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November 2, 2024

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PJM MRC/MC Preview: Dec. 15, 2021

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings on Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. Stakeholders will be asked to endorse proposed revisions to Manual 6: Financial Transmission Rights, conforming to the joint PJM-stakeholder proposal addressing auction revenue rights (ARRs) and financial transmission rights endorsed at the October MRC. The changes were initiated after the GreenHat Energy default in 2018, including a six-month review by an independent consultant and work done at the ARR/FTR Market Task Force. (See Stakeholders Endorse PJM ARR/FTR Market Changes.)

C. Members will be asked to endorse proposed revisions to Manual 10: Pre-Scheduling Operations resulting from a periodic review. The revisions were endorsed at the November Operating Committee meeting. (See “Manual Changes Endorsed,” PJM Operating Committee Briefs: Nov. 4, 2021.)

D. The committee will be asked to endorse proposed Manual 14B revisions resulting from a biennial review. The revisions include the addition of a new section that features details around the incorporation of end-of-life (EOL) needs in the Regional Transmission Expansion Plan, which were part of the tariff attachment M-3 discussions. (See “Manual Endorsements,” PJM PC/TEAC Briefs: Nov. 2, 2021.)

E. Stakeholders will be asked to endorse proposed revisions to Manual 14D: Generator Operational Requirements resulting from a periodic review. The updates featured the addition of several new sections, including one describing eDART modeling requirements. (See “Manual Changes Endorsed,” PJM Operating Committee Briefs: Nov. 4, 2021.)

F. Members will be asked to endorse proposed revisions to attachment DD of the tariff endorsed by the Governing Document Enhancement and Clarification Subcommittee. The revision includes removing section 6.2(c) of the attachment because FERC affirmed PJM’s position that this section of the tariff is no longer applicable and encouraged the RTO to remove this provision as part of its next tariff clean-up filing.

Endorsements (9:10-10:10)

1. Undefined Regulation Mileage Ratio Calculation (9:10-9:30)

The committee will be asked to approve the proposed issue charge to create a new senior task force to re-evaluate the current regulation market design. The issue charge was first presented at the November MRC meeting. (See “Undefined Regulation Mileage Ratio Calculation,” PJM MRC/MC Briefs: Nov. 17, 2021.)

If the MRC approves the issue charge creating the task force, another vote will be taken on the short-term proposals from PJM and the Independent Market Monitor addressing the undefined regulation mileage ratio calculation. Both proposals failed a vote at the October MRC. (See “Regulation Mileage Ratio Fails,” PJM MRC/MC Briefs: Oct. 20, 2021.)

2. Solar-Battery Hybrid Resources (9:30-9:50)

Stakeholders will be asked to endorse the proposed solution and corresponding tariff and Operating Agreement revisions to address market participation by solar-battery hybrid resources. PJM conducted a prefiling meeting with FERC staff in September, and the commission made suggestions to reconfigure the language to increase its chances for approval. (See “Solar-battery Hybrid Resources,” PJM MRC/MC Briefs: Nov. 17, 2021.)

3. Synchronous Reserve Deployment Stakeholder Initiative (9:50-10:10)

The committee will be asked to endorse the proposed solution and corresponding tariff and OA revisions addressing synchronous reserve deployment during a spin event. The proposal was developed from discussions in the Synchronized Reserve Deployment Task Force (SRDTF). (See “Synchronous Reserve Deployment Stakeholder Initiative,” PJM MRC/MC Briefs: Nov. 17, 2021.)

Members Committee

Endorsements (1:30-1:45)

1. Elections (1:30-1:45)

Stakeholders will vote on the proposed sector representatives for the 2021/22 Finance Committee and the 2022 sector whips. The new Finance Committee members include: Susan Bruce, PJM Industrial Customer Coalition (End-use Customer); Jeff Whitehead, Eastern Generation (Generation Owner); Bruce Bleiweis, DC Energy (Other Supplier) and; Alex Stern, PSEG Services (Transmission Owner).

The 2022 sector whips include: Adrien Ford, Old Dominion Electric Cooperative (Electric Distributor); Greg Poulos, Consumer Advocates of the PJM States (End-use Customer); Michael Borgatti, Gabel Associates (Generation Owner); Brian Kauffman, Enel N.A. (Other Supplier); and Sharon Midgley, Exelon (Transmission Owner).

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Biden Calls for Federal Procurement of 100% Clean Energy by 2030

President Joe Biden signed a sweeping executive order Wednesday directing the federal government to use carbon-free electricity for its 300,000 buildings and to decarbonize its 600,000 vehicle fleet.

The order requires 100% carbon-free power on a net annual basis by 2030, including 50% 24/7 carbon-free electricity. What that means, a White House fact sheet says, is that “the federal government’s real-time demand for electricity will be met with clean energy every hour, every day, and produced within the same regional grid where the electricity is consumed.”

The policy will “catalyze the development of at least 10 GW of new American clean electricity production by 2030,” according to the fact sheet.

The order seeks to lead by example and leverage the government’s massive purchasing power of $650 billion per year to “protect the environment, drive innovation, spur private sector investment, improve public infrastructure and create new economic opportunity,” it said.

The order sets out a list of emission reduction goals, including:

    • For all federal government buildings: net-zero emissions by 2045, with an interim goal of a 50% reduction by 2032;
    • For all federal government operations: net-zero by 2050, with an interim target of a 65% reduction by 2030; and
    • For federal procurement: net-zero by 2050, via a “Buy Clean” policy that will promote the use of low-carbon construction materials and other low-carbon materials across the supply chain.

The order also calls for electrification of the government’s fleet of 600,000 cars and trucks, requiring that 100% of new acquisitions be zero-emission vehicles (ZEVs) by 2035, with 100% ZEV acquisition for light-duty vehicles by 2027.

It allows exemptions for “any vehicle, vessel, aircraft or non-road equipment that is used in combat support” or for other military purposes. Exemptions are also allowed for government activities and facilities for reasons of national security or to protect intelligence sources or undercover law enforcement operations.

Implementation of the order will be overseen by a new federal chief sustainability officer, appointed by the president, and Biden also hopes to draw in executives from the private and nonprofit sectors for “term-limited appointments to bring innovative perspectives and expertise to federal government.” Key federal agencies will also be required to appoint chief sustainability officers and establish sustainability training for employees.

Funding for implementation, the fact sheet says, will come from the bipartisan infrastructure act, signed into law last month, and the Democrats’ Build Back Better budget reconciliation package passed by the House and now being negotiated in the Senate. Build Back Better includes $20 billion for federal clean energy procurement, according to the White House.

Demand-side Incentives

The order was immediately slammed by Sen. John Barrasso (R-Wyo.), ranking member of the Senate Committee on Energy and Natural Resources, who characterized it as an “outrageous and disgraceful” attack on the jobs of U.S. fossil fuel energy workers.

“President Biden’s plan is all about expanding government,” Barrasso said in an email statement. “He is adding a sustainability czar to the White House and every agency. … This is not build back better; it’s another backbreaking move to build bigger bureaucracy.”

Clean energy advocates praised the order, saying it will result in economic growth and job creation while also calling on Congress to finalize passage of the Build Back Better Act.

“This executive order is a critical step to getting the on-the-ground momentum for a complete transition to a decarbonized energy economy,” said Paula Glover, president of the Alliance to Save Energy. She noted that the order references the federal building performance standard now being developed by the White House Council on Environmental Quality for reducing building emissions.

Such standards will “accelerate clean energy research and manufacturing,” she said.

Assuming that building retrofits and vehicle fleet transitions will roll out gradually over a number of years, Harry Godfrey, manufacturing policy lead at Advanced Energy Economy, estimated the order could stimulate business sales of $35 billion to $70 billion by mid-decade, while adding 90,000 to 180,000 jobs in advanced energy manufacturing. The near-term impact on U.S. gross domestic product could be an additional $13 billion to $26 billion, he said.

“As we await the essential clean energy investments contained in Build Back Better to pass Congress, this executive order utilizes the vast purchasing power of the federal government to begin to scale up a large variety of advanced energy technologies and create good jobs in America,” Godfrey said in an email to RTO Insider.

Nancy Ryan, a partner at consulting firm eMobility Advisors, says the commitment to 100% EV acquisition will result in sales of thousands of vehicles per year.

“It’s a commitment going forward that auto manufacturers can take to the bank because they have this commitment to sales,” she said. A more indirect effect is “that it’s a vote of confidence from the federal government because these are working fleets. … It sends a really strong signal that working fleets can be electrified.”

It will also help build out the U.S. supply chain for the thousands of parts that go into electric vehicles, “boosting domestic manufacturing capacity [and] providing another nudge to put the capacity in the U.S. and the jobs that go with it,” she said.

Jason Walsh, executive director of the BlueGreen Alliance, also called out the order’s Buy Clean provisions as a way to “reshore” manufacturing work back to the U.S. “We make steel and cement and other materials in this country in much cleaner ways than some of our biggest competitors, notably China,” he said. “This creates really important demand pull for cleaner building products. We need to create those markets in order to incentivize changes in industry.”

Still another benefit of the order “is the fact that it’s long range, that it is not going to happen overnight,” said Costa Nicolaou, CEO of solar racking manufacturer PanelClaw Inc., an Esdec Solar Group company. “It creates yet another demand-side incentive for manufacturers to set up shop in the U.S., with that demand being in place. And for manufacturers that are already here, it can create a demand-side incentive to increase manufacturing in the U.S. … to scale up our manufacturing even further.”

Filling Skill Gaps

But Ryan said the executive order also creates challenges. For example, electrifying the federal fleet also means building out charging infrastructure, which in turn could put pressure on utility distribution systems, as charging up large fleets creates heavy demand on the grid. Utilities across the country are now looking at different options, such as managed charging programs, to handle that new demand, she said.

The U.S. also may not have the trained workers needed to meet Biden’s ambitious goals, and the executive order in and of itself will not be enough to spur workforce expansion, Walsh said.

“We have skill gaps in certain sectors,” he said. Funds in the Build Back Better Act would allow unions to dramatically increase training and apprenticeship programs to expand the clean energy workforce.

“We need to make clear to a whole new generation of workers that we’ve got to rebuild and repower and retrofit this country,” Walsh said. “And that is a project that is not only enormously important from a climate standpoint, but it also has the potential to be a pathway to career jobs that, if they’re union, can be high quality and family-supporting.”

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Youngkin Vows to Pull Va. from RGGI

Governor-elect Glenn Youngkin (R) said Wednesday he will pull Virginia from the Regional Greenhouse Gas Initiative by executive order once he takes office, but RGGI supporters said he doesn’t have the power to do so.

“RGGI will cost ratepayers over the next four years an estimated $1 billion to $1.2 billion,” Youngkin said in a speech at the annual meeting of the Hampton Roads Chamber of Commerce in Virginia Beach, according to the Richmond Times-Dispatch. “RGGI describes itself as a regional market for carbon, but it is really a carbon tax that is fully passed on to ratepayers. It’s a bad deal for Virginians. It’s a bad deal for Virginia businesses.”

In August, the Virginia State Corporation Commission approved Dominion Energy’s request to recover RGGI costs from ratepayers, which the utility estimated would cost the typical residential customer $2.39/month. Youngkin cited a Dominion filing Monday asking the SCC for permission to increase the surcharge to $4.37/month beginning Sept. 1, 2022.

Authority Questioned

The Democratic-controlled legislature approved a bill to join RGGI in 2020. Youngkin will take office Jan. 15 with a Republican-controlled House of Delegates but with Democrats still in control of the Senate.

As part of the compact, RGGI’s members — including Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont — agree to a declining cap on CO2 emissions from the power sector.

The Department of Environmental Quality’s (DEQ) regulation implementing the law capped CO2 emissions for Virginia at 27.1 million short tons for calendar year 2021 and decreases the emissions cap annually by about 3% to reach a 30% reduction from 2020 levels by 2030. Emission sources subject to the rule must obtain and surrender a CO2 emission allowance for every short ton emitted.

“I can assure you there’s a lot of lawyers … that are busy going to the [law] books right now,” Sen. Lynwood Lewis (D), who sponsored the RGGI authorization in the Senate, told The Washington Post.

“I thought Virginia freed itself from an all-powerful monarch in 1776? Perhaps Glenn Youngkin still thinks he’s a CEO and can’t recall his fourth grade separation-of-powers lesson?” tweeted Sen. Scott Surovell (D).

Youngkin’s transition office issued a statement saying the governor has authority to leave RGGI because “Virginia’s participation is governed by a contract agreement, signed by the Department of Environmental Quality and other regulations.”

Cale Jaffe-(UVA Law School) Content.jpgUniversity of Virginia Law School Associate Professor Cale Jaffe | UVA School of Law

University of Virginia Law School Associate Professor Cale Jaffe, director of the Environmental Law & Community Engagement Clinic, told the Virginia Mercury that although the governor will have authority over DEQ — which the legislation directed to manage the program — it would require action by the seven-member Air Pollution Control Board to quit RGGI. “The governor cannot just undo regulations that he might not like via executive order,” Jaffe said.

Democrats currently have a 7-0 majority on the board, and it could take Youngkin three years to win control of it. Two members’ terms expire next June; one expires in 2023; and two more expire in 2024.

Lee Francis, a spokesman for the Virginia League of Conservation Voters, which supports RGGI, agreed with Jaffe’s analysis. “Youngkin’s proposal is grounded in neither fact or law,” Francis told the Times-Dispatch.

Impact Challenged

In addition to legal questions over Youngkin’s authority, the governor-elect’s statement sparked a debate over RGGI’s impact.

Del. Todd Gilbert (R), who will become House speaker, said RGGI’s impact on climate change has been “negligible at best.”

“Virginia was reducing carbon emissions from power plants at a rate comparable to RGGI states before joining the cap-and-trade group,” Gilbert said in a statement. “When a policy costs the public a significant amount of money for no tangible benefit, that policy should be examined carefully and, if practical, rolled back.”

Dominion, which opposed joining RGGI, agreed, saying it continues to believe it “would result in a financial burden on its customers with no real mitigation of GHG emissions regionally.”

“Here in Virginia, we are focused on an all-of-the-above approach to sustainability while keeping our rates below the national average and our service reliability strong,” spokesperson Rayhan Daudani said. “This includes the largest offshore wind project in the nation, transformation of the grid, re-licensure of our nuclear units, energy storage and solar energy, all of which creates jobs and economic opportunity.”

But others said Youngkin’s action would eliminate the source of hundreds of millions in funding for flood preparedness and energy efficiency. Youngkin also told the chamber of commerce Wednesday he would develop a plan to “combat sea-level rise.”

The state is directing 50% of its RGGI auction proceeds to low-income energy-efficiency programs and 45% to a new Community Flood Preparedness Fund. The remainder offsets administrative expenses.

“Regardless of your political party, if you’re a legislator in an area that’s impacted by sea-level rise of just recurrent flooding … you should be very reluctant and cautious in completely devastating that fund,” Sen. Lewis said. “This was going to provide a significant source of revenue.”

Rising Prices

Virginia raised $227.6 million this year in carbon credit auctions this year, including $85.6 million in the quarterly results announced last week. The DEQ had previously predicted the state’s annual proceeds would be between $104 million and $109 million.

Last week’s quarterly auction cleared at $13/ton — the highest price and single largest price jump in the program’s history. (See RGGI Price Hits Record High, Jumps 40% over Last Auction.)

Dominion’s Dec. 6 filing with the SCC estimated the company will need 19 million allowances to cover the emissions from its Virginia-based generation fleet for the year beginning in September. The company said it assumed a weighted average price of $10.53/allowance based on December ICE futures contracts for 2021 and 2022 and the ICF International forward price curve for 2023.

Reaction

Environmental groups and others reacted with alarm to leaving RGGI.

The Northern Virginia Affordable Housing Alliance tweeted, “Saving $54 annually per household is not worth the tradeoff” with the loss of the EE funding.

“This is the wrong decision,” said Virginia Advanced Energy Economy.

Lynnhaven River Now, an environmental group, tweeted that Youngkin’s move would “gut” the flood preparedness fund.

“Hell no! This is unacceptable,” tweeted the Chesapeake Climate Action Network.

U.S. Rep. Don Beyer (D-Va.) tweeted that withdrawing from RGGI “would mean Glenn Youngkin’s first steps as governor of Virginia are steps backwards. He has time to take a closer look at this and reconsider, and that is what he should do.”

Maryland Del. Marc Korman (D) noted that Republican Gov. Larry Hogan attempted to pull Maryland from RGGI and was blocked by the legislature. “We are still in the cap-and-trade program,” he tweeted.

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WECC Regional Assessment to Focus on Variability

In a preview of WECC’s 2021 Western Assessment of Resource Adequacy (WARA), Branden Sudduth, the regional entity’s vice president of reliability planning and performance analysis, said the document will aim to provide readers “a better understanding of how increasing variability … is really forcing us to rethink resource adequacy in the interconnection.”

WECC introduced the WARA last year to supplement NERC’s Long-Term Reliability Assessment (LTRA), which Western stakeholders had complained did not capture all the risks that the Western Interconnection faced in 2020, such as rolling blackouts caused by record-setting heat waves in California. (See Western RA Planning Must Change, WECC Says.) This year’s WARA will be published concurrently with the LTRA, which is set to be released next Friday.

Peak hour demand variability across the Western Interconnection (WECC) Content.jpgPeak hour demand variability across the Western Interconnection | WECC

Sudduth told attendees of WECC’s Board of Directors meeting on Wednesday that the WARA seeks to account for variability in setting its projections. While expected peak demand in 2022 is set at around 165 GW (an increase of 15.7% from last year), weather and other factors mean there are a wide range of possible outcomes. A peak of more than 181 GW is a 10% possibility, and there is a 3% chance of a 190 GW peak, which Sudduth linked to a “one in 33 years type of event” similar to the August 2020 heat wave.

The range of possibilities widens out as the WARA’s projections extend into the future, representing the broader scope of possibilities to contend with. At the same time, demand overall is expected to continue shifting upward. By 2031, under the most likely scenario, peak demand will hit around 179 GW, with a 3% chance of reaching as high as 208 GW.

“The underlying load forecasts … will most certainly change over time, as we get closer to the time horizon,” Sudduth said. “But it illustrates the importance of being flexible and responding to any deviations from what we expect, because if we’re fairly good in our forecasting, and come close to that expectation, when the actual hour occurs there’s still a range of 29 GW above and below that will have to be accounted for with real time energy if an extreme weather event occurs.”

Variability Also Seen in Generators

A growing variability in the generation resource mix is also central to the WARA. Sudduth said that solar and wind resources continue to increase their share of the Western Interconnection’s generating fleet. Looking out to 2031, these resources are projected to grow by 101.7% and 25.4% respectively. By contrast, baseload generation is set to increase by 4.5% and hydro by 4.2%.

The behavior of wind and solar under extreme circumstances is another cause for concern. Under a similar projection modeling the most and least likely scenarios, solar and wind were found to experience a much steeper drop-off in availability than baseload. Solar experienced a 42% loss under the 10% likelihood scenario and wind experienced a 94% loss, while baseload dropped by only 12%.

Sudduth said that these projections, which are based on the peak-hour demand and resource availability, only tell part of the story. The full report will delve deeper into the unique behaviors of each resource under the range of possible scenarios.

“When the peak-hour demand is expected, during the middle of the day, these solar resources … are available to meet the growing variability for that hour,” Sudduth said. “The problem, as we’ve seen, is what is available in the evening hours, after the solar resources become less available and demand still remains high. This is why the assessment spends a good portion of the report discussing the risk over all of the hours and not just focusing on the peak demand hour.”

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New Mexico Regulators Reject Avangrid-PNM Merger

New Mexico regulators shot down Avangrid’s (NYSE:AGR) proposed $8.3 billion acquisition of PNM Resources (NYSE:PNM) after some officials pointed to Avangrid’s “demonstrated record of poor performance” in other states.

The New Mexico Public Regulation Commission (PRC) voted 5-0 on Wednesday to reject a stipulation — an agreement among parties with an interest in the proposal — thereby sinking the acquisition.

The commission’s order stated that “the potential harms resulting from the proposed transaction outweigh its benefits.”

The two companies had said the acquisition would bring more than $300 million of near-term benefits to PNM customers and the state. That would have included $94 million for customers in rate credits, program funding and forgiveness of unpaid bills.

The companies said the creation of 150 or more long-term jobs would bring $225 million in economic development benefits. And the deal would triple the clean energy electrification plan at PNM, which is New Mexico’s largest electricity provider with 530,000 customers.

Performance Issues

But PRC Chairman Stephen Fischmann said the purported benefits could be counteracted if Avangrid’s performance in New Mexico continues the company’s “demonstrated record of poor performance” in states such as Maine, Connecticut and New York.

“All of those so-called benefits will be soaked up in reliability issues and higher rates — if they perform as we’ve seen elsewhere — quite rapidly,” Fischmann said.

And Fischmann wasn’t convinced that the deal was a one-time opportunity. PNM could find “another suitor that’s more appropriate,” he said, or the PRC or state legislature could take action to accomplish some of the same objectives.

Avangrid said in a statement following the PRC vote that it is evaluating its next steps and hopes to “one day welcome New Mexico into the Avangrid family.”

Conservation and community groups on Wednesday lamented the loss of $300 million in benefits to the state, calling the commission’s decision unfortunate.

Cara Lynch, attorney for the Coalition for Clean Affordable Energy, said the agreement would have provided hundreds of millions of dollars in shareholder funds for customers and the environment.

“No other legal avenue exists to extract shareholder dollars for New Mexicans to conserve energy in their homes, to New Mexicans with arrearages due to the pandemic, or to provide valuable apprenticeships,” Lynch said in a release.

Nonprofit Fights Acquisition

New Energy Economy (NEE), a Santa Fe-based nonprofit, argued in PRC filings that Avangrid and its Northeast affiliates racked up more than $63 million in fines and violations over the last five years. NEE said reliability and performance issues at Avangrid subsidiaries in Maine, New York and Connecticut have resulted in regulatory actions.

NEE said Avangrid’s experience in renewables is primarily with wind power and that the company has little experience in solar.

In addition, NEE accused Avangrid of violating discovery rules in the PRC proceeding by giving incomplete responses and designating as confidential more information than necessary. The company said it acted in good faith in responding to discovery requests. Still, a PRC hearing examiner recommended $10,000 in sanctions against Avangrid and PNM as a result of the discovery issues.

The order that the commission approved on Wednesday also expressed concern about Avangrid and its parent company Iberdrola “in light of the ongoing criminal investigation in Spain involving high level officers.”

Some of the concerns regarding Avangrid were aired during the PRC’s meeting on Dec. 1. (See Bid-rigging Allegation Clouds Avangrid Bid for PNM.) PNM Resources and Avangrid hosted a news conference the next day to discuss the issues.

Avangrid has “always stressed the highest levels of ethics and accountability in everything we do,” said Robert Kump, the company’s deputy CEO.

In addition, Kump noted that Iberdrola was named one of the most ethical companies in the world for the last seven years in a row.

The companies also acknowledged in filings that Avangrid subsidiary Central Maine Power (CMP) experienced service issues between 2016 and 2019, but that the issues have been addressed.

“Avangrid and CMP moved quickly to add resources, implement system changes, and promote new leaders to improve customer service,” the companies said.

Since then, “CMP has addressed these issues and has satisfied, and continues to satisfy and exceed the Maine Public Utilities Commission’s stringent customer service metrics,” they added.

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LADWP on ‘Crash Course’ to Generate with Green Hydrogen

The largest municipal utility in the U.S. is betting big on generating electricity with green hydrogen out of sheer necessity, its top official said this week.

“We are on a crash course to recreate a new power system in Los Angeles, a new generating system to feed the electrical grid that we have, and we see green hydrogen as the solution to do that, and the only way that we know to accomplish the reliability that we need,” Martin Adams, general manager of the Los Angeles Department of Water and Power (LADWP), said Monday.

Adams was speaking at the Building Hydrogen Corridors in the Pacific West for a Carbon Neutral Future conference, a two-day event hosted by the New Energy and Industrial Technology Development Organization (NEDO) of Japan and the Japan External Trade Organization (JETRO).

The virtual conference convened panelists to discuss how governments, utilities, companies and other interested stakeholders could collaborate to accelerate adoption of green hydrogen as a fuel source throughout the western U.S. and Canada. It also provided a forum for Japan-based manufacturers to showcase their own efforts to bring green hydrogen into the mainstream for utility, industrial and transportation applications.

LADWP already has a major hydrogen project in the works with the conversion of the coal-fired Intermountain Power Plant (IPP) in Delta, Utah, into an 840-MW combined cycle natural gas-fired facility capable of burning a fuel mixture consisting of 30% hydrogen when it opens in 2025, transitioning to 100% by 2045. In partnership with Mitsubishi, which will provide the turbines for the new plant, the project will also include on-site production of green hydrogen, as well as storage of the fuel in massive salt caverns adjacent to the site. (See ‘Ecosystems’ Needed to Drive Green Hydrogen Growth.)

“In Delta, Utah, we have a very unique situation,” Adams said. “We have plenty of land for electrolysis; we have the setup for all the systems we need; we have plenty of water supply to convert the hydrogen. And we also have an underground salt dome rock formation, which allows us a really unique opportunity to store hydrogen.”

But a study published last March by the National Renewable Energy Laboratory showed that LADWP will require a large amount of dispatchable generation located much closer to home as it sets out to hit the city’s 100% renewable target — about 2,500 MW within the Los Angeles Basin.

The utility currently operates four gas-fired plants in the basin rated at a combined 3,400 MW of capacity. Three of the plants — Scattergood, Haynes and Harbor — sit on the coast and must be repowered or rebuilt to meet a California rule requiring power producers to phase-out plants that rely on ocean water for once-through cooling by 2029. Additionally, the Los Angeles City Council voted in September to require that 100% of the electricity used in the city be carbon-free by 2035, establishing a 2030 deadline for replacing the gas-fired plants.

That “confluence” of objectives dictates LADWP’s move away from natural gas to burning cleaner fuels, Adams said.

“And the only solution that we know and we see at this time is to burn hydrogen, and for us that means burning green hydrogen,” he said. The combined hydrogen power projects in the L.A. Basin would “dwarf” the IPP project in scope, he added.

“Those four power plants will have to have a number of power generating units that burn green hydrogen in the future in order to have a sustainable electrical grid and provide the kind of power supply that the city needs for the future and have a green supply,” Adams said.

While IPP, with its massive storage capability nearby, provides the “perfect setup” for a large-scale hydrogen project, Adams said those features can’t be transplanted into L.A.’s urban environment, raising questions about the kind of infrastructure needed to support hydrogen-fueled generation in the basin, and whether hydrogen must be shipped to the plants as a gas, liquid or ammonia.

“So we need to decide, what is the delivery pipeline going to look like? And where are we going to hold [the hydrogen]? … I’m going to generate power using hydrogen; I don’t want to be in the business of generating hydrogen. I like to deal with it and handle it as little as possible. Because right now, I bring in natural gas, and I just have a service connection. I handle as little as possible,” Adams said.

“I did not know that in the L.A. Basin, there’s 60 miles of hydrogen piping, running in the harbor area between certain vendors and oil refineries. How do we parlay into that? How do we get that hydrogen to become green hydrogen, instead of the gray hydrogen it is today? How do we get green hydrogen? And how do we build out that system? How do we take advantage of that infrastructure?”

Lower-cost Solution?

Sharing the panel with Adams was Peter Sawicki, regional director of sales and marketing at Mitsubishi Power Americas. Sawicki said Mitsubishi has performed its own study modeling the requirements of a net-zero grid by using the same energy market simulation software that utilities rely on to develop their integrated resource plans.

According to Sawicki, Mitsubishi “couldn’t get the [net-zero] model to converge without the use of hydrogen.” The alternative would require a “massive” amount of renewable generation subject to “massive” curtailment at times of oversupply.

The study concluded that a “pro-hydrogen” scenario results in a more efficient buildout of the grid, Sawicki said.

“We see what comes out to be a 20% lower system cost to reach net zero, which is kind of counterintuitive, when people think of hydrogen as being a very expensive infrastructure,” he said. “That is true, but if we think about the massive overbuild that would be needed to reach [zero carbon] without the use of hydrogen as a long-duration storage medium, that system cost winds up actually being more expensive.”

Adams thinks hydrogen’s day has arrived, but industry and the general public still need convincing.

“I get challenged all the time. People say, ‘Well, we’ve heard of hydrogen before; it’s come around in years past.’ I think we believe that we’re at the tipping point, that the momentum has changed, and this time it’s for real.”

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Robust Renewables Outlook Puts Supply Chain Issues in New Light

Steady past growth and a strong demand outlook for renewables in the U.S. are revealing the weak points in the sector’s supply chain.

While the U.S. hit renewable energy deployment records in each of the last three years, that growth was contingent on an import-heavy supply chain, Raymond Long, senior vice president of external affairs for Clearway Energy said Wednesday.

And the outlook for a domestic supply of renewable energy components isn’t getting better. For example, of the estimated 25 GW of solar that is slated to come online in 2022, only 5 GW worth of solar panels will come from U.S. manufacturing, Long said.

“We still have no choice but to source panels from overseas and import them to the U.S.,” he said during the American Clean Power Association’s CLEANPOWER 2021 conference in Salt Lake City.

Under the Biden administration’s target to reach net-zero energy by 2035, Long said the solar industry needs to deploy 75-100 GW every year for the next 15 years.

“As exciting as that is for the industry … it’s really a daunting thing to think about how we are going to meet that with pressure to buy American and not to import panels,” he said.

Trump-era tariffs designed to bolster U.S. manufacturing have not been effective, and the Build Back Better Act includes targeted incentives to grow domestic renewables supply. But Long said it’s not possible to overturn the current supply chain paradigm with “the flip of a switch.”

“You have to find the right ways to do it and give it the right amount of time,” he said.

The pandemic has highlighted unforeseen glitches across global supply chains, while other solar-specific challenges also cropped up this year. In August, an anonymous group of solar manufacturers asked the U.S. Department of Commerce to investigate Chinese solar panel companies for potentially avoiding anti-dumping duties. The department has since declined to launch an investigation, but Long said the industry is still “dealing with the impacts” of the petition.

And in June, the Department of Homeland Security began detaining silica-based product imports from China-based Hoshine Silicon and its subsidiaries over human rights concerns. Silica is used in solar panel production.

The review process for detained shipments is “hampered,” Long said, and the situation needs to improve to avoid project delays next year.

“We’ve heard from other developers in the sector that solar panels aren’t making it to projects that are under construction now,” he said. “In 2022, with all the projects that are being built, if things stay the way they are, panels will not make it to those projects on time.”

The department’s order applies to materials, such as polysilicon, that are derived from silica-based products. China is responsible for 80% of the world’s polysilicon production, said Josh Skogen, senior vice president of procurement at AES. The energy transition, he said during the conference, is really a transition from a fuel-intensive system to a minerals-intensive system.

Minerals needed for solar, wind and storage components, for example, come from a small number of countries with a concentrated production rate. U.S. reliance on more renewable technologies is introducing new trade restrictions, trade patterns and geopolitical concerns, Skogen said.

“With that concentration, if there is a trade restriction or a geopolitical concern or a pandemic, like we’ve experienced, the volatility and the supply of that feedstock, and the upstream effects that has on the construction of new projects, is exacerbated,” he said.

Flexibility is Key

Current supply chain challenges have been “overwhelming,” Art Fletcher, executive vice president of construction for Invenergy, said during the conference.

While the company has managed those challenges, he said, they’ve been a “significant strain” on resources at an “all-new level.”

Staying nimble is a necessity for executing projects now, Fletcher said.

“Previously, we would know [two years out] that we were using a certain wind turbine or a certain battery package or a certain solar package,” he said. “Unfortunately, with the supply chain challenges we’ve had, there’s a great uncertainty in what we might actually be able to source either domestically or internationally.”

The company must plan projects differently from an engineering perspective.

“We have to go back sometimes a year to what we were working on and reevaluate what that technology is and how it applies to our land, our permits and everything else,” he said.

On the supplier side, turbine manufacturer Vestas has been equally challenged by global supply chain issues, and it also relied on flexibility to make it through.

Vestas’ global supply chain allows the company to shift between countries under new tariffs or when geopolitical changes occur that it did not anticipate, said Noga Vilan, director of supply chain planning for Vestas Americas.

The supply chain lessons of the last two years will allow Vestas to improve itself in the next decade, she said, adding that the company’s ability to do that will be tied to project volume.

At Vestas, the long-term vision to build value in the industry is to create a “whole ecosystem supply chain,” Vilan said.

That means the company will execute wind turbine installations while also ensuring local roads are better and communities have more jobs, she said.

“We truly believe that creating renewable energy is not just having cleaner energy and cheaper electricity when you turn on the lights,” she said. “It’s creating meaningful life, and we can do much more than what we’re doing today.”

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Texas PUC Chair Lake: ‘The Lights Will Stay On’

During a Wednesday morning press conference designed for ERCOT’s and the Texas Public Utility Commission’s leaders to discuss the changes made to avoid a repeat this winter of February’s near-collapse and dayslong outages following a winter storm, PUC Chair Peter Lake boldly proclaimed, “The lights will stay on.”

Lake based his assertion on new weatherization rules for generation and natural gas facilities that went into effect Dec. 1; increased penalties for violations of those rules; and improved coordination between the electric and gas industries to prevent the loss of gas supplies that has been identified as the leading cause of the generation outages during the storm.

“No other power grid has made as many remarkable changes and in such an incredibly short amount of time as we have, and we will continue to improve our grid and the market,” he said.

The remarks echoed those of Texas Gov. Greg Abbott, who has been guaranteeing since November that the ERCOT grid will remain upright this winter. Abbott, who is fighting off several challengers on his Republican side of the aisle, has pointed to the 14 GW of installed capacity the grid operator has added during 2021. All but 1 GW of that capacity are wind, solar or battery storage.

Pressed by a local reporter that a recent ERCOT report — likely November’s seasonal assessment of resource adequacy (SARA) that included risk scenarios — went against his statement, Lake said the SARA “is a scenario analysis that evaluates a wide range of possibilities.” (See Twitter Blows up over ERCOT Communications.)

“It does not incorporate all of the extraordinary measures I’ve outlined today. It’s a scenario analysis; … it’s not a promise of an outcome,” he said. “When we look at all of the efforts we’ve made, the assets we have in ERCOT now … when we look at the realities on the ground in front of us, yes, we can say the lights are going to stay on.”

Interim ERCOT CEO Brad Jones said the grid operator has received attestations of winter readiness, signed by entities’ CEOs, for 97% of the more than 850 registered generation resources by a Dec. 1 deadline. Aided by two vendors, the grid operator’s new Planning and Weatherization Department has begun its inspections of those facilities.

Jones said staff have visited 55 generation units so far and plan to inspect more than 300 before the year is up. Those units accounted for 85% of the lost megawatts during the winter storm.

“We’ve had a good experience so far,” he said. “There’s been a lot of cooperation at each of the generation companies. There’ve been no red flags.”

Some companies have asked for good-cause exceptions. ERCOT will file a report with the PUC on Friday listing those companies.

PUC Docks 8 Generators

Following the press conference, PUC staff said they had filed violation reports against eight generation companies for failing to provide winter readiness reports by the Dec. 1 deadline, recommending $7.68 million in administrative fees.

The Division of Compliance and Enforcement identified 13 separate resources owned by the companies representing 801 MW of capacity. That amounts to less than 1% of Texas’ total installed capacity of 120 GW.

“Our commissioners have been abundantly clear that they expect generation entities to get ready for this winter,” PUC Executive Director Thomas Gleeson said. “The [PUC] cannot tolerate the failure of these companies to even file their readiness reports.”

Addressing the Texas Reliability Entity’s board meeting Wednesday, Commissioner Jimmy Glotfelty said, “Hopefully, this sends the signal that we are dead serious [that generators] have to winterize their facilities so that what happened in February never happens again.”

Shell Oil (NYSE:RDS.A) took the biggest hit. It was assessed $2.375 million for failing to file statements for four generating resources. Enforcement staff also recommended the penalty be increased $50,000 per day for each resource and an additional $25,000 for each day Shell remains in violation of the winter readiness rule after Wednesday.

Bull Creek Wind and OCI Alamo were each fined $1.1 million for not filing forms for two resources, with a recommended increase of $50,000 per resource for each day they remain in violation. The other companies and their recommended fees, which include a potential $50,000/day increase for remaining in violation, are:

The generators have 20 days to respond to the notices and can request a hearing.

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Princeton Study Examines 24/7 CFE Procurement

Corporate and industrial energy users in California and PJM that try to cut carbon emissions by using a 100% annual matching renewable energy strategy could reduce emissions much more by opting instead to procure carbon-free electricity (CFE) to match their hour-by-hour demand, according to a new report by Princeton University.

The study, released Nov. 19, used mathematical modeling methods to look at the impact of procuring CFE to match hourly demand. In California and PJM, 24/7 CFE would enable C&I energy users to cut emissions by considerably more than if they had used an annual matching strategy, according to the study by four researchers at the university’s Andlinger Center for Energy and the Environment.

The report, which describes itself as the “first analysis of the electricity system-level impacts of 24/7 carbon-free energy procurement,” addresses one of the failings of the 100% annual matching strategy that have emerged since its adoption in recent years by some high-profile corporate names seeking to eradicate carbon emissions. The most notable was Google (NASDAQ:GOOGL), which sponsored the study.

In a 100% annual matching strategy, the user buys clean energy equal to its entire annual energy use. But despite the name, the strategy mostly does not yield zero carbon emissions because the user invariably turns to fossil fuel-generated power to meet their needs in those times clean energy sources are not functioning, such as when the wind isn’t blowing or the sun shining. The use of fossil-generated electricity reduces the user’s clean energy consumption and increases carbon.

“So, while you might buy enough megawatt-hours of clean energy to match your total consumption, there’s a mismatch between when those megawatt-hours are produced,” said Jesse Jenkins, an assistant professor of mechanical and aerospace engineering and one of the four researchers that produced the study.

In a 24/7 CFE strategy, the user purchases electricity to match its energy use profile hour by hour, sourcing energy from carbon-free sources such as nuclear or thermal energy when there is no solar or wind energy available.

“Clean firm technologies are technologies that are available any time of the year, for as long as you need them,” Jenkins said at a Nov. 19 webinar on the report. As a result, he said, they have “the potential to enable much deeper reductions in CO2 emissions from electricity consumption.”

Emissions Reduction, Cost Increases

The Princeton report estimates that an annual matching strategy in California would result in CFE making up only 75% of electricity consumed; in PJM, it would only be 62%.

In contrast, a 24/7 CFE procurement strategy enables C&I users to “completely eliminate emissions,” the report said. The elimination is because of a “better alignment between electricity consumption and generation, which reduces periods of reliance on emitting grid-supplied electricity,” the study concludes.

However, the 24/7 strategy pushes up costs for energy users, the report adds. C&I energy users in California would pay 64% more in energy costs than with an annual strategy, the report said, while PJM consumers would pay 139% more.

The added cost of using 24/7 CFE would shrink in the future if some of the current technologies under development, such as geothermal and hydrogen-fueled generators, become viable, according to the report. And costs would also drop if the user was willing to accept something less than zero-emission energy; for example, 98% clean energy, the report said.

Corporate Zero-emissions Efforts

The 24/7 CFE strategy has emerged as more C&I energy users have started buying renewable energy to match their annual load. One early adopter, Google, has purchased renewable energy equal to its total consumption every year since 2017. But the company acknowledges that it is still a long way from its 2030 goal of using CFE in all locations and all hours, and the impact of the annual matching strategy was limited.

“When we surveyed our operations and our footprint, what we saw is that while we had put a lot of new renewable energy on the grid, we hadn’t taken off a lot of the dirty energy that was there,” Caroline Golin, global head of energy and climate policy at Google, told the Princeton webinar.

Google is among the more than 40 signatories to the 24/7 Carbon-free Energy Compact launched in September, one of several Energy Compacts coordinated in part by the U.N. Others include Orsted; AES; the city of Des Moines, Iowa; the city of Ithica, N.Y.; the government of Iceland; and the Nuclear Energy Institute. Microsoft and the U.S. government also are working on 24/7 CFE strategies, according to the Princeton report.

Under 24/7 CFE procurement, non-fossil sources of fuel are purchased within the same grid region, according to the report. The alternative energy sources cited by the report include conventional and advanced geothermal facilities, which tap into the heat deep below Earth’s surface, and nuclear energy. Others cited in the study include natural gas power plants that use carbon capture and storage technology and gas plants that use zero-carbon fuels. (See How Geothermal Can Support 24-7 Carbon-free Targets.)

Google and other corporate buyers say that greater use of storage will also be key to providing energy in those periods when wind and solar energy can’t. (See Storage the ‘Linchpin’ to 24/7 Carbon-free Power, Corporate Buyers Say.)

The Princeton study argues that a wide, speedy embrace of 24/7 CFE procurement would help advance development of storage technology and accelerate its uptake. A similar effect helped advance wind and solar technology as corporations embraced 100% annual renewable procurement, the report argues.

Retiring Fossil Fuel Plants

The amount that emissions can be reduced through the use of 24/7 CFE depends on two factors, according to the report. One is the volume of clean energy procured, because higher volumes of procurement drive producers to generate more clean energy. The other is timing, or the amount that non-wind and solar clean energy generators adjust the periods in which they produce energy to match those periods when solar and wind production is at its lowest, the report says.

A key reason that the 24/7 CFE strategy is less effective in PJM is that California has a larger share of existing CFE (64%) than PJM, which has just 22%, the report says. The 24/7 CFE strategy also has the effect of hastening the retirement of natural gas plants at a greater pace than would happen under the annual matching strategy as energy users turn to more sustainable methods, according to the report.

The Princeton researchers calculated that if 10% of the C&I energy users in California adopted 24/7 CFE, the shift would reduce gas generating capacity by more than 1.9 GW. That is more than four times as much as would be retired if the users adopted an annual strategy, the report says.

Likewise, the adoption of a 24/7 strategy by 10% of C&I users in PJM would retire more than 6.2 GW, 1.5 times as much as would be retired under annual matching, the report says.

Armond Cohen, executive director of advocacy group Clean Air Task Force, said the study raises an important question for corporations, because the “corporate 100% renewable goal was being interpreted as the complete solution set and a model” by some companies.

Speaking during the Princeton webinar outlining the report, Cohen said it is “important to kind of push the conversation a little farther, and align the corporate demonstration goals with the analysis suggesting that you need a full suite of technologies to address decarbonizing the grid because of the seasonal variation in wind and solar.”

The higher cost of 24/7 CFE “reflect reality,” he said.

“Commodity wind and solar is cheap. It gets you a certain part of the way. But we also have to recognize that full decarbonization is going to require some of these higher capex dispatchable technologies,” he said.

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Wash. Policy Makers Move to Address Expected Drought

In its upcoming session, Washington’s legislature will likely set up millions in funding to deal with a probable drought in 2022.

Two similar bills are in the works to accomplish this, the Washington Joint Legislative Committee on Water Supply During Drought learned last week. 

Gov. Jay Inslee’s office is working on one such a bill that would set aside $3 million to deal with any 2022 drought problems, a committee staff member said. Meanwhile, committee chair Sen. Judy Warnick (R) is putting together a bill that would provide $5 million. Warnick speculated that the two efforts would end up cooperating.

In July, Inslee declared emergency drought conditions for roughly two-thirds of the state, which triggered government actions to deal with the lack of water. The measures include moving water withdrawal allowances from one area to another for the duration of a declared drought, finding other emergency water supplies and dealing with situations when water has become scarce enough to hamper the passage of salmon up and down streams.

“When we left the session in April, who knew we were going to have a drought?” Warnick said. 

Inslee blames the drought on climate change. The joint committee only meets during years in which a drought is declared by the state government. State officials believe a 2022 drought is inevitable.

The two bills being written will address how to take drought countermeasures more quickly. “To move quickly is of the utmost importance,” committee member Rep. Tom Dent (R) said.

The bills will also try to prevent emergency withdrawals from exceeding existing water rights. And Warnick said funding sources need to be identified for expanded drought-related relief.

“We need to increase certainty around funding,” said Jeff Marti, the drought coordinator for the Washington Department of Ecology.

Other potential planks include authorizing the Ecology Department to allocate emergency funds as soon as the governor declares a drought and routinely setting aside money per budget biennium to deal with future droughts.  

A major reason that state officials expect a drought to reemerge in 2022 is that this year’s drought was so severe that Washington would require 150% of its regular rainfall through next spring just to recover the lost water in the agricultural breadbasket of the Columbia River Basin.

“That’s not likely to happen,” state climatologist Nick Bond said.

At a Sept. 29 committee meeting, the legislators were briefed on how the drought has cut back on Washington’s agricultural output. (See Crops, Wildlife Suffering Under Wash. Drought.)

“This was a horrible year for wheat,” said Michelle Hennings, executive director of the Washington Association of Wheat Growers. “The harvest this year was 46% of 2020’s wheat harvest, and that was the state’s lowest wheat harvest since 1964. “

“We had everything from complete crop failures to low [numbers of] bushels [per acre],” Hennings said.

The state’s cherry harvest dropped 20% from 2020. Cherries are a major Washington export to Pacific Rim nations.

The drought’s impacts on potatoes differed throughout the state. There was no impact in the Columbia River Basin south of Grand Coulee Dam. However, southeast of Grand Coulee, the aquifer faces future shortfall. 

Potatoes are heat sensitive, said Chris Voigt, executive director of the Washington State Potato Commission. Potatoes grow best in 75 to 80 degrees F, but they stop growing in the 90-95 degree range. That’s when they become misshapen and more susceptible to diseases and insects. All this translates to smaller yields and possibly more sugar in the potatoes, which produces more browning in French fries than restaurants want. 

Meanwhile, the northwestern corner of Washington produces 85% of the nation’s red raspberries. This year’s heat cut the harvest by 30% below normal.

“Is this a once-in-a-century event or a sign of what’s to come? We don’t know that,” said Henry Bierlink, executive director of the Washington Red Raspberry Commission.

“If we lose them, the country will wonder that Washington did to lose the raspberry growers,” Rep. Mike Chapman (D) said.