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October 7, 2024

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NYISO Management Committee Briefs: Nov. 17, 2021

2021 Strategic Plan

NYISO held its first in-person stakeholder meeting Wednesday after a hiatus of 615 days, CEO Rich Dewey told the ISO’s Management Committee.

The ISO will continue to assess week-to-week and consult working group committee chairs to determine whether COVID-19 pandemic conditions warrant in-person or virtual meetings, Dewey said.

“My preference by default is we would try to do them in person, but we … definitely want to take feedback from stakeholders if people are comfortable continuing to meet in person or if people have very specific concerns given the current state of the pandemic and local infection rates, which are on the rise again, unfortunately,” Dewey said.

Executive Vice President Emilie Nelson presented the ISO’s 2021 Strategic Plan, which outlines evolving state and federal policy drivers affecting the grid operator.

NYISO’s Board of Directors met with the MC in June to review the ISO’s strategic priorities, substantially informed by input from stakeholders, Nelson said.

“There is a rapid change underway on the electric grid, [partly] due to the electrification of other sectors,” Nelson said.

The change is framed in New York by the state’s Climate Leadership and Community Protection Act and at a national level through efforts such as the substantial infrastructure spending bill and a renewed focus on clean energy legislation, she said. (See Biden Signs $1.2 Trillion Infrastructure Bill.)

“Environmental justice and greater public participation are also a prominent part of policy today with respect to reliability and market considerations for a grid in transition,” Nelson said. “The magnitude of the change requires us to acknowledge that our collective understanding will be shaped through iterative analysis and work across planning, operations and markets.”

OKs Comprehensive Mitigation Review

The Management Committee approved tariff revisions related to the ISO’s Comprehensive Mitigation Review (82.03% in favor) and recommended that the board approve the necessary filing under Section 205 of the Federal Power Act. (See “Mitigation Review Moves Forward,” NYISO Business Issues Committee Briefs: Nov. 9, 2021.)

The MC also recommended that the ISO address capacity accreditation related to buyer-side mitigation (BSM) in the three different phases mentioned throughout the proceeding.

NYC-Tx-Security-Margin-(NYISO)-Content.jpgNYC transmission security margins are tight following peaker rule implementation, at 394 MW in 2025 and 115 MW in 2030. | NYISO

Phase 1 includes tariff changes for the proposed market design and will conclude with FERC acceptance; Phase 2 will discuss the procedures and details of capacity accreditation throughout 2022; and Phase 3 will focus on implementation of the capacity accreditation review.

NYISO intends to implement the updated capacity accreditation rules for the capability year that begins May 2024, said Michael DeSocio, director of market design.

In addition, assessment of financial risk of changes in future revenues is incorporated in the next demand curve reset process beginning in 2023.

The ISO is pursuing BSM reforms in time for the class year 2021 BSM evaluations. The class year study performs a detailed examination of the collective reliability impact of a group of projects, as well as a deliverability evaluation for requested capacity resource interconnection service and identifies and provides binding cost estimates for required upgrades.

2021-2030 Comprehensive Reliability Plan

The Management Committee unanimously recommended the board approve the 2021-2030 Comprehensive Reliability Plan (CRP) as presented by NYISO staff.

The ISO prepares a CRP in alternating years with the reliability needs assessment (RNA). Key updates to last year’s RNA include one to the load forecast — specifically a decrease in the Zone J peak load forecast by as much as 392 MW by 2030, said Kevin DePugh, senior manager of reliability planning.

Con Edison provided local transmission plan updates, including new 345/138 kV PAR-controlled 138 kV feeders for Rainey-Corona, Gowanus-Greenwood and Goethals–Fox Hills. A short-term reliability process solution for addressing a need arising in 2023 included changes to series reactor statuses from summer 2023 through 2030, DePugh said.

“In Zone J we actually had reliability violations until we did the updates, but that’s where we’re close to the margin right now,” DePugh said.

One stakeholder said the CRP report would look much different if it considered the more than 2,500 MW of solar, wind and hydro planned to be brought into New York City.

The state in September selected two transmission line projects to help decarbonize power in New York City, the 1,300 MW Clean Path New York project and the 1,250 MW Champlain Hudson Power Express project, from among seven projects submitted to the Clean Energy Standard Tier 4 solicitation issued in January. (See Two Transmission Projects Selected to Bring Low-carbon Power to NYC .)

“There are resources that we’re not accounting for here because they haven’t met our inclusion rules yet,” said Zachary Smith, the ISO’s vice president of system and resource planning. “There are some that could have a very positive impact, and that’s in the report itself. A lot of the conversation is around that there are a lot of unknowns, and in our opinion the unknowns tip more towards concern than optimism.”

The ISO added a “Road to 2040” section to the CRP to give long-term consideration to generation and transmission issues, DePugh said.

For generation, the study concluded that a grid with significant amounts of intermittent resources will need significant amounts of emissions-free, dispatchable resources that can run for multiple day periods, and that such resources are not yet available or currently in the NYISO interconnection queue.

In addition, more inter- and intra-zonal transmission capacity will be required to deliver a reliable system with a high level of renewables penetration. Transmission additions would not reduce the amount of dispatchable resource capacity but would decrease the volume of energy needed from them, the report said.

MMU Recommendations

The ISO’s Market Monitoring Unit, Potomac Economics, issued a memo on the CRP and presented its findings that NYISO’s markets “are well-designed and generally provide efficient investment signals,” but have room for improvement.

The first of three main recommendations concerns the locational signals provided in the capacity market.

“There are four zones in the capacity market, but naturally the details of the power system are more granular than that, so from time to time there are reliability issues at a smaller level,” said Pallas LeeVanSchaick of Potomac Economics.

To address possibly misleading market signals resulting from transmission constraints between Staten Island and New York City, for example, or between Zones G and H, the monitor recommends implementing capacity locational marginal pricing (C-LMP) to accurately reflect resource adequacy value at each location.

Other recommendations include implementing marginal capacity accreditation for all resource types; using reasonable assumptions for all resource types in transmission security analyses; and considering discounting capacity payments to resources that do not help address transmission security needs.

Asked by one stakeholder what the ISO thinks of C-LMP, Dewey said, “We’ve got concerns about how heavy a lift that is or how radical a change that is, and it just hasn’t bubbled up to meet the criteria of us thinking it’s a good idea moving forward based on the benefits.”

C-LMP is part of the set of recommendations that NYISO is considering and, while not specifically on the list for next year, it is something that the organization will include in the prioritization process going forward, Dewey said.

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FERC Seeks Comments on Reactive Power Compensation

FERC on Thursday issued a Notice of Inquiry (NOI) seeking comment on how reactive power capability should be compensated in the face of changing conditions on the nation’s electricity grid (RM22-2).

Unlike the “real” power generated on the grid, which provides energy to end-users (and is measured in watts), “reactive” power (measured in volt-amperes reactive) is needed to support voltages that allow power to flow along transmission lines, a necessary component of system reliability.

“At times, resources must either supply or consume reactive power in order for the transmission system to maintain the voltage levels required to reliably supply real power from generation to load,” FERC staff explained in a presentation during the commission’s open meeting Thursday.

FERC Order 888, issued in 1996, ruled that the reactive supply and voltage control supplied by generators is one of six ancillary services that transmission providers must include in their open access transmission tariffs. At the time, the commission pointed to two methods that providers used for managing voltage control: either installing equipment as part of the transmission system or relying on generation resources.

“The commission concluded that the costs associated with the first approach would be recovered as part of the cost of basic transmission service and, thus, would not be a separate ancillary service. The second, using generation resources, would be considered a separate ancillary service and must be unbundled from basic transmission service,” FERC staff said.

Order 888 was issued at a time when the country’s resource mix overwhelmingly consisted of synchronous generators containing mechanical rotors that rotate in sync with system frequency and generates both real and reactive power in response to the needs of the system.

As FERC staff noted Thursday, in 1999, the commission issued an opinion approving American Electric Power’s method for separately allocating the costs for synchronous generators between providing real power and reactive power capability, including operations and maintenance costs associated with each function.

“Subsequently, the commission recommended that all resources located in regions that base reactive power capability compensation on a resource’s individual costs and that have actual cost data and support documentation should use the AEP methodology when seeking to recover reactive power capability costs pursuant to individual cost-based revenue requirements,” staff noted.

But FERC’s recommendation did not constitute a mandate, and regions have adopted differing approaches to compensating generators for reactive power, with PJM, MISO and certain non-RTO regions generally relying on the AEP methodology, while ISO-NE and NYISO compensate based on a fixed rate multiplied by a resource’s tested reactive capability. CAISO, SPP and other non-organized markets do not compensate at all for reactive capability, FERC staff pointed out.

Existing arrangements for compensating reactive power remained sufficient until “a general shift away” from cost-of-service rates in the electric industry and the increased adoption of nonsynchronous — or inverter-based — renewable and energy storage resources, FERC staff said. Those resources do not use mechanical rotors that rotate in sync with the grid and must have their inverters configured to provide reactive power capability, among other services.

According to FERC staff, “the AEP methodology was designed based on the physical attributes of synchronous resources owned by a public utility that utilized the commission’s Uniform System of Accounts and annually submitted a FERC Form No. 1,” the annual financial and operating report submitted by regulated utilities.

But the commission is now finding that most of the reactive power rate schedule filings it receives are made by owners of non-synchronous resources exempted from the Uniform System of Accounts and Form 1, although they’re still subject to other reporting requirements. FERC staff said that in the last six years, the commission has processed at least 260 reactive power proceedings in PJM and 125 such proceedings in MISO.

“These factors have contributed to customers and the commission facing challenges in evaluating proposed reactive power rate schedules submitted pursuant to Section 205 of the Federal Power Act,” FERC staff said. “Therefore, the commission is seeking comment on various aspects of AEP methodology-based compensation; potential alternative methodologies; and reactive power capability compensation through transmission rates for resources that interconnect at the distribution level.”

“When I first arrived at FERC, I really didn’t have an idea we would be doing so many reactive power cases,” Chairman Richard Glick said during the commission’s open meeting Thursday. He noted that of the 395 total cases, the commission has sent 135 of them to its administrative law judges for settlement and hearing procedures. “I suspect there’s a better, more efficient way, and that is what this Notice of Inquiry is going to look into, among other issues.”

Commissioner James Danly thanked Glick for the NOI, saying “we’ve spent an inordinate amount of time on these cases without having a generic approach to them.”

“This is an important way to find efficiencies in the trenches and relieve staff to do other import work,” Commissioner Allison Clements agreed.

Comments on the NOI are due 60 days after its publication in the Federal Register.

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MISO Resource Assessment: 140 GW Needed Within 20 Years

MISO said this week that its members will need to nearly double its current 140 GW of generating capacity within the next 20 years to meet state carbon-reduction targets while also maintaining reliability.

The findings come from a draft of the RTO’s first 20-year regional resource assessment, which staff plans to make an annual undertaking.

Broken down, MISO anticipates the necessary 140 GW will consist of 68% wind, solar, and solar and storage combinations; 11% standalone battery storage and demand-side resources; and 21% natural gas and other thermal resources.

The projections would nearly double the 146 GW of total available capacity MISO said it had on hand for this past summer. The RTO said the additions could have renewables supplying 40% of energy while halving current carbon emissions by 2040 on a footprint-wide basis.

By 2030 alone, the grid operator estimates that it will need 75 GW worth of new resources.

Capacity-expansion-necessary-to-meet-renewable-and-decarbonization-goals-(MISO)-Content.jpgCapacity expansion necessary to meet renewable and decarbonization goals | MISO

“In 10 years, 20 years, the resource mix is going to look very different,” engineer Aditya Jayam Prabhakar said Wednesday during a workshop to discuss the report. “A lot of renewable resources will be added in the future.”

MISO said that its members’ publicly announced generation plans account for less than half of what’s needed by 2040 to meet load and decarbonization goals.

The grid operator said members’ decarbonization goals can be met through 2034 with their current portfolios and publicly known generation additions. After that, MISO said it’s unclear how members will stick to their goals.

Jayam Prabhakar said many members have 80% or more carbon-reduction goals by 2030.

Some stakeholders have challenged the need for MISO to produce long-term regional resource assessments, saying information contained in the reports could get misused in state dockets to contest utilities’ integrated resource plans. RTO leadership appeared at the Organization of MISO States’ annual meeting to garner support for sharing its resource-planning expectations. (See LSEs, Southern Regulators Pan MISO Resource Assessment, OMS Registers its Concern over Supply Insecurity.)

Jayam Prabhakar said MISO’s findings should not be used in investment decisions or formal proceedings.

“That’s not the purpose or intent of this,” he said. “This is not a plan as to how members should achieve their [emissions] goals.”

The assessment is for stakeholders to “collectively have an idea of what’s going on around us” and maintain reliability, Jayam Prabhakar said. He said the assessment reinforces staff’s recent conclusion that its daily peaks will shift to later in the evening and its system-wide annual peaks will start occurring in winter rather than in summer. (See MISO Wraps 1 Renewable Study, Promises More Research.)

Jayam Prabhakar said the 2022 iteration of the assessment will change as members’ resource plans evolve with more aggressive decarbonization goals. “The changes are coming; the announcements are happening at a rapid pace. … There’s so much change,” he said.

Going forward, MISO will survey its members early in the year to collect future generation data, Jayam Prabhakar said. He said MISO plans to publish an assessment report in the fourth quarter of each year.

MISO said it partnered with Applied Energy Group to scour publicly available data on resource decisions. Next year, staff said they will reach out to members directly to inquire about their resource planning.

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House Passes $1.75 Trillion Build Back Better Act

The U.S. House of Representatives on Friday passed the Build Back Better bill, the $1.75-trillion budget reconciliation package that is key to advancing President Joe Biden’s social and climate agenda.

The 220-213 vote came four days after Biden signed a bipartisan infrastructure bill and followed the release of a report from the Congressional Budget Office estimating that the bill would add $367 billion to the federal deficit from 2022-2031. One Democrat, Rep. Jared Golden of Maine, joined Republicans in opposition.

The CBO figures have been contested by the Democrats and Biden, who insisted in a statement that the bill is fiscally responsible, fully paid for and would reduce the deficit “over the long term.”

A central point of contention between the CBO and White House is how much the cost of the bill will be offset by increased taxes and more rigorous tax enforcement on wealthier Americans and corporations. The CBO estimate of $207 billion fell far short of the $400 billion figure cited by Treasury Secretary Janet Yellen in a statement released Thursday.

The bill contains $555 billion in spending to help the U.S. achieve Biden’s goals of a decarbonized electric power system by 2035 and a net-zero economy by 2050. It is in addition to about $50 billion in climate and energy related spending included in the $1.2 trillion infrastructure bill.

It would be the federal government’s largest investment ever to address climate change, dwarfing the $80 billion included  in the 2009 economic stimulus enacted under former President Barack Obama.

According to a White House fact sheet, Build Back Better’s energy spending includes:

  • $320 billion for 10-year federal tax credits for a range of clean energy technologies, including residential and utility-scale solar, storage, transmission and cleantech manufacturing.
  • $105 billion in “resilience investments” and incentives to address extreme weather — wildfires, droughts and hurricanes — and legacy pollution in communities. The money would also fund a Civilian Climate Corps, which would employ tens of thousands of people to fight climate change through projects such as reforestation and wetland restoration.
  • $110 billion in investment and incentives to support the build-out of clean energy supply chains and manufacturing.
  • $20 billion for federal government procurement of “next-gen technologies,” such as long-duration storage, advanced nuclear reactors and low-carbon construction materials.

With House passage, the bill now heads to the Senate, where Sen. John Barrasso (R-Wyo.), ranking member of the Senate Committee on Energy and Natural Resources, said it will meet “a buzz saw of resistance.” In a statement released Friday, Barrasso framed the bill as an attack on Wyoming’s fossil fuel communities and families.

“Senate Republicans are united in our efforts to plunge a stake through the heart of this Democrat disaster,” he said.

With Republicans opposed to it, the bill’s fate rests with two moderate Democrats, Sen. Joe Manchin (D-W. Va.) and Sen. Krysten Sinema (D-Ariz.), both of whose votes will be needed to reach 50 and a tiebreaker by Vice President Kamala Harris.

In an interview Thursday with The Washington Post, Sinema said the House version of the reconciliation package did not match the Build Back Better framework that had been agreed with the White House in October, so further work would be needed. The House bill includes several provisions that may not survive the Senate, including a paid-leave program, an increase in the $10,000 cap on the deduction for state and local taxes and immigration provisions.

Manchin did not immediately release any statement following passage of the bill on Friday but has previously raised concerns about its potential impact on the already high rates of inflation Americans are experiencing. Last week, Manchin expressed opposition to a $4,500 federal tax credit for union-made electric vehicles, saying it was “not American.”

Robust Investments

Clean energy advocates and other energy industry trade groups quickly issued a flurry of statements on Friday supporting the bill and urging Senate passage.

Gregory Wetstone, CEO of the American Council on Renewable Energy, said the 10-year time frame for clean energy tax credits “finally moves the country beyond years of on-again, off-again renewable tax credits.”

The bill will provide “a stable, predictable and long-term clean energy tax platform that will spur critically important investment in renewable power, energy storage and advanced grid technologies. This is America’s last best chance to take timely action to address the global climate crisis, and it is imperative we rapidly accelerate the renewable energy transition,” Wetstone said.

Similarly, Jim Matheson, CEO of the National Rural Electric Cooperative Association called out provisions that will allow tax-exempt co-ops and municipal utilities to access clean energy incentives through a direct pay mechanism. The bill also includes $10 billion to help co-ops offset the costs of closing coal plants and investing in clean alternatives, he said.

Such measures are, Matheson said, “appropriate recognition of the need to level the playing field for not-for-profit cooperatives, reduce costs and open new doors for innovation.”

The bill’s support for offshore wind and building up clean energy supply chains earned praise from Liz Burdock, CEO of the Business Network for Offshore Wind.

“Fully harnessing the incredible potential offered by offshore wind requires a concentrated national industrial strategy that lays out clear clean energy goals, supports manufacturers and small businesses, builds up a workforce, and rebuilds our ports,” Burdock said. “The Build Back Better Act takes significant steps towards this strategy by providing the long-term support that will spark major investments in new factories manufacturing the blades, foundations and towers that will build the industry.”

The Carbon Capture Coalition also applauded House passage of the bill, with External Affairs Manager Madelyn Morris calling it “a package flush with robust investments in clean energy technologies.”

“If enacted, the package, in combination with the groundbreaking carbon management provisions included in the recently enacted Infrastructure Investment and Jobs Act, could deliver an estimated 13-fold increase in deployment of carbon management technologies and between 210 and 250 million metric tons of annual emissions reductions by 2035,” Morrison said.

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Should US Follow EU: Make Green H2 with Offshore Wind?

The Clean Energy States Alliance, a national association of state agencies, is urging states that will have access to considerable power from offshore wind turbines to consider allowing industry to dedicate some of that electricity to produce renewable, or “green,” hydrogen.

In a report issued in October and promoted recently in a webinar, CESA examined what European governments and companies are already considering and then looks at the feasibility of doing the same in the U.S.

Europe, with an already mature offshore wind industry and a commitment to decarbonize its economy, is looking seriously at replacing natural gas with hydrogen.

And offshore wind power, according to CESA and in other discussions, is being considered as the best source to power large electrolyzers that strip hydrogen out of water. The price of offshore wind is already falling and expected to further decline as larger projects proliferate, the report notes.

Wind projects in Europe, for example, are now transitioning to turbines that generate 12 MW, especially those very large projects being built or planned further offshore. Future projects will be measured in gigawatts. These developments are leading to economies of scale, lowering the price per megawatt-hour.

Another factor that further lowers prices is that turbines operate at a higher capacity factor; that is, they are able to operate at a higher percentage of time on any given day, generating more total power.

Finally, it appears that offshore power projects are expected to proliferate globally.

“The installed capacity of offshore wind is expected to quadruple globally over the next decade, growing from a cumulative installed capacity of around 50 GW in 2021 to 225 GW in 2030,” the report notes. “Approximately 50% of total offshore wind capacity in the world will be in Europe in 2030; Asia will account for roughly 40% of global installed capacity, and the U.S. for the remaining 10%.”

CESA-Webinar-Panel-(Clean-Energy-States-Alliance)-Content.jpgWarren Leon, (left) executive director of CESA and moderator in a CESA-produced hydrogen webinar questioned whether there are downsides to using wind energy to produce hydrogen from water. Val Stori, a CESA project director, said electrolyzers that use power to break apart the hydrogen and oxygen atoms in water are inefficient, meaning most of the energy used to make hydrogen is lost. Lee Wilkinson, a UK-based consultant, said European nations want to replace natural gas with hydrogen for industrial uses. But to be competitive, wind energy used to make hydrogen must be significantly lower priced that it is now, he said. | Clean Energy States Alliance

 

Lee Wilkinson, a senior consultant at UK-based BVG Associates and a consultant on the CESA study, summed it up this way: “A key reason why Europe is looking at hydrogen is that many people see it as a good replacement for natural gas. As soon as you say … we want to use hydrogen in our energy system, now you’ve got to find the best places to get it. And for many European countries, that’s wind.

“Europe has very good offshore wind resources that they have begun to capitalize on. So there’s a link between hydrogen and offshore wind, where Europe can start to make a connection on how [to] decarbonize more of its energy system.

“There are a few more subtleties to that. The first one is to get the cost of hydrogen down [and] keep the costs low, it’s best to produce hydrogen at scale. One benefit of offshore wind is that it is very good at being deployed at scale. Many wind farm has been deployed today in excess of 1 GW.

“Compared to other sources of renewable electricity like onshore wind and solar, you can get larger economies of scale if you power up your hydrogen production with offshore wind,” he said.

Big oil companies are also moving into offshore wind, he said, further building momentum for hydrogen production, as it somewhat resembles fossil fuels.

But a U.S. leap to hydrogen may not be as easy as it might initially appear. Not only did European offshore wind begin two decades ago, many European nations are already committed to decarbonizing their economies.

“One of the reasons we wrote this report is we wanted to advise U.S. policymakers, particularly states, as to what and how they should be thinking about hydrogen. There are some really big differences between where Europe is and where the U.S. is,” said Val Stori, CESA project director and author of the report.

“And I think one of the big ones is that Europe and the European states have legally binding targets to achieve carbon emission reductions. Significant ones, net-zero ones: 55% by 2030, compared to 1990 at the EU level.

“So … some of the most ambitious decarbonization targets in the world are in place in Europe. In addition, you have an offshore wind energy industry that is mature and is growing and costs are declining rapidly. So 70 GW of offshore wind projects are expected to come online in Europe by 2028 and 300 GW by 2050. That’s huge compared to where we are in the U.S.”

Getting the price of offshore wind down is based on another factor, said Stori: Today’s electrolyzers are inefficient. “That means a large portion of the renewable energy that we’re pouring in to make green hydrogen is lost upwards of 82%” across the full cycle of production and use, she said.

Noting that U.S. offshore wind is in its infancy, the report concluded that powering electrolyzers with wind energy is a use that probably should be considered in the future rather than immediately.

“It may ultimately make sense to use some of the offshore wind output in the United States for green hydrogen production. However, offshore wind in the U.S. is at a much earlier stage of development than offshore wind in Europe. For at least the next decade, the output from U.S. wind farms will be fully needed for electricity production that displaces fossil-fuel generation. That electricity will be especially valuable because the wind farms will be relatively close to major load centers,” the report concludes.

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FERC Again Dismisses Queue Complaint Against NYISO, Central Hudson

FERC on Thursday modified and upheld its July dismissal of a complaint by Hecate Energy that NYISO and Central Hudson Gas and Electric delayed the company’s 20-MW solar project in Greene County, N.Y., burdening it with $10 million in unnecessary system upgrade costs (EL21-49).

The commission said it continued to find Hecate has not met its burden under Section 206 of the Federal Power Act to show that the respondents violated the tariff or the FPA by failing to use reasonable efforts to process the project’s interconnection request.

“The reasonable efforts standard requires ‘efforts that are timely and consistent with Good Utility Practice and are otherwise substantially equivalent to those a party would use to protect its own interests.’ It does not require best or optimum efforts,” the commission said.

FERC in July dismissed the developer’s allegation that NYISO and the utility failed to use reasonable efforts in processing the interconnection request for the Greene County 3 project and violated the FPA by applying an “inclusion practice,” which was used to determine the firmness of an interconnecting project but is not delineated in the tariff regarding queue position. (See FERC Denies Solar Queue Complaint against NYISO, Central Hudson.)

In September, FERC denied Hecate’s request to rehear the order but said it would address the company’s concerns in a future order — the one issued Thursday.

“Hecate continues to downplay the various features that made the project atypical and contributed to the lengthier than typical study process,” the commission said in its latest order.

For example, FERC said Hecate asserted that the project has always been 20 MW. While that statement was true on Jan. 10, 2017, the date of the interconnection request that ultimately sparked the complaint, it does not portray the full picture the commission found. As NYISO explained, and Hecate corroborated, prior to Hecate’s submission of the project’s interconnection request, the company submitted an interconnection request for a 50-MW facility, which was subsequently withdrawn and split into three separate projects, one of which represents the original the project, the commission said.

The commission said it continued to find that the amount of time between the date the interconnection request and when respondents executed the facilities agreement was reasonable “given the complexities of the project.”

The commission also noted that Hecate’s request for relief was premature.

“As the project now will enter the subsequent Class Year, where it will be restudied, the possibility remains that the cost or amount of system upgrade facilities assigned to the project will change as the upgrade costs may be allocated to several projects,” the commission wrote.

Nor did FERC agree with Hecate’s contention that Central Hudson’s inclusion practice ”unfairly delayed its place in the queue.”

NYISO’s tariff “provides sufficient notice that transmission owners will update NYISO regarding facilities that should be included in the Base Case for NYISO’s studies of interconnection requests,” and the “‘rule of reason’ does not require the ‘inclusion practice’ to be explicitly set forth in the tariff,” the commission found.

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California Looks to Cloud Seeding for Hydropower

A California Energy Commission workshop this week looked at using cloud seeding to increase winter precipitation and snowpack as a way to boost late spring and summer runoff and hydropower, especially in the current drought.

“Those of us who are based in California are all too aware that the ongoing drought situation makes these issues particularly salient right now,” Susan Wilhelm, team leader for energy-related environmental research at the CEC, said Tuesday at the workshop. “While hydroelectric power is an important source of zero-carbon dispatchable power in our state, by late summer, hydropower resources are significantly diminished. This is especially so during drought conditions and has been especially so this year.”

Most of the state is in exceptional or extreme drought, according to the U.S. Drought Monitor. Major reservoirs behind hydroelectric dams stand far below their averages for November. Lake Shasta, the state’s largest reservoir, held 35% of its average content in mid-November and Lake Oroville held 58% of its average. The hydroelectric facility at Lake Oroville stopped producing power this summer for the first time since it opened in 1967 due to low water levels.

“There is a dire situation … [and] so cloud seeding is one of the viable alternatives to mitigate some of the adverse impacts of drought,” said Ramesh Gautam, manager of the snow survey program at the California Department of Water Resources. California and other Western states, including Arizona, Idaho and North Dakota, have been seeding clouds for decades, he said.

The Sacramento Municipal Utility District (SMUD) has been seeding clouds over the upper American River watershed southwest of Lake Tahoe since 1969 to increase hydropower production.

“To obtain this, we use glaciogenic seeding techniques, dispersing silver iodide particles when cloud conditions are ideal,” said Kaitlyn Bednar, SMUD hydrographer and cloud seeding project manager. The particles can be dispersed from ground units or airplanes, she said.

“Silver iodide is used as a cloud seeding agent because it has a crystalline structure similar to ice crystals,” she said. “It acts as an effective ice nucleus at around negative four degrees Celsius and lower. Once seeded, these newly formed ice crystals then continue to grow at a more rapid rate and fall out of suspension.”

Seeding clouds in the right conditions increases snowpack by roughly 3% to 10%, Bednar said.

“So, for example, in an average year if you get 50 inches of snow water equivalent, cloud seeding can increase that value up to 55 inches, translating to a large increase of runoff and power generation,” she said.

SMUD expanded its target area in 2017 from roughly 190 square miles to 444 square miles and seeds from November to March, Bednar said. Evaluations in 1975 and again in 2017 showed SMUD’s cloud-seeding has had insignificant environmental effects, if any, she said.

Pacific Gas and Electric, the state’s largest utility, has been seeding clouds in the Sierra Nevada since 1952. It halted one longtime effort over Lake Almanor, in the Sierra Nevada foothills, due to push-back from residents concerned about toxins. But PG&E continues to seed the Mokelumne River watershed in the mountains southeast of Sacramento, as it has been doing for 70 years.

“The Mokelumne cloud-seeding project is one of the oldest continuous cloud-seeding projects in the world,” said Kenneth Ericsson, a PG&E meteorologist who works in the utility’s cloud-seeding program.

PG&E uses ground-based burners to send silver iodide particles into cold, water-laden clouds, resulting in precipitation increases of 6% to 15%, Ericsson said.

“With a 6% increase, this can add approximately 8,700 acre-feet of water per year over the long term for the Mokelumne project,” he said.

PG&E has been studying a proposal to seed clouds in the watersheds of the Pit and McCloud rivers near Mount Shasta in an area with 7 million-acre feet of natural underground aquifer storage, Ericsson said. Lake Shasta holds about 4.5 million acre-feet in comparison.

During severe or prolonged droughts, the aquifer could produce about 10% of usable water in California, he said. A 5% increase in precipitation from cloud seeding could add approximately 210,00 acre-feet of water per year to the aquifer, rivers and Lake Shasta, increasing hydropower production, he said.

Does It Work?

The efficacy of cloud seeding has been debated for decades, with increases in precipitation difficult to measure scientifically or with statistical accuracy.

Sarah Tessendorf, a project scientist with the National Center for Atmospheric Research in Boulder, Colo., said supercomputing advances have allowed the “development of a new cloud seeding modeling capability that simulates the physics of cloud seeding.” Radar tracking and snow-gauge measurements have correlated with the computer predictions, Tessendorf said.

“One of the benefits of running the model is we can have a controlled experiment where we can see it in a simulation, and we can run the same simulation without seeding and look at the differences,” she said. “Something that we’ve been struggling with for decades is to have a truly controlled experiment in order to quantify the impacts of cloud seeding, so this modeling capability really moves us forward in that regard.”

In Idaho, an airplane distributed silver iodide while flying a zig-zag pattern. It resulted in precipitation falling in the same distinctive pattern, she said.

Frank McDonough, a former NASA scientist who heads the cloud-seeding program for the Desert Research Institute in Reno, Nev., said human air pollution has lessened rainfall and snowfall, making it more difficult to determine if cloud seeding works.

“Potentially, the challenge of finding the cloud-seeding signature is we’re seeding in a time when precipitation efficiencies are decreasing,” McDonough said. “So what we might actually be doing is keeping the storms the way they were by doing the cloud seeding.”

Additional comments and materials can be found on the CEC’s website at docket 19-ERDD-01. The CEC said it would eventually post a recording of the workshop but had not done so as of Thursday afternoon.

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GridEx VI Incorporates Recent Cyber Lessons

NERC’s biennial GridEx security exercise this week “incorporated elements of some of the major [cyber]attacks” experienced in the past year, according to Manny Cancel, senior vice president at NERC and CEO of the Electricity Information Sharing and Analysis Center.

GridEx VI consisted of two parts. First was a two-day distributed play exercise on Tuesday and Wednesday, in which more than 700 organizations took part including electric utilities, federal and state governments, manufacturers and supporting industries. The second part was a tabletop session on Thursday with executives from the electric, natural gas, finance and telecommunications industries; the Electricity Subsector Coordinating Council (ESCC); and U.S. and Canadian government officials.

In a media call prior to the tabletop session, NERC CEO Jim Robb said that he feels “really good about the defenses” the electric industry has created, citing the cybersecurity protections implemented through NERC’s Critical Infrastructure Protection standards and the “highly engaged executive culture” exemplified by the ESCC. However, the dependence of electric utilities on other sectors which do not have the same level of preparedness makes it imperative that they build strong relationships with those stakeholders, he said.

 “We all have to recognize that we can’t draw a box around the industry. Cross-sector impacts and the role of supply chain in assuring reliability and security are key, and that’s why events like GridEx are so important,” Robb said. “It brings all the players in the ecosystem together … to practice and drill, get to know each other, and grease those critical communication skids that would be required in an actual emergency. And it makes us all stronger together.”

While NERC did not reveal details about the scenarios for the distributed play or tabletop exercises, Cancel said that “supply chain attacks … attacks on remote access platforms, as well as ransomware [were] all incorporated.” Each of these attack vectors has been a major topic of conversation among critical infrastructure providers this year thanks to incidents like the hacks of the SolarWinds Orion and Microsoft Exchange platforms and the ransomware attack against Colonial Pipeline.

Pandemic Impacts Inform Exercise

This year’s GridEx was also the first since the outbreak of the COVID-19 pandemic, and while participants praised the industry for showing up in spite of the logistical difficulties, the impact of the virus was keenly felt at the event. Southern Co. CEO Tom Fanning said that the industry is well aware of the cybersecurity risks created by the need for most employees to work from home, and that these threats were a necessary element of the exercise.

“The pandemic opened up a different work environment, which I think will persist from here on out. The old work environment, of 80% of your employees having to be physically in the office, is probably [gone], and I’m sure we are all adopting hybrid approaches … that require linkages from your distant location into work,” Fanning said. “And so every intersection of communication provides an opportunity for the bad guys to get in.”

Fanning added that the workforce changes caused by the pandemic are “tactical” and do not rise to the same level of concern as “strategic changes” such as the growth of artificial intelligence and computing power that enable more sophisticated cyberattacks.

Robb added that the pandemic also affected the logistics of the event itself, forcing the tabletop exercise, which is usually held in person, to be conducted online. However, this decision did lend a bit of verisimilitude to the exercise, he added.

“In many ways [it’s] unfortunate because the relationships that we’ve built in the past through the tabletop have been very valuable, but it’s probably more reflective of reality,” Robb said. “In the event of an actual grid emergency, the likelihood of us getting 50 key people in a room in Washington, D.C. on day one [is around] zero. So I think this allows us to test our ability to work in a dispersed manner, to deal with a very real scenario that could play out.”

RTOs Pitch In

Representatives from the RTOs also took part in the exercise. Matt Turner, executive director of enterprise support and campus operations for CAISO, said the scenario modeled “multiple cyber and physical attacks” that gave more than 300 participants and observers from the organization and its reliability coordinators a chance to test their emergency response plans. The exercise included a test of the effectiveness of high-frequency radio communication among “multiple balancing authorities and [the Governor’s Office of Emergency Services].”

ERCOT, NYISO and ISO-NE also participated, with Zachary Hutchins of NYISO calling the exercise “an excellent opportunity … to test response plans alongside governmental agencies, supply chain partners, other ISOs and the broader utility industry.” PJM said more than 300 of its personnel took part in a “rigorous simulated challenge to our crisis response plans,” while nearly 200 MISO employees “tested system operations, security, [information technology], communications and the Unified Incident Command structure,” the RTO said.

“We have to be ready to respond not only to those events that we can imagine but also be flexible in these exercises to handle situations that we have never encountered,” said Mike Bryson, senior vice president of operations at PJM. “GridEx is invaluable for us to test our ability to keep the power flowing at all times while also learning how we can improve our own practices and fine tune our response plans.”

NERC will review the results of this year’s exercise for a public report, which it plans to release in March 2022.

Jason York, Michael Yoder, Michael Kuser, Hudson Sangree, Amanda Durish Cook and Tom Kleckner contributed to this article.

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CHESSA Working with Conservative Groups to Promote Solar in Rural Virginia Counties

Democrats’ stunning electoral losses in Virginia’s recent elections could usher in new opportunities for bipartisan action on clean energy and create a model for the rest of the country, according to Ron Butler, state director of Conservatives for Clean Energy Virginia (CCE-VA).

“I do think the change in government here could actually be a positive thing for what we’re trying to do,” Butler said during a panel discussion at the Chesapeake Solar and Storage Association (CHESSA) Solar Focus conference Tuesday. “That’s what I am going to be focused on over the next few months: trying to get some positive voices coming out on our side.”

He noted that Republican Governor-Elect Glenn Youngkin has supported an “all-of-the-above” approach to energy, which includes wind and solar. Youngkin was also a clean energy advocate when he was co-CEO of the Carlyle Group investment firm, boasting about the company’s achievement of carbon-neutrality in 2018, Butler said.

Making an economic and locally focused case for clean energy was a major theme in two conference sessions Tuesday: one on rural solar development in Virginia, and a second looking at the state’s solar market in general and the potential legislative challenges ahead with a new 52-48 Republican majority in the House of Delegates.

On the one hand, Del. Todd Gilbert (R), the incoming speaker, has set the repeal of Virginia’s landmark Clean Economy Act (VCEA) as a priority, while Del. Terry Kilgore (R), the new majority leader, voted for the law and has been a strong advocate for energy storage. Passed in 2020, the VCEA sets Virginia on a path to zero greenhouse gas emissions by 2050 and mandates the closure of most of its coal-fired plants by the end of 2024. The law also calls for the state to develop 5,200 MW of offshore wind, 16,000 MW of solar and onshore wind, and 3,100 MW of energy storage.

Harry Godfrey, executive director of Virginia Advanced Energy Economy (AEE), said the Democrat-led state Senate should serve as a firewall to stave off any repeal attempts. But he also stressed that solar industry advocates should “emphasize the job creation opportunities, the community investment opportunities and then the broader economic gains that are being made as a result of this [law], and as a result the business certainty the VCEA creates.”

The law is driving major economic development opportunities in the state, Godfrey said, drawing data centers and other energy-intensive businesses; for example, Microsoft’s planned expansion of its data center in southern Virginia. The companies are coming, Godfrey said, “because they are looking for states where they know they’re going to be able to effectively decarbonize their load, and the VCEA will help give them certainty and … manage their costs.”

In rural counties, the economic argument can also help ease projects through local permitting before city councils or land-use boards, said Skyler Zunk, Virginia field director for the Land & Liberty Coalition, a nonprofit which began in Michigan and now works in a total of 10 states, supporting “conservative, responsible” clean energy development.

“Since the outset, our goal has been to create a baseline of support in every county in which we engage so that developers can come into these communities, and [we can] point them toward a list of good conservatives who support these energy projects for their own set of reasons,” Zunk said. “Some want to see it bolster the local county tax revenue budget. Some want to see diversification of income; some want to see investment, creation of jobs [and/or] more spending in their communities when these multimillion-dollar projects come to these locations. We’re taking everybody’s different angles into our tent and hopefully making them better advocates.”

‘Stay the Course’

The panel on the Virginia solar market looked more at the impact of the November election than specific market drivers or segments.

While concerned about possible Republican efforts — both in the House and at the Virginia State Corporation Commission — to roll back the state’s progress on clean energy, Del. Alfonso Lopez (D) framed the Democratic losses as “a short-term issue … from a political, electoral standpoint. The long game in Virginia is very much embracing renewable energy, embracing the benefits of an environmental as well as just a bottom-line perspective, and that we only have room to grow.”

He also noted that many of Virginia’s clean energy laws have passed with bipartisan support; for example, the 2019 compromise legislation (SB 1769) that raised the cap for net metering for the state’s electric cooperatives, opening the way for more residential rooftop solar development.

Given past bipartisan successes and current political realities, Virginia AEE’s approach is to advocate for a “diversified energy future,” Godfrey said. “It is not overly reliant upon one particular resource but is a combination of solar and wind, battery storage and grid-edge solutions, along with a host of other technologies, all working in tandem to provide affordable, reliable and clean generation. … Our philosophy is how do we bring these technologies into play? How do we create markets that allow each of these technologies to thrive?”

Based on the job creation and other economic benefits the VCEA is already providing, he said, industry messaging to state legislators should emphasize the need to “stay the course. If you believe you’re a pro-business lawmaker and want to see Virginia grow, the best thing to do is stay the course.”

Brandon Smithwood, senior director of policy for Dimension Renewable Energy, a solar developer, said he spends a lot of time in Republican states where advancing solar depends on making it a bipartisan issue, especially at the local level.

“Some of the challenges that we’re seeing, they’re really [about] permitting projects,” Smithwood said. “A lot of these projects are in conservative parts of the state, and so it was going to be a bipartisan issue anyways because it’s local supervisors in those counties that are making the decisions whether the projects move forward.”

Lopez called for the solar industry to be “out in force” for the coming session of the Virginia legislature, and not just for single organized days. “It’s got to be the dozens of solar CEOs and executives who are building large footprints here in the commonwealth. You’ve got to be in Richmond throughout the session, and you all have to be pushing the same narrative about why growth of renewable energy and growth of solar specifically is so vitally important in Virginia,” he said.

Consistency will be critical, Lopez said. “Every time there’s a hearing, every time there’s a conversation, you’re basically knocking it out of the park,” he said. “That’s how we continue to move forward. That’s how we avoid going back.”

Different Perspectives, Different Tools

The permitting roadblocks developers like Dimension have encountered in Virginia’s rural, largely Republican counties  have prompted CHESSA to work with conservative groups like CCE-VA and Land & Liberty, a recent effort discussed during the panel on land-use issues and rural solar development.

“The goal of CHESSA was to work with rural counties and to bring a value proposition to them that would be unique to them,” said John G. “Chip” Dicks of Gentry Locke Attorneys, CHESSA’s lobbyist in the state capital of Richmond. Local opposition to solar projects means “we need to take a different perspective and to use different tools and a different rationale,” Dicks said.

Land & Liberty started in Michigan, where despite Democratic leadership in state government, projects were still running into local opposition and permitting problems, said Bradley Pischea, the organization’s deputy director. The group’s mission is twofold, he said, “to amplify the voices that already exist in a supportive community, but then also [to] go out and find the ones we can pull into that chorus that already exists.”

The focus is always on issues that resonate well with conservatives, Pischea said. “This is going to fund your local police force. This is going to fund your roads and flow into school funding as well.”

Land & Liberty’s approach aligns well with the findings of a survey CCE-VA conducted in the summer months before the election, Butler said. While the survey found broad support for solar across the state, the one issue that elicited the most positive response was property rights, he said.

“The property owner should have the right to use their land to develop solar if that’s what they want to do because it’s clean energy that benefits everyone,” he said. “The climate change issue doesn’t really resonate with [conservatives]; that’s not something that gets them to ‘yes,’ but the property rights angle does.”

Even before developers are on the scene, Land & Liberty starts building relationships with local conservatives, positioning the organization as an educational nonprofit with a particular focus on land-use issues. Zunk has been traveling the state, talking “with local folks, boards of supervisors, planning commissions, business owners, community members, everybody who has some feasible way of touching the solar industry,” he said.

“When we’re able to approach them with a good deal of on-the-ground knowledge and speak the language that these board members are used to speaking and message to them the kinds of messages that they’re most likely to support —  property rights, economic development, paying for local public goods with their tax revenue — it’s easy to chat with them and have a normal conversation,” Zunk said. “We’ll never lead off with, ‘Hey, there’s this project that you should support.’”

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Louisiana PSC Defers Vote to Force MISO Exit

Louisiana regulators on Wednesday shelved a vote that might have compelled Entergy Louisiana and Cleco Power to leave MISO for another grid operator.

The Louisiana Public Service Commission deferred an agenda item that could have required Entergy and Cleco to provide MISO a one-year notice of membership withdrawal. The potential vote was postponed to the commission’s Dec. 14 meeting and set off a tense exchange between PSC Chairman Craig Greene and Commissioner Eric Skrmetta.

Louisiana regulators in October said they would consider forcing their utilities to leave MISO if their ratepayers are forced to fund transmission built in the footprint’s northern reaches. Skrmetta was most vocal about the exit option. (See La. Regulators Threaten MISO Departure over Tx Costs.)

According to its membership agreement for transmission owners, MISO requires departing TOs to provide it with a year’s advance notice of their intent to exit the system.

Skrmetta said the delay gives the PSC time review MISO’s cost-allocation FERC filing for its long-range transmission plan.

The RTO has said it will create two separate but identical cost-allocation designs for its Midwest and South subregions that rely on a 100% postage stamp rate to load. But the grid operator also committed to conducting three-year reviews examining whether new Midwestern transmission benefits MISO South. (See MISO Schedules Cost-allocation FERC Filing.)

“The good news is there are alternative markets available if MISO does not prove to be [an] economic value to the citizens of the state,” Skrmetta said during the commission’s meeting Wednesday, referring to SPP or the new Southeastern Energy Exchange Market (SEEM).

The Entergy Regional State Committee recently hosted SPP staff and SEEM representatives for presentations on the organization’s membership. Louisiana regulators have considered both as alternatives to MISO, although staff has not embarked on a formal study. (See SPP, SEEM Woo Entergy Regulators at NARUC.)

Entergy has been part of the MISO grid since 2013. Its membership suspended a federal antitrust investigation into the utility.

Greene, Campbell Balk at MISO Divorce

The vote delay appeared in part because of Greene’s hesitation at Louisiana utilities forgoing MISO’s market savings. He acknowledged there’s currently a lot of “noise” around the RTO’s transmission-planning process.

“Participation in the MISO market has delivered hundreds of millions of dollars of benefits to [Louisiana] utility customers over the last seven years by expanding access to more resources,” he said. “The more resources available, the better for customers. I do not support walking away from an organized market that provides opportunities to attract private investment to the state.”

Greene also said the state hasn’t conducted a cost-benefit analysis “indicating we would somehow be better off without MISO.”

“So far, I think it’s universal that we all agree we want to get the best benefit and value for ratepayers. So far, I think it’s only Commissioner Skrmetta’s opinion that we should leave MISO, not the opinion of the public service commission, or at least of me,” Greene said.

“Speak for yourself,” Skrmetta retorted.

“Yeah, I think you have already,” Greene countered.

“Well, you’re doing a good job on your own. I’m your huckleberry,” Skrmetta said.

Greene noted that the commission’s concerns with MISO relate to transmission planning and cost allocation. He said he would wait until the grid operator made its cost allocation filing before rendering judgement.

“I look forward to that clarification and removing the uncertainty around this issue in December,” Greene said, adding later that it’s “pivotal” that Louisiana work with MISO on reliability and affordability.

Greene previously said an organized wholesale market is a “necessity” for Louisiana.

Commissioner Foster Campbell pointed out that ratepayers in his northern Louisiana district are expected to pay for Entergy’s storm recovery efforts in coastal and southern Louisiana. He drew parallels between that and MISO South bearing transmission costs from the Midwest.

“The argument is, ‘They’re doing something up north, and we’re paying for it down south,’” he said. “Let me remind you something … we’re paying for: all the storms we never have with Entergy. … We’re talking all of this about north and south. Sometimes that happens. … We pay like we were living in New Orleans.”

Campbell said he doesn’t support a break with MISO, just like he doesn’t advocate splitting Louisiana into separate cost zones.

“You all were bragging about how good it was last year. And this year, you all don’t have the religion. I don’t know what happened,” he told commission staff, referencing previous savings under MISO membership.

Skrmetta reminded commissioners that MISO is considering $130 billion worth of transmission projects.

“That’s a monumental element that would attack our rates in a way we’ve never seen,” he said. “So, we need to keep our eye on the issue; we need to keep our eye on what’s the best market for our public. It really is about the money.”

Entergy Louisiana spokesperson Brandon Scardigli said the utility remains satisfied with MISO membership.

“Since Entergy Louisiana became a member of MISO, our customers have realized significant cost savings and operational benefits associated with MISO membership,” he wrote in an emailed statement to RTO Insider. “We will continue to actively participate in the MISO stakeholder process to advocate for policies that ensure that our customers’ interests are protected and that they continue to receive a reasonable level of benefits from MISO membership.

“We also support the Louisiana PSC’s interest in continuing to monitor Entergy Louisiana’s participation in MISO to ensure that membership remains beneficial for our customers,” he said.