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November 18, 2024

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SPP to Phase Out WEIS as New Market Offerings Expand

SPP said Wednesday it plans to eventually close its Western Energy Imbalance Service (WEIS) after current members join either its expanded RTO West or its Markets+ program, now under development, that will offer a bundle of RTO-like services.

“We don’t intend to have three different offerings in the West,” Kara Fornstrom, SPP director of state regulatory policy and a staff member working on Markets+ design, said in a briefing for the Western Interstate Energy Board.

The webinar gave Western utility regulators the chance to ask questions about the Markets+ program. Fornstrom made her comments while answering a question from Colorado Public Utilities Commission Chair Eric Blank.

“I just realized this a few days ago, that the WEIS market, the energy imbalance market, is at some point in the future going to sunset as entities join the RTO and the Markets+ day-ahead,” Blank said.

“I was just surprised that WEIS is going away,” he added.

Blank asked if Markets+ would also “sunset” or would be a “permanent option.”

Fornstrom said most of the WEIS’s current members “will have moved already to the RTO expansion … before Markets+ launches, so the WEIS will have shrunk before we get to Markets+, and the remaining entities in WEIS that we have today have expressed their interest … to go to Markets+ rather than just the [WEIS’s] real-time service.

The move is “based on [WEIS members’] interest level on adding the [Markets+] day-ahead service,” she said.

Markets+ will be a “long-term durable solution” in the West, Fornstrom said.

Later, Joe Fina, a stakeholder member of the Markets+ design team and assistant general counsel at the Snohomish County Public Utility District, said: “The WEIS will be replaced by Markets+.”

And SPP spokeswoman Meghan Sever said in an email to RTO Insider that it is “SPP’s intention to only provide one market offering in the West in order to provide maximum benefits for Western utilities. Current WEIS participants will have the option to join the RTO or participate in Markets+. Until then, SPP remains fully committed to continue providing Western reliability coordination and operating the WEIS market.”

Toe-to-toe with CAISO

SPP launched the WEIS, a real-time interstate trading market, in January 2021, making it the first RTO with energy markets in both the Eastern and Western interconnections. It intended for the WEIS to compete with CAISO’s larger and well-established Western Energy Imbalance Market (WEIM).

SPP has had some success competing with CAISO. In January, three Colorado utilities that had planned to join the WEIM instead decided to join the WEIS. Public Service Company of Colorado, Platte River Power Authority and Black Hills Colorado Electric followed Colorado Springs Utilities in switching allegiance from CAISO to SPP. (See Colorado Utilities Choose WEIS over WEIM.)

The WEIS, however, has gained fewer members than the WEIM, which was launched in 2014.

CAISO’s imbalance market has attracted 22 current or planned participants, including major utilities such as Arizona Public Service and NV Energy, while the huge Bonneville Power Administration is scheduled to go live next month. The WEIM has produced $1.93 billion in economic benefits for its members in the past eight years and is expected to cross the $2 billion mark with its next quarterly report. (See Western EIM Nears $2B in Total Benefits.)

With the addition of the Colorado utilities, WEIS has 14 current or future members including Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, Tri-State Generation and Transmission Association, Guzman Energy and the Western Area Power Administration’s Upper Great Plains West and Rocky Mountain regions and its Colorado River Storage Projects.

CAISO has been working to develop an extended day-ahead market (EDAM) as an additional offering to the WEIM, a real-time interstate market that was the first of its kind. CAISO also provides reliability coordination services through its RC West to most of the Western Interconnection.

The ISO, however, is limited by its one-state governance from becoming a Western RTO.

SPP also offers RC services in the West and is administrator for the Western Power Pool’s Western Resource Adequacy Program (WRAP). Once fully implemented, the WRAP will help Western balancing authorities respond to potential generation shortages during critical hours as the region addresses the retirement of thermal resources and its growing reliance on variable renewable resources. (See NWPP Rebrands as Western Power Pool.)

Unlike CAISO, SPP can offer full RTO membership to Western entities. It intends to expand its RTO footprint and develop a Western market system that is fully integrated with its existing market system.

The Markets+ program is aimed at utilities that do not want to join an RTO but need a range of services normally provided by an RTO, including day-ahead and real-time unit commitment and dispatch. SPP says Markets+ will provide easy transmission service across the footprint and set the stage for the reliable integration of renewable energy’s growth.

SPP presented the Markets+ model to interested participants during a virtual meeting in December and plans to hold in-person forums throughout the West. The RTO is gathering information from interested parties, including WRAP participants, as part of an extensive process leading up to the program’s launch. Wednesday’s WIEB briefing on program governance and other matters was part of that process.

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US Interstate Highways: A NIMBY-free Corridor for Grid Expansion?

An exhaustively researched report examining the use of the U.S. interstate highway system as a ready-made corridor for expansion of the nation’s high-voltage transmission system, as well as a broadband internet access, concludes it can be done relatively quickly and at a lower cost than siting new transmission corridors.

Prepared for the Minnesota Department of Transportation by Seattle-based NGI Consulting and The Ray, an Atlanta nonprofit, the 81-page analysis offers national conclusions. It argues that “NextGen Highways” ought to include buried HVDC transmission lines co-located with fiber-optic cables.

The recommendation to open interstate rights of way (ROWs) is in line with policy changes issued in 2021 by the U.S. Department of Transportation giving state DOTs the option to allow utilities to site energy infrastructure, including pipelines and even renewable energy projects, within interstate ROWs.

The release of the massive study also comes a year after the Biden administration announced the availability of $5 billion in loan guarantees to encourage the expansion of the grid, noting that decarbonizing transportation will require the grid to double or even triple in size.

The transportation sector accounted for 29% of carbon emission in 2019, more than power generation did, according to EPA, making transportation decarbonization a priority issue.

The report argues that state departments of transportation should:

      • “site and build fiber in a way that allows for buried HVDC transmission to be co-located at a later date;
      • “develop and invest in their relationship with utilities, public utilities commissions and other state agencies with transmission siting jurisdiction; [and]
      • “determine the amount of operational funding required to support the co-location of electric and communications infrastructure in their ROW.”

The report’s recommendation of underground HVDC power lines is no accident. HVDC power lines can move power long distances without line losses and without inducing currents in nearby conducting materials. And unlike AC lines, HVDC lines can connect systems operating at different AC frequencies. Yet few HVDC lines have been built in the U.S., according to the report.

“Unlike the U.S. Interstate Highway System, the U.S. power grid is composed of many discrete regions. Modeling study after modeling study has shown that connecting these regions is critical to cost-effective grid decarbonization,” the report states. “It is also critical for grid reliability and resiliency.

“Despite the importance of connecting the electric grid regions using interregional transmission lines, project after project has failed in the U.S. Since 2014, the U.S. has not built a single gigawatt of interregional transmission capacity. Meanwhile, China, Europe, South America and India have collectively built nearly 350 GW of interregional transmission capacity.

“Most recently, the construction of the New England Clean Energy Connect transmission line was stopped indefinitely by a public referendum in November 2021. This was an incredible result given that the New England Clean Energy Connect had already received the required regulatory approvals and was in the process of being built.”

One of the most important conclusions of the study is that decarbonizing the grid itself — moving clean power to where it is needed, particularly for charging electric vehicles — will be less costly using HVDC transmission lines.

“As seen in Europe and now in New York state, buried HVDC transmission is being used to build the interregional transmission required to cost-effectively and reliably decarbonize the electric grid,” the report said.

And in one of the dozens of supplemental documents attached to the report, the analysts explain in more detail that “many of the richest wind and solar resources are located far from the urban load centers where most of the country’s energy is consumed. The nation’s transmission infrastructure must at least double to accommodate the exponential growth of wind and solar that will accompany decarbonization.

“Without the addition of significant multiregional transmission, system planners will need to overbuild local renewable resources in order to manage weather patterns and meet demand, resulting in extreme curtailment of local wind and solar resources, even if high levels of storage capacity are available, dramatically increasing costs.”

Additionally, the expected development of solid-state converters to replace conventional transformers will allow for the development of medium- and high-voltage charging stations, the report postulates, further arguing that the buildout of HVDC converter stations will create “economic development zones … logical locations to site fleet and over-the-road EV charging infrastructure and data centers.”

While the study makes national recommendations, its analysis initially focuses on state DOTs because they control highway corridors and ROWs.

Most states, including Minnesota, have not permitted overhead transmission lines to run along highways because of the possibility of vehicular accidents. Many states limit transmission line intrusions to crossing over highways, the report found.

Wisconsin is one of the few states that does allow transmission lines to parallel highways inside the ROW and, according to the report, has permitted the construction of an overhead line to run inside an ROW after state lawmakers approved the practice in 2003.

That legislation requires utilities and grid companies building new transmission to first consider existing utility corridors and then highway and railroad corridors and even recreational trails before seeking to establish new utility corridors. The Wisconsin Department of Transportation (WisDOT) then amended its policies to reflect the new law, as did the state Public Service Commission (PSCW).

“In 2009, as a result of Act 89, WisDOT’s updated utility accommodation policy, and the development of new transmission infrastructure, WisDOT and PSCW entered into a cooperative agreement ‘to ensure that whenever practical, WisDOT and PSCW shall utilize existing transportation or transmission corridors instead of creating new corridors for electric transmission facilities.’ …

“The legislation, policy and agreements described [here] have fostered a collaborative and trusting relationship between Wisconsin utilities and WisDOT and have resulted in the efficient, cost-effective and successful siting of over 800 miles of transmission infrastructure in and along interstate and highway ROW in Wisconsin,” the report notes, adding that “Wisconsin has the playbook for siting transmission in DOT ROW.”

The Great Plains Institute, based in Minneapolis; Satterfield Consulting in Madison, Wis.; 5 Lakes Energy of Lansing, Mich.; and consultant Tracy Warren in D.C. assisted with the research and release of the report.

In a statement, Morgan Putnam, founder of NGI Consulting, announced the release of the report and what the team expects to do next.

“Given the positive findings from this study, we will be launching a NextGen Highways Coalition later this year. The coalition will facilitate conversations between state DOTs, transmission developers and governors to support the co-location of buried fiber and transmission in highway and interstate ROW.”

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SERC Urges Industry Effort on Facility Ratings

A new report released Wednesday by SERC aims to help “registered entities … reduce the risk of facility ratings challenges, resulting in a more reliable and secure” bulk power system.

The report, “Facility Ratings Themes and Lessons Learned,” was inspired by the “hundreds of individual instances” of violations of NERC reliability standard FAC-008-5 (Facility ratings) and its predecessors that SERC has logged since 2017. SERC based its analysis on data from those violations, as well as information “gathered through [its] various voluntary outreach and training activities.”

Improper facility ratings are a frequent source of compliance issues in SERC and other regions: FERC last year approved a $570,000 penalty leveled by ReliabilityFirst against American Electric Power over misratings at nearly 600 facilities. (See AEP to Pay $570K in NERC Penalties.) WECC also lodged a $265,000 settlement with Public Service Company of New Mexico over facility ratings issues last year, and SERC settled with the Tennessee Valley Authority for the same reason in March. (See FERC OKs $265,000 PNM Penalty.)

At SERC’s Board of Directors and Members meeting last month in Savannah, Ga., the regional entity’s vice president of operations, Tim Ponseti, said the frequency of facility ratings violations was becoming a source of concern for the ERO Enterprise and prompted the report. (See SERC Board of Directors/Members Briefs: March 30, 2022.) With the growing risk of extreme weather from climate change, as well as the ongoing adoption of new generation resources, the RE felt it was necessary to address the reasons behind the issues.

“Facility ratings have a far- and wide-reaching impact [on] daily operations: real-time analysis, next-day planning, long-term planning, modeling … and the list goes on,” Ponseti said. “All these areas are making critically important decisions, and at their fundamental basis is a reliance on an assumption of accurate facility ratings.”

Utilities Lack Awareness of Own Systems

The report identified three major themes associated with the majority of the FAC-008 violations encountered by SERC in the last five years. Each theme was considered the primary cause of about a third of the infringements studied. While the document identified “potential mitigation strategies” for each issue, SERC emphasized that these should not be considered binding requirements or directives for industry.

The first theme, accounting for 28% of violations, was lack of awareness, which SERC defined as the absence of “an accurate physical accounting or understanding of the current-carrying equipment” within a utility’s system. Failure to develop and implement a facility ratings program also falls under this category.

When this occurs, entities tend to rely on rating information provided by equipment manufacturers, nameplate ratings or outdated field inspection reports. Without frequent inspections, inaccurate ratings may “go undetected for a long duration.”

SERC suggested addressing this issue by enhancing the engagement and oversight of senior management, urging leaders to “set a positive ‘tone at the top’ by creating a culture … that treats facility ratings as a program — like safety — and not like a one-time project with a finite start and end date.” This approach includes establishing a level of engagement with the entity’s RE and with NERC; the report noted that the ERO Enterprise has performed “a significant amount of outreach” to industry regarding facility ratings and that keeping up with these efforts could help utilities build awareness of potential deficiencies in their programs.

Periodic field validations are an essential component of a facility ratings program that is too often neglected, SERC said. As equipment is replaced in the field during restoration from extreme weather events, entities must ensure that they are not simply reusing the same ratings, which may not apply to the new items. Physical walk-downs can also help to spot equipment that an entity may have lost track of after a merger or acquisition.

Asset, Data and Change-management Challenges

Another theme identified in the report, and comprising 34% of violations, is inadequate asset and data management. Asset management is defined as the identification, management and tracking of physical facility ratings assets, while data management is the collection, validating and storage of ratings-connected data.

Managing assets and data can be challenging, because physical assets can range in size from very large to extremely small and may also be located in places that are physically difficult to inspect; data are often stored by the same departments that use them, for which storage is not necessarily a priority. This means that when data are needed during an audit or review, a utility may face delays tracking them down.

Mitigation strategies for asset and data management include periodic field verification programs, as well as effective data capture and verification strategies and spreadsheets or databases to store information properly. Entities must also include contractors in their strategies and make sure they are also trained in the proper data management schemes.

The third theme is inadequate change management, which SERC said enables “facility and equipment rating changes to be captured, coordinated and implemented throughout the entity in a timely manner.” Failure to properly track changes to an entity’s equipment can create an inaccurate assessment of its system, leading to breakdowns at critical moments.

SERC described a case when a generator owner and transmission owner installed a new transformer at a facility, replacing a transformer that had been the most limiting element there. The new component had a higher rating and was therefore no longer a limiting element; however, the utility failed to account for this by updating its facility rating. In another case, a transformer was shared between two units. The utility retired one of the units and reconfigured the high-voltage bus, but nobody thought to adjust the facility ratings.

The report’s authors recommended implementing a strong change-management process that provides “clear roles and responsibilities,” as well as a quality assurance review process for each change. The process should be communicated to personnel through regular training and verified through field inspections, they said.

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E-ISAC Warns of Escalating Russian Cyber Threats

Staff at the Electricity Information Sharing and Analysis Center (E-ISAC) warned this week that Russia’s electronic warfare teams are becoming more aggressive, both in their attacks against Ukraine and in their willingness to punish the country’s perceived allies worldwide.

“They will use a number of tools in their toolkit, including dis- and misinformation, as well as cyber and physical attacks against critical infrastructure, including the grid in North America,” Matthew Duncan, director of intelligence at the E-ISAC, said during Thursday’s regular Talk with Texas RE webinar. “We know this because they have done it before, whether it was in Ukraine in 2015 and 2016, or this week.”

By “this week,” Duncan was referring to the revelation on Wednesday of a new breed of malware with the ability to gain full access to a wide range of industrial control system (ICS) and supervisory control and data acquisition (SCADA) devices. The threat was first publicized by cybersecurity firm Dragos, which called the new malware “Pipedream” and its developer “Chernovite”; the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency confirmed the discovery separately in a joint statement with the FBI and National Security Agency.

Pipedream makes use of “custom-made tools for targeting ICS/SCADA devices,” CISA said in its advisory; in particular, the malware targets programmable logic controllers (PLC) from Schneider Electric and Omron Automation, along with Open Platform Communications Unified Architecture (OPC UA) servers. PLCs are computer systems that constantly monitor the state of input devices and control the state of output devices, while OPC UA is an open-source standard for data exchange between sensors and cloud applications.

The malware is deployed once attackers have established a foothold in an operational technology (OT) network. Attackers can use the bug to look up details on the target device, upload malicious configurations and code, backup or restore its contents, and modify its parameters. They can also “move laterally within an IT [information technology] or OT network and disrupt critical devices or functions.”

Dragos believes Pipedream has not yet been deployed in the wild, calling it “a rare case of accessing and analyzing malicious capabilities … before their deployment and … a unique opportunity to prepare in advance.” The same cannot be said of another threat exposed this week by Ukraine’s Computer Emergency Response Team (CERT), an apparent sequel to the Industroyer malware used by Russian attackers to devastating effect against Ukraine’s energy sector in 2016.

In the first Industroyer attack, hackers managed to knock about 20% of Kyiv’s power grid offline for about an hour; the U.S. Department of Justice later brought criminal charges against six Russian military intelligence officers believed to be involved in the attack. (See Six Russians Charged for Ukraine Cyberattacks.) Unlike the earlier incident, this week’s hack — dubbed “Industroyer2” — was apparently foiled before any outages were caused. However, Duncan warned that the incident shows the seriousness of the ongoing threat.

“Analysts reported clear similarities between the components of [the first] Industroyer and the sequel that was announced this week, and they have high confidence that the new malware was created by the same authors: this Sandworm team [from] the Russian military intelligence,” Duncan said. “But the exact capabilities of this new grid-focused malware specimen remain far from clear, and I suspect we will see more information coming out about this in the coming days.”

Against the rising threat level, Duncan praised the U.S. government for ramping up its efforts to disrupt operations against domestic targets; in particular, he pointed to the FBI’s announcement last week that it had shut down a Russian government-operated botnet — a group of thousands of devices with malware that allows hackers to use them for coordinated cyberattacks — before it did any harm. He urged private sector organizations to work with each other and with the government to ensure that threats are spotted quickly.

“It’s good to see that the government is being proactive and engaging the adversary on this, and that’s why it’s really important to share information with government partners [and] with the E-ISAC to make sure we’re [connecting] those dots,” Duncan said.

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Ariz. Regulators Reject Expansion of SRP Gas Plant

Arizona regulators have rejected Salt River Project’s proposed expansion of the Coolidge Generating Station, a gas-fired power plant in Pinal County, citing concerns about the impacts on the nearby Randolph community.

The Arizona Corporation Commission voted 4-1 on Tuesday to deny a Certificate of Environmental Compatibility for the project.

The expansion would have added 16 gas turbines to the Coolidge plant with a combined capacity of 820 MW. The generating station’s current capacity is 575 MW from 12 single-cycle turbine units, according to SRP’s website.

SRP said the project is needed to meet growing energy demand as more residents, manufacturers and industrial users move to the area. The utility is forecasting growth in peak demand of about 16% by 2025, or roughly 1,200 MW.

In addition, the expansion would provide reliability to support the addition of renewable energy, SRP said.

Commissioner Sandra Kennedy agreed that additional capacity is needed but said it doesn’t have to come from “a polluting fossil-gas facility.”

“An investment of $1 billion … on fossil-fuel infrastructure in 2022, when that money could instead be used to accelerate clean energy technology, is a tragic displacement of funds,” Kennedy said.

Incomplete Info Alleged

Commission Chair Lea Márquez Peterson said SRP didn’t provide complete information on the project.

SRP did not issue an all-source request for proposals for the expansion, saying it had previous RFPs that provided enough data, according to an order approved by the commission. But data from the past RFPs allegedly were not submitted as part of the record in the application.

A required power flow and stability study also wasn’t provided to the commission, according to the order.

And even though SRP contracted with E3 to see how much solar plus storage would be needed to provide the same reliability as the natural gas expansion, the utility didn’t provide the complete study to the commission’s Line Siting Committee or to the SRP board before a vote to move ahead with the project, the order stated.

Commissioner Justin Olson was the lone “no” vote on denying the expansion. He said natural gas is a key component in the expansion of renewable energy because it provides reliability at times when renewable energy is not available.

“If we are going to eliminate any natural gas energy generation, or any expansion of it, we are not going to have the ability to meet the energy demands of Arizona residents,” Olson said. “We’ve seen this happen in California.”

SRP didn’t respond to a request for comment on Thursday. But following Tuesday’s vote, SRP said on its website that it would “continue to evaluate what generation and market options to pursue in the near term to address the resource challenge this decision creates for serving our customers with reliable, affordable, sustainable energy.”

Historic Community

Construction of the Coolidge Generating Station was completed in 2011. SRP bought the plant in 2019.

The power plant is near the community of Randolph in unincorporated Pinal County.

Commissioner Anna Tovar noted the historic significance of Randolph, which she described as a Black community founded in the 1920s by people who came from Arkansas and Oklahoma to pick cotton. Because they weren’t allowed to buy property in nearby Coolidge, they settled in Randolph instead.

“I do not believe it is wise to put further pressure on this community to relocate,” Tovar said. “The history is important, and we shouldn’t lose that.”

And even though SRP had made progress in mitigating impacts of the proposed project, Tovar said it wasn’t enough.

“The increase in emissions, when combined with the pre-existing environmental and air quality issues, will result in an unacceptable total environment for the Randolph community,” she said.

Reaction from environmental groups to the commission’s vote was positive.

Adam Stafford with Western Resource Advocates called the decision “a win for climate action and environmental justice in Arizona.”

“It’s time for SRP to find clean alternatives and revisit its sustainability goals to adopt mass-based emissions reduction targets in line with what scientists say is needed to avoid the worst effects of climate change,” said Stafford, who is WRA’s managing senior staff attorney in Arizona.

Ellen Zuckerman with the Southwest Energy Efficiency Project also applauded the decision.

“At a time when far too many Arizonans are making painful economic decisions and falling behind on their bills, we simply cannot rubber-stamp $1 billion for improperly rushed and poorly vetted projects.” Zuckerman said in a statement.

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BPA Foresees No Capacity Deficits in Binding WRAP

The Bonneville Power Administration should have enough generation to avoid capacity deficits if it decides to join the “binding” phase of the Western Resource Adequacy Program (WRAP), the federal power marketing agency said Wednesday.

Participation in the WRAP will also have little impact on BPA’s marketing of surplus power, Steve Bellcoff, a BPA public utilities specialist, told customers during a public meeting Wednesday.

Surplus sales are a key source of BPA’s revenue, helping to defray overall system costs and reduce prices for the agency’s “preference” customer base of publicly owned utilities.

BPA has already committed to participating in the initial “nonbinding” phase of the Western Power Pool’s WRAP, scheduled to roll out in the third quarter of this year. In that phase, participants will be asked to offer “forward showings” of resource adequacy and availability seven months in advance of the summer and winter capacity periods but will not be penalized for failing to meet their requirements. (See NWPP RA Program Taking Shape for Q3 Launch.)

The agency has yet to issue a decision on whether to join the binding WRAP, which will impose penalties on participants that fail to close capacity deficits ahead of operating days.

“It’s in the coming months that we’ll start to get to a point where we’re looking at the contemplation of a decision to join for Bonneville,” Russ Mantifel, BPA Director of Market Initiatives, said during Wednesday’s meeting.

During the meeting, Bellcoff described some key — albeit surmountable — challenges to how BPA can ensure that it has enough capacity to meet its WRAP obligations. The difficulties arise, in part, from conflicts between WRAP processes and how the agency manages a hydroelectric system subject to the vagaries of weather.

Bellcoff explained that BPA begins its forecasting from the resources side, examining historical stream flows, applying current constraints and operations, then modeling the expected energy available from its hydro resources to determine how much load can be served.

On the other hand, the WRAP forward showing capacity requirement starts with the P50 (50% or higher probability) load forecast, and then adds a planning reserve margin (PRM) to that forecast.

“So everything that is done [for the WRAP] is on the opposite side of what we do today,” Bellcoff said.

Misaligned Timelines

Further complicating matters is the misalignment between WRAP timelines and BPA planning and forecasting horizons. The WRAP requires participants to submit forward showings by March 31 for the following winter season. Bellcoff noted that BPA doesn’t begin its hydro modeling for the following winter until June, months after that submittal.

“Prior to our first modeling for the next water year, we don’t have any idea what our water looks like in March or the following winter,” Bellcoff said.

Similarly, the forward showings for the WRAP’s summer season are due the previous Oct. 31, the start of the water year in the Pacific Northwest.

“The water forecast in October can be drastically different than what we would see in the spring, and those are important things because, in October, we’re still pretty conservative [in projecting] for the following summer,” Bellcoff said.

“There’s just way too many variables in our water year planning to establish at the forward showing seven months in advance of the seasons that we have vital knowledge on what our hydro looks like,” he said.

The conflicting timelines mean that BPA must rely on estimates from its long-term planning process to calculate expected capacity figures for the forward showings. Despite that complication, BPA’s own scenario planning suggests the agency has enough resources at its disposal to avoid capacity deficits along any of the WRAP’s operational timelines.

Bellcoff said the projected PRM requirements for the WRAP, based on data produced for the nonbinding phase, are 16% for winter and 12% for summer. For BPA that translates into PRMs of 1,102 MW and 768 MW, respectively.

“That’s what gets added to the load,” he said. “Those numbers are well within that wide-variety range that we look at today and plan for on the resource side, so they’re all within the uncertainty we plan for today.”

Bellcoff said that BPA also does not expect the WRAP to affect how its power operations department and trading floor work together to develop marketing strategies to deal with energy and capacity surpluses and shortages.  And because BPA does not foresee capacity deficits, it does not expect WRAP to affect its marketing of surplus power to benefit preference customers.

A slide presented at Wednesday’s meeting summed up BPA’s perspective on the issue: “The capacity obligation associated with PRM is within today’s range of resource and load variability. In advance of any specific condition, it is not known when, or if, the forward showing capacity requirement would become additive to BPA’s trading floor’s existing risk tolerance.”

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MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest

[EDITOR’S NOTE: This story was updated on Friday, April 15, 2022, to include comments made by MISO officials and stakeholders during a teleconference that day.]

MISO’s 10th annual Planning Resource Auction (PRA) saw all its Midwestern zones clearing at the nearly $240/MW-day cost of new entry (CONE), signaling the prospect of temporary outages and a dire need for additional generation.

Zones 1 to 7 — which include the Dakotas, Illinois, Indiana, Iowa, Kentucky, Michigan, Minnesota, Missouri, Montana and Wisconsin — all cleared at $236.66/MW-day in the 2022/23 capacity auction, MISO announced Thursday. Zones 8 to 10 — Arkansas, Louisiana, Mississippi and Texas — did not feel the pinch and cleared at $2.88/MW-day.

MISO said that even with nearly 97 GW worth of offers, 1.3 GW of resource contributions external to MISO and 1.9 GW worth of imports from MISO South, MISO Midwest remained a little more than 1.2 GW short of its 101.2-GW planning reserve margin requirement.

The RTO said 8 GW in its North and Central regions were exposed to the CONE clearing price. MISO’s load-serving entities that don’t have enough contracted capacity to cover their load obligations use the PRA. During a teleconference with stakeholders on the results Friday, MISO Director of Resource Adequacy Coordination Zakaria Joundi said that only 8% of load participated in the auction this year. Participation in the PRA is voluntary.

Ahead of the 2022/23 planning year, MISO anticipated a 121-GW coincident systemwide peak, with 157 GW in total installed capacity and just short of 128 GW in total unforced capacity.

The grid operator attributed some of the shortfall to post-COVID load increases.

It also said that even though it has about 4 GW more worth of installed capacity footprint-wide than it did in 2018, it has about 8 GW less in accredited capacity, reflecting an uptick in intermittent generation and retiring thermal generation. Unless members build more capacity that can reliably generate, MISO said, “shortfalls such as those highlighted in this year’s auction will continue.”

Joundi said that although MISO is maintaining “decent amount of installed capacity,” accredited capacity “keeps going down.”

He said as generation retirements and suspensions were being replaced with lower-accredited renewable resources, MISO demand levels rebounded as the nation emerged from the worst of the pandemic.

“We couldn’t find enough capacity in the North-Central region,” Joundi said.

MISO’s South-to-Midwest transfer limit bound in the auction, limiting imports that could pass to the north, Joundi said. The South finished the auction with about 2 GW of surplus.

“This is an outcome we’ve been worried about for a decade,” MISO Independent Market Monitor David Patton said. He said the capacity auction’s vertical demand curve — which values reliability requirements over economics — doesn’t produce efficient enough economic signals and has caused generation that should be otherwise economic to retire. The Monitor has been a vocal proponent of a sloped demand curve for years.

“We obviously have been sounding the alarm for some time,” Michelle Bloodworth, CEO of coal trade organization America’s Power, said of thermal retirements. She said she foresees a worsening retirement crisis over the next decade.

In a press release, the RTO said it “remains committed to continue its work with members and state regulators to maintain grid reliability.”

“We have anticipated challenges due to the changing energy landscape and have communicated our concerns. … We have prepared for and projected resource fleet transformation, but these results underscore that more attention is required to offset the rate of acceleration,” MISO CEO John Bear said. “These results do not undermine our ability to meet the immediate needs of the system, but they do highlight the need for more capacity flexibility to reliably generate and manage uncertainty during this transition.”

MISO said zones 1 to 7 will head into the June 1 start of the planning year with a chance of temporary load shedding. Joundi told stakeholders to prepare for more frequent emergency procedures throughout the planning year. He also said MISO is evaluating the resource forecasting information it receives from members.

“The reality for the zones that do not have sufficient generation to cover their load plus their required reserves is that they will have increased risk of temporary, controlled outages to maintain system reliability,” MISO President and COO Clair Moeller said. “From a consumer perspective, those zones may also face higher costs to procure power when it is scarce.”

Patton has reviewed and certified the auction results.

Coalition of Midwest Power Producers representative Travis Stewart said the results were a bit of a head-scratcher, as the Midwest appeared to have sufficient capacity based on unforced capacity values heading into the auction. He said it seemed that more market participants are holding back supply up to MISO’s 50-MW withholding threshold, but Patton said he didn’t discover any withholding that would run afoul of MISO’s rule.

The price separation between MISO Midwest and South in previous auctions became even more pronounced this year. In the 2021/22 auction, zones 8 to 10 cleared at an all-time low of 1 cent/MW-day, while zones 1 to 7 cleared at $5/MW-day. (See MISO Capacity Auction Values South Capacity at a Penny.)

This is the second time CONE has made an appearance in the PRA. Zone 7, which covers MISO’s territory in Michigan, was MISO’s first local resource zone to clear at the then $257.53/MW-day CONE, in the 2020/21 auction.

The Organization of MISO States and MISO’s joint annual resource adequacy survey in 2020 warned of possible capacity shortfalls in the Midwest by 2022. However, by 2021, the survey had moved the risk into 2023. (See OMS-MISO Survey Sees Uncertain Supply Future and 2021 OMS-MISO Resource Adequacy Survey Shows Less Cause for Concern.)

“We didn’t necessarily expect this outcome to happen this year,” Joundi said. He reminded stakeholders that the OMS-MISO survey is a snapshot in time, and circumstances have changed since the last one. “Slight surpluses did erode.”

MISO said this year’s auction results show a need for market redefinition and more efforts to make resources more available. It could also be one of MISO’s last single annual capacity auctions. The grid operator has filed for FERC permission to conduct four seasonal auctions beginning in 2024. It has also asked to implement a minimum capacity requirement, in which LSEs must demonstrate that they’ve secured half of their load obligations prior to the auction. Last month, FERC issued MISO a deficiency notice for outstanding questions of the design. (See Deficiency Notices for MISO’s Seasonal Capacity Auctions Bid.)

At a Feb. 28 executive update with stakeholders, MISO General Counsel Andre Porter said the RTO’s seasonal auction and long-range transmission planning are meant to ensure it has adequate reserves amid changing resource portfolios and increasingly unstable weather.

“Even while we wait, volatility and uncertainty continue,” Porter said of FERC’s decision time on the seasonal auction. He said MISO is encouraging states to scrutinize their resource adequacy plans to make sure they’re appropriate for a changing landscape.

But Patton said that the long-range transmission plan will only help auction results if a project increases the transfer capability between Midwest and South. MISO doesn’t plan on addressing the constraint in the long-range transmission effort anytime soon.

Patton said the RTO should consider asking for greater flow capacity between the South and Midwest when it next refreshes the transmission use agreement it has with SPP and other parties. “That is something we should think about as that agreement gets renegotiated.”

Some stakeholders called for an operational analysis of adding transmission capability between the regions.

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MISO Focuses Stakeholders on $10B LRTP Projects

MISO convened a special meeting of its Planning Advisory Committee Wednesday to underscore the urgency for $10 billion in long-range transmission projects in its Midwestern region.

Jarred Miland, the RTO’s senior manager of transmission planning coordination, stressed the grid operator’s pressure to build transmission as members’ generation portfolios transition to cleaner resources.

“The resource portfolio has been changing rapidly over the past 10 years and reliability will become increasingly difficult as renewable energy increases across the footprint,” Miland told stakeholders.

He said the long-range transmission portfolio (LRTP) seeks to “provide an orderly and timely transmission expansion effort that supports key goals,” including keeping system performance reliable in greater supply volatility and accessing lower-cost and cleaner energy.

MISO’s first set of long-range projects could be the largest portfolio of regional projects ever proposed in the U.S. The grid operator has projected that the $10.4 billion package will yield anywhere from $23 billion to $52 billion in financial benefits over the projects’ 20- to 40-year lifespans, resulting in a 2.6:1 overall benefit-to-cost ratio. (See MISO Updates Stakeholders on $10B Long-range Tx Package.)

The LRTP is broken down into six groupings of 18 line segments. Staff assumes all projects will be built by 2030.

First cycle of long-range transmission plan (MISO) Content.jpgProjects under the first cycle of MISO’s long-range transmission plan | MISO

 

Miland said “work is still ongoing” to determine whether some segments will be open to competitive bidding. MISO plans to post a draft list of the portfolio’s competitive facilities by June 1.

Staff calculated the portfolio’s benefits by quantifying transmission’s ability to solve reliability issues, reduce congestion and fuel costs, avoid new generation and other transmission investments, trim reserve margins, avert loss-of-load events and meet utility and state decarbonization goals.

MISO adviser Joe Reddoch said the RTO played it conservatively when approximating the projects’ benefits and did not overstate savings. He said although the level of benefits will differ between Midwestern transmission pricing zones, they all stand to receive benefits.  

While WEC Energy Group’s Chris Plante worried aloud that the LRTP’s benefits were too optimistic, Sustainable FERC Project attorney Lauren Azar said the identified list of benefits was probably “too narrow.”

Clean Grid Alliance said the projects can enable the additional 52.7 GW of renewable power projected in the most conservative of the  three planning scenarios. That would power about 12 million homes and support 213,000 jobs, the group said.

Stakeholders asked whether MISO has accounted for the spiking costs of building materials and labor.

Aubrey Johnson, vice president of system planning, said staff will update cost estimates over the next month, but that he doesn’t expect the figures to change much. He said MISO was cautious from the start when estimating project costs and said he only expects “fine-tuning around the margins.”

The Planning Advisory Committee will vote on whether to recommend the portfolio to the Board of Directors during a May 27 meeting. The board will vote on the portfolio on July 25.

Determining LRTP’s Effect on the Interconnection Queue

MISO is determining how long-range projects will interact with its generator interconnection queue.

During a Monday Interconnection Process Working Group, MISO’s Jesse Phillips said staff is planning to monitor when new generation projects making their way through the queue are affected by a long-range transmission project.

Phillips said if a project is found to resolve a constraint found in network upgrade studies and is approved by the board within a year of an interconnection customer striking a generator interconnection agreement, the customer will not be financially responsible for transmission upgrades. He said the generation project will then be contingent upon the transmission project instead of a network upgrade.

Generation projects that entered the queue as early as 2017 could be affected by the new considerations, Phillips said

Stakeholders expressed doubts that the long-range projects will be built in time to support new generation projects advancing through the queue. Several pointed out that the transmission projects don’t have specific in-service dates yet.

Some also asked whether MISO would consider reinstating projects to the queue that were previously priced out by high network upgrades. Before staff embarked on their long-range planning, some stakeholders criticized the RTO for placing the system expansion’s financial burden on generation developers.

Phillips said staff is in the early stages of analyzing how they should treat projects affected by the LRTP. He said MISO is accepting written opinions through April 29 on how to integrate long-range projects into interconnection studies.

The discussion came as generation projects are experiencing multiple delays in the interconnection queue’s definitive planning phase. MISO is also trying to get a feel for how many developers are lining up to enter the queue this year. Staff are asking developers for a heads up on whether they plan on submit projects by the Sept. 15 deadline.

MISO said the submittals will be used for resource forecasting and won’t supplant the need for a queue application. It also said the information developers share will be non-binding and confidential.

In March, the queue contained 848 projects totaling 133 GW of installed capacity. Solar projects accounted for 62% of the capacity, with wind, storage and hybrid formats each responsible for 11%.

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177-MW Morris Ridge Project Builds Buzz for Solar Beekeeping

A study of EDF Renewables’ 177-MW Morris Ridge project in Western New York is gaining attention for its innovative take on designing utility-scale solar with a purposeful plan for beekeeping and honey production.

The emerging agrivoltaic practice of solar beekeeping seeks to find synergies in land use in agricultural areas, according to Mary Kate MacKenzie, business manager for Sweet Grass Meats in Naples, N.Y., and co-author of the report “Co-locating Solar and Agriculture at the Morris Ridge Solar Energy Center.”

“We’re going to be seeing a lot of change in some of our agricultural landscapes as solar expands in the coming years, so solar beekeeping is an opportunity for the same piece of land to support solar energy production as well as an agricultural enterprise,” she said during a large-scale agrivoltaics webinar hosted by United Solar Energy Supporters on Tuesday.

EDF won a contract from the New York State Energy Research and Development Authority to build the Morris Ridge solar facility on 1,000 acres of leased land previously farmed for crops, such as corn and soybeans. The developer plans to incorporate agrivoltaic practices into the project, which is slated for commissioning next year.

To support that plan, the town of Mount Morris commissioned the Morris Ridge study to understand the opportunities for sheep grazing and beekeeping on the property. The study was selected for a poster presentation at the AgriVoltaics2022 Conference in Italy in June.

“It feels pretty nice that we went from first time on the drawing board to being a poster child, you could say, for sheep and bees,” said Town Supervisor David DiSalvo. “I’m hoping we have a couple of herds and a lot of beehives to be one of the leading producers of honey in New York.”

Bee-friendly Takeaways

Honey production is an $11 million/year industry in New York, and the value of honeybee commercial pollination services can reach up to $400 million/year, according to MacKenzie.

Utility-scale solar developers interested in attracting beekeepers to their facilities can take a few key points from the Morris Ridge study, she said.

The top consideration for developers is to understand the factors that will support a strong operating profit margin for the grouping of bee colonies known as an apiary.

“Beekeepers really need a minimum honey yield for an apiary to be economically viable,” MacKenzie said. “If you, as a developer, want to recruit a beekeeper to your site, you need to convince them that the honey yield will be there.”

Predicting honey yield requires an intimate knowledge of the solar facility’s landscape composition.

Vegetation in the landscape affects honeybee productivity, including how much pollen they collect and how healthy they are, MacKenzie said. The facility needs to provide the right plants for pollen collection and not expose bees to dangerous insecticides used for crop management within their foraging range.

While the study found that the Morris Ridge site does not currently have the ideal landscape composition for a profitable apiary, EDF plans to make changes that MacKenzie said will help.

“The intent of the developer is to establish permanent pasture on the site under and around the solar panels, as well as some pollinator-friendly plantings in the buffer zones across the site,” she said.

Developers will also need to understand that their approach to the business of beekeeping will be different than how it’s traditionally done.

“Beekeepers are rural folks who take great pride in having longstanding relationships with landowners, but they’re often just handshake agreements,” MacKenzie said. The study, she added, recommends that solar developers create a mutually beneficial relationship with beekeepers through written agreements.

A survey of local beekeepers used in the study found that most respondents had positive attitudes toward solar beekeeping. One respondent, however, did not believe the landscape would have the criteria he looks for in an apiary site.

“The key here is understanding what beekeepers look for and ensuring that you can provide that and communicate that as you’re trying to recruit someone to work with you,” MacKenzie said.

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PG&E Settles Kincade, Dixie Fires with Prosecutors

Critics on Tuesday denounced Pacific Gas and Electric’s $55 million settlement with prosecutors over two massively destructive fires, comparing it unfavorably to the $51 million compensation package that PG&E CEO Patti Poppe received in 2021 and the utility’s sharply rising electric rates for residential customers.

While “Poppe was raking in the money” last year, the company’s equipment started the second largest wildfire in state history, the nearly 1-million-acre Dixie Fire, which PG&E said could cost it $1.15 billion, “much of it from homes and entire communities burned to the ground,” the Environmental Working Group, a Washington D.C.-based nonprofit, said in a statement.

PG&E’s rates have risen 19% for average residential customers since Jan. 1, and the utility has asked the California Public Utilities Commission for 23% in cumulative rate hikes over the next four years. (See PG&E Rate Request Prompts Protests.)

“PG&E’s customers may not know how high their monthly gas and electric bills may go this year, how they’ll pay them, or exactly how much of California the company will burn to the ground in 2022,” Environmental Working Group President Ken Cook, a California resident, said in the statement. “But when they learn that the head of PG&E earned $51 million last year, they will know this: PG&E is out of touch and out of control.”

Dixie-Fire-Closes-Historic-District-(US-Forest-Service-Lassen-National-Forest)-Alt-FI.jpeg

The Dixie Fire bore down on the historic town of Greeneville, which was later destroyed. | U.S. Forest Service/Lassen National Forest

On Monday, PG&E (NYSE:PCG) and the Sonoma County District Attorney issued separate statements saying they had agreed to settle their dispute over the October 2019 Kincade Fire, which burned down large swaths of Sonoma County wine country and hundreds of homes and commercial structures. A broken jumper cable on a PG&E transmission tower sparked the blaze, the California Department of Forestry and Fire Protection (Cal Fire) determined.

The $20 million settlement with Sonoma County dismisses the numerous criminal charges that prosecutors had filed against PG&E and requires it to submit to an independent monitor and to create 80 new wildfire safety jobs in Sonoma County, District Attorney Jill Ravitch said in a statement defending the agreement.

“Although criminal charges are dismissed, the level of punishment and oversight provided by this judgment is greater than could be achieved against a corporation in criminal court,” Ravitch said. “For the next five years, PG&E’s operations in Sonoma County will be closely scrutinized. Furthermore, the costs of this oversight, as well as other payments under this judgment, will not be passed on to ratepayers.”

Trust but Verify?

In a separate settlement Monday, PG&E said it had signed a $35 million stipulated judgement with the district attorneys of Plumas, Lassen, Tehama, Shasta and Butte Counties to resolve “any potential criminal prosecution” of the utility in connection with last year’s Dixie Fire, which burned through all five counties over three months.

That settlement also subjects PG&E to an independent safety monitor for five years and requires the utility to hire 80 new fire safety workers across the five counties.

None of the total $55 million in settlement proceeds will be recoverable from ratepayers, PG&E said in an April 8 report to the U.S. Securities and Exchange Commission.

The CPUC fined PG&E $125 million for the Dixie Fire in December. (See CPUC Assesses PG&E $125M for Kincade Fire.)

In its 2022 proxy statement submitted April 7 to the SEC, PG&E said Poppe’s total 2021 compensation of $51.2 million last year included her base pay of $1.35 million, a $6.6 million bonus and more than $41 million in stock, based partly on meeting operational performance and safety metrics.

“We are committed to doing our part, and we look forward to a long partnership with these communities [damaged by wildfires] to make it right and make it safe,” Poppe said in Monday’s news release.  “We respect the leadership of the local DAs, welcome the new level of transparency and accountability afforded by these agreements, and look forward to working together for the benefit of the communities we collectively serve.”

Plumas County District Attorney David Hollister said in PG&E’s statement that the utility’s “new leadership team has demonstrated they are committed to change and will continue to work towards earning our trust. I appreciate this commitment and, to paraphrase the 40th President of the United States [Ronald Reagan], look forward to verifying these efforts as provided by today’s agreement.”

Others were not as enthused, including some who lost family members, homes and businesses in the catastrophic fires that PG&E equipment caused in 2015 and in each of the past five years. The fires included the November 2018 Camp Fire, which killed 84 people and leveled the town of Paradise.

PG&E pleaded guilty to 84 counts of involuntary manslaughter and one count of arson in that case while it was serving five years of federal probation stemming from the 2010 San Bruno gas pipeline disaster.

During its probation, PG&E started at least 31 wildfires, killed 113 people, destroyed nearly 24,000 structures and burned approximately 1.5 million acres, federal Judge William Alsup, of the U.S. District Court for Northern California, wrote in his final comments before reluctantly releasing PG&E from court supervision in January. (See PG&E Ends Probation as a ‘Menace to California,’ Judge Says.)

Survivors lamented the dropping of criminal charges and the settlement amounts, which they said were too low to deter PG&E from starting future fires.

In a statement by Reclaim Our Power Utility Justice Campaign, a coalition of 75 groups “fighting to hold PG&E accountable,” Mary Kay Benson, a survivor of the 2015 Butte Fire, asked what that would take.

“How many more burned-down towns, more lives upended, more burned lungs do we need to see until we get justice?” Benson said. “For the millionaire executives at murderous PG&E, the money in this settlement is a rounding error and is an appalling way to mistreat the families, farmworkers, forests and lives damaged by this monstrous company.”