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April 8, 2022December 13, 2023

Ann Arbor Using Federal Funds for Solar Panels

Ann Arbor, Michigan, officials voted to use the largest portion of the city’s $24 million federal stimulus money to place solar panels on as many as 18 municipal buildings.

When completed, the project should generate 4 MW of electricity, enough to power 550 houses, said Missy Stults, Ann Arbor’s sustainability and innovation director.

City council voted 10-1 this week to use $4.5 million of the $24 million in federal monies for the solar project.

Stults said the initial designs for the solar panel projects are competed and that she is working on final pricing. Stults said she plans to present the council with a proposed contract at its May 2 meeting, break ground on construction in June and have all the projects completed by winter.

At least 17 buildings will get solar panels, Stults said, though she hoped pricing would allow 18 to get the panels. Ironically, one building that will not get the panels is Ann Arbor’s City Hall, though panels will go on a nearby parking garage. “We have a crowded roof,” Stults said.

Panels will be installed on every major park facility, the city’s water and sewage treatment plants and at its airport. All the buildings will still have utility hookups.

Stults also said decisions are being made on locating EV chargers at the sites. One building that will likely get EV chargers is the downtown farmer’s market, which is an open space with a roof structure.

A spokesperson for the Michigan Municipal League said the organization is encouraging communities to include sustainability projects in their projected spending of federal funds, but he did not know whether any other city in the state had plans for projects.

April 8, 2022

SEC’s Proposed Climate Rule: ‘Materiality’ is the Question

The U.S. Securities and Exchange Commission’s proposed rule issued March 21 to require standardized disclosure by public corporations of the impact of their practices on the environment follows a dramatic increase in the demand for such disclosure from investors, a former commissioner said.

“It is important to recognize and to acknowledge the amount of progress that businesses have already made on this front, that this rulemaking takes place against what is a dramatic increase in climate-related disclosures that companies, facing interest and pressure from various stakeholders, have chosen to disclose,” former SEC Commissioner Troy Paredes said in a discussion Thursday at the Bipartisan Policy Center.

“And that actually is exactly what ‘market discipline’ and private ordering would predict,” he added in a discussion with BPC senior adviser Tim Doyle about the role of the SEC and its relationship with corporations as well as investors. “I think that’s an important backdrop, worth taking some note of.

“It’s important to recognize that there are shifts in terms of market expectations of one type or another. There are different stakeholders demanding different information for one reason or another.”

But this climate-related rule comes at a time when President Biden has made addressing climate change a whole-of-government issue with his January 2021 executive order, Doyle noted.

And “in May of 2021, he issued an executive order dealing with climate-related financial risk. I think you could make a pretty good argument that this rule has at least some connection with [the executive order], especially given the language that is in that executive order about a consistent, clear, comparable and accurate disclosure of climate financial risks,” he said.

Paredes, an appointee of President George W. Bush who served on the SEC from 2008 to 2013, said the climate issue is not new and that the market is already further along in the process than otherwise might be expected.

“From a company’s perspective, it strikes me that this rulemaking is extraordinarily consequential,” he added.

The question of “materiality” — that is, what to report — is at the heart of controversy about the SEC proposal, Paredes and Doyle agreed.

They also agreed that deciding what’s material has been an issue without a concrete definition since Congress created the SEC in 1934 in response to the stock market crash of 1929. The issue evolved gradually over time, except when Congress passed new legislation from time to time setting out specific requirements.

“The way it gets articulated … is investor protection; fair, orderly and efficient markets; and facilitating capital formation. They are often times identified as three separate parts to the SEC mission,” Paredes said. “The fact of the matter is that they intersect, and they support one another, but there may be instances where they can come into some tension,” he added in reference to the growing controversy over the rule, approved by a 3-1 vote. The rule will become effective in December unless challenged in court and could cost corporations billions of dollars to comply.

“I think there’s widespread agreement that the SEC’s core operating tool is disclosure,” Paredes said, “to get investor information in the hands of investors so that investors can make better informed decisions about how to allocate their capital. And the focus there in particular has been historically on material information.”

The proposal could require a company to disclose not only the impact of its operations on the environment but also the environmental impact of its products, if any, and the impact of its suppliers — requirements sure to be debated in the coming months.

To that coming battle, Paredes pointed out that historically, the SEC’s rules have leaned toward allowing the market, rather than the government, to decide.

“Go back to the founding of the SEC, [and there has been] a recognition that it’s better to allow the marketplace to decide how capital is going to be allocated as compared to the government making the decisions around capital allocation. And again, the means to facilitate that is to give information to investors so they can make those decisions in an informed way but still in lieu of the government making those decisions.”

Doyle agreed, adding that the tension between a hard and fast rule and giving companies the ability within a framework to disclose information has been at the heart of many of the commission’s corporate requirements.

Paredes added that even when Congress ordered the SEC to issue new rules in a particular area, over subsequent years “everything has always been a bit of a blend” of rules and reasonable practice. He said requirements that started out as guidance sometimes become a bit more rule-like over decades of interpretation.

“The demarcation sometimes can be a bit a bit blurry. But I do think it comes down as a practical matter in some respects, to how much discretion does the board [or] management team have in fashioning disclosures versus how much of that is going to be dictated more prescriptively by the regulator,” he said.

April 8, 2022December 13, 2023

Enviro Groups Push Wisconsin DNR to Scrutinize Cardinal-Hickory Creek Line

Attorneys for conservation groups have asked Wisconsin’s Department of Natural Resources (DNR) to revoke wetlands and waterway permits for the embattled Cardinal-Hickory Creek transmission line.

The Environmental Law & Policy Center — representing the Wisconsin Wildlife Federation, Driftless Area Land Conservancy, Defenders of Wildlife and the National Wildlife Refuge Association — last month sent a letter to the DNR asking it to halt construction of the 101-mile, 345-kV line until the agency and the Wisconsin Public Service Commission conduct a new environmental review.

“Wisconsin DNR has the obligation and duty under Wisconsin law to stop this orchestrated trainwreck, pause the construction spree, and provide for the proper environmental process to take its course without the specter of a rushed construction process and a forced decision leading to wasteful costs and unnecessary environmental harms and property damages,” lead attorney Howard Learner wrote.

The letter is the latest step in the conservation groups’ ongoing battle against Cardinal-Hickory Creek’s construction.

U.S. District Judge William Conley last month issued a final ruling forbidding the line from running through a protected wildlife refuge in southwestern Wisconsin’s Driftless Area. He agreed with the groups and overturned the line’s environmental impact statement (EIS), prepared by the U.S. Department of Agriculture’s Rural Utilities Service. The EIS didn’t adequately consider line alternatives and failed to comply with the National Environmental Policy Act, the judge ruled. (See Federal Judge: Tx Line Can’t Cross Wildlife Refuge.)

The line’s co-owners — American Transmission Co., ITC Midwest and Dairyland Power Cooperative — have asked a federal appeals court to suspend the decision until an appeals panel decides the case. They argue the project will be able to cut through the refuge.

Learner told the DNR that ATC, ITC and Dairyland are “aggressively continuing to build two costly and environmentally destructive high-voltage transmission line segments in Wisconsin and in Iowa with no legally permissible connection through the protected Upper Mississippi River National Wildlife and Fish Refuge.” He said the companies are deliberately “pushing forward with construction despite their lack of a lawful path to completion so they can create maximum leverage … while passing on costs and risks to the captive utility ratepayers.”

Learner said a new, “lawful” environmental review is in order, especially because the DNR’s 2019 wetlands and waterway permits rely on the now-invalid EIS. The DNR must “divorce itself from the transmission companies’ bulldozing and bullying,” Learner added.

The nearly $500 million line is the last of MISO’s $6.7 billion, 17-project Multi-Value Project portfolio approved in 2011. MISO has since moved on to another long-range planning effort. (See MISO Updates Stakeholders on $10B Long-range Tx Package.)

Some MISO stakeholders have asked the RTO to omit the project from system modeling it performs for transmission planning, saying its completion is no longer a foregone conclusion.

ATC, ITC and Dairyland have so far spent $161 million on the project. Construction began last fall, and the line currently has a December 2023 in-service date.

ATC spokesperson Alissa Braatz said the developers disagree with both Conley’s ruling barring passage through the wildlife refuge and the argument that the original EIS requires changes. Although “legal proceedings continue, [the utilities] have the regulatory authorization to move forward with construction activities, and project construction will continue in areas outside of the refuge,” she said.

“Renewable generation developers and distribution utilities are depending on the Cardinal-Hickory Creek project to facilitate our region’s transition from fossil fuels,” Braatz said in an email to RTO Insider. “The critical role of this project in meeting our region’s energy needs compels us to ensure it is built for the benefit of electricity consumers by the scheduled in-service date.”

April 8, 2022November 23, 2023

Senate Democrats, Republicans Find Common Ground on Critical Minerals

The witnesses before the Senate Energy and Natural Resources Committee on Thursday were unanimous.

The ability of the U.S. to meet President Biden’s clean energy goals will depend on how quickly the country can stand up a domestic supply chain for the critical minerals — such as lithium, cobalt and nickel — that are essential to the manufacture of a range of clean technologies.

But while the need for a domestic supply chain “is now firmly embedded in the mindset of policymakers … the urgency of the situation is still not understood by many,” Duncan Wood, vice president for strategy and new initiatives at the Woodrow Wilson International Center for Scholars, told the committee. “Policymakers must embrace the painful truth that the highly worthy targets set for the energy transition can only be met by a combination of public policy incentives and massive investment now by the private sector, here in the United States and abroad, in new mining activities.

“What is needed today is a whole-of-society approach that incorporates all levels of government, private sector, research and educational institutions, and end users of critical minerals,” Wood said. “This means adopting a holistic, open-minded approach to the issue, embracing the development of new resources, new forms of extraction and processing, new technologies, energy efficiency models, and recycling and waste reduction. Ignoring any one of these elements makes it impossible to build a new energy model and maintain it.”

Unlike Biden’s clean energy targets ― a 100% clean grid by 2035 and a net-zero economy by 2050 ― the critical mineral supply chain is an issue on which the often adversarial Democrat and Republican members of the committee appeared to find common ground Thursday. The demand for these minerals and other rare-earth elements is massive, and the U.S. is largely dependent on China for much of its clean energy supply chain, both Committee Chair Joe Manchin (D-W.Va.) and Ranking Member John Barrasso (R-Wyo.) stressed in their opening statements.

Barrasso pointed to reports from the International Energy Agency and the World Bank predicting exponential increases in critical mineral demand. For example, he said, the IEA report estimates the demand for lithium could grow more than 4,000% by 2040.

Manchin expressed “grave concerns about moving too quickly towards an [electric vehicle]-only future when it comes to the EV battery supply chain. China is responsible for 80% of the world’s battery-material processing, 60% of the world’s cathode production, 80% of the world’s anode production and 75% of the world’s lithium-ion battery cell production,” he said, citing figures from Securing America’s Future Energy. “With numbers like these, it is frustrating to hear calls for a swifter transition to electrify transportation to reduce our dependence on foreign oil. We cannot replace one unreliable foreign supply chain with another and think it’s going to solve our problems.”

Developing clean hydrogen as an alternative fuel should also be pursued, he said.

‘Heading Toward a Cliff Edge’

Joe Britton, executive director of the Zero Emission Transportation Association (ZETA), a trade group representing companies across the EV supply chain, acknowledged the complexity of the challenge, “but turning away in the face of these obstacles only means conceding to foreign commercial interests.”

“American companies are working hard to onshore their supply chains, but they need federal support through predictable permitting, battery, vehicle and charging tax incentives and a whole-of-government approach to drive transportation electrification,” Britton said.

He noted that a number of ZETA members are developing lithium and cobalt production facilities in the U.S., such as Lithium Americas’ Thacker Pass strip mining project in Nevada and Jervois’ Idaho cobalt project.

At the other end of the supply chain, J.B. Straubel, founder and CEO of Redwood Materials, said his company is developing recycling processes that will create “a fully closed-loop domestic supply chain for lithium-ion batteries.” At present, the company is receiving and recycling enough end-of-life batteries to manufacture 60,000 EVs, he said.

Straubel, who was formerly chief technology officer at Tesla, estimated that building out a complete domestic supply chain for EVs could take five to 10 years, while David Howell, acting director of the Department of Energy’s Office of Manufacturing and Energy Supply Chains, projected a 2040-2050 time frame.

Wood argued that any estimate would be unrealistic. “We’re heading toward a cliff edge,” he said. “When you look at just the amount of materials that are going to be needed to reach 50% of the vehicle fleet being electric in the next decade or so, there just aren’t enough being produced globally.”

Part of the challenge, he said, is that “whereas traditional hydrocarbon-based energy generation systems are fuel-intensive, renewable energy systems are material- and, specifically, mineral-intensive. To give one example, an onshore wind block requires nine times more mineral resources than a gas-fired power plant.”

Sen. Catherine Cortez Masto (D-Nev.) countered that the clean energy transition is America’s current “moonshot.”

“It’s important for the administration to stake a goal for all of us to marshal our resources,” she said. “Whether we achieve that goal can always be in question, but at least we are moving in the same direction. … Now we can sit here and armchair quarterback everything about it, but without an administration and a focus, we will never get there.”

Straubel also chimed in, noting that the comparison of petroleum and lithium is skewed because unlike the fossil fuels used to power a generator or a car, lithium-ion batteries are not consumed. “We refine it; we put it into inventory in the fleet; and it’s there for many decades,” he said. “It’s essentially infinitely reusable. … We can refine it back to new quality every single time.”

A National Battery Reserve

Thursday’s hearing was the second of two the committee has held on critical mineral supply chains and the urgent need for federal action to develop domestic sources in the wake of delays and price increases triggered by the combined impacts of the COVID-19 pandemic and the war in Ukraine. Beyond oil and gas, Russia is a major supplier of nickel.

Both Democrats and Republicans on the committee had previously called for President Biden to invoke the Defense Production Act (DPA), which he did March 31, even as the committee held its first critical mineral hearing.

Originally passed in 1950 as part of a federal effort to ramp up production of key materials needed for the Korean War, the DPA was most previously invoked by Biden to increase manufacturing of medical supplies during the pandemic. To increase production of critical minerals, Biden called on Defense Secretary Lloyd Austin to “create, maintain, protect, expand or restore sustainable and responsible domestic production capabilities of such strategic and critical materials.” (See Biden Invokes the Defense Production Act for Critical Minerals.)

Howell pointed to a recent memorandum of agreement between DOE and the departments of State and Defense to create “a critical mineral stockpile process to support the U.S. transition to clean energy and national security needs.” The three departments will partner on acquiring and recycling “selected materials for technologies that range from grid-scale batteries to wind turbines,” he said.

But building critical mineral supply chains and reserves often depends on demand, Britton said. The U.S. did not previously develop critical mineral processing “because there wasn’t a critical mass of battery cell production,” he said. “So, there’s a through-line where we are creating these products here; we’re building these battery cells and building these vehicles. It then has follow-on impacts where we’re justifying additional investment and processing.

“Every vehicle that we bring to America or that we make here and manufacture, it becomes part of a national battery reserve,” he said.

Wood also stressed the need for both urgent action and a long-term strategy. Biden’s invoking of the DPA was only a first step, he said. Building a critical mineral supply chain “is not something that we’re going to resolve with a one-and-done solution. … It’s not an either/or; it’s an all-of-the-above. The fact is we need recycling; we need new resources; we need tax credits. We need massive investment in human capital.

“The danger here is that if we take our eyes off the prize because we’ve done something, then we miss ultimately achieving that goal,” he said.

April 8, 2022December 13, 2023

NERC: GridEx Lessons Already In Use

Last year’s GridEx VI security exercise provided some much-needed practice for the security challenges facing the electric grid today, officials from the U.S. government said in a media briefing on Thursday.

Speakers at the briefing, held to mark the release of NERC’s after-action report on the exercise, said that several elements of the exercise have since been seen in practice during Russia’s invasion of Ukraine, including the use of social media to spread misinformation about the developing situation to cause civil unrest. Brandon Wales, executive director of the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA), said the experience of GridEx VI has already prompted action at the federal level to address this potential threat.

Brandon Wales, CISA | NERC

“We’ve begun … working across various sectors and with relevant technology and social media companies about being prepared to respond to these blended attacks, where they’re using social media [and] disinformation to make the impacts of cyberattacks potentially worse,” Wales said. “That is something that I think in the future will likely be in the playbook of multiple adversaries if they are looking to really stress our systems.”

Puesh Kumar, director of the Department of Energy’s Office of Cybersecurity, Energy Security, and Emergency Response (CESER), said that the use of exercise scenarios requiring collaboration across industries, as well as between the public and private sectors, helped lay the groundwork for coordinating the response to the developing situation.

“We have lowered the bar for sharing information in terms of what we are seeing, not only out in Russia and Ukraine, but even here,” Kumar said. “You heard the president [say] about two or three weeks ago [that] we are seeing cyber activity targeted at critical infrastructure in the United States. … There are over 3,000 electric utilities across the United States. All it takes one or two utilities seeing activity, and we quickly cascade it to the others out there.”

Attendance Down from Last Time

NERC conducted the sixth iteration of GridEx across three days last November. As in previous years, the exercise was developed, managed and delivered by the Electricity Information Sharing and Analysis Center (E-ISAC). (See GridEx VI Incorporates Recent Cyber Lessons.)

GridEx VI was performed in two stages: First came the distributed play, held Nov. 16-17. In this part of the exercise, participants — more than 3,000 people across 293 organizations in the electric industry, government and other stakeholders — worked a core exercise scenario developed by E-ISAC, which also provided a virtual environment for the exercise to play out. Each organization administered the scenario itself, resulting in a “unique exercise experience” for every participant.

The second component was the executive tabletop, hosted by E-ISAC Nov. 18 for almost 200 participants from 88 organizations, including investor- and publicly owned utilities, cooperatives, independent system operators, and U.S. and Canadian government entities, as well as the natural gas and telecommunications industries. The tabletop was held online for the first time due to the COVID-19 pandemic, allowing participation by a larger and more diverse group of entities while inadvertently mirroring the way a crisis would likely play out.

Unlike the tabletop, participation in the distributed play was down significantly from the 526 organizations represented in GridEx V. Last year’s 293 organizations represent the lowest official participation in the biennial exercise since 2013’s GridEx II. (See NERC: COVID-19 is Chance to Test GridEx Lessons.) The 3,000 individuals participating were likewise fewer than half of GridEx V’s approximately 7,000.

NERC’s report attributed the decline, in part, to the participation challenges posed by the pandemic and also to changes in how participants were counted. Unlike in previous years, participants in GridEx VI were only required to register with E-ISAC to use the exercise tools or access planning materials. NERC said in light of these shifts, “future participation numbers are likely to be more comparable to those recorded for GridEx VI.”

Cyberattacks Get Personal

The scenario of GridEx VI threw myriad challenges at participants. The distributed play simulated a major cyber and physical attack against the North American power grid as customized for each organization, while the tabletop presented a similar scenario centering on the U.S. and Canadian West Coast and included attacks against the natural gas and telecommunications industries.

Timeline of the two-day distributed play component of GridEx VI | NERC

Incidents in the two-day distributed exercise were grouped into four periods, representing the morning and afternoon of each day. The first day saw control system and transmission substation faults accompanied by physical attacks on pipelines and liquid natural gas production facilities that constrained generation capacity.

Manny Cancel, E-ISAC | NERC

On the second day the adversary “directly targeted critical employees” with threats against them and their families, while social media users threatened more attacks on transmission and distribution facilities. Manny Cancel, senior vice president at NERC and CEO of E-ISAC, confirmed that the personal targeting of key personnel was derived from real events and the known capacities of potential adversaries.

“We all know that our adversaries are very sophisticated, and one of the techniques they use is to go after some of the folks in our agencies. Whether it’s through phishing campaigns or other ways to harvest credentials or data, they look for the weak link and try to take advantage of it,” Cancel said.

“Distributed planning especially is informed by the work of the people that are … on the ground. Over 700 planners … have helped us build the scenario, and they leverage the experiences they’ve been through.”

Communications Issues Highlighted

One of the most urgent recommendations from the report was that the electric and telecommunications industries strengthen their coordination in light of the “well-understood” interdependencies between both sectors. In this year’s tabletop scenario, a widespread outage in landlines and mobile phones “essentially [halted] the grid restoration process,” highlighting the need for “technical alternatives that have rudimentary functionality and high reliability.”

In Thursday’s briefing, Wales emphasized that “the report is not implying that there are no backups” for these communication systems, mentioning satellite phones and radio as methods for utilities to stay connected to their field personnel. Instead, he said, the thrust of this recommendation is to allow entities greater “certainty” about their ability to respond in an emergency.

“What’s coming out of this is a little bit deeper kind of understanding — what are the minimum requirements needed at any given location for power to be restored effectively?” Wales said. “What are the various tools that can be brought to bear? … I think that’s going to be some of the work that we do over the next two years, before the next GridEx.”

April 7, 2022December 13, 2023

FERC Approves $132K Penalty Against APS

FERC approved a slate of settlements between regional entities and utilities for violations of NERC reliability standards last week, including an agreement between WECC and Arizona Public Service (APS) carrying a penalty of $132,000 (NP22-16). Additional settlements between WECC and the Western Area Power Administration’s Rocky Mountain Region and between SERC Reliability and the Tennessee Valley Authority had no monetary penalties.

NERC submitted the settlement with TVA to the commission in a Notice of Penalty on Feb. 28. The APS and WAPA settlements were part of a spreadsheet NOP submitted the same day, along with an NOP detailing a settlement between SERC and Broad River Energy. (See related story, SERC Alleges Years of Noncompliance by Broad River in $435K Settlement.)

FERC indicated in a filing March 30 that it would not review any of the settlements, leaving the penalties intact. The commission also said it would not review two other NOPs involving violations of NERC’s Critical Infrastructure Protection standards, while reserving judgement until April 29 on a third CIP-related settlement (NP22-12, et al.). Details on the three CIP settlements were not made public, in keeping with NERC and FERC’s policy on such violations. (See FERC, NERC to End CIP Violation Disclosures.)

Breakdown Blocks Assessment for APS

WECC’s settlement with APS stems from a violation of TOP-001-4 (Transmission operations), which was in effect from July 1, 2018 to March 31, 2021. APS submitted a self-report of the infringement on July 29, 2019.

Requirement R13 of the standard, in place at the time, required that transmission operators “ensure that a real-time assessment [RTA] is performed at least once every 30 minutes.” APS found that on April 17, 2019, its energy management system (EMS) had lost visibility to some of the data being shared between APS, its reliability coordinator and neighboring entities because of “configuration issues and uncoordinated troubleshooting efforts” in a pair of recently replaced firewalls at APS’ primary control center (PCC).

As a result, the utility’s real-time contingency analysis tool — essential to performing the RTA — was unable to function and the RTA could not be done. The conditions continued until staff restored connectivity to the new firewalls, at which point the EMS regained visibility and the RTA resumed, three hours and 26 minutes after the interruption began.

During the breakdown, APS informed its neighboring entities of the issues and confirmed the loss of the relevant data with the RC. Staff in the PCC monitored the system via reports from field personnel and worked with adjacent balancing authorities to manually manage BA responsibilities.

WECC assessed the violation as a moderate risk because the lack of data from the firewalls meant APS could not perform BA functions, while the inability to perform an RTA meant that bulk power system functionality could have been lost in an emergency. However, the regional entity also noted that the utility was proactive in notifying its neighbors of the problem, and that staff continued managing BA responsibilities as best they could.

APS’ mitigating actions include implementing a formal asset change management process to verify that all newly installed devices are functioning normally, and conducting updated training for all personnel that support the EMS application. WECC considered these steps, as well as APS’ internal compliance program, as mitigating factors in determining the penalty.

WAPA Operator Missed Late-night Warning

The settlement between WECC and WAPA originated with a phase-to-ground fault on a 115-kV transmission line on June 3, 2020, at 2:02 a.m. Because of the fault, a breaker on the line tripped and could not reclose automatically; an alarm was generated through the supervisory control and data acquisition (SCADA) system, but the night shift system operator was “distracted [and] did not recognize the visual and audible alarms for over two hours.”

WECC said this failure to act amounted to a violation of TOP-001-4 requirement R1, mandating that transmission operators “act to maintain the reliability of [their] transmission operator area.”

The operator finally tried to close the breaker via SCADA at 4:17 a.m., though unsuccessfully; after maintenance went to investigate the problem, they found a broken jumper about 3 miles from the terminal where the breaker tripped. During this process a shift change occurred and the night operator left without completing an interruption report and transmission log entry. WAPA did not notify its RC and the affected transmission operator (TOP) of the event until nearly 8 a.m., and the unit was restored to service at 3:30 p.m.

By neglecting to inform the RC and transmission operator in a timely manner, the night shift operator violated requirement R8 of TOP-001-4, WECC said. This requirement specifies that RCs and TOPs be informed of “operations that … could result in an emergency.” In addition, the failure to file a 30-minute forced outage notification with the RC infringed on IRO-017-1 (Outage coordination), which requires TOPs and BAs to “perform the functions specified in [their RC’s] outage coordination process.”

WECC did not assess a monetary penalty for WAPA’s violation, citing a D.C. Circuit Court of Appeals ruling that FERC and NERC cannot impose such penalties against federal government entities. The RE did note WAPA’s mitigating actions, including updating internal procedures for restoring 115-kV lines and emergency line restoration, event reporting plan and system operator shift change, along with ensuring operators review the new procedures.

Misratings at TVA Facilities

Because TVA is also a federal government entity, SERC’s settlement with it did not result in any monetary sanctions.

The agreement between the RE and the utility involved violations of FAC-008-3 (Facility ratings) discovered through a spot check by SERC in 2017, in which the RE discovered nine instances of incorrect facility ratings, about 16% of the facilities examined. As a result of the spot check, TVA had to derate the affected facilities by as much as 49%.

SERC attributed the misratings to a number of factors; prominently, the RE found that TVA had misinterpreted requirement R3 of the standard to allow historical facility ratings or design ratings to be used to establish initial facility ratings until the ratings for the actual equipment could be determined. Not only was this assumption incorrect because the standard requires the use of actual ratings, but TVA’s facility ratings methodology lacked a time frame for the unverified data to be replaced; as a result, the use of incorrect ratings could continue “months or years after installation.”

The RE noted that a compliance audit in 2019 found no facilities with incorrect ratings, indicating “improved performance during [the intervening] time.”

While SERC was unable to assess a monetary penalty, it did impose sanctions in the form of a requirement that the RE will perform annual spot checks at TVA facilities beginning this year. The agreement did not specify how long these inspections will continue. TVA also agreed to conduct walkdowns of all transmission substations and switching stations over the next five years.

April 7, 2022January 31, 2024

CAISO Reports High Energy Prices in Q4

High natural gas costs drove wholesale electricity prices sharply higher in CAISO and its Western Energy Imbalance Market (WEIM), the ISO said in its fourth-quarter 2021 Report on Market Issues and Performance, released this week.

Day-ahead electricity prices in CAISO rose by about 50% compared with the same quarter in 2020, reflecting a similar rise in natural gas prices at key trading hubs, according to the Q4 report. Gas prices increased by more than $2/MMBtu at the Henry Hub in Louisiana, SoCal Citygate near Los Angeles, PG&E Citygate near Sacramento, NW Sumas in Washington State and El Paso Permian in Texas, it said.

PG&E Citygate saw a 65% price jump and SoCal Citygate experienced a 57% increase over the same quarter one year earlier, it said.

The price spike led to higher marginal energy prices across CAISO and the WEIM, which covers much of the Western Interconnection. Prices averaged $62/MWh in the day-ahead market, $59/MWh in the 15-minute market and $53/MWh in the real-time market.

“Electricity prices in western states typically follow natural gas price trends because gas-fired units are often the marginal source of generation in the [CAISO] balancing area and other regional markets,” the report said.

Natural gas prices drove up energy costs. | CAISO

In the WEIM, energy prices in California were 18% higher than in the rest of the interstate trading market.

“Prices tend to be higher in California than the rest of the system due to both transfer constraint congestion and greenhouse gas compliance costs for energy that is delivered to California,” CAISO said.

Congestion on three lines — the Los Banos-Quinto 230-kV line in Central California, the Miguel 500/230-kV transformer nomogram and the Imperial Valley-El Centro 230-kV nomogram, both in Southern California — affected CAISO prices the most, it said.

On major interties, “the frequency and import congestion rent on Palo Verde [feeding power from Arizona to Southern California] remained notably high relative to the same quarter in 2020,” but congestion decreased on the Pacific AC and DC interties linking the Pacific Northwest to California and the Southwest.

Prices in the WEIM’s Northwest region — which includes PacifiCorp West, Puget Sound Energy, Portland General Electric, Seattle City Light and Powerex — trended lower than in other balancing areas “due to limited transfer capability out of this region during peak system load hours,” the report said.

CAISO was a net importer during most hours except the middle of the day when California’s ample supply of inexpensive solar power makes it a net exporter.

“Compared to the fourth quarter of 2020, imports into the California ISO from Arizona Public Service and Salt River Project were partially replaced by imports from Los Angeles Department of Water and Power,” the ISO said.

CAISO’s addition of a net-load uncertainty requirement to the WEIM’s bid-range capacity test in June 2021 caused the most resource sufficiency failures in Q4 2021, but CAISO removed the controversial requirement from the test in February.

While gas prices were rising, renewable production increased by about 600MW, or 9% compared to Q4 2020, CAISO said. Hydroelectric, wind and solar generation increased 12%, but geothermal and biogas-biomass generation were down 4%, it said.

The prolonged Western drought eased from October to December, helping to increase hydropower slightly from last year’s fourth-quarter low point, but California then saw its driest January to March on record.

April 7, 2022June 14, 2023

NY Offshore Wind Transmission Project Draws No Residential Comment

The first-ever offshore wind transmission project in New York will bring 816 MW from Empire Wind 1 right under Brooklyn streets — and has drawn no comment from local residents (21-T-0366).

Siting major new energy infrastructure in New York City is notoriously difficult and expensive. Equinor (NYSE:EQNR), which is managing the project on behalf of itself and partner BP, will likely pay half a billion dollars or more to lay 17.4 miles of twin submarine cables in state jurisdictional waters. But it is facing no opposition to its plans to bring the 230-kV lines ashore at the South Brooklyn Marine Terminal.

Only developer representatives, labor and industry interests, and academics spoke at a public hearing hosted by the New York Public Service Commission on Tuesday.

According to Mariah Dignan — regional director on Long Island for Climate Jobs New York, a statewide labor coalition representing 2.6 million workers — the project and its related onshore work will undoubtedly serve the public interest and is necessary to meet the state’s climate action goals, especially the 9,000-MW target for offshore wind energy by 2035. Dignan made her remarks Tuesday.

“In addition, the project and related onshore work and construction must be done with good union, family-sustaining jobs,” Dignan said. “We look forward to working with the applicant to make this clean energy economy a reality through a just transition for not only our workforce but also our communities.”

The 50/50 joint venture of Equinor and BP (NYSE:BP) also includes Empire Wind 2 and Beacon Wind 1. The three projects will collectively provide 3.3 GW of electricity, Harrison Feuer, director of public affairs in the state for Equinor Renewables U.S., said in a presentation at the hearing before it opened to public comment.

Empire Wind Tx Proposal (Empire Wind) Content.jpg

The EW1 onshore export cables between the cable landfall and the onshore substation will consist of a three-core 230-kV HVAC bundle and are not expected to differ from the submarine export cables. | Empire Wind

The operations and maintenance base for all three projects will be situated in an industrial park adjoining the South Brooklyn terminal. “We do extensive environmental and social impact evaluations to minimize the effects on wildlife and local communities, and that happened long before we get started,” Feuer said.

The developers expect state permitting to conclude between the end of 2023 and beginning of 2024, when construction will then commence, said Joshua Verleun, Equinor manager for the permitting process in New York.

After landfall at South Brooklyn, the 230-kV export cables will be connected to an onshore substation to up the voltage to 345 kV for interconnection to the grid.

“When the cables make landfall, they will be pulled directly through the bulkhead to terminate into the onshore substation,” Verleun said. “From the onshore substation there is a short interconnection cable that runs along New York City streets and connects into the existing Con Edison Gowanus substation.”

The approval of the project’s transmission lines will be a critical milestone in its development, said Fred Zalcman, director of the New York Offshore Wind Alliance, a coalition of OSW developers, including Equinor, national environmental organizations, labor and academia.

“This project presents many good benefits to the electric grid of downstate New York, and one of the key benefits I see is its proximity to the New York City load center,” said Thomas Barracca, director of the Office of Economic Development at Stony Brook University, which runs a workforce development program for the OSW industry in New York. “In terms of environmental impact, the project has been very well conceived and thought out, and has obviously been vetted with a lot of stakeholders in the environmental community.”

The developers engaged with local fisheries, whose feedback helped inform decisions on how the project is made, and also worked closely with the U.S. Bureau of Ocean Energy Management and Department of Defense to mitigate any potential interference of coastal defense and radar, Feuer said.

“We are delighted that the cable connection would be going to Brooklyn,” said Adrienne Esposito, executive director of Citizens Campaign for the Environment, a statewide group with 140,000 members. “We all know that the greatest load of fossil fuel use is … in New York City and also on Long Island, and that’s why it’s so imperative that wind farms get connected to both of those areas.”

April 7, 2022October 25, 2023

NY Greenlights $345M, 280-MW Excelsior Solar Farm

New York officials on Wednesday approved a NextEra Energy Resources subsidiary to build and operate a 280-MW solar farm with 20 MW of battery storage capacity on a few thousand acres of farmland between Rochester and Niagara Falls (19-F-0299).

The state Board on Electric Generation Siting and the Environment authorized a certificate of environmental compatibility and public need for the estimated $345 million Excelsior Energy Center project in the Town of Byron in Genesee County. The facility will be the largest solar farm ever built in New York, with solar panels covering 1,716 acres on a project tract of about 3,443 acres and is expected to begin commercial operation in late 2022.

Administrative Law Judge Gregg Sayre detailed the reasoning of the Department of Public Service staff recommendation to the siting board, saying the contested issues fell into three areas: the use of agricultural land, particularly prime farmland; the impact of the project on the character of the community as a result of its size and visual impact; and the alleged noncompliance of the project with the Town of Byron and Genesee County comprehensive plans.

Contested Issues

The state Department of Agriculture and Markets objected to 30% of the project being located on prime farmland and claimed that a solar energy project constitutes a permanent conversion of farmland to non-agricultural uses.

The Siting Board rejected the argument about permanent conversion of farmland in the Hecate Energy Albany case in January of 2021 when it concluded that a commercial solar facility does not result in a permanent loss of farmland where certificate conditions require the land to be fully restored as closely as possible to its prior condition upon decommissioning (17-F-0617).

Judge Gregg Sayre, NYDPS | NYDPS

“In this case there is some permanent loss of farmland due to access roads and other similar construction, but it amounts to only about 31 acres, which is less than 1% of the project’s area,” Sayre said. “Although the department is certainly correct that agricultural production will be reduced in the footprint of the project for approximately 30 years, the reason behind that loss is that the property owners in question have voluntarily entered into lease agreements with the applicant.”

A local group, Byron Association Against Solar (BAAS), filed at least 20 documents regarding safety concerns, issues concerning soil and air contamination, concerns about the danger of battery fires, and the layout of the project, roads, boundaries and set-backs.

BAAS offered two studies to support its position that the project will have a massive negative impact on farming in the town of Byron, but one of the reports was based on what Sayre said is a “completely erroneous” number of affected acres. The report, he said, is deficient in using one year of crop pricing in its analysis of impacts rather than a longer average given the price fluctuation that occurred over the course of several years in the town’s top 10 crops.

The second study produced by BAAS claims that the project would cause a redistribution of farms and lands and an increase in farming costs, but it fails to support its conclusions that the project would increase the cost of farming in the area, Sayre said.

BAAS also put in the testimony from Eric Zuber, owner of a large dairy farm adjoining the project area, who stated that he would lose the use of farmland on which he spreads excess manure.

Secondly, the order concluded that claims that the project will destroy the rural community were “overstated” and that visual impacts have been avoided or minimized to the maximum extent practicable.

Laws and Plans

The third issue in dispute was based on the testimony of a local resident speaking for himself, not for the town or the county, that the project is inconsistent with the town and county comprehensive plans.

Tammy Mitchell, NYDPS | NYDPS

“The resident is absolutely correct in stating that the protection of agricultural lands is listed as a goal in both of those plans, but … the town comprehensive plan also explicitly supports the development of clean energy resources, so there is necessarily, as with most land-use issues, some balancing required of competing goals,” Sayre said.

Last year, the town adopted a solar law, finding that the law is consistent with its comprehensive plan, and the county planning board implicitly found that the law was consistent with both the town and county comprehensive plans when it approved the town law, Sayre said.

“I believe that the proposed draft order granting a certificate of environmental compatibility and public need for the Excelsior solar generating facility is well balanced and avoids or mitigates impacts to the extent practicable,” said Tammy Mitchell, director of the DPS Office of Electric, Gas and Water, serving as alternate chair of the board in place of Public Service Commission Chair Rory Christian.

The other alternates for the permanent members of the Siting Board were Louis Alexander, representing the commissioner of the Department of Environmental Conservation; Dr. Elizabeth Lewis-Michl, representing the commissioner of the Department of Health; Vincent Ravaschiere, representing the commissioner of the Department of Economic Development; and John Williams, representing the chair of the New York State Energy Research and Development Authority.

The Siting Board for the Excelsior case also included one ad hoc member, Norman Pawlak, dissenting.

April 7, 2022November 9, 2023

California Seeks to Blaze Trail for Long-duration Storage

California Gov. Gavin Newsom is looking to earmark $380 million for long-duration energy storage (LDES) incentives in his proposed 2022/23 state budget. For California energy officials, the state’s grid operator and LDES developers, that money can’t arrive soon enough.

California defines “long-duration” as any storage resource able to discharge energy to the grid for at least eight hours at full output, but the state also has a “stretch goal” of 20 to 100 hours. While otherwise technology-neutral, Newsom’s incentive program would seek to boost the commercial prospects of alternatives to lithium-ion batteries and pumped hydro. Priority would be given to technologies on the verge of commercialization or positioned for widespread deployment within the next five to 10 years.

Speaking Tuesday at an interagency workshop exploring ways to advance the adoption of non-lithium-ion LDES, California Energy Commission Chair David Hochschild acknowledged that the $380 million in funding “still has a little ways to go” before passing the legislature.

“But part of the reason for coming together today was feeling an incredible sense of urgency about getting this right, particularly on program design,” Hochschild said.

Two issues are driving that urgency, according to speakers at the workshop.

The first is that California’s grid, increasingly reliant on variable renewable generation, will soon push its reliability limits by relying on four-hour batteries as a substitute for gas-fired peaking resources.

The second factor is more global in nature, with competition for worldwide lithium supplies heating up as more consumers purchase electric vehicles and government policies across the world encourage the electrification of most forms of transportation and heavy-duty equipment.

‘Incredibly Versatile’

Two years ago, CAISO had about 200 MW of battery storage on its grid. Today it manages 3,100 MW, most of which is lithium-ion. By summer, that number is expected to reach 4,000 MW.

During Tuesday’s workshop, Hochschild praised the state’s ability to integrate that kind growth in such a short time.

“We’re not finished, of course; there’s a lot more to go; but just to actually have that installed and dispatchable is incredible,” he said.

“Not only is California leading the way in terms of [storage] technologies that are on the grid, and what we’re operating today, we’re also leading the way in terms of the tools that we have to actually manage and operate these resources,” said Gabe Murtaugh, storage sector manager at CAISO.

California’s battery storage resources, predominantly four-hour in duration, are “incredibly versatile,” helping CAISO manage peak loads and “operational uncertainty” on the grid, Murtaugh said. The ISO has committed much time to developing market models that manage the state of charge of those resources, he said, ensuring they’re available when needed most, such as on the hottest summer days.

But the continued emergence of storage requires a dynamic approach to managing the resources, Murtaugh said. The California Public Utilities Commission’s 2032 integrated resources plan calls for 15 GW of storage by 2032, with 30 to 50 GW looking further out, according to Jonah Steinbuck, deputy director of the CEC’s Energy Research and Development Divsion.

“Just because we have a model that works today, and we’re sharing that model with other ISOs and RTOs across the country, doesn’t mean our work on storage is done by any means,” Murtaugh said. “We know that there’s other different kinds — different flavors — of technology: long-duration technology; other short-duration batteries as well. And as we’ve mentioned before, the ISO is technology-agnostic, so we really need to design our models to be able to accommodate all kinds of technologies potentially.”

The growing prevalence of variable generation in California will alter the shape of CAISO’s “duck curve,” the iconic graph that depicts the deep trough in the ISO’s “net load” during the middle of the day (formerly the period of peak demand) as solar resources reach full output, followed by the steep rise in net load heading into evening as those same resources taper and cease production.

Longer-term peak load forecasts from the CEC indicate the middle of the duck curve will become even deeper and wider as California brings on more solar resources, while net loads in the late afternoon and evening will become even steeper with increased electrification of the state’s economy.

The key for the ISO is to shift the solar oversupply in the trough period to the high needs during the ramp. Using the CEC’s forecasts, CAISO predicts that, by 2024, four-hour batteries discharging at full capacity will be insufficient to provide the energy flows necessary to meet demand across a longer and steeper evening peak. Long-duration storage will be needed to cover that gap and avoid continued reliance on peaking plants.

“Obviously, you can take a four-hour battery and operate it at something less than its full output for a longer period of time, but you’re probably losing some efficiency there,” Murtaugh said.

More challenges loom beyond 2024, as the state pursues its policy of achieving a zero-emissions grid by 2045, requiring use of even longer-duration storage of up to 100 hours, Murtaugh said. That’s because CAISO expects the grid will shift from a summer- to winter-peaking system.

“The hardest times will be during multiday periods when we have low wind and low solar availability, which is more prevalent in the winter than it is in the summer,” he said. “And in those kinds of situations, when we’re very heavily reliant on renewables to produce the energy that’s going to be consumed in the state, then you need storage or some other solution to generate new energy in order to keep the lights on across those periods.”

Other factors will compound the need to adopt long-duration storage by the middle of this decade, according to James McGarry, a senior analyst in integrated resource planning at the CPUC.

Among them is the expected retirement in 2024 of 1.3 GW of gas-fired capacity 40 years or older and the closure of 3.7 GW of thermal plants relying on once-through cooling, followed by the 2025 retirement of the 2.3-GW Diablo Canyon nuclear plant.

“And throughout this time period, West-wide heat and drought conditions paired with neighboring states increasing their own clean energy commitments are leading us to expect tighter availability of imports during peak demand periods,” McGarry said.

“As we look across different use cases and applications, long-duration storage has a major role to play in the ISO’s local capacity requirements,” said Jin Noh, policy director for the California Energy Storage Association. “Studies are already showing a significant need to look at long-duration storage if we really want to replace local gas generation.”

Noh said long-duration storage could provide more of the “diverse capabilities” the ISO is seeking to manage a system increasingly dominated by inverter-based resources, including offering inertia support and helping to “better optimize and utilize the other resources on the grid.”

‘Dirt Cheap’

According to Noh, long-duration storage technologies already benefit from “pretty significant” private investment. But Gov. Newsom’s proposed incentives would “serve as that tipping point for technologies that are really on the verge of commercialization” while easing the “first-mover burden” on those organizations adopting the new technologies.

CEC Vice Chair Siva Gunda pointed out that part of that burden includes testing — then rapidly scaling — the new technologies. Lithium-ion batteries benefited from about 10 years of deployment and providing operational data before attracting broad private investment, he said.

To help alleviate the proof-of-concept burden for LDES, the U.S. Department of Energy has proposed the Rapid Operational Validation Initiative, designed to accelerate testing and have resources ready for commercialization by 2030, ahead of the Biden administration’s 2035 target for a clean U.S. electricity system, said Eric Hsieh, DOE’s director of grid systems and components.

“We’re looking to use these demonstrations to collect data from them [and] combine them with accelerated testing procedures in the lab with domain knowledge and [artificial intelligence/machine learning] algorithms, with the intent of being able to provide investment-grade performance projections with just one year of data,” Hsieh said.

And another key development adds to the time pressure to deploy LDES, according to Larry Zulch, CEO of Invinity Energy Systems, a flow battery developer.

“I talk to a lot of metals companies, people who are in the trade, and they keep telling me, ‘You have no idea what kind of lithium shortage is coming along because of the [transportation sector] requirements,’” Zulch said.

Zulch said the applications that will rely on energy-rich lithium-ion batteries, which include EVs, airplanes and construction equipment, “far exceed the increased production capabilities” of lithium and nickel mines.

Invinity’s flow batteries rely on vanadium, which Zulch said is more abundant than copper and found throughout the world, preventing it from becoming a “conflict” mineral.

Other LDES company representatives speaking during a workshop panel also touted the relative abundance of the critical minerals used in their systems. Mateo Jaramillo, CEO of Form Energy, said his company’s iron-air design relies on the most heavily mined mineral on Earth, present on every continent. Henrik Stiesdal, founder of Stiesdal A/S, said the storage medium in his company’s thermal energy system is crushed basalt, which he called “dirt cheap.”

Unsurprisingly, company executives were unified in their belief that the moment has already arrived for LDES.

“I think the [LDES] batteries that all of the panelists, along with myself, are able to produce and provide are addressing a specific market need that’s already there,” said Balki Iyer, chief commercial officer of Eos Energy.

“What we see here is the fact that we actually have a longer-duration need from the market [that’s] driving the shift, moving away from lithium to non-lithium, longer-duration batteries,” he said.