase over FCA 14. The FCA will start at a price of $13.932/kW-month. | *ISO-NE*

The New York reduction was largely the result of the state’s need to meet higher peak and energy demand forecasts because of increased load forecast uncertainty (40 MW). New York’s increasing need for emergency assistance available from the Canadian control areas reduced the assistance available to New England, Zeng said.

Another 50-MW reduction was attributed to a change in New York’s behind-the-meter PV model: The penetration and hourly shape increased the correlation in the hourly loads between New York and New England.

In addition, a lower Northeast Massachusetts/Boston transmission import capability contributed to a 40-MW reduction, while the retirement of Mystic Units 8 and 9 resulted in a 25-MW decrease. “Tie benefits are a function of how much assistance New England needs and how much assistance our neighboring areas are able to provide,” RTO spokesman Matt Kakley explained. “The retirement of Mystic results in a small decrease in what we would need to be able to replace in an emergency.”

The region’s internal transmission interface transfer limits reflect several anticipated transmission upgrades: the Greater Boston upgrades with the 345-kV Wakefield-Woburn line in service (2021/22); the Greater Hartford/Central Connecticut upgrades; southwest Connecticut upgrades; and the Southeast Massachusetts/Rhode Island reliability project upgrades.

Subtracting the Hydro-Québec interconnection capability credits (HQICCs) of 883 MW (down from 941 MW the prior year), the net ICR is 33,270 MW, a 2% increase over FCA 14. The reserve margin is 16.6% with the HQICCs and 13.5% without.

“HQICCs are capacity credits that are allocated to interconnection rights holders, which are entities that pay for and, consequently, hold certain rights over the Hydro-Québec Phase I/II HVDC transmission facilities,” Kakley said.

The gross cost of new entry (CONE) for the cap of the marginal reliability impact system demand curve for FCA 15 is calculated as $11.951/kW-month, with net CONE at $8.707/kW-month. The FCA will start at a price of $13.932/kW-month.

FCA 15 will model the same zones as FCA 14, with Maine nested inside Northern New England as export-constrained and Southeast New England as import-constrained.

The Participants Committee will vote on the ICR and related values on Oct. 1, with a FERC filing expected by Nov. 10.

September 4, 2020

FERC Rejects SPP’s Zonal Planning Criteria

FERC on Thursday rejected SPP’s proposed Tariff revision to develop uniform local transmission planning criteria, siding with stakeholders who argued they would be unduly discriminatory or preferential (ER20-2334).

GridLiance High Plains, Tri-County Electric Cooperative, Kansas Power Pool and a group of eight cooperatives and municipalities protested the filing, which proposed to use zonal planning criteria to evaluate the need for zonal reliability upgrades in SPP’s regional transmission planning process.

The RTO proposed that the network customer with the zone’s largest total network load would designate each year a transmission owner within the zone as the facilitating TO. That TO would develop a single set of zonal planning criteria, conducting open meetings with the zone’s other TOs and transmission customers taking long-term service within that zone.

SPP Zonal Planning Criteria — SPP’s transmission pricing zones | *SPP*

All TOs within the zone would apply the zonal planning criteria “comparably” to all the zone’s load.

SPP has 18 transmission pricing zones, 10 of which comprise multiple TOs. Currently, each TO submits its own local planning criteria to the RTO, which then uses its regional transmission planning process to determine whether a reliability violation requiring new reliability upgrades should be considered.

Those objecting to SPP’s proposal charged it would give facilitating TOs “unilateral power” and “unduly” benefit them and the zone’s largest network load customer by allowing a single customer, based on the size of its load, to dictate planning criteria for everyone else in the zone.

In a joint protest, GridLiance and Tri-County said “this puts every other entity within the zone at a disadvantage and unduly discriminates against smaller loads in the zone and non-facilitating” TOs. KPP and the cooperatives contended the facilitating TOs are not obligated to take stakeholder input into account when establishing the planning criteria.

The comments echoed their concerns over transparency and equality when the revision request was discussed and approved during SPP’s April governance meetings. Four representatives on the 21-person Members Committee, which advises the Board of Directors with a show of hands, voted against the measure and a fifth abstained. (See “Directors Approve Zonal Planning Criteria, Z2 Elimination,” SPP MOPC Briefs: April 14, 2020.)

FERC agreed with the protests, finding that in zones with multiple TOs, SPP’s proposal would give an undue preference to the network customer with the zone’s largest total network load and to the facilitating TO.

In an email to RTO Insider, GridLiance High Plains President Brett Hooton said, “FERC’s important ruling recognizes that the proposal would have given large incumbent transmission owners complete control over transmission upgrade criteria.”

“Under SPP’s proposal, the network customer with the largest total network load in the zone would have sole authority to designate a single transmission owner in the zone as the facilitating transmission owner, which could be the network customer itself (if it is also a transmission owner) or a transmission-owning affiliate,” the commission said.

“This raises concerns that the facilitating transmission owner could potentially select zonal planning criteria that address its own local reliability needs … or could potentially foreclose SPP’s consideration of local reliability needs of other transmission owners in the zone when identifying the need for zonal reliability upgrades,” FERC wrote. In that case, it noted, the resulting reliability upgrades’ costs would be allocated to all customers in the zone.

The commission said SPP’s proposal would be unduly discriminatory toward the zone’s other transmission customers that do not serve the largest share of load and toward non-facilitating TOs. Aside from attending open meetings, FERC said the zone’s other customers and TOs would have “no formal process rights” or the ability to influence the facilitating TO’s decisions in establishing the planning criteria.

“Facilitating transmission owners could potentially prevent the local reliability needs of other transmission owners in the zone from being considered and thus prevent zonal reliability upgrades from being constructed in response to those needs,” FERC said.

The Tariff proposal was one of 21 recommendations from the Holistic Integrated Tariff Team, which spent 15 months in an effort to help SPP adapt to the evolving grid and electricity markets.

September 4, 2020

NYISO Looks at Pricing Supplemental Reserves

As new solar and wind energy resources come onto the grid, NYISO is preparing to be able to adapt its reserve requirements quickly to a changing resource mix by procuring supplemental reserves during times of system uncertainty.

Supplemental reserve procurements can help provide for system uncertainty introduced by weather-dependent resources, both distributed and grid-connected, as well as potentially more volatile load, according to NYISO. It hopes to have a market design complete this year, Pallavi Jain, energy market design specialist, told the Installed Capacity/Market Issues Working Group on Tuesday.

NYISO is not proposing to add any supplemental reserve requirements now. Rather, it will propose Tariff revisions to establish the process and procedures for implementing requirements when warranted in the future, Jain said. The reserves would be priced lower than the proposed lowest shortage pricing value, $25/MWh, in tiers:

Any 30-minute reserves: $10/MWh
10-minute total reserves: $12/MWh
10-minute spinning reserves: $15/MWh

To help determine the appropriate values, the ISO analyzed historic reserve shadow prices and reserve supply offers.

NYISO Supplemental Reserves — Pricing analysis of historic reserve supply offers, with those from New York City and Long Island broken out separately to help identify any potential for material differences in offer costs from resources in these regions. | *NYISO*

Stakeholder Concerns

Couch White attorney Kevin Lang, representing New York City, said he was concerned about extending undue discretion to the ISO to change reserve requirements without stakeholder authorization.

Increasing reserve requirements is in conformity with current practice, with any action taken brought to the soonest meeting of the Operating Committee, said Aaron Markham, director of grid operations at NYISO. “We want to be prepared to change quickly to meet reliability needs,” he said.

Brian Wilkie, manager for New York wholesale strategy at National Grid, suggested that the ISO could communicate its needs beyond the OC, as many stakeholders do not attend its meetings.

Michael DeSocio, NYISO’s director for market design, said there is a way to balance stakeholder concerns and still provide flexibility for the grid operator.

“We’re not delaying addressing any reliability needs, and still have the issue of developing the software we need,” DeSocio said. “I do worry that there is a notion that we can continue to rely on out-of-market actions … which is probably not in the best interests of consumers in the long run, nor in the best interests of achieving the state’s clean energy goals.”

Stakeholders were also presented a consumer impact analysis to aid further discussion of the proposal. NYISO currently plans to seek stakeholder approval of the proposal at the October meetings of the Business Issues and Management committees. If approved, the enhancements would be implemented in 2021, which the ISO expects to occur after implementation of the Reserves for Resource Flexibility project.

September 4, 2020

Overheard at NECEC Back to Work Webinar

The COVID-19 pandemic has roiled the clean energy industry and caused the loss of more than 600,000 related jobs nationwide, and the economic slowdown has also exacerbated social and environmental inequities.

The Northeast Clean Energy Council (NECEC) on Wednesday held the first in a series of webinars — called the Clean Energy Back to Work Challenge — which brought together a public official, an environmental advocate and a solar developer to explore how energy infrastructure and policy affect environmental justice and social welfare.

“As we know, clean energy is a key element to the economic recovery and the way out of the recession and economic challenges posed by COVID-19,” said Jeremy McDiarmid, vice president of policy and government affairs at NECEC. “We need to make sure that the recovery is just and equitable, and that traditionally disadvantaged populations are getting access to the benefits of clean energy while avoiding the environmental harms associated with fossil generation and pollution.”

Following is some of what we heard at the event.

Broad Goals, Public Policy

Kathy Kelly, Daymark Energy Advisors | *NECEC*

The clean energy industry now faces three key issues: the environmental justice question, social welfare needs and the intersection of those with public policy on new energy infrastructure, said Kathy Kelly, vice president of operations at Daymark Energy Advisors.

“We have very broad energy goals as a country around decarbonization and the adoption of clean energy and how that fits into our long-term plans,” Kelly said. “We need to make sure that as we do that, unlike the past, that all sectors of our society have access to clean energy and are treated equally as we implement the clean energy infrastructure.”

The disadvantages from energy development in the past hit poor people worst, which has lessons for overcoming the challenges of today, she said. For example, the housing stock in low-income areas is unable to accommodate renewable energy improvements, whether because of outdated wiring inside, or roofs unable to support solar panels.

It’s important not to repeat the mistakes of the past, said John Odell, director of energy and asset management for the city of Worcester, Mass.

Certain parts of the community bear more of the burden than others, which is why the city is developing a Green Worcester Plan to serve as a roadmap, he said.

“We want to get as much clean energy out there, remove as much waste from the waste stream, make sure our natural systems are enhanced as best we can and to do as much of that as fast as we can,” Odell said. “It’s often easier to do those things in areas that don’t have the disadvantages, so that’s where the issues of social equity come to the forefront. It’s easier to build on your strengths than it is to correct your weaknesses.”

Environmental Justice and Social Welfare

Health care accounts for more than 10% of greenhouse gas emissions nationally, but the sector also represents about 18% of GDP and is the largest employer in Massachusetts, said Eugenia Gibbons, Boston director of climate policy for Health Care Without Harm (HCWH), an international nonprofit organization with a network of more than 1,200 hospitals in the U.S.

“We employ about 500,000 people in the state and the sector also holds a significant amount of real estate across the commonwealth,” Gibbons said. “So when hospitals and hospital systems begin to implement climate strategies and try to address climate change in their own systems it’s actually having a huge impact on the surrounding communities and on the state as a whole.”

The pandemic has reinforced the link between air quality and poor health outcomes, which is now undeniable, she said. Low-income communities and communities of color have been proven more susceptible both to the virus and to the effects of climate change and air pollution.

“They have been ravaged by COVID,” Gibbons said. “We have to move away from the impulse to think about climate action as strictly an exercise in reducing GHG emissions, and really try to anchor the work in the communities and anchor the work around people.”

86-kW solar installation financed by Sunwealth at the Provincetown, Mass., Water Treatment Plant | *Sunwealth*

The pandemic has caused many disruptions to supply chains, and a combination of the coronavirus and recent protests against racial injustice across the U.S. has “forced a lot of organizations and businesses to have a come-to-Jesus moment and say, ‘We’re either prioritizing this or we’re not,’ and a lot of people are making those commitments,” Gibbons said. “It’s up to everyone to see that they follow through.”

Solar development, finance and construction is “pretty resilient,” said Jon Abe, CEO of solar finance firm Sunwealth, which backs small- and medium-size projects, especially in lower-income communities.

Early on in the pandemic, in many states, solar was deemed an essential service, so while it was complicated, it was relatively easy compared to other businesses to implement the appropriate safety measures at job sites, he said. Sunwealth has almost a dozen developers and installers in the field employing more than 100 electricians and installers at various sites across the U.S.

Sunwealth has been lobbying on low-income community solar inclusion in Massachusetts, where neither the administration nor the legislature has done enough, Abe said.

September 4, 2020May 12, 2025

Sustainable FERC Project Hones on Nixed MISO Renewables

The Natural Resources Defense Council’s Sustainable FERC Project has released a new interactive map of MISO’s interconnection queue, highlighting how many renewable gigawatts the footprint has lost out on because of limited transmission capacity.

The organization’s director, John Moore, said it’s important for regulators and policymakers to see where once economic renewable generation projects have evaporated.

“The primary reason we did this is the MISO doesn’t offer a lot of insights into the locations of these projects. And I don’t think people are aware of the projects that are growing and dying right in their backyards,” Moore said in an interview with RTO Insider.

The ma p displays in-progress and canceled projects on the county level. The Sustainable FERC Project found that 245 clean energy projects — or 40% of withdrawn projects over the past four and a half years — “had reached advanced stages of the generator interconnection process” when they were shelved. The organization said the projects could have generated 30.9 GW.

Michigan and Minnesota had the most withdrawn generation projects, the organization said. Michigan, which experienced a capacity shortage to meet local load obligations in this year’s MISO capacity auction, saw 42 projects worth about 5.1 GW abandoned from 2016 to 2020. Minnesota saw 36 projects that could have generated nearly 5 GW withdraw.

“It illustrates in another way that problem,” Moore said of the map. “Twice as many projects are falling out of the queue than normal because of the cost of integrating them.”

The Sustainable FERC Project said many developers are forced to scratch projects because of MISO’s inability to approve “large-capacity transmission lines and grid upgrades.” Moore said that while the cost of network upgrades isn’t the only reason for projects falling out of the queue, it’s become the most significant one.

MISO earlier this month announced it will embark in a series of long-range transmission studies that could produce project approvals as early as the end of 2021. (See MISO Processing Heftiest Interconnection Queue Ever.) The grid operator is also working with stakeholders to try to better line up its annual transmission planning with needed network upgrades that are identified in interconnection queue studies.

The MISO queue currently contains 756 projects totaling 113 GW, 64% of which is solar. It’s the grid operator’s largest-ever interconnection queue, with 353 project proposals representing about 52 GW of new generation entering in July alone.

Moore isn’t hopeful all that solar generation will see the light of day. He said MISO is late to arrive at the long-term transmission studies, and he predicted that many projects in the record-breaking queue will fall off.

“I’m still not hopeful because I don’t think the planning is keeping up with the queue,” Moore said. “The costs for the network upgrades are obviously far too expensive for any developer to absorb. So, no, I’m not hopeful.”

Clean Grid Alliance, Solar Energy Industries Association and the American Wind Energy Association said upgrade costs have been raising the cost of renewable generation projects in MISO West by more than 60% on average.

The Sustainable FERC Project’s map doesn’t yet include the lineup of new projects that entered in July, but Moore said his organization plans to update it and continue to keep tabs on unrealized projects for regulators and policymakers.

“Leaders aren’t familiar with the types of projects that are coming and going and trying to get on the system,” he said.

Moore said that though MISO is moving in “better directions” with a long-term transmission process approach and trying to coordinate grid planning, states’ clean energy targets could be compromised by project withdrawals. He pointed to integrated resource plans in Michigan and Minnesota, which order more renewables online while the two states see promising proposals vanish.

“Whatever the intention of utilities, the lack of transmission makes it significantly harder,” Moore said, adding that MISO could benefit from using longer-term study assumptions for both generator interconnection and transmission planning.

The Sustainable FERC Project pointed to EDP Renewables’ planned 100-MW wind farm in southwestern Minnesota that was dropped this year after MISO assigned the project an $80 million network upgrade cost — eight times what the developer expected.

EDP Origination Manager Vipul Devluk said the project could not absorb the cost burden. “Ultimately, we had to cancel our power purchase agreement discussions with the customer, and we had to relay to the local community that the benefits they were expecting from this project would not be forthcoming,” he said.

Moore said that even MISO South is susceptible to thwarted renewable megawatts because of MISO’s lack of transmission buildout. The map shows Mississippi lost nearly 2 GW in planned solar generation from 2016 to 2020.

“There is economic development and carbon-free energy being left on the table,” Moore said. “Once there were projects, and now there are none; once there were plans, and now they’re gone.”

MISO spokesperson Allison Bermudez said the RTO “continues to work with our stakeholders to determine the most cost-effective transmission investments needed to support future energy needs.” She declined to comment further on the map.

The RTO has said it can likely operate its system reliably with renewable penetration targets up to 50%, but only if members engage in dramatic transmission expansion. (See MISO Renewable Study Shows More Tx, Tech Needed.)

September 3, 2020

Expert Says Nuclear’s Future Lies in Small Reactors

Small, dispersed reactors are the nuclear industry’s best chance at future success and can forge a quicker path to zero-carbon electricity portfolios, one nuclear energy policy expert told her audience Tuesday.

Carnegie Mellon University researcher Jessica Lovering said the industry is making strides on small modular reactors (SMRs), light-water reactors, molten salt reactors, helium-cooled fast reactors and micro reactors. Those advancements could prove a renaissance for the nuclear industry, she said during a webinar on advanced nuclear technologies hosted by environmental policy nonprofit Resources for the Future.

nuclear Small Reactors — Jessica Lovering, Carnegie Mellon | *Resources for the Future*

Lovering said the first-ever small modular reactor is close to commercialization. Portland, Ore.-based NuScale Power’s SMR design last week passed the U.S Nuclear Regulatory Commission’s final review for design certification. NuScale said customers can now proceed with plans to develop their power plants. (See NRC OKs NuScale’s Small Modular Reactor Design.)

Micro reactors have much longer core lifetimes that can operate up to 30 years between refueling, Lovering said, and some advanced technologies come equipped with a lifetime core.

Other reactors can be designed so that the cores are already fueled when shipped from factories, Lovering said. When those reactors reach the end of their lifespan, she said, they can be packaged and sent back for either refueling or decommissioning.

“You ship the whole reactor back, and that’s good for communities that don’t want to deal with the whole refueling and decommissioning process,” she said. “This can really open up new markets in communities. … The waste won’t sit on site. It’ll go back to a central facility. Of course, that still leaves what the central company will do about disposal.”

Lovering said there’s much research and development on waste disposal and processing that is yet to be tackled.

Most small reactors have sealed cores to prevent access to the nuclear material, minimizing the risk of accidents or terrorism, she said. Lovering also said molten salt retains its liquid form even at very high temperatures, minimizing explosion danger.

“It’s really going to be up to proving the safety case to the regulators,” she said.

Lovering said nuclear capacity has stagnated in the U.S., hovering around 20% of generation since the 1990s. That share is at risk of retirement as electrification boosts energy demand, she said. More nuclear capacity should come online beyond the two plants under construction in Georgia, she argued.

The International Energy Agency estimates that global nuclear capacity needs to double by 2050 to meet aggressive carbon-reduction goals.

“Some of the big obstacles to building new nuclear … are really high cost and long construction times,” Lovering said. “They’re too big and expensive for deregulated markets.”

She said it’s no surprise that the only two new plants in construction, Georgia Power’s two additional units at Plant Vogtle, are in the regulated southeastern U.S. The Vogtle expansion has nearly doubled in price from the original $14 billion the Georgia Public Service Commission approved more than a decade ago. Last week, Georgia Power told the PSC that the project is on schedule, with the first unit set to go online in November 2021 and the second to follow a year later.

Lovering also noted that some states have moratoriums on new nuclear generation until the national waste disposal problem is addressed.

Communities with coal-fired plants set to retire in the next decade could be an ideal fit for a small nuclear reactor placed on the plant’s site, Lovering said. That would retain some jobs, she said, as even small, dispersed nuclear reactors will need staff.

“You can take advantage of the existing coal plant site and power lines,” she said, adding that some coal plant employees could be retrained to staff the reactor.

Micro reactors can also be installed to provide emergency services on existing grids, keeping hospitals and other essential services running in a blackout, she said.

Lovering also said it’s important to prolong the operation of existing nuclear plants for as long as they are safe and not let economic forces compel early retirements. She said as nuclear plants are decommissioned before their useful life ends, they lose their spot in the public consciousness as a viable option for zero-carbon energy resources.

“It’s a real shame to close any of them early. What we see is when they’re shut down, they’re often replaced with natural gas,” she said.

Lovering said the Nuclear Energy L eadership Act, introduced in Congress last year, could spark more industry growth. The bill would provide funding for two advanced nuclear reactor demonstration projects by 2025 and up to five such projects by 2035.

Talk of a Green New Deal in Congress has fostered an openness to new nuclear capacity, she added.

“That’s really driven by the reality on the ground,” Lovering said, noting that wind and solar generation continue to have a variability problem that needs solving.

September 3, 2020

ERCOT Reports Adequate Capacity for Fall

ERCOT said Wednesday it expects “adequate” installed capacity available to meet demand this fall and winter.

The grid operator’s final seasonal assessment of resource adequacy (SARA) for the fall forecasts a peak demand of nearly 61 GW, unchanged from the preliminary fall forecast. It expects it will have more than 86 GW of capacity available. That takes into account a generation-outage projection of 14.3 GW, based on the historical average of outages for weekday peak hours during the last three fall seasons.

ERCOT capacity — ERCOT is adding more solar resources than wind resources for the fall. | *ERCOT*

ERCOT has added 753 MW of solar capacity and 127 MW of wind capacity since the preliminary fall SARA. It also expects another 1.5 GW of planned wind and solar capacity to be online for the fall season (October and November).

“We study a range of normal to extreme scenarios prior to each season to determine whether there are any operational risks associated with meeting the forecasted peak demand,” Manager of Resource Adequacy Pete Warnken said in a press release. “At this time, our assessments show there will be adequate generation for fall and winter.”

ERCOT also released a preliminary SARA for the winter (December-February) that includes a peak-demand forecast of 57.7 GW, well below the winter demand record of 65.9 GW set in January 2018.

The assessment includes a low-wind scenario that will be used in all future seasonal assessments because of renewables’ growth in the ERCOT system. The grid operator reported a shade shy of 25 GW of installed wind capacity and 3.3 GW of installed solar capacity at the end of July, but its interconnection queue lists almost 77 GW of solar capacity and more than 25 GW of wind capacity in various forms of study.

Staff developed their peak-demand forecasts for fall and winter using revised Moody’s Analytics economic data obtained in April.

September 3, 2020

SPP Expands its Western RC Footprint

Still in its first year as a reliability coordinator in the Western Interconnection, SPP on Tuesday announced it will add 3.45 GW of generating capacity to its RC footprint in 2021.

The RTO said it will add eight generating resources that are part of Gridforce Energy Management ’s balancing authority in Washington, Oregon, Arizona, and New Mexico, effective April 1.

Gridforce operates primarily as a BA for independent power producers and electric utilities, but the company offers a range of other operational services. Three of its Arizona BAs are currently in SPP’s RC footprint: Griffith Energy, Arlington Valley and New Harquahala Generating Co.

Gridforce President C.J. Ingersoll said the company’s continued relationship with SPP will help its expansion and growth.

“Gridforce will continue to work with clients that receive reliability coordinator services from both SPP and [CAISO’s] RC West,” he said in a press release. “We are looking forward to continued focus on reliable system operations and the benefits of working with highly capable RCs.”

SPP launched its Western RC service in December 2019 for Gridforce and 14 other customers. It has been an RC provider in the Eastern Interconnection since 1998.

“We’re happy to see our reputation as a service provider of choice growing in the West,” said Bruce Rew, SPP’s senior vice president of operations. “We want the chance to prove ourselves just as we’ve done for Eastern utilities.”

SPP Western RC Footprint — SPP’s Western RC footprint will expand in April 2021. | *SPP*

Stakeholders Complete Work on WEIS Tariff

SPP is also developing a real-time balancing market in the West that is scheduled to launch Feb. 1. On Wednesday, the RTO’s Western stakeholders approved a final necessary revision request as staff work to refile with FERC a proposed Tariff for its Western Energy Imbalance Service (WEIS).

The measure (WRR6) completes the RTO’s response to a series of issues the commission raised in rejecting its first attempt (ER20-1059 , ER20-1060). (See FERC Rejects SPP’s WEIS Tariff.)

WRR6 provides that SPP will include constraints in its economic dispatch engine to use the combined transmission capability made available by market participants (MPs) and participating BAs on transmission facilities within a participating BA area or on transmission facilities used to transfer energy between participating BAs.

The revision was a holdover from last week, when the Western Markets Working Group and Western Markets Executive Committee held two joint meetings. The stakeholder groups were able to pass three other WRRs. (See SPP Stakeholders Agree on WEIS Tariff Changes.)

Both groups passed WRR6 unanimously after agreeing on language that clarified that “SPP, in its capacity as market operator,” would, before constraining market dispatch, receive communication from joint dispatch transmission service providers and other MPs.

FERC said any future WEIS market proposal “should include the mechanisms or agreements that will ensure that the SPP WEIS market respects the transmission capacity of nonparticipating entities with appropriate constraints in the [security-constrained economic dispatch].”

Much of the debate centered on whether or not to capitalize “market operator,” as it is not defined in the WEIS’ Tariff or protocols, and how Robert’s Rules of Order governed WRR6 motions from the week before.

“I’ll be an expert on Robert’s Rules one day,” joked Basin Electric Power Cooperative’s Valerie Weigel, the working group’s chair.

SPP staff said they likely need the Board of Directors’ authorization to refile the Tariff. They plan to first meet with FERC staff for a prefiling meeting later this month before scheduling a board meeting.

September 3, 2020

OTC Plants to Remain Open, Calif. Water Board Rules

Four aging natural gas plants scheduled to retire in December will keep operating because of California’s anticipated capacity shortfall, state water officials decided Tuesday.

The four members of the State Water Resources Control Board voted unanimously to reverse a prior board decision ordering the once-through-cooling (OTC) plants to cease operations by the end of this year, saying they are needed for grid reliability.

“This decision doesn’t come lightly to us as board members,” Chair E. Joaquin Esquivel said. But “there was always the understanding that we needed to balance [environmental concerns with] grid reliability.”

Tuesday’s ruling allows selected units at the Alamitos Generating Station in Long Beach, the Huntington Beach Generating Station in Orange County and the Ormond Beach Generating Station in Oxnard to operate for three more years, until Dec. 31, 2023. The Redondo Beach Generating Station in Los Angeles County got a one-year reprieve to Dec. 31, 2021.

The Alamitos (1,200 MW), Huntington (250 MW) and Redondo (850 MW) plants are owned by AES California. The Ormond plant (1,500 MW) is owned by GenOn.

The OTC plants use ocean water for cooling, killing billions of marine organisms, the water board found. In 2010, it ordered the phase-out of 19 OTC plants along the coast. Some plants retired, while others updated to air-cooling or alternative water-cooling technologies. The last four plants, built in the 1950s and 1960s, still use their original cooling designs.

California OTC plants — Alamitos Generating Station | *California Energy Commission*

The hulking plants loom over densely populated coastal communities, wetlands and sandy beaches. Many residents and elected officials want them closed because they are noisy, unsightly and polluting. Dozens spoke at Tuesday’s meeting, encouraging the board to adhere to its original plans.

However, the California Public Utilities Commission projected capacity shortfalls of 2,300 to 4,400 MW starting in the summer of 2021 and extending through 2023. Last year the commission ordered utilities to collectively procure 3,300 MW by August 2023, with 50% to come online by August 2021 and 75% by August 2022. It also recommended the water board extend the OTC compliance deadlines. (See California PUC Votes to Keep Old Gas Plants Operating.)

The three organizations that oversee energy in California — the CPUC, CAISO and the state Energy Commission — urged the water board to let the plants remain open until the new capacity could come online.

“These compliance date extensions would provide a bridge of about 3,740 MW in 2021, 2,230 MW in 2022 and 1,380 MW in 2023,” board staff said in their report.

California is on an ambitious course to supply 100% carbon-neutral energy to retail customers by 2045. It has ample solar generation but still needs thousands of megawatts of battery storage to let solar meet evening demand.

With fossil fuel generation retiring across the West, the OTC peaker plants help the state meet high demand on hot summer evenings after solar generation falls away. The rolling blackouts of Aug. 14-15 occurred under such conditions. (See CAISO Provides More Details on Blackouts.)

The board on Tuesday also voted to amend the retirement dates of the Diablo Canyon Nuclear Power Plant, California’s last nuclear generating station. It extended Diablo Canyon Unit 2’s closing date for eight months to August 2025 and shortened Unit 1’s retirement date by two months to November 2024.

“These revisions match the expiration date of each unit’s Nuclear Regulatory Commission operating license, as requested by the Pacific Gas and Electric Co. as part of its plan to retire Diablo Canyon,” the board said in a written summary.