Agenda packet, first session — Glendale City Council, February 15, 2022 (part 3 of 3)

Sincerely,

Dr. Hank Schlinger
Ms. Julie Riggott
1755 W. Mountain St.

Glendale, CA 91201
---------------------------

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From: Sammy Roth — L.A. Times < [email protected]> Subject: Boiling Point: California's last gas plant?
Date: January 27, 2022 at 6:01:12 AM PST
To: <[email protected]>
Reply-To: Sammy Roth — L.A. Times < reply-fef71077766d05-18_HTML-1479595- [email protected]>

Boiling Point

January 27, 2022
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2 Glendale was founded in 1906, has a population just under 200,000 and shares a border with Los Angeles at Griffith Park. It’s home to Walt Disney Imagineering (for now) and has excellent hiking trails in the Verdugo Mountains and San Gabriel foothills.

Also, it’s quite possibly the last city or utility company that will build a fossil-fueled power plant in California.

Climate activists thought they had won in 2019 when the Glendale City Council postponed a final decision on investing in natural-gas-fired generators to help replace the city’s aging gas plant. Surely by the time replacement power was needed, activists reasoned, the city would have enough low-cost clean energy options that new planet-warming gas engines wouldn’t be needed.

Not so, according to Glendale Water & Power.
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4 Glendale Water & Power staff lead a tour of Grayson Power Plant in 2015. (Tim Berger / Glendale News-Press)
The city-run utility released a final environmental impact report last week that settles on two preferred outcomes, both of which involve continuing to burn gas at Grayson Power Plant. In one scenario, Glendale would spend $260 million on five new gas engines, relatively less polluting than the ones in place now. In the other, the city would refurbish several existing gas turbines to comply with air-pollution rules, at a cost of $201 million.

The City Council is expected to vote on those possibilities on Feb. 8.

Byron Chan, an attorney with the nonprofit law firm Earthjustice, remembers seeing hundreds of protesters outside Glendale City Hall in 2019 demanding the utility ditch natural gas. He said it feels like déjà vu to be fighting this battle again in 2022. “There was this belief that Glendale Water & Power would go back and look at clean energy options. We’ve seen hardly any momentum in that direction,” Chan said. “We fully believe that Glendale does not need any more gas.” Officials at Glendale Water & Power disagree.

They say the gas units will serve as a crucial backup power supply that can keep the city’s lights on — and air conditioners blow ing — when transmission lines are shut down to prevent wildfire ignitions, or when a wildfire actually takes down a transmission line. The gas units will also fire up on hot summer evenings when the sun goes down and solar energy production drops off a cliff.

Utilities across the country are making similar arguments about the need for gas — and although they may not not always be right, it’s important to take them seriously. Despite a growing body of research showing 100% clean energy should be possible before too long, nobody has actually done it yet. Many utilities are understandably terrified of being forced to give up gas.
“For reliability, we don’t see another way to do it,” said Mark Young, general manager of Glendale Water & Power.
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5 Still, California law requires 100% clean energy by 2045. And utility companies are starting to figure out how it will work.

Pacific Gas & Electric announced this week it would buy 1,600 megawatts of lithium-ion battery storage, in response to an order from state officials. Southern California Edison is making similar investments. A group of Bay Area energy agencies just announced a deal for lithium-ion batteries capable of providing power for up to eight hours, double the technology’s traditional capability.

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6 Solar panels tilt toward the sun at NextEra Energy’s Blythe and McCoy solar farm in Riverside County. NextEra plans to add batteries that will supply electricity to San Francisco. (Sammy Roth / Los Angeles Times)
When I spoke earlier this month with Elliot Mainzer, president of the California Independent System Operator, he told me 2,595 megawatts of battery storage are now connected to the state’s main electric grid — up from 250 megawatts two years ago.

By this summer, Mainzer hopes the total will be a staggering 4,500 megawatts of batteries.
“They’re so fast and so flexible — they almost instantaneously can take energy off the system or add it back,” he said.

Glendale isn’t just investing in gas: Officials plan to install a 75-megawatt, 300-megawatt- hour battery system at Grayson Power Plant, which is pretty darn big for a city of 200,000.

They’re negotiating a contract with rooftop solar company Sunrun for a 28-megawatt “virtual power plant,” which would involve installing solar panels and batteries at thousands of homes and using those resources to serve the city as a whole. They’ll also buy climate-friendly power from a solar-plus-storage facility in Kern County.

But Glendale officials say they’ve pushed those clean energy options as far as they can go — in part because there’s limited space on regional power lines to important electricity from outside the L.A. Basin. They say having a reliable power source close to home will be especially important as more Californians buy electric cars and replace their gas furnaces with electric heat pumps.
“This whole portfolio is very progressive. And I don’t think we’re getting the credit for that,” Young told me.

Climate activists aren’t impressed. They say the city is wildly overstating its backup power needs and refusing to take full stock of its clean energy options. They also say the money Glendale plans to invest in gas might be better spent on new power lines. 843 of 983
7 “It’s a bridge they’re building that’s leading to nowhere,” said Chan, who represents the Sierra Club.

Although Glendale might build California’s last in-state gas plant, it isn’t the last California power provider investing in the fuel: The Los Angeles Department of Water and Power plans to demolish its coal-fired Intermountain Power Plant outside Delta, Utah, and build a gas plant in its place. L.A. is making extensive plans to transition from fossil gas to renewable hydrogen at Intermountain as soon as the technology is ready, and Young says there’s a good chance Glendale will pursue a similar path at Grayson.

LADWP employee Greg Huynh walks past one of two steam turbine generators at Intermountain Power Plant. (Luis Sinco / Los Angeles Times)
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8 Now let’s zoom out for a minute and look at another high-stakes fight that could reshape California’s power grid.

I’ve been writing recently about the role of rooftop solar in meeting the state’s energy needs, and a proposal from the California Public Utilities Commission that would slash solar incentives. As you may recall, utility companies, ratepayer watchdogs and even some environmentalists have argued the “net metering” incentive program benefits the rich at the expense of the poor.

The fight has only intensified since Gov. Gavin Newsom called for changes to the commission’s proposal to overhaul net metering. U.S. Sen. Dianne Feinstein came out against the plan this week, and both sides of the debate are now airing television ads.

I was especially struck by a mailer sent out by the California State Assn. of Electrical Workers, which represents utility employees who want to see solar incentives reduced.

The mailer claims state policies are “making billionaires & big business rich,” which is a real stretch — nobody is getting rich off rooftop solar, and the vast majority of net metering beneficiaries are not billionaires. The mailer also quotes an unrelated news story to falsely imply those billionaires may be engaged in “Enron-style ‘manipulation.’” Although nobody knows what the Public Utilities Commission will decide, both sides are already plotting their next moves. The Solar Rights Alliance filed a state ballot initiative this month that, if approved by voters, would lock in favorable financial terms for rooftop solar and set aside $3 billion in funding for battery incentives. State Assemblymember Wendy Carrillo, meanwhile, moved this week to revive a failed billthat would gut net metering. The bill is sponsored by labor unions representing utility employees. 845 of 983
9 Sunrun employees carry a 215-pound lithium-ion battery to be installed at a home in Granada Hills. (Mel Melcon / Los Angeles Times)
Why am I telling you all this in an article about Glendale? Because the city’s deliberations are part of a larger debate over how California ought to go about eliminating fossil fuels. Should the power grid of the future be dominated by big solar farms and long- distance transmission lines? Or should “distributed” resources like rooftop solar panels and home batteries rule the day?
The utilities commission’s proposal would decimate the rooftop solar market, with installations falling from a projected 1,308 megawatts to 716 megawatts in 2024, according to a new analysis from research firm Wood Mackenzie. The full picture is 846 of 983
10 actually even worse for the solar industry because WoodMac’s earlier projection had already assumed less-dramatic cuts to net metering.

Glendale’s virtual power plant — with thousands of solar panels installed at homes across the city — wouldn’t be affected by the commission’s proposal, because the agency only regulates investor-owned power companies such as PG&E and Edison.

But the big questions facing Glendale and the rest of the state are basically the same:

What’s the best way to confront the climate crisis while keeping the lights on? And do we need to keep investing in gas, at least for a little longer, to make it all work? In the grand scheme of things, the amount of gas capacity Glendale is considering — about 100 megawatts — won’t be the diffe rence between a habitable planet and a future of devastating wildfires, floods, droughts and heat waves. But the same is true of just about any energy decision. They’re all too small to matter. They all add up to something larger.

I’ll keep you updated on the city’s decision.

Until then, here’s what’s happening around the West:

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11 End of advertisement

TOP STORIES

Water pours from a pipe in the San Bernardino Mountains, where the company BlueTriton Brands collects water for bottling. (Allen J. Schaben / Los Angeles Times) A bottled water company is profiting from public resources during a drought, and it may not even have valid rights for most of what it’s taking. My colleague Ian James broke the story back in 2015 on the questionable source of Arrowhead bottled water in 848 of 983
12 San Bernardino National Forest, and now he’s got a new investigation scrutinizing the company behind the brand, which is fighting efforts to limit its operations. This is happening against a backdrop of continued water scarcity. The Times’ Hayley Smith reports that California will deliver 15% of promised allocations to State Water Project customers, up from a previous prediction of 0% allocations — but with a dry January quickly diminishing snowpack from December storms, drought is still the watchword. For more on drought, listen to this recent episode of our daily news podcast, The Times, featuring our resident “masters of disaster.”
Is anyone surprised to see California burning in January? I mean, historically speaking it’s extraordinary, but we live in an era of unprecedented climate change. Our wildfire reporter, Alex Wigglesworth, wrote about the Big Sur and Sonoma County blazes, one of which was caused by embers from trees and vegetation that were being burned after a thinning operation meant to reduce fire risk. The blazes broke out just after Vice President Kamala Harris visited Southern California to highlight billions of dollars in federal funding to reduce wildfire risk and help communities recover, as Alex Wigglesworth and Melanie Mason reported.

The recent volcano-triggered tsunami caused millions of dollars in damage along the California coast— and such events ar e likely to get worse with sea level rise. Here’s the story from my colleague Jonah Valdez. This isn’t just a California problem:

As climate-influenced floods, fires and other disasters get worse across the country, many Americans are discovering that private insurance and government relief don’t cover nearly all the damages, Janet Wilson and Kyle Bagenstose report for the Desert Sun.

ADVERTISEMENT
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13 POLITICAL CLIMATE
The federal government has begun to dole out $15 billion from the recently approved infrastructure bill to remove lead pipes, which can pollute water and lead to serious health problems. Details here from my colleague Erin B. Logan. The bill also included $4.7 billion for cleaning up abandoned oil and gas wells — which is a big deal, but probably not nearly enough to cover all abandoned wells across the country, Nick Bowlin writes for High Country News. Meanwhile, Republicans who voted against the bill are nonetheless bragging to voters about money being spent in their districts, Erin B.

Logan and Anumita Kaur report.

President Biden says it’s time to break up his Build Back Better bill into chunks that can pass on their own — including th e $555 billion for climate and clean energy. Here’s the story from The Times’ Eli Stokols and Noah Bierman. Are there sufficient votes for climate, though? The New York Times asked every Senate Republican 850 of 983
14 if they’d support those provisions, and not a single one said yes — meaning passage might once again hinge on Democratic Sen. Joe Manchin III, who built his fortune on coal.

Gov. Gavin Newsom and Democratic lawmakers still can’t agree on how to spend $4.2 billion in high-speed rail funds approved by voters in 2008. Newsom’s budget proposal includes a big chunk of change for a bullet train through the Central Valley, as I wrote earlier this month. The problem is, Los Angeles-area lawmakers want more of a focus on transit investments in Southern California, per our Sacramento bureau chief, John Myers. The stalemate shows no signs of ending. In another obstacle for high-speed rail, Burbank says the bullet train’s proposed route would disrupt the city’s water supply by forcing it to relocate two wells that draw from an underground aquifer and buy pricey replacement water in the interim, Ralph Vartabedian reports.

WATER IN THE WEST
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15 At the International Bird Rescue in Fairfield, Calif., northern fulmars, a type of seabird, wait to be fed in a pool before some are released at Doran Beach in Bodega Bay. (Carolyn Cole / Los Angeles Times)
Hundreds of northern fulmars — a subarc tic migrating bird — washed up dead along the California coast in 2020 and 2021. The cause isn’t clear, but climate change is devastating the bird’s northern breeding waters, The Times’ Susanne Rust and Carolyn Cole report. For context, see Susanne and Carolyn’s recent reporting from the Arctic. In another example of how global warming is wreaking havoc on natural water cycles, the Desert Sun’s Janet Wilson reports that two iconic California desert plants — ocotillo and Washington fan palms — seem to be slowly dying out as moisture-starved desert creatures turn to them for sustenance.
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16 The Supreme Court will hear a challenge to the Clean Water Act. The case involves an Idaho couple challenging the definition of “waters of the United States,” which determines which bodies of water are subject to the federal law, Robert Barnes reports for the Washington Post. That question is especially relevant to the arid West, as Stanford professor Michael Wara explains in a Twitter thread. Wara writes that the court’s conservative majority could exclude “any flow that isn’t continuous,” which means many crucial Western waterways “would be totally excluded from federal water quality protection because of their seasonal nature.”
Poseidon Water is looking to secure millions of dollars in state bonds to help build a controversial seawater desalination plant in Huntington Beach. Critics say the money should go to affordable housing instead, Matt Szabo reports for The Times. The desalination developer is also hoping for approval from the California Coastal Commission in March, Lilly Nguyen reports.

THE ENERGY TRANSITION
Los Angeles City Council voted to ban new oil and gas drilling, and to study options for phasing out existing wells. Fossil fuel extraction has led to serious health and environmental damage in low-income communities of color, but the oil and gas industry isn’t going down without a fight, my colleague Dakota Smith reports. L.A. County, meanwhile, is hiring researchers to study long-term health effects from the Aliso Canyon gas leak, six years after the fact — but the county has refused to subpoena Southern California Gas Co. to turn over data on chemicals released during the blowout, Hayley Smith reports for The Times.

The need for long-duration energy storage is growing — and it means new pumped hydropower facilities might finally be built. There’s a fully permitted project in Oregon that’s ready to start construction as soon as it gets a customer, possibly a California utility, Julian Spector writes for Canary Media. But while some pumped storage projects have avoided environmental controversy, others, such as Eagle Mountain near Joshua Tree National Park, continue to face opposition from conservationists. 853 of 983
17 Speaking of batteries, Times columnist George Skelton is (relatively) optimistic about Gov. Gavin Newsom’s proposals to spur lithium extraction at California’s Salton Sea. “This may not be another 20th century oil boom or 19th century gold rush for California. But it may be for people around the Salton Sea,” Skelton writes. For background, see my story on the lithium drilling that is happening right now at the southern shore of the salty, shrinking desert lake, after years and years of false starts.

ONE MORE THING

A Chevron sign at a gas station in Miami. (Alan Diaz / Associated Press) If you encounter any “news” stories overly favorable to Chevron Corp., you might want to stop and question where they came from. Times columnist Michael Hiltzik reports that the California-based oil giant is currently recruiting for a so-called “newsroom” that will “proactively tell our story” by creating “digital news articles, video scripts, newsletters, and social media posts.”
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18 As Hiltzik writes, “What’s insidious about this is the blurring of the line between news and propaganda, vastly in favor of propaganda. What enables it is the shrinking of the news industry as once-robust newspapers, magazines and television news divisions become ever more underfunded and unable to give influential politicians and businesses a healthy dose of scrutiny.”
Want to support real journalism that holds the powerful accountable? Subscribe to the L.A.

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1 Ghazarian, Renia
From: Hollyanne Sparks <[email protected]>
Sent: Thursday, January 27, 2022 1:03 PM
To: Najarian, Ara; Kassakhian, Ardashes; Brotman, Daniel; Agajanian, Vrej; Devine, Paula Subject: Stop Gas at Grayson!
CAUTION: This email was delivered from the Internet. Do not click links, open attachments, or reply if you are unsure as to the sender.

Hello,

I am writing to ask that you do not vote to install the gas equipment at Grayson Power Plant. Now more than ever we need
to invest in clean energy sources. We must protect this planet and this community. We also must be an example to other communities that clean energy is an option. The outrage from the community has proven how important this is to so many. Please vote no to install this new polluting equipment at Grayson.

Thank you for your time.

Hollyanne Sparks
857 of 983
1 Ghazarian, Renia
From: David Levine <[email protected]>
Sent: Saturday, January 29, 2022 10:56 AM
To: Devine, Paula; Agajanian, Vrej; Najarian, Ara; Kassakhian, Ardashes; Brotman, Daniel Subject: NO to new Grayson Power Plant
CAUTION: This email was delivered from the Internet. Do not click links, open attachments, or reply if you are unsure as to the sender.

As a customer of GWP and resident of Glendale. I am STRONGLY OPPOSED to building the new Grayson Power Plant. Pease focus on cleaner energy options, let’s have Glendale lead in a cleaner environment.

Sincerely,
D. Levine - Montrose (Glendale)
858 of 983
1 Ghazarian, Renia
From: Elizabeth Vitanza <[email protected]>
Sent: Sunday, January 30, 2022 3:36 PM
To: Devine, Paula; Agajanian, Vrej; Brotman, Daniel; Kassakhian, Ardashes; Najarian, Ara; Sustainability; GWP Commission
Subject:

No Gas at Grayson
CAUTION: This email was delivered from the Internet. Do not click links, open attachments, or reply if you are unsure as to the sender.

Dear Mayor Devine, Councilmembers, and Commissioners.

I live in the 91208 neighborhood of Glendale, own a business in Glendale, and send my child to school in 91201.

I oppose the Glendale Water and Power (GWP) plan to install 93+ MW of polluting equipment, costing at least $200 million, at the Grayson Power Plant. Much more clean energy is possible in Glendale and should be the top priority investment.

In 2018, City Council rejected the original plan for 262 MW of gas-burning after residents and stakeholders spoke against it. In 2019, GWP proposed four clean energy projects along with 93+ MW of gas equipment and a battery installation at Grayson. City Council approved the 2019 plan while asking GWP to continue exploring clean energy alternatives.

But the plan released in 2021, two years later, has hardly any new clean energy, with the Grayson Repowering project still including 93+ MW of gas burning. Glendale should pursue a commercial solar plus battery program, maximize solar on city properties, load management solutions, and new transmission opportunities all before investing in gas-burning equipment.

A large investment in gas-burning equipment commits Glendale to burning fossil fuels for many years to come.

However, California is mandating 100% clean energy by 2045; if that deadline moves up, equipment might have to be decommissioned.

GWP talks of converting the new equipment so that it can burn clean hydrogen. Why would we build something simply to "convert" it a few years later? We don’t know how costly this alleged hydrogen technology is, nor do we know how the GWP would produce or transport the hydrogen, and whether it would be a good investment for the amount of energy we get.

The Los Angeles region has among the worst air quality in the country, and residents who live and students who go to school near Grayson are already heavily burdened by freeway air pollution. The Grayson Power Plant produces significant amounts of air pollutants that cause cancer, asthma, heart disease, and dementia, as well as impaired cognitive development in children. We need to make clean air and a healthy environment our top priorities. We need to stop investing in fossil fuels and fossil fuel equipment.

Please reject the Grayson Repowering Plan and ask GWP to maximize clean energy in Glendale.

Sincerely,
859 of 983
2 Elizabeth Vitanza
1661 Santa Maria Avenue
Glendale, CA 91208

860 of 983
1 Ghazarian, Renia
From: Damon McMahon <[email protected]>
Sent: Monday, January 31, 2022 10:58 AM
To: Devine, Paula; Agajanian, Vrej; Kassakhian, Ardashes; Najarian, Ara; Brotman, Daniel Subject: Please consider clean energy option instead of Grayson Power Plant CAUTION: This email was delivered from the Internet. Do not click links, open attachments, or reply if you are unsure as to the sender.

Hi,
We live in the Rossmoyne area of Glendale with our 10 month old baby.

We are very worried about your plans to allow the Grayson Power Plant, and implore you to please consider the health of our child, and the many many more that live in Glendale, by supporting a clean energy alternative.

Sincerely,
Damon, Laura and Faye
861 of 983
1 Ghazarian, Renia
From: Analisa Swan <[email protected]>
Sent: Sunday, January 30, 2022 9:46 PM
To: GWP Commission; Sustainability
Cc: Kassakhian, Ardashes; Brotman, Daniel; Devine, Paula; Najarian, Ara; Agajanian, Vrej Subject: Stop Gas At The Grayson Power Plant
CAUTION: This email was delivered from the Internet. Do not click links, open attachments, or reply if you are unsure as to the sender.

Good evening.

I am a resident of Burbank, CA.

I am urging the GWP Commission and Sustainability Commission to take a position of holding off on further building of gas powered equipment at the Grayson Power Plant.

The City of Glendale should research and invest in more clean energy alternatives. Given the expense, magnitude of the Grayson Power Plant project, as well as the impact on the immediate and surrounding communities, more time should be spent investigating clean energy alternatives e.g., by consulting with clean energy experts.

This will
be more cost effective and environmentally sustainable especially given the State of California’s clean energy goals.

The City of Glendale should lead by prioritizing clean energy alternatives with far less dependency on fossil fuels.

Thank you for your courtesy and attention to this matter.

-Analisa Swan
ADEM AD 44 (prior to redistricting AD 43)
--
Analisa Swan, Esq.

CONFIDENTIAL COMMUNICATION
Ford & Wallach
3619 Motor Avenue
Los Angeles, CA 90034
Telephone: (213)-380-3140
Facsimile: (213)-480-0249

This e-mail message and any attachments are intended for the use of the addressee names above and may contain information that is privileged and confidential. If you are not the intended recipient, any dissemination, distribution, or copying is strictly prohibited. If you received this e-mail message in error, please immediately notify the sender by replying to this email message or by telephone.

Thank you.

Sent from my iPhone.
862 of 983
1 Ghazarian, Renia
From: Jane Lawton Moore <[email protected]>
Sent: Monday, January 31, 2022 5:19 PM
To: GWP Commission
Cc: Devine, Paula; Agajanian, Vrej; Najarian, Ara; Kassakhian, Ardashes; Brotman, Daniel Subject: Do not recommend the Grayson FEIR
CAUTION: This email was delivered from the Internet. Do not click links, open attachments, or reply if you are unsure as to the sender.

Dear Commissioners,

I am writing to urge you not to recommend the Grayson FEIR. In 2019 the Glendale City Council instructed GWP to pursue more clean energy projects with the aim of reducing the gas plan of 93 MW. This was three years ago and no RFPs have been pursued by GWP since then.

GWP has recognized the value of a commercial solar virtual power plant after Permacity came forward with such a proposal. Nothing has been done to pursue this kind of project. GWP has claimed they could put together a commercial solar vpp without the help of PermaCity. But nothing has been done. Sunrun came forward with a proposal for a residential vpp. This project has been in negotiations with GWP for over 3 years.

72 MW of transmission will also become available to Glendale in 2027. By the time the repower would be finished it would be 2025. Why should we be spending over $200 million for 93 MW of gas installation when we will be getting an additional 72 MW in short time? Certainly the city has to have ways to access more energy during the three years in which the repower infrastructure would be installed. Why couldn't that plan be extended to 2027 once more transmission becomes available? And the $200 million or more that would be spent on gas infrastructure could be spent on clean energy projects like commercial solar.

With the 2045 state mandate that all gas plants must close, it seems fiscally foolish to be spending this much on gas installments. It's going to take years to build the clean energy projects needed to meet the 2045 mandate. In short time Glendale will be paying for these new technologies anyway while still paying off the costs of this gas proposal. And residents will be stuck footing the costs.

Thank you for considering these concerns. I trust you will make a sound decision and recommend that GWP reduce this gas plan to a more reasonable, lower amount, given the arguments above.

Sincerely,

Jane Potelle
863 of 983
1 Ghazarian, Renia
From: Daria Marinelli <[email protected]>
Sent: Monday, January 31, 2022 5:19 PM
To: Devine, Paula; Agajanian, Vrej; Kassakhian, Ardashes; Najarian, Ara; Brotman, Daniel Subject: No Power Plant.

CAUTION: This email was delivered from the Internet. Do not click links, open attachments, or reply if you are unsure as to the sender.

Hello,

I am a concerned Glendale citizen and I am please please please asking you to vote no on this powerplant. We do not need the electricity and we don't want to be the last gas plant that CA builds. Or even the last handful.

DMM
--
Daria Miyeko Marinelli (they/she)
www.DariaMiyekoMarinelli.com
914.837.6559

AMPLIFYING: The Okra Project | NDN Collective | For Afghan Women PETITIONS TO SIGN: reimagining supremacist landmarks in PVD | stop the glendale grayson power plant

864 of 983
1 Ghazarian, Renia
From: Monica Lago-Kaytis <[email protected]>
Sent: Wednesday, February 2, 2022 11:35 AM
To: Kassakhian, Ardashes
Subject: Grayson EIR by GWP Commission
CAUTION: This email was delivered from the Internet. Do not click links, open attachments, or reply if you are unsure as to the sender.

Hello!

My name is Monica Lago‐Kaytis and I have been a resident of Glenoaks / Scholl Canyon for 26 years. I on Devonshire Lane, which
is one of the last streets before you enter the Scholl Canyon Golf Course & Tennis Courts gate.

We were promised that the operations at Grayson would not proceed. It goes strictly against what the state of California is attempting to do which which is move to clean energy.

Please
help us come up with another option that while it might cost more, will protect the residents; humans, flora and fauna in this beautiful canyon.

I am a cancer survivor and I do not believe this plan is healthy for me, my family, my neighbors, friends and animals in the canyon.

Please stop investing in fossil fuels and move into the clean air future now!

Please vote no on this!

Thank you!
Monica
865 of 983
1 Ghazarian, Renia
From: Lyndon Ongyiu <[email protected]>
Sent: Wednesday, February 2, 2022 12:57 PM
To: Devine, Paula; Kassakhian, Ardashes; Najarian, Ara; Brotman, Daniel; Agajanian, Vrej Subject: Grayson Repowering Project - Reject the project! CAUTION: This email was delivered from the Internet. Do not click links, open attachments, or reply if you are unsure as to the sender.

Hello,
Please vote to reject the Grayson Repowering Project in its current form and tell GWP to further reduce the need for gas generation by prioritizing local distributed solar and storage, energy efficiency, and other ways to reduce energy demand. All new transmission into Glendale should be included in energy planning. Glendale needs to explore ways to avoid the financial and health risks of this project.

Thank you,
Gráinne Ong Yiu
866 of 983
1 Ghazarian, Renia
From: Karen Lowe <[email protected]>
Sent: Wednesday, February 2, 2022 1:43 PM
To: Kassakhian, Ardashes
Subject: Let us breathe....

CAUTION: This email was delivered from the Internet. Do not click links, open attachments, or reply if you are unsure as to the sender.

Dear Kassakhian,

I’m writing to ask you to, please, not support more turbines at the Grayson plant. Aside from the expense, and the absurdity of doing this amid a push for renewables, there are deleterious health concerns to consider.

Pushing ahead with fossil fuel powered turbines will only worsen the air quality in the Los Angeles area, most
notably your own constituents. My husband suffers from asthma, and close friends have serious lung conditions that are impacted by poor air quality. And, sadly, we already have the sorry distinction of having the worst air quality in the nation.

https://abc7.com/la‐pollution‐california‐los‐angeles‐air‐ozone/10535612/ This lays it out succinctly.

Please, please, please… do not support the GWP’s proposal for Grayson.

Best regards,

Karen Lowe
1114 La Zanja Drive
Glendale 91207

867 of 983
1 Ghazarian, Renia
From: [email protected]
Sent: Tuesday, February 1, 2022 7:52 PM
To: Devine, Paula; Kassakhian, Ardashes; Brotman, Daniel; [email protected]; Agajanian, Vrej; Steve Hunt; Golanian, Roubik
Subject:

TGHS Comments on HPC Review and Recommendation on Grayson final EIR Attachments: Grayson Letter to City Council.pdf
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Dear Mayor Devine and Glendale City Council,

Please see the attached letter that outlines TGHS concerns about the lack of HPC review and recommendations on the final Grayson EIR. We strongly believe this review should happen prior to City Council certification as Grayson has been deemed a discretionary historical resource by the City of Glendale.

Thanks in advance for your time.

Respectively,

John Schwab‐Sims
VP Preservation
The Glendale Historical Society

868 of 983
1 Ghazarian, Renia
From: THOMAS METZLER <[email protected]>
Sent: Wednesday, February 2, 2022 10:05 PM
To: Kassakhian, Ardashes
Subject: No New Gas Generators at Grayson!
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Dear Ardy,

It has been a year or so since we have spoken, so I hope that everything is going well for you and your family!

I know that there is an important vote coming up soon regarding the Grayson Power Plant. I am probably preaching to the choir, as they say, but I want to reiterate where I stand on this issue.

As you know, I have been a resident and business owner in Glendale for the last 42 years. I would like to ask you to
please not vote for funding of new gas generators at the Grayson Power Plant, and to try to influence your less progressive colleagues in this direction as well! The gas option is too expensive, will create more pollution, and will quickly become obsolete. That means we must have only clean energy solutions going forward, including solar, wind, and hydro, as well as advanced battery storage solutions.

Thank’s for listening to me, Ardy, and for voting “No” to more gas generators!

Sincerely
Tom Metzler
126 W Lomita Ave.

869 of 983
1 Ghazarian, Renia
From: Maureen Palacios <[email protected]>
Sent: Thursday, February 3, 2022 1:41 PM
To: Kassakhian, Ardashes
Subject: More clean energy!
CAUTION: This email was delivered from the Internet. Do not click links, open attachments, or reply if you are unsure as to the sender.

Dear Ardy-
I want Glendale to be a pro-active city, instead of one that is reactionary. It has shown courage to fess up to past inequities, with respect to Glendale's past Sundown history.

It is with this in mind that I ask you to consider your actions to the Grayson Repowering Project.

Please DO NOT LET GLENDALE SLIDE BACKWARDS investing in fossil fuels that contradict the state's forward looking clean energy mandates.

Instead, vote for more clean energy and insist that GWP develop plans to do so.

Thank you!

Maureen Palacios
Owner
Once Upon A Time
"Your family bookstore"
2207 Honolulu Ave.

Montrose, CA 91020
818.248.9668
<http://www.ShopOnceUponATime.com/>
[email protected]

Once Upon a Time is the nation's oldest children's bookstore! What I'm reading & enjoying now: DAMASCUS STATION by David McCloskey 870 of 983
1 Ghazarian, Renia
From: Bethany Armstrong Johnson <[email protected]> Sent: Thursday, February 3, 2022 4:45 PM
To: Devine, Paula; Agajanian, Vrej; Kassakhian, Ardashes; Najarian, Ara; Brotman, Daniel Subject: No to Grayson
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Dear Glendale City Council Members,

I'm sure this isn't the first message like this you'll receive, and probably won't be the last. But I just wanted to write to tell you that investing in the Grayson power plant instead of clean energy is not what the residents of Glendale want. Why would we want to spend more time and money on a project that furthers the use of harmful technologies, especially when other cleaner technologies are available? Why would we want to continue paying for a useless plant in tax money once the California mandate for clean energy has passed? Why would we want all the environmental and health ramifications of such a plant? We've seen wildfires and floods and all sorts of unpredictable weather hitting our world because we haven't been taking care of it, so why would we want to do anything that furthers the climate disaster instead of bettering it?

Please do not recommend the Grayson Repowering project and continue the work of finding alternative energy sources. Lead California in being a part of the climate crisis solution.

Thank you,

Bethany Johnson, Glendale resident and worker

871 of 983
1 Ghazarian, Renia
From: Brian <[email protected]>
Sent: Friday, February 4, 2022 4:53 PM
To: Brotman, Daniel; Devine, Paula; Agajanian, Vrej; Kassakhian, Ardashes; Najarian, Ara Cc: Golanian, Roubik; Young, Mark
Subject: Re-power Grayson as soon as possible
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Dear Mayor Devine, Councilmembers and City Staff:

As you all know I am a strong proponent of moving forward with the replacement of Grayson so Glendale can continue to benefit from reliable, affordable and locally generated electricity.

Over the last few weeks my position has been made clear on Nextdoor.com as I responded to those who feel solar, wind and batteries can provide Glendale residents with reliable, affordable and always available power for our homes and businesses. I am guessing those of you who follow the debates on ND have seen my posts so I won't reiterate them here.

Please move forward as the replacement of Grayson is the most pressing issue, in my opinion, facing Glendale from an infrastructure perspective. The sooner the plant comes online, the more secure our energy future will be.

The downsized thermal generation proposal (Alternative 7 I believe) is the best option at this time.

Sincerely,

Brian Ellis

--
Brian Ellis
[email protected]
818-521-8015 (voicemail or text only)
872 of 983
1 Ghazarian, Renia
From: Ann Dorsey <[email protected]>
Sent: Saturday, February 5, 2022 9:11 PM
To: Kassakhian, Ardashes
Subject: Include clean renewable energy in the Grayson project CAUTION: This email was delivered from the Internet. Do not click links, open attachments, or reply if you are unsure as to the sender.

Councilmember Kassakhian,

I urge you to vote no on the Grayson project as it is currently proposed. It is imperative that energy is transitioned to clean renewable sources as much as possible as soon as possible. Glendale has an opportunity to do that by incorporating clean renewable energy in the Grayson project.

Thank you,

Ann Dorsey

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1 Ghazarian, Renia
From: Joy Meserve <[email protected]>
Sent: Saturday, February 5, 2022 9:44 AM
To: Devine, Paula; Agajanian, Vrej; Brotman, Daniel; Kassakhian, Ardashes; Najarian, Ara Subject: Please REJECT the Grayson Powerplant Project As-is CAUTION: This email was delivered from the Internet. Do not click links, open attachments, or reply if you are unsure as to the sender.

Dear Esteemed City Council Members of Glendale,

Indivisible Media City Burbank joins the Glendale Environmental Coalition in opposing the Glendale Water and Power (GWP) plan to install 93+ MW of polluting equipment, costing at least $200 million, at the Grayson Power Plant. We believe much more clean energy is possible in Glendale and should be the top priority investment.

But the plan released in 2021, two years later, has little new clean energy, with the Grayson Repowering project still including 93+ MW of gas burning. Glendale should pursue a commercial solar plus battery program, maximize solar on city properties, load management solutions, and new transmission opportunities all before investing in gas-burning equipment.

A large investment in gas-burning equipment commits us to burn fossil fuels for many years to come. California is mandating 100% clean energy by 2045; if that deadline moves up, equipment might have to be decommissioned. GWP speaks of converting the new equipment so that it can burn clean hydrogen. We don’t know how green that technology is, how realistic and how costly adapting the engines would be, how Glendale would produce or transport the hydrogen, and whether it would be a good investment for the amount of energy we get.

The Los Angeles region has among the worst air quality in the country, and residents who live near Grayson are already heavily burdened by freeway air pollution. The Grayson Power Plant produces significant amounts of air pollutants that cause cancer, asthma, heart disease, and dementia, as well as impaired cognitive development in children. We need to make clean air and a healthy environment our top priorities. We need to stop investing in fossil fuels and fossil fuel equipment. We need to urgently plan for a clean energy future.

Please reject the Grayson Repowering Plan and ask GWP to maximize clean energy in Glendale.

Thank you!

Regards,

Joy Meserve
Co-Founder of Indivisible Media City Burbank
874 of 983
2 COO, iD Tech
Sister City Resident of 20 years, Burbank
818-988-0968
875 of 983
1 Ghazarian, Renia
From: Andrew Delman <[email protected]>
Sent: Friday, February 4, 2022 5:04 PM
To: Devine, Paula; Agajanian, Vrej; Brotman, Daniel; Kassakhian, Ardashes; Najarian, Ara Subject: Say no to Grayson expansion
CAUTION: This email was delivered from the Internet. Do not click links, open attachments, or reply if you are unsure as to the sender.

Dear Mayor Devine and Glendale City Council,
I urge you to reject the expansion of natural gas burning at the Grayson Power Plant and consider more forward-looking alternatives. As a resident of Glendale, I am concerned about climate change and the resilience of our community in the face of it. As the father of a 1-year old child, I want him to grow up in a city that is leading the way towards the infrastructure of the future rather than doubling down on fossil fuels. Natural gas is a very popular inexpensive fuel now, but we can not responsibly make the decision to be spewing more dangerous emissions 10, 20, or 30 years from now. Please don't commit our city to a power plan that in 2040 or 2050 will be embarrasingly retrograde.

Thank you very much for your time and your efforts serving Glendale.

Best regards,
Andrew Delman
876 of 983
1 Ghazarian, Renia
From: Devine, Paula
Sent: Tuesday, February 15, 2022 10:23 AM
To: Garcia, Michael
Subject: Fwd: More clean energy, reduce fossil fuel investment FYI
Sent from my iPad

Begin forwarded message:

From: Diana Matsushima <[email protected]>
Date: February 15, 2022 at 10:06:00 AM PST
To: "Devine, Paula" <[email protected]>, "Agajanian, Vrej" <[email protected]>, "Brotman, Daniel" <[email protected]>, "Najarian, Ara" <[email protected]>, "Kassakhian, Ardashes" <[email protected]> Subject: More clean energy, reduce fossil fuel investment

CAUTION: This email was delivered from the Internet. Do not click links, open attachments, or reply if you are unsure as to the sender.

Dear Mayor Devine and City Council members,
I am a member of the Glendale Environmental Coalition and urge you to consider their thorough detailed report on how the City can transition to clean energy faster and avoid unnecessary financial investments.

Their review of capacity resources and capacity needs indicate that the amount of new fossil fuel equipment costing more than $200 million could be reduced significantly. Action needs to be taken now to avoid worsening of the climate crisis which is readily apparent in the recent 80+ degree weather in February and the fires in Los Angeles and Orange County.

I look forward to hearing from you. I appreciate your consideration and action regarding this urgent situation.

Sincerely,
Diana S. Matsushima
Verdugo Woodlands
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GEC Questions from February 10, 2022 E-mail

1. What would the capacity of Unit 8A be post-refurbishment? If Unit 8A were converted to simple cycle it would have a capacity of about 26 MW.

2. What is the estimated cost of refurbishing just Unit 8A, including all costs specific to preparing the site for the unit and re-installing the unit? Unit 8A is a combined cycle unit. In that context, refurbishing Unit 8A would entail addressing the both the gas turbine and steam plant as the gas turbine cannot run independently. Alternative 8 contemplated only retaining the gas turbine.

Implementing Alternative 8 with only Unit 8A would only save the Unit 8BC costs, on the order of $20 million.

3. What is the estimated cost of installing 2 Wartsila ICE units, including all costs specific to preparing the site for the units and re-installing the units? Installing two Wartsilas versus five would reduce the cost somewhat. The environmental, Owner’s Engineering, project management, Unit 9 separation, demolition/site improvement, Tesla, Balance of Site EPC contractor, UOC improvements, and spare parts remain unaffected by the change in the number of engines. Wartsila’s engineering costs would remain largely unaffected, with some reduction in equipment and construction costs offset to some degree by loss of economy of scale. An initial estimate for reducing the Wartsila scope to installing two engines and associated equipment might reduce the total cost of Alternative 7 to $310 million.

4. Do you currently foresee refurbished Unit 8 equipment or Unit 9 being convertible to combust a hydrogen-gas blend or pure hydrogen in the future, and if so, at what maximum concentration?
This topic was addressed in the 2021 PR-DEIR Response to Comments, L5.

5. If a repower used refurbished Unit 8 equipment instead of new Wartsila equipment, would GWP support a plan to retire the equipment earlier than the Wartsila’s retirement or conversion to 100% hydrogen?
The Unit I gas turbines can also run on RNG today similar to the Wartsila engines.

To reach 100% clean, we need to plan for (green) hydrogen conversion for Unit 8, the same as with the Wartsila option.

GWP can only commit for early retirement if there is a viable alternative local resource that can address our reliability requirements.

6. With either the refurbished or Wartsila equipment, do you see a possibility of stopping burning carbon-emitting fuel before 2035, and if so, what would make that possible?
GWP can only commit for early retirement if there is a viable alternative local resource that can address our reliability requirements. 878 of 983
GEC Questions from February 10, 2022 E-mail

7. When we met, in discussing the new 72 MW of transmission Glendale has gained rights to, Mark referred to potential issues with getting capacity to fill that transmission. What are the constraints he was referring to? The addition of 72 MW
gross/68 MWnet of transmission on the STS shifted the 2nd largest contingency to the STS line which subsequently increased the reserve requirements. IPP contractual provisions on the delivery of renewable energy to the injection point to produce green hydrogen for the IPP project may potentially use up a significant amount of capacity on STS. This is still being deliberated with other project off-takers. GWP may therefore have limited access to purchase energy due to the high demand for renewable energy required for hydrogen production.

8. What are the prospects for installing fewer ICE units now and then potentially more at a later time if clean energy doesn’t come through as planned? What are the limiting factors on that option?
Two Wartsila units with 75 MW of BESS is insufficient. GWP did an hourly evaluation, similar to what was done in Topical Response 8, using:
• August 28-31, 2017 actual loads
• Grayson Units 1-8 retired
• Grayson Unit 9 (24-48 MW)
• Magnolia (35 MW summer net)
• Eland (358 MWH, more than contract guarantee to reflect August conditions) • Local DER (40 MWH)
• VPP (58 MWH, more than contract guarantee to reflect August conditions) • 2 Wartsila units (9-37 MW) plus 75 MW/300 MWH BESS
• Pacific DC Intertie (200 MW) and STS transmission (72 MW) imports • Scholl Canyon (11 MW)
• N-1 (100 MW, 1 circuit on PDCI) and N-1-1 (64 MW, STS) With this configuration – 2017 loads and 2027 resources – there were 12 hours when there was insufficient generation. The maximum shortfall was 35 MW – the equivalent of two more Wartsilas. When you extend out to 2030 loads, the situation deteriorates further.

Trying to add units later is extremely difficult and more costly. A critical constraint is that addition of the new units cannot affect the operating units. The new units would also likely need to be in a separate building because:
• Operation of existing units with building partially opened for new units would create a noise issue
• Fire protection would be compromised
• Constructing new units next to operating units is a challenge because of noise levels in the working area.
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GEC Questions from February 10, 2022 E-mail
• Pile driving for the new engines poses a unit trip hazard Having two buildings will lead to less efficient utilization of space. There will also be very limited laydown space available, particularly after the Glendale Switching Station is built.

9. How many existing solar installations are there in Glendale, and what is the approximate maximum capacity from those installations? How many of these are paired with storage systems, and what is the approximate maximum capacity of the storage systems?
As of this writing there are 2,039 solar PV installations within GWP with a total CEC- AC capacity of 21.5 MW.

There are 106 energy storage installations associated with PV installations with an aggregated capacity of 0.5 MW/1.3 MWH. There is no real financial benefit to the customer unless they move to Time-of-Use rates. Customers have paired their PV with storage to serve as back-up power in case of an outage. Note that most BTM solar PV installations are sized based on the customer’s average consumption.

Outside the summer season, excess generation that can be used to charge the battery could be marginal non-existent.

10. In discussing the potential for fuel cells, Mark noted a concern that they use a substantial amount of water. It is our understanding that the Bloom fuel cells only use water in the electrolysis process that produces hydrogen, and that when hydrogen is used to generate electricity in the fuel cell, that process produces water, so the water needed isn’t that great. We wonder whether the technology has changed since GWP first considered it, and would it be a good idea to take another look at the latest fuel cell technology? We’re very interested in comparing the cost and energy efficiency savings, along with the emissions reductions, with natural gas and hydrogen combustion.

GWP currently has four fuel cells connected to the 12 kV distribution system. These are all fueled with natural gas.

The Bloom fuel cells utilize solid oxide technology. This type of fuel cell operates at a high temperature. As a result, they have a long startup time as the cell first needs to heat up to operating temperature before the process can start. This feature makes them unsuitable for fast and flexible resource that Grayson needs to be. 880 of 983
Aliso Canyon Action Plan to Preserve Gas and Electric
Reliability for the Los Angeles Basin
Prepared by the Staff of the California Public Utilities Commission, California Energy Commission, the California Independent System Operator and the Los Angeles Department of Water and Power

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Aliso Canyon Action Plan to Preserve Gas and Electric
Reliability for the Los Angeles Basin

Table of Contents
Executive Summary ....................................................................................................................................... 3 Introduction .................................................................................................................................................. 5 Background ................................................................................................................................................... 7 Gas System Operating Characteristics ...................................................................................................... 7 Core Versus Noncore Customers ............................................................................................................ 11 Gas Scheduling and Balancing................................................................................................................. 12 Gas Demand, Capacity and Reserve Margin ........................................................................................... 15 Los Angeles Department of Water and Power ....................................................................................... 17 Risk Assessment .......................................................................................................................................... 18 Winter 2016 ............................................................................................................................................ 19 Summer 2016 .......................................................................................................................................... 20 Winter 2017 and Longer‐Term ............................................................................................................... 23 Mitigation Measures ................................................................................................................................... 24 Prudent Aliso Canyon Use ....................................................................................................................... 24 Tariff Changes ......................................................................................................................................... 25 Operational Coordination ....................................................................................................................... 27 Maximize LADWP Operational Flexibility ............................................................................................... 29 Reduce Natural Gas and Electricity Use .................................................................................................. 30 Next Steps ................................................................................................................................................... 32 Conclusion ................................................................................................................................................... 32

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3 Aliso Canyon Action Plan to Preserve Gas and Electric Reliability for the Los Angeles Basin
Executive Summary
Several actions are underway to respond to the major natural gas leak that occurred at the Aliso Canyon Natural Gas Storage Facility on October 23, 2015. With the leak now stopped, there is a moratorium that prohibits the operator of the facility, Southern California Gas (SoCalGas), from injecting natural gas into the underground reservoir until a comprehensive safety review of the facility is completed. This safety review requires that all 114 wells in the facility are either thoroughly tested for safe operation or removed from operation and isolated from the underground reservoir.

The implementation of these safety measures means that the Aliso Canyon facility is not operating as it normally does to provide gas for the energy demands in the Greater Los Angeles area. Only 15 billion cubic feet of natural gas remains in the Aliso Canyon underground reservoir—less than one‐fifth of the capacity of the facility—for use to maintain electrical and gas service in the region if it is needed.

The Aliso Canyon facility has operated for decades as a critical part of the natural gas transmission and distribution system in the Los Angeles region. Aliso Canyon provides gas supplies to 11 million customers for home heating, hot water and cooking fuel. The facility also provides gas supplies to natural gas‐fired power plants that play a central role meeting regional electrical demand. Aliso Canyon is critical to meeting peak gas usage demands in winter months and helping to meet peak electrical demands during the summer months. Gas supply from Aliso Canyon has never before been constrained at current levels, which introduces uncertainty and concerns regarding energy reliability in the Greater Los Angeles area.

Four energy agencies came together to assess possible impacts to electrical service during the summer months recognizing that the current situation at Aliso Canyon threatens energy reliability. The California Energy Commission (Energy Commission), California Public Utilities Commission (CPUC), California Independent System Operator (California ISO) and the Los Angeles Department of Water and Power (LADWP) collaborated to develop a technical assessment of energy impacts stemming from the current gas supply limitations of Aliso Canyon. Technical staff from these four entities joined with staff from SoCalGas in a Technical Assessment Group to conduct an engineering analysis that details potential energy impacts in the coming summer months.

The Technical Assessment Group finds that Aliso Canyon plays an essential role in maintaining both natural gas and electric reliability in the greater Los Angeles area. As a result, the limited current operations of the facility create a distinct possibility of electricity service interruptions in the coming summer months. The engineering analysis, which applied complex industry standard hydraulic modeling to simulate operations on the SoCalGas system suggests that without any gas supply from Aliso Canyon, there are 14 days this coming summer during which gas curtailments could be high enough to cause electricity service interruptions to millions of utility customers. Factors leading to gas curtailments, even 883 of 983
4 on days with only moderately high demand, include differences between gas scheduled and received into the SoCalGas system (receipts) versus actual customer demand (sendouts) as small as 0.15 Bcf; gas storage and pipeline maintenance work planned for this summer, and unplanned outages.

Using the 15 billion cubic feet of gas currently stored at Aliso Canyon as directed by the CPUC and taking several other actions described below can reduce ‐ although not eliminate‐‐ the possibility of these electric interruptions. It is also important to note that, using most or all the gas remaining in Aliso Canyon during this summer would result in greater risk of shortages next winter if normal operations of the facility are not restored in time to store new gas there for winter use. The Technical Assessment Group will present in the near future an analysis of energy reliability challenges for the upcoming winter in the event of continue constrained operations at Aliso Canyon.

The technical assessment of potential energy impacts informed the development of a joint Draft Action Plan by the four energy agencies to preserve electrical reliability in the coming summer months in the greater Los Angeles area, which is described in this document. The Action Plan identifies actions to reduce the risks of gas curtailments this summer, including using the current supply of 15 billion cubic feet stored in Aliso Canyon during periods of peak demand to avoid electrical interruptions, directing all shippers to closely match their scheduled gas deliveries with their actual demand every day, and asking customers to use less energy. This Reliability Action Plan represents intense coordination among the state’s utility regulator, energy planning agency, SoCalGas and the electric balancing authorities to develop plans trying to preserve reliability for electrical service over the coming several months.

This Draft Action Plan proposes implementation of 18 specific measures to reduce the possibility of electrical service interruptions this summer. These measures will reduce, but not eliminate, the risk of gas curtailments large enough to cause electricity interruptions. The measures themselves are not cost‐ free. Some require regulatory approval; including potentially by the Federal Energy Regulatory Commission. The measures fall into five major categories: efficient use of Aliso Canyon, noncore gas tariff changes, greater operational coordination, LADWP‐specific measures, and measures aimed at reducing natural gas and electricity consumption. The detailed measures are listed below in order of relative importance in reducing risk and impact of curtailment.

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5 Table ES‐1: Summary List of Mitigation Measures
Category Mitigation Measure
Prudent Aliso Canyon Use Utilize the 15 Bcf Currently Stored At Aliso Canyon to Prevent Summer Electricity Interruptions
Efficiently Complete the Required Safety Review at Aliso Canyon to Allow Safe Use of the Field
Tariff Changes Implement Tighter Gas Balancing Rules
Modify Operational Flow Order Rule
Call Operational Flow Orders Sooner in Gas Day
Provide Market Information to Generators Before Cycle 1 Gas Scheduling
Require California ISO Generators to Show Gas Lined UP before Bid into Day‐Ahead Electricity Market
Operational Coordination Increase Electric and Gas Operational Coordination Establish More Specific Gas Allocation among Electric Generators In Advance of Curtailment
Determine if Any Gas Maintenance Tasks Can be Safely Deferred LADWP Operational Flexibility Curtail Physical Gas Hedging Stop Economic Dispatch Sales
Curtail Block Energy and Capacity Sales
Reduce Natural Gas and
Electricity Use
Use New and Existing Programs s Asking Customers to Reduce Natural Gas and Electricity Energy Consumption
Expand Gas and Electric Efficiency Programs Targeted at Low Income Customers
Expand Demand Response Programs that Target Air Conditioning and Large Commercial Use
Focus and Reprioritize Existing Energy Efficiency Towards Projects with Potential to Impact Usage this Summer and Coming Winter Reprioritize Spending in Existing Solar Thermal Program to Fund Projects Installable this Summer and by end of 2017

Introduction
On October 23, 2015, a significant natural gas leak in well SS25 was detected at the Aliso Canyon natural gas storage facility owned by Southern California Gas Company (SoCalGas).  The facility is near the community of Porter Ranch, in the north end of the San Fernando Valley.  Numerous attempts to “kill” – plug up ‐  the well and stop the leak in November and December 2015 failed.  In the meantime, SoCalGas withdrew gas from the field in hopes of increasing the success of further kill and to reduce the rate of the leak.  The California Energy Commission (Energy Commission), the California Public Utilities Commission (CPUC), and other state agencies including the Department of Conservation’s Division of Oil, Gas and Geothermal Resources (DOGGR), and the Governor’s Office of Emergency Services, as well as the California Independent System Operator (California ISO), worked to assess potential impacts to natural gas and electricity reliability, recognizing that the storage field could be out of service or available only at reduced capacity for some period.
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6 Governor Edmund G. Brown Jr. issued an Emergency Proclamation1 on January 6, 2016, acknowledging the significant and ongoing impacts of the well leak on the local community.  The Proclamation noted the response had included "months of regulatory and oversight action from seven state agencies mobilized to protect public health, oversee Southern California Gas Company’s actions to stop the Aliso Canyon leak, track methane emissions, ensure worker safety, safeguard energy reliability and address any other problems stemming from the leak."  The proclamation specifically called on the Energy Commission, CPUC, and the California ISO to work together and "take all actions necessary to ensure the continued reliability of natural gas and electric supplies during the moratorium on gas injections into Aliso Canyon."
The Energy Commission, CPUC, and the California ISO replied to Governor Brown’s Emergency Proclamation with a letter on February 1, 2016, in which they committed to work together with a sense of urgency to identify and address potential threats to reliability that might arise during the time that Aliso Canyon is unavailable or available at less than full capacity.  This effort is similar to the effort undertaken by these same agencies when the San Onofre Nuclear Generating Station (San Onofre) unexpectedly closed. The two agencies and California ISO committed to completing an assessment by April 2016 of the reliability risks for summer 2016 and present a plan for addressing them.  The agencies and California ISO were joined by the Los Angeles Department of Water and Power (LADWP).   LADWP performs its own balancing of electricity loads and resources along with some other municipal utilities in the LA area, and as such is not a member of the California ISO.

The nexus between the gas and power systems in the Los Angeles Basin (L.A. Basin) is complex. A technical assessment must consider the constraints on gas deliveries, system operations features, rapid changes in electricity demand that occur every day, and electric transmission constraints that limit electricity imports into the area. Given these complexities, reliability planning for the two sectors combined requires an in‐depth explanation into operational nuances and detail that even many experts do not have easily at hand using data that are often held confidentially, sometimes for business reasons and sometimes for critical infrastructure security reasons. SoCalGas has long used Aliso Canyon as a critical component of the natural gas transmission and distribution system it uses to provide gas service.

This natural gas serves both “core” customers ‐‐ homes and small businesses ‐‐ and “non core” customers – which includes large customers like hospitals, local governments, oil refineries and 17 large natural gas‐fired power plants. With much of the necessary natural gas system data held solely by SoCalGas, the California ISO invited the gas company to join a task force to perform and review the required reliability analysis and help explore mitigation measures. The Technical Assessment Group worked over several weeks, developing the analysis assumptions, subjecting the results to hours of review, and assessing the ultimate impact on electricity operations for power plants within both the California ISO and LADWP balancing areas.

The action Plan begins with a background discussion about the natural gas system in southern California.

A summary of the risk assessment follows, additional details of which are described in the Technical

1 For the Proclamation see https://www.gov.ca.gov/news.php?id=19264 886 of 983
7 Assessment Group’s report accompanying this Action Plan. The Reliability Action Plan describes the mitigation measures and next steps for implementation of the mitigation measures and analyses that need to be launched for winter 2017 and beyond.

Background
Understanding the rationale for the mitigation measures and the importance of Aliso Canyon requires providing some background about the natural gas system in southern California. It also requires knowledge of, natural gas customer types and the associated tariff rules and operating procedures and planning that govern their service. This section also provides background information about LADWP’s natural gas requirements and its alternatives to in‐basin gas‐fired generation in the short term.

Gas System Operating Characteristics
SoCalGas bills 5.7 million accounts, translating to 22 million customers, 11 million of which are within the L.A. Basin. To serve those customers, SoCalGas owns and operates high‐pressure gas pipelines (known as the “backbone transmission system”) that can accept as much as 3.875 Billion Cubic Feet per day (Bcf per day) of natural gas from several pipelines that connect California to gas producing areas.

Those gas producing areas are often hundreds of miles away, in New Mexico, Texas or the Rocky Mountains (primarily Wyoming).2 The general configuration of SoCalGas’ system is shown in Figure 1.

Some of the gas delivered via the backbone transmission system flows directly to customers. The remainder, however, is injected into one of SoCalGas’ underground gas storage fields (Aliso Canyon, Honor Rancho, La Goleta or Playa del Rey) for later use. Before the situation at Aliso Canyon, the four storage fields could deliver as much as 3.8 Bcf per day, with Aliso Canyon alone being able to deliver 1.9 Bcf per day. Winter demand, can be as high as 5.1 Bcf per day on a peak day with several days more than 4 Bcf per day.3 These winter demands are higher than the 3.875 Bcf per day that SoCalGas can take from the pipelines bringing gas into its system from gas producing areas.4 Gas storage is therefore essential to meeting winter natural gas demand.

Table 1: SoCalGas Underground Gas Storage Fields Key Operating Characteristics

Field

Location Connects To
Working Gas Maximum
Inventory (BCF)
Withdrawal
(BCFD)
Injection
(BCFD)
Aliso Canyon San Fernando Valley LA Loop 86.2 1.9 0.4 Playa del Rey Marina del Rey LA Loop 1.8 0.4 0.2
Honor Rancho Santa Clarita Backbone North 27.0 1.0 0.07 La Goleta Santa Barbara Coastal 20.2 0.4 0.2
TOTAL 136.1 3.8 1.1
Source: Direct Testimony of Philip E. Baker on Behalf of SoCalGas in CPUC A.14‐11‐004, p. 5

2 Only 10 percent of the supply is produced in California.  Some can also come from Canada. 3  See 2014 California Gas Report, p. 90.
4  This is also true for the Pacific Gas and Electric system: both require use of gas in storage to meet winter gas requirements.
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8 Gas storage, specifically gas from Aliso Canyon, is also essential to meeting summer demand.  Aliso Canyon and Playa del Rey are the only two fields inside the L.A. Basin and are on the lower pressure local transmission system (sometimes referred to as the “L.A. Loop”).  Gas can come into the Basin but cannot overcome the higher pressure of the Backbone Transmission System to leave the Basin.  In addition, when there is not enough gas coming into SoCalGas’ system to meet all demand, SoCalGas allows the flowing gas supply to stay on the Backbone Transmission System to meet demand there and pulls gas from Aliso to meet demand in the L.A. Loop.

SoCalGas particularly pulls from Aliso to meet hourly demand changes. Natural gas wells and long distance transmission pipelines flow natural gas at a constant hourly rate. Given the small size of Play del Rey, and the facts that Honor Rancho is several hours of flow farther away and La Goleta is too far away and only marginally connected to the L.A. Loop, Aliso Canyon is the only storage field available to support hourly operating changes within the LA Basin. This makes the Aliso Canyon storage facility essential to the overall reliability of both the gas and electrical systems (especially but not solely within the L.A. Basin), and uniquely critical to meet gas demand in the summer months. Summer gas demand is driven by demand for electricity and can display large and rapid swings in gas demand.

Figure 1: Southern California Gas Company Natural Gas Transmission System5

5 Source: Southern California Gas Company
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9 Furthermore, there are many days that the full 3.875 Bcf of pipeline capacity is not available due to maintenance or unplanned outages.

Even on days when the 3.875 Bcf of pipeline capacity is available, less than 3.875 Bcf gas may flow into the system if weather patterns in regions east of California drive up gas demand in those regions and gas is diverted to meet their demand. Extreme cold weather in the producing basins can also trigger a reduction in gas production in those basins, as the liquids freeze in wellheads or gas gathering pipelines.

Sometimes both these events occur together, with cold causing higher demand and reducing production. Either means that Southern California cannot count on 3.875 Bcf per day of gas supply flowing in from upstream sources and SoCalGas must withdraw gas from storage to meet demand.

It is also possible that even when the 3.875 Bcf of pipeline capacity is available and there are no weather issues to the east, the pipeline still will not be full. As will be explained fully later in this section, noncore customers who are responsible for purchasing and scheduling transportation of their own gas supply do not have to bring in enough supply each day to cover their usage.

Use of the storage capacity at Aliso under normal conditions can be supplemented, to a limited extent, using increased flowing supply delivered via pipelines or from the Honor Rancho storage facility.

However natural gas flows through high pressure pipelines only at a rate of about 25 to 30 miles per hour, and closer to 20 miles per hour on lower pressure pipelines. This means that flowing gas supplies, that is, those that come into the LA Basin from the supply areas that are hundreds of miles away, cannot respond in time to hourly changes in electric‐generation demand. But even more important to this equation is that on most days there are differences, known as “imbalances,” between the quantities of gas that large customers schedule for delivery into SoCalGas’ system versus what they actually use.6 The lower pressure gas pipeline system within the L.A. Basin does not have enough of what is known as “pack and draft” capability to match supply with demand each hour.7 Storage gas inside the L.A. Basin is the only way, today, to match supply with demand.8
Today, there are 17 major gas‐fired electric plants in the LA Basin. As can be seen in Figure 2, many are near the southern end of the Basin. These plants have a combined capacity of 9,838 megawatts (MW).

The Energy Commission has calculated that 1 MW serves about 1,000 homes. All 9,838 MW don’t all operate every day, but most of this capacity operates on hot days, when electricity demand rises to

6  More about how the natural gas industry “schedules” gas deliveries the day ahead of use appears further below. 7  If supply exceeds demand, operating pressures could increase above acceptable and safe tolerances and ultimately could have to be vented to the atmosphere to prevent the line from failing.  If supply is too far less than demand, there can be insufficient pressure to keep gas moving through the line.  A customer could open a valve to use gas and find none.  The gas system operator monitors line pressures and issues warnings or curtailment notices when safe operating limits cannot be achieved.
8 Playa del Rey is also located within the LA Basin.  As the operating analysis will show, Playa del Rey is not sufficient to keep operating pressures at safe levels because of the small size and the length of time it takes to refill the facility once any gas is withdrawn.  Early on, the CPUC and the Energy Commission considered whether compressed or liquefied natural gas tankers deployed near power plants would be helpful.  The agencies concluded they would not be as those vehicles introduce safety concerns and deliver too little gas relative to power plant requirements to be useful.
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10 support cooling needs met with air conditioning.  SoCalGas relies on Aliso Canyon on these days to meet the hourly change in gas requirements as these gas‐fired electric generators fire up and operate during peak hours. Moreover, some of the 17 gas‐fired generating plants must be available to produce quickly, in case of outages on the electricity system.9  Again, Aliso Canyon is the only source that can provide immediate gas supply in time to prevent collapse of operating pressures within the Basin.

This frequent use and reliance on Aliso Canyon is documented in Table 2. Over the 3‐year period from 2012‐2015, SoCalGas withdrew gas from Aliso Canyon an average of 134 out of 151 “winter” days and 70 out of 214 “summer” days.10,11
Table2: Average Number of Days of Withdrawal from Aliso January February March April May June July August September October November December Average # of Days per
Year Aliso
Withdrawals
31 21 18 7 3 6 13 18 12 12 26 31
Source: CPUC Energy Division Preliminary Staff Analysis, February 16, 2016

9 Electricity reliability planners refer to these outages as “contingency events.” 10 Winter is defined as November 1 through March 31, and summer is April 1 to October 31. These dates coincide with the traditional underground gas storage withdrawal and injection seasons for the natural gas industry. 11 SoCalGas’ Envoy™ system reports withdrawals on a system accumulated basis and not by individual storage facility, thus, these data are not available except via data request to SoCalGas. This contributes to the inability of many members of the public to immediately understand why Aliso Canyon is so important to reliable gas operations.
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11 Figure 2: Electric Generation Plants Served by Aliso Canyon

Source: Energy Commission Staff
Core Versus Noncore Customers
In 1988, the CPUC separated gas supply (or, procurement) service from gas transportation service and split gas utility customers into two basic groups: core customers and noncore customers. The distinction between core and noncore customers is based on size; it determines where the responsibility lies for procurement of their gas supply, the reliability of that supply, and the rates each pays, for gas transportation service. Core customers are homes, small commercial operations, and small industrial customers, all of whom typically receive their gas‐related services from the gas utility, all together in a single package, including procurement, transmission, storage, distribution, metering, and billing.12 SoCalGas purchases the gas supply and then provides transportation, storage and balancing service for these customers. Ninety nine percent of SoCalGas’ customers, representing roughly 80 percent of the annual load, are in the core category. Core customers are to be the last customers curtailed in the event

12 The core customer bill shows the commodity cost of the gas procured separately from the other services but the gas utility still buys the gas on their behalf. Noncore customers, in contrast, are required to buy their own gas. 891 of 983
12 that there is insufficient supply in the system.13 This is not only because of the “human needs” nature of the service to core customers but because gas safety requires restarting gas service by purging lines of air and any water that might have invaded, then relighting pilot lights on gas appliances building‐by‐ building and distribution feeder‐by‐distribution feeder sequentially. This process can take several days, depending on the number of customers involved. Customers must be present to provide building access and numerous gas company employees are required. This is not to ignore the significant safety and economic risks should electricity service be interrupted and rotating or other electricity outages ensue, or that many gas appliances cannot operate without electricity.

Noncore customers consist mainly of large industrial and commercial customers, including hospitals, electric generators (power plants), and oil refineries. These customers procure their own natural gas supplies. They use SoCalGas’ transmission and distribution system to transport, or ship, the gas supply they purchase elsewhere.14 They also can purchase gas storage service. These customers pay lower rates recognizing their lower order in the priority of service and that there is not enough capacity to serve them under peak winter conditions. A subsequent section of this Reliability Action Plan explains in detail the relative contributions of core and noncore customers to winter peak gas demand.

Gas Scheduling and Balancing
Today’s gas market structure with noncore customers purchasing their own gas supply means there are many entities who need to communicate and confirm operations up and down the gas supply chain to keep track of whose gas is coming from where and make sure it gets delivered. Shippers, therefore, have to notify the gas company of how much gas they plan to transport onto the system and subsequently use at their facility.15 In doing so, shippers are not required to, and often do not, bring in each day exactly the amount of gas they will use. Noncore customers are not required to balance their demand and delivery of gas each day; instead, SoCalGas requires that noncore customers total demand for the month must match up with the gas they deliver in that month within a tolerance band of plus or minus 10 percent. That difference does not have to be made up until the next month. In other words, a shipper can be out of balance by up to 10 percent of its monthly gas use and make up that difference next month at no penalty.

These balancing provisions have been in place for a long time and have provided great benefits to all shippers on the SoCalGas system. The flexibility balancing shippers enjoy were made possible by the

13  Priority rules for order of service in case of curtailment still generally reflect those adopted in the 1970’s gas shortages when little natural gas was used for electricity generation.  For a time, the Fuel Use Act actually prohibited use of natural gas in non‐cogeneration baseload electric generating plants; many gas‐fired generators also had the ability to burn an alternate fuel.  Today, many gas appliances require electricity to ignite meaning that many will not work if electricity service is out.
14 This is why noncore customers are sometimes referred to as “shippers.”  In addition, gas marketers can ship gas over the SoCalGas system and inject it into storage for later sale to noncore customers, also in this context as a “shipper.”
15  This notification is called, variously, “scheduling” or “nominating” their gas. 892 of 983
13 large amount of gas storage available in southern California.16   The work by the Technical Assessment Group, discussed in the subsequent Risk Assessment section of the Aliso Action Plan, demonstrates that imbalances cannot be sustained without being able to use Aliso Canyon routinely. This is an unfortunate reality that is a result of removing the Aliso Canyon gas storage field from service due to the well leak and safety inspections required prior to restoring any wells service..

The only exception to the current balancing rules occurs when SoCalGas has to call an Operational Flow Order (OFO). An OFO is a specific warning to customers that the SoCalGas system is so far out of balance that gas from storage alone cannot balance the system. Thus, the OFO notifies customers, after initial scheduling requests are received and processed, that they must match their deliveries with their use more closely. Those who do not or cannot comply are charged a penalty that varies with the severity of the system imbalance. OFOs occur somewhat unpredictably and the notices are issued late in day, after a problem is discovered. At that point shippers have few tools available to respond. OFOs are intended to be the exception rather than the rule.

As explained above, storage was key to the broad tolerance allowed in the gas balancing rules: when customers did not bring enough flowing supply to the receipt points, SoCalGas used storage to provide make‐up supply. In operating its system, SoCalGas often used flowing supply to meet demand outside the Basin and withdrew from Aliso Canyon to meet demand inside the Basin. SoCalGas also used Aliso to follow hourly load changes within the Basin. It has no other tool that can perform this role inside the Basin: Honor Rancho is too far away, and Playa Del Rey is small, with limited injection capability that keeps it from being quickly refilled. The L.A. Loop also operates at a lower pressure than the higher pressure pipelines coming in from the border receipt points and often uses Aliso Canyon to meet hourly changes in demand that are often larger than its limited pack and draft can address.17 Another complexity to scheduling gas deliveries is the timing in which this scheduling occurs. Figure 3 depicts gas scheduling alongside electricity scheduling to make apparent the timing mismatches.

Shippers, including electric generators, schedule their gas at 9:30 a.m. Those generators don’t bid into the California ISO’s day‐ahead electricity market until 10:00 a.m. They then won’t learn which of them are dispatched by the California ISO until the California ISO announces awards at 1:00 pm.18 The fact that generators must schedule gas supply before they receive their awards forces generators to guess

16 Electric utilities have pointed out that this flexibility is of particular comfort as California adds more renewables and needs to ramp up and down more frequently use of gas‐fired generating facilities. Other noncore customers may use it to facilitate price arbitrage or for other reasons.

17 Pack and draft describes the ability within a pipeline to operate at a slightly higher operating pressure and effectively compress more natural gas molecules into the same space. It occurs when more gas is flowing in than customers are using. Conversely, draft occurs when the pressure drops and the molecules spread out. This occurs when customers are using more gas than is flowing into the system. 18 Effective April 1, 2016, the nomination times shown above changed. For example, 9:30 a.m. will change to 11:00 a.m., and 2:30 p.m. will change to 4:00 p.m. A fifth intraday (ID) window will be added. Figure 3 shows the old format for simplicity.
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14 how much gas they will use.19 This situation leads to variances between nominations and actual burn. If large enough, the variances contribute to the need for SoCalGas to call OFOs or, worse, curtail gas service.

Figure 3: Simplified Timeline Illustrating Gas and Electricity Scheduling

Source: California Energy Commission
Compounding these timing complexities, the interstate pipelines that bring gas from producing areas in Texas, New Mexico, Colorado, Wyoming or even Canada, must also confirm to SoCalGas that they will meet the scheduling requests submitted by SoCalGas’ shippers. The pipelines do not deliver these “confirmations” to SoCalGas until 2:30 pm. This is the first indication SoCalGas gets of whether deliveries from the pipelines will match customer demand for the next gas day. By the time SoCalGas receives those pipeline confirmations and determines whether they need to call an OFO (or worse, a curtailment), the day‐ahead wholesale power market is closed. This is especially problematic for LADWP, which has fewer options to replace any gas‐fired generation that might be curtailed. LADWP’s system and options are discussed more fully in the next subsection of this Reliability Action Plan.

19 Generators often guess very well owing to their experience watching weather and market conditions.

Generators’ use can also vary, as their efficiency changes with ambient air temperature changes. Generators can also end up being dispatched in real time differently than from the day‐ahead market awards should, for example, real‐time demand differ from the day‐ahead forecast.
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15 Gas Demand, Capacity and Reserve Margin
On a peak demand day in winter, core customers account for more than half of the gas demand in SoCalGas’ service territory.Out of the 5.077 Bcf/day of forecasted demand on the peak 2016 winter day, 60 percent (3.050 Bcf) of demand comes from core customers, 20 percent (1.031 Bcf) of demand comes from electric generation plants, and another 20 percent (0.996 Bcf) comes from other noncore customers. Table 3 shows the forecast of winter peak demand for 2016.

Table 3:  Forecasted 2016 Winter Peak Day Demand20
Customer   2016 Forecasted Peak Demand Percent of Peak Demand Core   3.050 Bcf 60
Electric Generation   1.031 Bcf 20
Noncore, not electric generation21 0.996 Bcf 20
Winter Total   5.077 Bcf 100
Source: CPUC Energy Division Preliminary Staff Analysis, February 16, 2016; initially taken from 2014 California Gas Report, p. 90
In the summer, the demand profile flips.  Noncore customers consume more during these periods as core loads that are sensitive to heating degree days fall off and electric generation increases due to air conditioning load.  Table 4 illustrates this occurrence. Based on SoCalGas’ 2016 peak summer forecast, the peak demand for natural gas will be 3.211 Bcf perday. Sixty‐one percent of that peak demand comes from electric generation plants.  Another sixteen percent comes from refineries with combined heat and power facilities that often provide electricity into the market after meeting their own requirements.

Most of the refinery load is inside the Basin and much of it cogenerates electricity using waste heat at the refinery.

Table 4 Forecasted 2016 Summer Peak Day Demand22
Customer   2016 Forecasted Peak Demand Percent of Peak Demand Core   0.634 Bcf 20 t
Electric Generation   1.943 Bcf 60
Noncore, not electric generation23 0.634 Bcf 20
Summer Total   3.211 Bcf 100 t
Source: CPUC Energy Division Preliminary Staff Analysis, February 16, 2016; initially taken from 2014 California Gas Report, p. 90
When SoCalGas’ system is short of either gas supply or the capacity needed to deliver that gas supply, procedures call for SoCalGas to curtail service first to noncore customers. This is aligned with the goal, as explained previously, to preserve service to core customers. The current tariff specifies that electric

20 Winter peak demand is calculated by SoCalGas as demand at 1‐in ‐35 year conditions for core customers plus 1‐ in‐10 year conditions for heating degree day‐sensitive noncore customers. See 2014 California Gas Report, p. 90. 21 This includes approximately 0.5 Bcf of use by oil refineries. 22 The summer peak day reflects dry hydro‐electric conditions observed to occur once every ten years. See 2014 California Gas Report, p. 90.
23 This includes about 0.5 Bcf of use by oil refineries. 895 of 983
16 generation plants are to be curtailed in rotation with other noncore customers. Some of these noncore customers are oil refineries, which are also key to California’s economy. In practice, however, SoCalGas has found curtailment circumstances to arise so quickly that they have been deemed gas emergencies.

In those circumstances, SoCalGas has turned to electric generation to reduce that load first, before involving other noncore customers.24 This is because electric generation loads are large, allowing more load to be shed with fewer phone calls.25
Table 5 shows the gas reserve margin under design conditions versus recent experience. At 15 Bcf in storage, pressure within Aliso Canyon allows a withdrawal capacity of Aliso Canyon of about 0.88 Bcf/day.26 The combined withdrawal capacity from the other SoCalGas storage fields (Honor Rancho, La Goleta, and Playa del Ray) is 1.7 Bcf/day. Adding the storage withdrawal ability to SoCalGas’ pipeline design capacity of 3.875 Bcf SoCalGas appears able to meet its winter peak demand of 5.077 Bcf/day, with a reserve margin of 0.5 Bcf.

However, there are several reasons that the system does not normally flow at 3.875 Bcf of supply or capacity. SoCalGas’s daily operating data show, that 3.4 Bcf per day has been the highest flowing supply coming into its system at any time in the last five years, and, most often, it is 3.0 Bcf per day or less.27 Using this experience, SoCalGas would not be able to serve all the forecasted winter peak day demand without some contribution of withdrawals from Aliso Canyon. The gas reserve margin calculation contained in Table 3 shows that SoCalGas would be 1.0 Bcf/day short without Aliso Canyon withdraws.

This calculation will become important when Aliso Canyon Action Plan Entities start work to protect reliability in winter 2017.

Table 5: Illustrative Gas Reserve Margin Under Design Versus Experience if Winter Demand Exceeds Historical Supply/Capacity without Aliso Canyon
Supply/Demand Design (Bcf/day) Recent Experience (Bcf/day) Pipeline Capacity Supply 3.8 3.0
Other Storage Supply (excluding Aliso) 1.7 1.0
Peak Winter Gas Demand (5.0) (5.0)
Reserve Margin 0.5 (1.0)
Source: CPUC Energy Division Preliminary Staff Analysis Note 1: Typical outages can reduce capacity 0.5‐1.0 Bcf/day Note 2: Electric generation typically requires 1.0‐2.0 Bcf/day

24 SoCalGas has Application No. 15‐06‐020 pending before the CPUC to change the curtailment rule in its tariff to be more consistent with its operating practice.
25  The gas curtailments of the 1970’s led to requirements that every state to adopt priority of service rules.  In nearly every instance, states,  (including California) approved making electric generation the lowest priority for natural gas service.
26  This 0.888 Bcf may not be achievable if fewer wells or available or with changed withdrawal characteristics using tubing only instead of operations using both tubing and well casing, consistent with DOGGR’s March 4 emergency rules.
27 As calculated from data posted on SoCalGas’ Envoy™ system.  The 3.4 Bcf occurred on October 16, 2014.

Envoy™ also shows maximum gas sendout to customers of 5.2 Bcf on January 14, 2013. 896 of 983
17 Los Angeles Department of Water and Power
LADWP is the nation’s largest municipal electric utility and the third largest electric utility in California. It serves a 465 square mile area in Los Angeles and much of the Owens Valley, which is in the south eastern Sierra Nevada. LADWP provides electricity to the city of Los Angeles and serves a population of more than 4 million people with 1.4 million residential and business retail customers. LADWP owns and operates its own generation, transmission and distribution system, making it a vertically integrated utility delivering power from its generation sources to its customers. LADWP has 7,957 MW of generation capacity from a diverse mix of energy sources, including gas, coal, nuclear, hydroelectric, and renewable sources. 28 LADWP’s electric transmission system network spans five states, including Oregon, Nevada, Utah, Arizona, and California. The LADWP electric system was designed and evolved to rely upon L.A. Basin gas‐fired generation to assure reliability of the system, while importing additional power supplies from outside the LA Basin. LADWP operates its transmission facilities and balances loads and resources within them, serving as its own balancing authority.29 Thus, it is separate from the California ISO balancing authority.

As its own balancing authority, LADWP must meet specific supply reliability metrics. These metrics require LADWP to maintain transmission line loading within limits and provide voltage support for its system; without in basin generation this voltage support LADWP becomes unable to accept into its system the portion of its generation that is imported. Gas‐fired generation plays a key role in meeting these metrics with specific generation minimums required, which vary based on system load and conditions. Some 40 percent of the gas‐fired generation capacity in the LA Basin is owned by LADWP.

This local, in‐basin generation represents about 24 percent of LADWP’s total electrical generation to meet its load; it imports the rest of the electricity it needs using electric transmission lines it owns. 30 LADWP forecasts its gas‐fired generation requirement to meet its load and reliability requirements and schedules the necessary gas to meet this generation requirement. This gas requirement forecast is based on expected system demand, weather, and system conditions. LADWP’s gas consumption typically ranges between 0.2 Bcf and 0.4 Bcf; during the 2015 summer, it averaged 0.141 Bcf with a maximum usage of 0.336 Bcf. Loss of a generation resource or transmission circuit, an unexpected reduction in variable generation (primarily wind and solar), and/or weather forecasting error may significantly increase the need for gas‐fired generation. These events often happen suddenly or with littlewarning.

28 Source: CEC Form S‐1, Capacity Resource Accounting Table (issued 12/2014). 29 The North American Electricity Reliability Council defines a Balancing Authority Area as the collection of generation, transmission, and loads within the metered boundaries of the Balancing Authority. The Balancing Authority maintains load‐resource balance within the respective area. 30 Source: CEC Form S‐2, Energy Balance Table (issued 12/2014) 897 of 983
18 At its 2016 summer peak load forecast of 5,787 MWh, roughly 72 percent of LADWP’s import capability is used to import electricity generated outside LADWP’s system.31 That electricity may come from generating resources owned by LADWP or purchased from others. On these high demand days, LADWP has only 1,000 MW of electric transmission capacity remaining unused and available to import replacement electricity from outside its system. This remaining import capability is useful, however, only if energy is available for purchase. LADWP also has a relatively small amount of additional generation capacity it may be able to obtain from its Castaic hydroelectric pumped storage facility. This pumped hydro resource can be used only if LADWP has advance notice so that it can pump water up to use for generation the following day. Last, LADWP has some additional transfer capability with the California ISO that may be able to replace a portion of LADWP’s own gas‐fired generation but the quantity would depend on whether the California ISO has excess energy available and the ability to transmit it to the tie with LADWP. In sum, LADWP has limited capability to shift load away from its gas‐ fired resources. The closing hour for day‐ahead wholesale electricity markets and the time needed to pump water into Castaic mean that the shorter the notice it receives from SoCalGas that it needs to reduce its gas demand, the fewer these options become.

Risk Assessment
The Aliso Canyon Action Plan Entities32 began in December to discuss the threats to gas and electric reliability that could arise without the ability to withdraw from Aliso Canyon. The technical analysis revealed that Aliso Canyon is needed to meet high core gas demands that occur in the winter months, along with high electric generation demand in the summer months. Moreover, SoCalGas uses Aliso Canyon to balance its system on a daily and hourly basis, throughout the year. Aliso Canyon is critical is due to location within the L.A. Basin, where it is close to SoCalGas’ key loads and is connected to the lower pressure local transmission system in the Basin.

The initial assessment focused on winter 2016 and how much gas might be needed from Aliso Canyon during cold weather events, reflecting the critical need to protect gas service reliability for core customers. As the Aliso Canyon Action Plan Entities understood how frequently and precisely how SoCalGas uses Aliso Canyon, reliability risks in both winter and summer became clear. It is likely that using the gas remaining at Aliso would reduce those risks, but as yet it remains unknown how the reconfigured field, as safety inspections are completed, will perform. The winter 2016 and summer 2016 analyses are described below. Winter 2017 is discussed only at a cursory level and requires additional analysis before conclusions can be reached.

31 See p. ES‐5 of LADWP’s 2014 Integrated Resource Plan. The Energy Commission’s 2016 Integrated Energy Policy Report showed a 1‐in‐10 day summer peak load forecast for LADWP of 6,712 MW. See California Energy Demand Revised/Final Forecast, 2016 ‐ 2026, Mid Demand Baseline Case, Mid‐AAEE Savings, Form 1.5d. 32 The detailed Risk Assessment compiled by the Technical Assessment Group (consisting of the Aliso Canyon Action Plan Entities staff members plus SoCalGas) Aliso Canyon Action Plan Entities is contained in the detailed technical report include in the Appendix to this Reliability Action Plan. 898 of 983
19 Winter 2016 (With Some Overlap Into Summer)
SoCalGas began withdrawing gas from Aliso Canyon in November 2015, after the leak was detected at well SS‐25. SoCalGas increased those withdrawals in December, with the onset of colder weather and with the goal of pulling as much natural gas as possible out of the storage field to reduce the operating pressure of the field.33 DOGGR directed SoCalGas not to inject any gas into the storage field until a safety review of the facility is completed. With the inability to inject and the field inventory declining, the agencies looked carefully at how much gas was needed – specifically from Aliso Canyon ‐ to prevent gas service curtailments with the onset of cold weather. The February 16 preliminary analysis noted that, if withdrawals were to continue at the late‐December pace, the field would be empty by mid‐ February. This would have left no gas in the field for withdrawal in late winter. With no ability to inject, there would be no gas in the field for the upcoming summer.

Winter reliability requirements focus on making sure the utility has enough capacity and supply to meet projected demand on extreme cold days. As discussed, SoCalGas forecasts gas demand under 1‐in‐ 10 and 1‐in‐35 year conditions and plans to meet those extreme condition demands with a combination of supply flowing through the backbone transmission system and gas from storage.34 Core customers receive the highest level of protection due to the criticality of home heating, along with the cost of restoring service after an outage. SoCalGas projects that demand on an extreme winter peak day will be

5.3 Bcf. As explained, the expectation is that about 3 Bcf of flowing supply will be available from the interstate pipelines into SoCalGas’ backbone transmission system. That means that all the remaining supply needed to serve demand above 3 Bcf must be met by storage.

CPUC Decision 07‐12‐019 determined that SoCalGas would need a total storage withdrawal of 2.292 Bcf to meet the 1‐in‐35 demand for core customers served by SoCalGas, SDG&E, plus Southwest Gas and City of Long Beach. Of that, 1.65 Bcf could come from the combination of SoCalGas’ other three storage facilities (that is, Honor Rancho, La Goleta and Playa de Rey). This leaves 0.642 Bcf as the remaining supply needed to reach the total required from gas in storage under these system design conditions.35 This gas can come only from Aliso Canyon.

Gas is withdrawn from storage under natural pressure. The withdrawal capability from the gas field declines as inventory declines, because lower volume in the field results in lower pressure. The preliminary analysis acknowledged SoCalGas’ estimate of the relationship between inventory and withdrawal pressures. From this estimated relationship, the Aliso Canyon Action Plan Entities agreed that 5 Bcf of inventory was needed to assure the ability to pull 0.642 Bcf from Aliso Canyon on any given day. SoCalGas further indicated it was concerned that the leak mitigation efforts (that is, the attempts

33 This was to reduce the rate at which gas was leaking from the field and to reduce the field pressure that attempts to kill the well from the top needed to overcome. 34 The term 1‐in‐10 represents the coldest condition expected to occur once in 10 years and is used for planning capacity needed to serve noncore customers. Similarly, 1‐in‐35 represents the coldest condition expected to occur once every 35 years and is used for planning capacity needed to serve core customers. 35 In 2007 when this withdrawal capability was adopted, peak winter demand was forecast to total 5.58 Bcf, higher than the current forecast. This forecast is due to a general decline in peak natural gas demand. 899 of 983
20 to “kill” the well from the top) could have degraded the performance of the field. This possibility reinforces the need to keep 5 Bcf in the field.

The Aliso Canyon Action Plan Entities added 10 Bcf, for a total of 15 Bcf to be retained in the field. This additional 10 Bcf was based the amount of gas needed from Aliso during the remainder of the winter if the weather and demand experienced in 2015 was repeated in 2016 and all other facilities were operated at their maximum. It was determined that about 4.1 Bcf would be needed. The same approach was used to determine the requirement from Aliso for June through October 2016 that maximum use of all facilities and a repeat of 2015 summer weather. An estimated 4.9 Bcf was indicated. While 2016 weather will not be identical to that of 2015, this additional volume was left in the field to account for the fact that some gas would be withdrawn on peak days but volume and pressure must be maintained for future high demand days.

These findings culminated in an order from CPUC Executive Director Timothy Sullivan that directed SoCalGas to withdraw natural gas from Aliso Canyon down to an “actual working gas inventory” of 15 Bcf. This translates to a 20 Bcf volume reported on Envoy™, less the 5 Bcf estimated to have leaked.

Sullivan further directed SoCalGas to hold the gas inventory at this level to meet “energy reliability requirements.” As discussed in the CPUC’s February 16 “Preliminary Analysis,” three general risks are addressed by holding this level in inventory: a) the inability to rely solely on flowing supplies to meet peak demand; b) the operational uncertainty about how the field will perform at such a low inventory level; and c) the need to use some gas from storage during the summer.

Summer 2016
With the 15 Bcf reserved, the Technical Assessment Group conducted a more detailed look at reliability planning for summer 2016. The preliminary analyses behind the recommendation to hold inventory at 15 Bcf allowed for SoCalGas to withdraw as much gas to support electricity generation demand this coming summer as it did during summer 2015. Granted, summer 2016 weather may not be the same as that of summer 2015’s, but it offers some protection. In addition, those analyses, were based on a straightforward comparison of daily demand to daily supply. In preparing the subsequent more detailed risk assessment for summer, the Technical Assessment Group looked beyond the daily balance of supply and demand to perform an engineering analysis simulating operating pressures on the system and communication time schedules between the gas and electric industries.

The engineering analysis used the industry standard hydraulic model that simulates gas system operations, measuring flows and pressures within key pipelines, from an engineering perspective. 36 The model simulation estimates operating pressures on the SoCalGas system continuously using a series of differential equations for compressible fluids that calculate actual flows through a pipeline given design parameters such as size of the line, maximum operating pressure, and minimum acceptable operating pressure. It takes into account where gas comes into the system, where load is located, the pressure limiting stations, and other operating characteristics. The output tells the modeler when any of the key

36 The model is now owned and supported by international consultancy DNV‐GL. It is used by most gas utilities and pipelines and remains known to many in the natural gas industry as the Stoner pipeline simulation model. 900 of 983
21 operating parameters are violated. Such modeling is routinely used for system design. It is also used to determine if a large, new load can be accommodated successfully at a given location.

The Technical Assessment Group selected four specific days to simulate.37 These were days that were expected to stress the system and included days, particularly in the summer, when SoCalGas often relied upon stored gas from Aliso Canyon to follow hourly changes in electric generation gas demand that, left unmitigated, could create operating problems. The four were relatively high demand days, including days on which recorded demand for the California ISO and LADWP was high (September 16, 2014 and September 9, 2015), a day that reflected the largest change in hourly gas demand from electric generators (July 30, 2015) and a winter day on which electric generator gas demand was high (December 15, 2015). Demand on the summer days was close to what would be expected under SoCalGas’ forecast of summer high sendout days, but none were particularly extreme relative to SoCalGas’ peak demand for natural gas, which occurs in the winter.38 Operating assumptions included hourly demand, including hourly electric generation demand provided by California ISO and LADWP. The simulation limited flowing gas receipts from the pipelines to 3.5 Bcf per day, consistent with historical experience. The simulation assumed that no gas was injected or withdrawn at Aliso Canyon. The Technical Assessment Group agreed this assumption was reasonable because it remains unknown when the well inspections will be complete or what the ultimate withdrawal capability of the field will be. The analysis allowed 1 Bcf per day withdrawn from Honor Rancho. Playa del Rey withdrawals were held back and used as the sole tool left in reserve to fix any disruptions that might occur on the system within a given gas day. The initial simulation also allowed no planned or unplanned outages of any gas system equipment, such as compressors, valves, or wells.

Last, the simulation required restoration to normal operating pressures overnight. This assures that the gas system is not in a worse position the next day, which could lead to worsening outages on successive days.

The two higher demand days in the simulation showed that all demand could be met with no operating pressures or other conditions out of acceptable and safe tolerance; the simulation for the two lower demand days, however, did not. Under these simulated conditions, real‐time operators, seeing the pressures falling toward unsustainable operating levels, would trigger calls to curtail gas use. When the simulation failed to maintain operating pressure within tolerances it was for a single reason: gas flows into the system on those days did not match demand.39 In fact, day 3 (September 9, 2015) showed operating pressure problems when the difference between receipts and demand was only 0.25 Bcf per day. The pressures were lowest at the southern end of the LA Basin system, farthest from Aliso Canyon

37 The focus at this point is on reliability planning for summer 2016; planning for winter 2017 will introduce additional issues and will be addressed in the coming months. 38 More detail about the four days, the simulations and results can be found in the report of the Technical Assessment Group. Demand on the four days ranged from 3.19 Bcf to 4.02 Bcf. The biggest distinguishing feature was the relative difference between scheduled gas and actual gas demand across the four days. 39 The technical report explains how, with pressures dropping, particularly at Yerba Station, SoCalGas would be forced to choose between letting more gas into the LA Basin to preserve its operating pressures versus sending it south to San Diego.
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22 and even farther from Honor Rancho. Moreover, withdrawals from Honor Rancho were already at maximum in the scenario. Increased gas deliveries, if more gas were available, from the high pressure transmission pipelines could not reach the LA Basin system quickly enough to restore operating pressures. The result would require SoCalGas’ to call on customers to curtail load.

This result turns out to be down to about 0.15 Bcf per day.40 In other words, the biggest contributor to gas curtailments (assuming first that capacity is sufficient to meet daily demand) is a difference between what customers deliver into the SoCalGas system versus what they consume. As highlighted previously in this Reliability Action Plan, that difference can occur because customers are using the flexibility they are allowed between what they deliver into the system and what they use.

With these results in hand, the next questions are a) how often could there be a difference of 0.15 Bcf per day between flowing supplies and demand when total demand ‐ demand in general, under any temperature or weather condition ‐‐ exceeds 3.2 Bcf; and b) how would planned and unplanned gas facility outages modify this calculation (including potential days of overlap). Last is the most complex question to answer: How big does the gas curtailment have to be before LADWP and the California ISO would need to interrupt electric service to consumers?
The Technical Assessment Group used SoCalGas operating data to answer these questions, combined with SoCalGas’ analysis of capacity outage impacts under its 2016 maintenance schedule. The operating data are publicly available. The number of days which the difference between flowing supply receipts and demand was greater than 0.15 Bcf was 121. SoCalGas then estimated that planned outages to perform maintenance on gas storage facilities (other than Aliso Canyon) that would take more than 0.4 Bcf out of service over 97 days. Another 158 days are planned for maintenance that would reduce pipeline capacity by more than 0.5 Bcf. The number of days in a year on which all of these things could occur coincidently is 23. In other words, there are 23 days in the year where a supply/demand imbalance plus the combination of planned work on storage or pipelines would have a large enough impact to cause a gas load curtailment. The magnitude of the curtailment varies according to the exact conditions. Most of the planned outages would occur in summer, since summer is when gas utilities conduct most of their maintenance.

Unplanned outages, however, could occur at any time of the year. . Here the Technical Assessment Group looked at unplanned outages over the three years between 2013 and 2015. There were an average 21 days per year on which storage withdrawal capacity was reduced by more than 0.4 Bcf and 117 that reduced pipeline capacity by more than 0.5 Bcf. Some of these days overlap such that the average number of coincident days of unplanned outages is 9.

Layering the planned and unplanned outages on top of days with demand greater than 3.2 Bcf and assuming customers match their deliveries to within 0.15 Bcf of their actual demand, yields an estimate

40 The technical report describes in greater detail that the 0.25 Bcf translated to 0.15 Bcf after taking into better account the cut‐off at which the operators in Gas Control would institute curtailments to prevent the pressure from reaching minimum
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23 of 16 days this summer to expect gas curtailments, assuming no withdrawals of any of the 15 Bcf held at Aliso. Unless gas is withdrawn from Aliso, 14 of these days are likely be large enough to interrupt much of the generation located in the LA Basin, affecting both the California ISO and LADWP. In sum, the risk of curtailment exists when combinations of following occur:
 Scheduled gas does not match actual gas demand.
 Pipeline outages reduce delivery capacity.
 Outages at the SoCalGas’ other storage facilities reduce remaining storage capacity.

For ease of reference, the number of curtailment days and related causes are summarized in Table 6.

Table 6: Identifying Risk of Natural Gas Curtailment and Electricity Service Interruption (Using None of the 15 Bcf from Aliso)
Description Number of Days
in Summer
Mismatch between scheduled gas receipts and actual gas demand of 0.15 Bcf 2 Mismatch of 0.15 Bcf plus Planned Outages at Non‐Aliso Storage Facilities with impact greater than 0.4 Bcf
2 Mismatch of 0.15 Bcf plus Planned Outages of pipeline capacity with impact greater than 0.5 Bcf
9 Days the storage and pipeline work could occur coincidently (for total impact of

0.9 Bcf)
3 Total 16
Number of days in which gas curtailments are too large for California ISO and LADWP to remedy (aka days of risk of electric service interruption) 14 Source: Technical Assessment Group Analysis
Winter 2017 and Longer‐Term
Planning for winter 2016 and summer 2016 have been the top priorities. With those analyses completed, the Aliso Canyon Action Plan will turn to longer‐term analyses involving winter 2017 and beyond. Much of the impact beyond this summer will depend on the well inspection results, the possible return to injection capability as wells are found to be safe, and other regulations that might be adopted by DOGGR.

At this point, the team anticipates the analysis above, which combines hydraulic gas flow modeling with days of outage impact, will raise similar concerns about gas curtailments and electricity service interruptions as raised above. Other issues to consider include uncertainty about if reinjection at Aliso Canyon will be allowed and what the injection and withdrawal volumes allowed will be. There should be no doubt that winter reliability will be threatened if all or part of the 15 Bcf now held at Aliso is withdrawn and cannot be replaced before winter. The degree to which it will be threatened, however, is yet to be determined and will require the Aliso Canyon Action Plan Entities to perform additional assessments to determine how much gas SoCalGas will have available to deliver to customers throughout the winter and particularly on a cold day. Honor Rancho will provide some incremental gas 903 of 983
24 supply, but the fundamental issue of too little gas being available to follow load in the LA Basin will remain as long as Aliso Canyon operations are uncertain.

Mitigation Measures
The Aliso Canyon Action Plan Entities have identified and propose implementation of 18 measures to reduce the need for and magnitude of natural gas curtailments. Some of these mitigation measures have already been implemented; for others implementation is still under consideration, while several more are held on “standby” for later implementation, if needed. The measures can be grouped into five general categories: Prudent Use of Aliso Canyon; Tariff Changes (both state and federal); Coordination; LADWP Operations; and Reducing Natural Gas and Electricity Use. Each of these is discussed below.

Prudent Aliso Canyon Use
Use the 15 Bcf at Aliso Canyon to Prevent Summer Electricity Interruptions: Of the roughly 15 Bcf of gas stored at Aliso Canyon under CPUC Executive Director Sullivan’s January 21 direction, 10 Bcf was designated for withdrawals to maintain reliability for core customers and limit curtailments to noncore customers (some of whom are gas‐fired electric generators). The 10 Bcf designation assumed that as much as 5 Bcf would be needed to maintain reliability should 1‐in‐35 conditions occur through the remainder of the 2015/16 winter season (at the time, the last of January and the months of February through March). Five Bcf was reserved for use during the summer. Due to favorable weather conditions this winter, no withdrawals have been made since the Executive Director’s order and the 10 Bcf remains available for reliability‐based withdrawals. 10 Bcf is more gas than was withdrawn from Aliso Canyon for reliability purposes in the summer of 2015. If noncore customers and SoCalGas can closely match their scheduled gas with actual demand, there are no prolonged heat waves, and there are no prolonged unexpected outages of the backbone pipeline transmission system, the 10 Bcf could be enough to meet demand this summer. SoCalGas needs to provide the CPUC with detailed plans and procedures detailing how it will use the 15 Bcf to prevent summer electricity interruptions.

The Aliso Canyon Action Plan Entities have not yet focused on detailed planning for next winter.

However, it appears based on the summer analysis, the winter demand forecast, and the gas reserve margin analysis in Table 3, maintaining reliability next winter with only 15 Bcf at Aliso Canyon could pose a significant challenge. What is known now about the well inspection plan suggests some ability to reinject is likely to occur at some point this summer but it remains unclear how much SoCalGas would be able to reinject or how the operating characteristics of the field may change the maximum daily withdrawal capability. Because of the uncertainty about reinjection for winter and what exact withdrawal capability might exist as the inspections progress, SoCalGas has not committed to using any of the gas at Aliso Canyon this summer.

The Aliso Canyon Plan Entities therefore propose clear direction be given to SoCalGas to use the 15 Bcf this summer to the extent needed to prevent electricity interruptions. By planning to use that gas when curtailments of gas service to electricity generators would be large enough to cause electricity service interruptions, the entities can prolong the benefit of the gas held in storage and help prevent the 904 of 983
25 economic damage and public safety risk associated with electricity interruptions. Implementing this measure may require developing rules for triggering events.

Efficiently Complete the Required Safety Review at Aliso Canyon to Allow Safe Use of the Field:

Governor Brown’s emergency proclamation states that SoCalGas may not inject any gas into the Aliso Canyon Storage Facility until a comprehensive review, using independent experts, of the safety of the storage wells and the air quality of the surrounding community is completed. This safety review, developed in consultation with independent experts from Lawrence Berkeley, Lawrence Livermore, and Sandia National Laboratories requires each of the 114 wells of the facility to undergo a battery of tests to confirm the safety and integrity of the well or to remove the well from service and isolate it from the underground reservoir. No new gas injections will be allowed until all 114 wells have either passed a comprehensive set of tests or been taken out of service and isolated from the underground reservoir.

SoCalGas, in consultation with DOGGR and its independent experts, plans to take all wells out of service and isolating groups of them from the underground reservoir. Then, as SoCalGas completes the well inspections, it can bring a small group of wells that have passed the safety and integrity inspection back in service. This approach would allow Aliso Canyon to return to service in a limited capacity sooner than if all 114 wells were inspected before any are returned to service. The Aliso Canyon Action Plan Entities eagerly await information about which wells will be able to withdraw, how much natural gas can be withdrawn, and when so that the entities can incorporate that information into the Reliability Action Plan as it is revised and updated.

Tariff Changes
Implement Tighter Gas Balancing Rules: The current balancing rules for gas transportation service allow shippers (that is, noncore customers and marketers) a tolerance band on the difference between what they delivery into the L.A. Basin and what they actual use so that they don’t have to balance delivery and usage on a daily basis. Instead they are allowed to balance supply and demand on monthly basis with a 10 percent margin of error on their monthly demand, with the difference made up the following month at zero penalty. These monthly balance rules mean SoCalGas must with draw or inject gas into storage on days when the noncore customers do not match their supply and demand. With Aliso Canyon unavailable (except for withdrawals to maintain system reliability), the gas system has much more limited ability to balance differences between shipper deliveries and actual customer load.

The Technical Assessment Group’s hydraulic models found that even relatively small imbalances can reduce operating pressures during the gas day sufficient for Gas Control to call for curtailments.

The Aliso Canyon Action Plan Entities therefore recommend moving away from the monthly balancing with the 10 percent tolerance and replace it with something tighter 41 The hydraulic modeling by the Technical Assessment Group shows that SoCalGas does not have the ability to support 10 percent monthly balancing while it cannot routinely use Aliso Canyon. It is essential

41 SoCalGas, with its affiliate San Diego Gas & Electric Company (SDG&E), filed a motion with the CPUC in an application they already had pending (Application No. 15‐0‐020), to implement this mitigation measure. 905 of 983
26 to get help from all shippers – who have not created the problem at Aliso Canyon ‐ by asking them to match their actual usage very closelywith their scheduled delivery quantities so that the gas system can avoid curtailments. The Technical Assessment Group estimates there still will be some days where even a 5 percent difference between deliveries and burn will result in gas service curtailment. If shippers, in aggregate, cannot successfully balance deliveries with their consumption, the number of days of estimated gas curtailment and/or the need to withdraw gas from Aliso Canyon would increase.

Modify Operational Flow Order Calculation: On December 1, 2015 SoCalGas implemented a new rule, approved by the CPUC in D.15‐06‐004 to call a “low” OFO. An OFO directs shippers to get into balance; low OFOs occur when customers have scheduled too little gas to meet their requirements. SoCalGas normally pulls from storage the gas needed to cover customer imbalances, when the imbalance is larger than the storage withdrawal capability available, however, SoCalGas calls an OFO, which requires customers to step in, use a subsequent scheduling window to correct their nomination and thereby remedy their imbalances themselves
The quantity of storage provided by Aliso Canyon is zeroed out in the calculation, reflecting the fact that Aliso Canyon is not available to help provide balancing service. The Aliso Canyon Action Plan Entities are concerned , that the current tariff rule and related storage‐based calculation apply system‐wide, taking into account all of SoCalGas’ storage. As discussed in this Action Plan, the storage on the rest of SoCalGas’ system is mostly irrelevant to providing balancing service within the L.A. Basin. Thus, the current calculation could trigger or not trigger an OFO but might not capture all instances in which an imbalance causes low operating line pressures within the L.A. Basin that could trigger curtailment. .

Until the gas and electric utilities have operating experience with the daily balancing rule, the Aliso Canyon Action Plan Entities suggest placing this mitigation measure on a “stand by” list and watch for conditions that might call for re‐opening the discussion.

Call OFOs Sooner in the Gas Day: This is another measure the Aliso Canyon Action Plan Entities suggest holding on the stand by list as daily balancing may make it unnecessary. SoCalGas does not know how much difference there might be between supply into its system versus deliveries to customers (that is, receipts versus sendout) until late in the afternoon before the next gas day. If other indicators could be developed, SoCalGas could use those indicators to trigger OFOs sooner. The earlier that notice can be given, the more the options that LADWP and California ISO will have to modify gas‐fired generation. The difficulty in implementing this measure, however, is that it is not clear SoCalGas would have the information actually needed to call an OFO sooner in the gas day. OFOs are called once there is a problem, while daily balancing is aimed at preventing a problem. The Technical Assessment Group thought daily balancing was easier to implement and more certain.

Provide E Dispatch Information Prior to Cycle 1: Today, generators must nominate and schedule their natural gas before the California ISO releases its day‐ahead market awards. This requires gas‐fired generators to essentially guess what their gas use will be. California cannot change the gas schedule; the gas nomination windows are set on a nation‐wide basis and are passed up the natural gas supply chain, across pipelines and time zones. But the Aliso Canyon Action Plan Entities believe that giving 906 of 983
27 generators guidance about likely dispatch before they schedule their natural gas with the gas utility, pipeline, and supplier can help reduce some of the guessing and ease compliance with daily balancing.

The California ISO is therefore considering how it could provide dispatch information to inform the generators prior to the “timely,” or first, window to nominate gas for the next day.42 This information will give generators a better idea of whether they will be dispatched, which allows them to predict their gas use with less error. This mitigation measure should help reduce the variance between nominations and actual burn. This information is in “Beta status” and is being tested with the gas utilities. The report is being fine‐tuned through modifications to the forecasting process and it is expected to take a couple months to achieve a level of consistent quality. Expansion of this new process will require ISO tariff and Business Practice Manual changes that must be approved by the Federal Energy Regulatory Commission.

Consider CAISO market changes that increase gas‐electric coordination in response to Aliso Canyon43:

The CAISO has initiated a stakeholder process to consider market changes that may be necessary in response to the Aliso Canyon issue and to reduce the risk to reliability. This expedited initiative is considering if timing of the day‐ahead market or other information prior to the gas nomination cycle could better align gas procurement with electric generation needs. Also being considered are change to the real‐time market that may be necessary to constraint the real‐time dispatch around day‐ahead results to minimize gas use changes from day‐ahead expected levels. Lastly, compensation and bidding rules changes that may be necessary to could improve ISO’s ability to better model and compensate resources for the higher costs associated with committing or dispatching resources subject to proposed gas balancing rules.

Operational Coordination
Increase Electric and Gas Operational Coordination: Recognizing the increasing interdependence between the gas and electric systems, the California ISO and SoCalGas have, over the past five years, made significant strides to improve the quantity, content and timing of communication to coordinate between electricity and gas operations. For example, SoCalGas is using the California ISO’s notifications that restrict maintenance on the electric system to help inform SoCalGas of areas where maintenance may be limited or modified. Furthermore, the California ISO receives notice of operational flow orders from Pacific Gas and Electric Company (PG&E), Kern River and SoCalGas, thereby enabling the California ISO to assess grid conditions during times of gas system strain and to take measures to ensure reliable operation of the electric system. With this information, the California ISO can compare pipeline operators’ operational flow orders with outages and constraints on transmission lines and generation locations to assess whether the operational flow order could adversely impact grid reliability. The California ISO also presents SoCalGas operators with daily forecasted gas burn information, based on Day Ahead Market awards. This lets SoCalGas know what level of electric generation gas use to expect and allows it to compare what it sees happening on its system with what the day‐ahead awards led it to

42 Known as “Cycle ,” among the four traditional gas day scheduling windows. A fifth window, or cycle, is added at the end of the day beginning April 1.
43 http://www.caiso.com/informed/Pages/StakeholderProcesses/AlisoCanyonGasElectricCoordination.aspx 907 of 983
28 expect. SoCalGas and the California ISO communicate in real time when significant challenges are anticipated, when weather changes occur, or when changes are seen in gas consumption patterns. The California ISO will also develop a forward‐looking report that reflects gas burn rates two days in advance of operating day, enabling the gas companies to anticipate upcoming changes in gas flows and best prepare for them.

Further, the California ISO implemented an Operating Procedure for Gas Transmission Pipeline Outages or De‐rates, which formalizes the communication between the California ISO and SoCalGas during challenging events, as well as examines how each entity proactively addresses changing conditions. This procedure was a key component in a table top exercise held between thee California ISO and SoCalGas on March 2, 2016, in anticipation of summer challenges made evident by the Aliso Canyon constraints.

The California ISO will hold a follow up table top exercise that includes LADWP before the summer.

Moreover, the California ISO will regularly monitor both SoCalGas’ Envoy™ and PG&E’s Pipe Ranger gas pipeline notification systems as well as the interstate pipelines for operating condition information that could be relevant to system conditions in California.

LADWP also monitors gas supply conditions and has responded to SoCalGas operational flow orders.

Starting last summer during a period of gas curtailments, LADWP interacted with SoCalGas and the California ISO and is working cooperatively with them to better coordinate gas fuel usage and system planning. Armed with this information, LADWP can better forecast and plan its resource utilization for the upcoming day. LADWP now provides to SoCalGas a day‐ahead forecast of the gas it expects to burn each hour at its in‐basin generators for high load days. It is looking to automate this process and provide it every day and potentially expand it to a two‐day‐ahead forecast. These forecasts are presented in an hourly usage format. LADWP will also monitor the SoCalGas EnvoyTM notification system. LADWP and California ISO will continue and expand their joint emergency training to improve operator knowledge and improve coordination under normal and emergency conditions. LADWP and SoCalGas plan additional table‐top exercises as well.

For summer 2016, California ISO and LADWP will also look at how they can coordinate during gas curtailment events as well as electricity contingency events. There must be clearly defined rules of the order of curtailments. In an electricity contingency event, gas‐fired contingency reserves may need to be called upon to meet demand. Natural gas will need to be available for these gas‐fired contingency reserves or other reserves or sharing will be needed. The California ISO and LADWP are still discussing whether alternatives need to be found to relying on gas‐fired generation to satisfy electric contingency events. One alternative might be to rely more on in‐basin generation and hold out‐of‐basin generation in reserve.

Establish More Specific Gas Allocation among Electric Generators In Advance of Curtailment: The Reliability Aliso Canyon Action Plan Entities propose that SoCalGas work with the California ISO and LADWP to develop a more specific and clear procedure for allocating a gas curtailment among generators so that they are agreed upon and known in advance Both prefer that the procedure be worked out in advance rather than working them out on the day of curtailment, while SoCalGas prefers 908 of 983
29 to leave as much flexibility as possible to tailor the allocation to exact system operating conditions.44 The June 30, 2015 gas curtailment left many parties, including the, CPUC, the Energy Commission, the California ISO and LADWP with questions about how the determination was made that day about which generators should cut usage, by how much they should do so, and whether their minimum generation reliability requirements were taken into account.45 A procedure needs to be created to clarify how a gas curtailment would be spread among electric balancing authorities and/or generators so that minimum generation requirements are satisfied and so that the balancing authorities can plan for how much gas‐ fired generation to replace. This more specific set of curtailment procedures may require CPUC approval.

Determine if Any Gas Maintenance Tasks Can Be Safely Deferred: The 2010 gas pipeline explosion at San Bruno that killed eight people resulted in requirements from both state and federal regulators (i.e., the CPUC and the U.S. Pipeline and Hazardous Materials Safety Administration) to enhance the safety of the natural gas system. Pursuant to these requirements, SoCalGas has several programs to perform maintenance, testing and pipeline and valve replacement work. The main two programs are Pipeline Safety Enhancement Plan (PSEP) and Transmission Integrity Management Program (TIMP). Projects under PSEP and TIMP are performed throughout the year, but the most busy months are in the summer when the weather permits to perform construction work and the gas demand is typically at its lowest.

Last year, a key pipeline was out of service for PSEP maintenance during a summer heat wave that reduced electricity imports. SoCalGas was unable to supply enough gas and therefore electric generation was curtailed, while both LADWP and California ISO scrambled to find replacement power. In this instance, curtailment was necessary even though Aliso Canyon storage facility was in service. Without Aliso Canyon, these types of situations may become frequesnt in the summer if major pipelines are taken out of service as well.

SoCalGas has been directed to file the list of projects that SoCalGas believes it needs to defer in order to ensure reliability. The CPUC will evaluate, through a public process, the deferred projects to understand safety risks and mitigate them as necessary.

Maximize LADWP Operational Flexibility
LADWP has implemented three actions designed to maximize its operational flexibility this summer.

These measures will position LADWP to respond quickly and without encumbrance should gas curtailments to its electric generation facilities be required. These actions impose significant cost on LADWP and its customers.

Curtail Physical Gas Hedging: LADWP would normally have purchased physical gas hedges, which consist of commitments to take a given quantity of gas supply at a price that is fixed and agreed upon in advance. LADWP instead will not enter into agreements to take any fixed quantity of gas and will not

44  The Aliso Canyon Action Plan Entities appreciate the tension between implementation flexibility and locking down the detailed procedures in advance.
45  An Appendix to the Technical Report describes the June 30‐July 1 curtailment in greater detail. 909 of 983
30 receive the benefit of the price being locked down in advance.  This will enable LADWP to vary its gas burn without worrying about needing to take some gas each day or risk violating a physical gas purchase agreement.

Stop Economic Dispatch: this action halts economy dispatch sales of energy to other market participants. These sales typically occur when LADWP is able to generate electricity at a lower cost than others; the sale represents an economic benefit to both LADWP and the electricity buyer. Those buyers will now have to buy more costly electricity instead of buying from LADWP and LADWP will no longer benefit from a sale.

Curtail Block Energy and Capacity Sales: Agreements to sell blocks of energy or capacity would have been entered into as commitments to use LADWP’s power plant capacity to generate electricity and sell energy or capacity to others. A simple example would be LADWP agreeing to sell 10 MW of output to some buyer in December at some price negotiated between LADWP and the buyer. Again, such agreements would have been used where LADWP had capacity and ability to generate at a price that would have produced benefits to both parties. LADWP is foregoing these block energy and forward capacity sales so that it will retain flexibility to reduce its generation when it needs to curtail gas use.

Reduce Natural Gas and Electricity Use
Use New and Existing Programs Asking Customers to Reduce Natural Gas and Electricity Consumption:

The Flex Alert program has been used to encourage consumers to reduce electricity usage. It played a key role in reliability planning after the San Onofre closure and prior to that, in the 2000‐2001 energy crisis. Because any reduction in energy consumption can help reduce the need for or magnitude of service interruptions that might otherwise be needed, the Aliso Canyon Action Plan Entities recommend deploying the Flex Alert program as long as Aliso Canyon is not fully available.

The California ISO took over administering and funding the program beginning in 2016. It owns and operates the Flex Alert call list, the program brand, and the website. To deploy the program now, the CPUC issued a proposed decision on March 14 directing SoCalGas to provide $15 million to fund energy conservation advertising including Flex Alert. The CPUC aims to issue a final ruling on this matter by May.

Using less natural gas is also important. There is no program analogous to Flex Alert for natural gas conservation, so a portion of the funding provided by SoCalGas will be for natural gas conservation messaging. Care will be needed in determining how to message electric and gas conservation efforts to minimize customer confusion. Other marketing campaigns need to be developed to stress to customers that the issues at the gas storage facility are the driving the requests for energy conservation. The campaign should be a joint effort of SoCalGas, LADWP, other local utilities, local governments, and state agencies. The campaign should be focused not just on paid media but must make use of community based organizations an dsocial media.

Expand Gas and Electric Efficiency Programs Targeted at Low Income Customers: An Assigned Commissioner’s Ruling issued on March 14, 2016 directs SoCalGas and Southern California Edison (SCE) 910 of 983
31 to prioritize near‐term natural gas and electric savings through their Energy Savings Assistance (ESA) Program efforts in low‐income communities affected by the Aliso Canyon Gas Storage Facility leak. The ruling also contemplates several potential changes to the existing ESA program activities to increase energy savings in the impacted communities. In Los Angeles, LADWP offers electric savings in combination with SoCalGas’ mandated ESA program to reach low‐income customers.

Expand Demand Response programs that Target Air Conditioning and Large Commercial Use: A number of the demand response (DR) efforts instituted with the loss of San Onofre in 2012 continue to be in place today. New demand response reporting templates have been developed to allow the California ISO to better plan for grid requirements in the summer, the demand response offerings in the region have been enhanced with new DR programs including SDG&E’s US Navy Demand Bidding Programs, and SCE instituted improvements to its air conditioner cycling program. Finally, demand response was included as a preferred resource in a Commission Decision that authorized SCE to solicit procurement of electric capacity in the areas impacted by San Onofre. Beyond these efforts the DR program administrators and the CPUC should and are pursing the following program changes focused on the LA Basin.
 Encouraging increased customer participation and potentially providing addition funding for SCE’s Base Interruptible, residential and non‐residential AC Cycling and Agricultural Pumping Interruptible programs ;
 Conducting a custom Demand Response Auction targeted at the areas most impacted by the gas leak, or adjusting the scope of the current 2017 Demand Response Auction and  Accelerating implementation of Assembly Bill 793 (Quirk, Chapter 589, Statutes of 2015) in affected areas by offering rebates to customers for the purchase and installation of smart programmable thermostats, combined with enrollment in an SCE DR tariff or load control program.

Focus and Reprioritize Existing Energy Efficiency Toward Projects with the Potential to Affect Usage this Summer and Coming Winter: Given the number of changes that are already underway with energy efficiency programs and the time it takes for program implementers to develop the infrastructure needed to roll out new efficiency measures it is unlikely that major program changes beyond what is already in the pipeline will have major impacts on gas or electric demand this summer. However, there are likely some benefit and little risk to accelerating programs that are under development and projects that are in the pipeline such that they will have more savings impact by this summer or by the winter of 2016. CPUC staff is coordinating with SCE and SoCalGas energy efficiency staffs to identify large projects that could be expedited to come on line to reduce peak electric demand for SCE by this summer and end use gas demand for SoCalGas by next winter. These efforts should include providing more staff with the program administrators, and the CPUC to speed approval of projects under development, provide increased incentives to efficiency providers who can install new measures before the end of 2016, and work with local governments to prioritize any necessary permitting.

In Los Angeles, LADWP is adding new components to its existing portfolio of energy conservation programs, incentives and rebates that reach all customer groups, including residential, commercial, 911 of 983
32 industrial and institutional. Its 2016‐2017 fiscal year budget for energy efficiency programs is $178 million. These existing programs target commercial lighting, HVAC and industrial process load, rebates for and replacement of appliances for residential customers, including the popular pool pump rebate program and replacement of old refrigerators for low‐income customers. New programs that will be available by the summer include residential and commercial air‐conditioning tune‐ups, residential light emitting diode (LED) lamp replacement and rebates to reduce home lighting load, and behavior‐based energy conservation programs. LADWP is also working with the Los Angeles Unified School District (LAUSD) to implement energy savings measures at schools under a three‐year memorandum of understanding with LAUSD.

Reprioritize Spending in Existing Solar Thermal Program to Fund Projects Installable This Summer and by the End of 2017: The CPUC oversees a solar thermal program that provides rebates for solar water heating that generally replace gas heaters. The CPUC is working with solar thermal (solar water heating) rebate program administrators for rule changes to the solar thermal program that will focus immediate efforts on installations in the L.A. Basin that will result in fuel switch/gas savings. The CPUC’s Energy Division has already approved additional funding of the low‐income program incentive budget, which was exhausted, with funds from the general market program. Likely additional changes include:
increasing early‐stage incentive rates and moving additional funding from late‐stage incentive steps to early‐stage incentive steps. The CPUC aims to have these program changes in place by June.

In Los Angelese, LADWP offers financial incentives for solar PV for both residential and commercial customers and has taken steps to reduce approval times for solar system installations.

Next Steps
Implementing the Aliso Canyon Action Plan requires several follow‐up steps besides those noted above.

Those additional steps include:
 Developing and tracking the milestones to continue implementation of the Action Plan.  Updating reliability risk assessments and adjusting the action plan as well testing plan unfolds and results potentially allow changes to injection and withdrawal capability.  Preparing risk assessment analysis for Winter 2017 Reliability.  Preparing analyses on long‐term storage viability, including reliability impacts if DOGGR adopts statewide a rule limiting injections and withdrawals to tubing.

Conclusion
The Aliso Canyon Action Plan Entities developed an action plan to address risks to natural gas and electricity service during the time that Aliso Canyon operations are constrained. The plan entities found a need first, to maintain inventory at 15 Bcf through the end of winter and into summer, withdrawing only as needed to augment flowing supply coming into the SoCalGas system via pipeline during critical times.
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33 A more detailed analysis consisting of an engineering assessment confirmed Aliso Canyon to be an integral part of the southern California energy system, both for reliable natural gas service and reliable electricity service. The limited current operations of the facility create a possibility of electricity service interruptions in the coming summer months. Without any gas supply from Aliso Canyon, there are 14 days this coming summer during which gas curtailments could be high enough to cause electricity service interruptions to millions of utility customers. Factors leading to gas curtailments, even on days with only moderately high demand, include differences between gas scheduled and received into the SoCalGas system (receipts) versus actual customer demand (sendouts) as small as 0.15 Bcf; gas storage and pipeline maintenance work planned for this summer, and unplanned outages.

The Aliso Canyon Action Plan Entities have developed 18 mitigation measures, grouped into five categories. Some measures are for implementation as soon as possible; a few are to hold in case they are needed later. The sooner the facility can safely be brought back online, the lower the risk to gas and electric reliability. Until then, the actions described above will reduce the risk to reliability, though they will not eliminate it.
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February 15, 2022

Agenda item 8c. Grayson

Dear Mayor Devine and Councilmembers Agajanian, Brotman, Kassakhian and Najarian,

I support the GEC’s position. It is futile and fiscally irresponsible to refurbish or purchase equipment to produce fossil fuel. The climate crisis is mushrooming at a terrifying rate, a situation that is continuing to escalate.

The City of Glendale has taken significant steps to convert our energy portfolio to cleaner technology. However we have not followed up with “aggressive pursuit of renewable energy alternatives at every opportunity” -- in fact, elimination of fossil fuel has progressed in fits and starts and now we face the 11th hour in the life of obsolete and aging gas engines. Why didn’t the Grayson decommissioning process and replacement with clean energy begin in earnest earlier so we can now get by with much less than 93 MW at Grayson or no gas at all?

The proposed multimillion dollar investment in Grayson to address the city’s energy needs for peak demand/emergency at 14 percent is unbelievable. If the City is willing to live with such a costly and damaging and almost useless ‘insurance policy’ then total elimination of Grayson is achievable.

You cannot say “we’re only a small part of the world so what we do at Grayson doesn’t matter that much”. We can’t continue to pollute, increase the risk of disease, and throw good money after bad.

Tonight’s meeting outcome must come with conditions:

1. Immediate creation of a GWP Zero Carbon Action Plan with clear interim target dates for each step leading to a 100% clean energy grid by 2030. I realize we are confronting fast changing technology, transmission issues, cloudy skies, a multi-year horizon, etc, etc. However, our ‘good intentions’ need to be memorialized in a plan, the city must hold itself accountable for delivery dates and progress must be regularly disclosed to the community.

2. Resolve the VPP issues and pursue rooftop solar and solar farm sites.

3. Create a community Advisory Taskforce representing residents, landlords, small and big business, and environmental advocates specifically for this issue. GWP, the GEC, and stakeholders have to work together to coordinate efforts on both public and private property and help educate the entire population of Glendale in a just and equitable way.

4. Ensure formalized cooperation between Glendale’s leaders and the leaders of adjacent communities to ensure reliable transmission and sharing of resources. We’re all breathing the same dirt coming out of Grayson.

The GWP Commission succumbed to Alternative 7. The Sustainability Commission failed to decide.

We are counting on you to do the right thing tonight.

Arlene Vidor
Glendale resident
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1 Ghazarian, Renia
From: Garcia, Michael
Sent: Tuesday, February 15, 2022 11:30 AM
To: Ghazarian, Renia
Subject: FW: CEQA-historic resources and Grayson-
Categories: Printed, To Do, Last Communication
FYI.

Michael J. Garcia, City Attorney ● City of Glendale ● Office of the City Attorney 613 East Broadway, Room 220 ● Glendale, CA 91206 ● (818) 548-2080 ● Fax (818) 547-3402 ● [email protected]

The City Attorney’s Office is committed to serving the City’s legal needs during the COVID-19 pandemic. Consistent with guidance from the City, as well as county, state, and federal authorities, our attorneys and staff may be working remotely for an undetermined period of time. Please know that we are making every effort to respond promptly, but there may be some delays in our responses. Be assured that we are monitoring email and voicemail, and we will respond to your inquiry as soon as possible. Because staff may not receive regular U.S. mail or other deliveries during this period of time, please also e-mail copies of anything you send by regular mail and notification of the delivery. Service of process of court or similar documents must be made pursuant to prior arrangement with the attorney who appeared on your case. Finally, please ensure all communications include a telephone number where you can be reached.

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From: Catherine Jurca <[email protected]>
Sent: Tuesday, February 15, 2022 11:00 AM
To: Garcia, Michael <[email protected]>
Cc: DL City Council <[email protected]>; Golanian, Roubik <[email protected]>; Young, Mark <[email protected]>; van Muyden, Gillian <[email protected]>; Godinez, Christine <[email protected]>; Adjemian, Aram <[email protected]> Subject: Re: CEQA‐historic resources and Grayson‐

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Dear Mr. Garcia:

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2 I am grateful to Mayor Devine for her request. And thank you for this explanation of the City’s insupportable position that it can bypass Historic Preservation Commission review of the FEIR for a project that would lead to the demolition of a historic resource.

I agree that asking the HPC to certify the FEIR and adopt a Statement of Overriding Consideration under these circumstances is unwise. I didn’t write the Historic Preservation Ordinance. Obviously you didn’t do it with a power plant in mind. But that’s not what I’m asking for.

I’m surprised to hear you say that Chapter 15.22 was designed to prevent “inadvertent” demolition of historic resources. That was the point of adding “potential” historic resources to the HPC’s purview, for which the historic preservation community is grateful. But the point is also, obviously, to ensure that the City’s appointed body with expertise in historic preservation is given a chance in a public forum to weigh in on projects and environmental clearance documents when there are possible impacts to historic resources. That is the intent of the ordinance, and nothing less than HPC review of the project and the FEIR in advance of a City Council decision in this case will satisfy it.

I am, of course, assuming there will be no additional EIR for the demolition clearance application, for which the HPC has both decision-making and environmental review authority as clearly spelled out in the Code. If that is the case—that there will be a new EIR, where the HPC can discuss mitigation measures, etc. as part of its decision regarding the loss of a historic resource--then that would be an appropriate process as spelled out in the code and under CEQA. But I am thinking not.

The “Update” at the HPC meeting was a bait and switch, a fake review process for a long and complex EIR in a whirlwind powerpoint. The City had at least one caller who tried to get through, so it even violated public participation rules. I raised the obvious problems with the handling of the Grayson review at the meeting, in some detail. I have no idea why staff has pushed ahead, after those objections, rather than just bringing it back for a proper hearing at the HPC before going to Council. Why are you so afraid of an HPC review? That’s not a hint at some terrible smoking gun that the HPC would uncover. I literally don’t understand why the City has decided to handle the process in this way. My guess is it’s the bind the language of the ordinance puts you in, which makes everything tricky, obviously. Or possibly that staff doesn’t want another public airing of the bad behavior around their communication with the State Historic Preservation Officer. (If the goal was really to provide her with “more complete information,” surely that would have included the review prepared by TGHS; also, the repeated false assertion by attorneys that the SHPO found the Boiler Building not to be a historic resource, rather than the truth—she found it, based on the City’s incomplete evidence, not eligible for the National Register—had conse quences for the direction of City Council on December 15, 2020). Regardless, this work-around won’t do.

Please don’t waste more time. Abort, and take it to the HPC for its formal review and recommendation regarding the FEIR. Then, it goes to Council, and if Council decides to approve an alternative that involves demolition of the Boiler Building, it goes back later to the HPC for the demolition clearance application. The crucial difference is that the HPC’s obligation and responsibility for reviewing the environmental clearance documents for projects involving historic resources will have been fulfilled. If the City does this, I will be satisfied, and, more importantly, the clear intent of the Historic Preservation Ordinance will be satisfied. I can’t imagine anyone foolish enough to litigate on the basis of the weird technicality of HPC final environmental review authority in the Code.

Sincerely,
Catherine Jurca

adding cc to Mr. Adjemian, to insure this is in the record.

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3 On Feb 15, 2022, at 9:41 AM, Garcia, Michael <[email protected]> wrote:

Ms. Jurca:

Mayor Devine has asked me to respond to your email regarding the role of the Historic Preservation Commission (“HPC”) with respect to the Grayson Repowering Project (“Project”). You contend that the HPC must be the first body to review and consider approval of the Final Environmental Impact Report (“FEIR”) for the Project simply by virtue of the fact that the HPC will be asked to consider and approve a demolition clearance for the Grayson Boiler Building which is identified as a discretionary historic resource in the FEIR. That contention is erroneous factually and legally, and would be impractical for the reasons discussed below.

First, your assertion that the City is separating project review and environmental review is incorrect. The Council is being asked to certify the FEIR and give a project approval by selecting a project alternative for staff to move forward. There are multiple other approvals that will have to be issued for the Project to move forward, including Council approval of contracts, Council approval of a bond ordinance, issuance of air quality permits by AQMD and HPC’s issuance of a demolition clearance. However, the Council is the appropriate decision-making body in this instance. Indeed, CEQA Guidelines section 15356 defines a “decision-making body” as “any person or group of persons within a public agency permitted by law to approve or disapprove the project at issue.” The Council clearly falls within that definition since it must approve a Project Alternative, bonds, and contracts in order to move forward. The fact that the HPC must issue one of the required permits does not vest it with the sole authority to approve the FEIR for the Project. Thus, while the City must perform the CEQA review before issuing the demolition permit, this does not mean the body to issue the demolition clearance must be the first to consider the CEQA review if the demolition is just one of many discretionary permits a project must receive.

Second, the cases you cite to support your contentions - POET, LLC v. State Air Resources Bd. (2013) 218 Cal.App.4th 681 (“POET”) and Citizens for the Restoration of L Street v. City of Fresno (5th Dist. 2014) 229 Cal.App.4th 340 (“Citizens”) – are inapposite. In POET, the Court of Appeal held that the State Air Resources Board (“ARB”) improperly approved low carbon fuel standard (LCFS) standards while delegating the CEQA review to its Executive Officer. The court held that the ARB improperly split the approval authority with the CEQA review by delegating CEQA review to the Executive Officer. That is not the case here. The Council is being asked to certify the FEIR and approve a Project Alternative, and then subsequently approve bonds and contracts. This is the opposite of delegation.

The Citizens case is similarly inapplicable. In that case, the Court of Appeal held that since the City of Fresno’s municipal code did not grant its preservation commission with the authority to participate in environmental review process, the Council’s review of the appeal of the preservation commission’s decision was invalid since it did not act as an independent decision-making body in reviewing the mitigated negative declaration.

Here, as discussed above, the Council would be acting as an independent decision- making body to certify the FEIR and grant an approval to a Project Alternative. Nothing in Citizens compels a different result.

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4 Third, asking the HPC to certify the FEIR and issue a demolition clearance before the Council has approved a Project Alternative would be impractical and unwise. The Council could choose not to select Alternative 7 or 8. Since Alternatives 7 or 8 are the only alternatives before the Council at the moment that would require demolition of the Boiler Building, it is premature and counterproductive to request a demolition permit before the Council has made the policy and financial choice to move forward with an Alternative that would actually require the demolition of the Boiler Building. Indeed, as noted in Topical Response No. 3, GWP hasn’t even applied for the demolition permit yet because the project hasn’t been approved and financed, nor has a demolition contractor been hired. Thus, going to the HPC for a clearance for a demolition permit is premature at this time. If the Council certifies the FEIR, selects an Alternative, approves the financing, hires a demolition contractor, and applies for a demolition permit, then it would be appropriate for the consideration of a proposed demolition clearance to come before the HPC.

With respect to your concern regarding Chapter 15.22 of the Glendale Municipal Code, it is our opinion that Chapter 15.22 pertaining to demolition of historic and potentially historic structures was specifically intended to prevent the inadvertent destruction of buildings, structures or objects of historic, architectural or cultural importance and ensuring completion of environment review prior to issuance of a demolition permit for a historic or potentially historic resource. See G.M.C. §15.22.010. That’s not at issue here, since the City has done a complete analysis of the Boiler Building in the FEIR, designated the Boiler Building as a discretionary historic and will seek the HPC’s approval for its demolition if the Council chooses to move forward in the Project. All of the requisite environmental review will have been performed before consideration of a demolition permit, which is the fundamental purpose of Chapter 15.22.

Thank you for your inquiry.

Respectfully,

“The City Attorney”

<image001.jpg> <image002.jpg> <image003.jpg> <image004.jpg>

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5 THIS E-MAIL, ITS CONTENTS, AND ANY ATTACHMENT(S) ARE CONFIDENTIAL, ATTORNEY-

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From: Catherine Jurca <[email protected]>
Date: February 10, 2022 at 7:58:39 AM PST
To: "Devine, Paula" <[email protected]>, "Agajanian, Vrej" <[email protected]>, "Brotman, Daniel"
<[email protected]>, "Kassakhian, Ardashes"
<[email protected]>, "Najarian, Ara"
<[email protected]>, "Golanian, Roubik"
<[email protected]>, [email protected], "Young, Mark" <[email protected]>
Subject: CEQA-historic resources and Grayson-

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Dear Mayor Devine, Members of the Glendale City Council, and Staff:

I wanted to provide more details regarding my concerns about the approval process for the Grayson Power Plant project. I think it clearly violates the Glendale Municipal Code and CEQA, and the city is poised to make a significant mistake in how it handles the project approval.

I’m not trying to be a jerk. What happens with Grayson—whatever shape the project takes—is a big deal for the city and should not get held up because the City failed to follow the right process.

Glendale may well get sued over approval of a gas power plant at Grayson, just as a suit has been filed over Scholl Canyon, and I think staff are unnecessarily opening the city up to an very easy lawsuit by bypassing a necessary review, which could delay the project for more than year.

On Tuesday, the City Attorney said, in response to my comments:
we reviewed it and it complies with the Code and CEQA. I don’t think that’s adequate; nor should you. You should press them for 919 of 983
6 details and ask them to justify their position in light of the evidence I raise below.

At the Historic Preservation Commission (HPC) meeting in January, I raised concerns about the Grayson “update.” HPC Updates occur at the very end of the meeting, and usually are a few sentences from Jay. This “update” was a long powerpoint from Stantec, with very little detail about the historic resource issues.

The FEIR had been issued one or two days before. No
commissioner had reviewed it; I was probably the only one who knew it had been posted. But, we learned, the point of the “update” was to solicit our comments on the EIR. That is not an update. And it’s not an EIR review. A powerpoint cannot do justice to a 400- page EIR. This really felt like a bait and switch, with the public as the losers.

I know for a fact there was a caller at the hearing and staff never asked for callers. We were at the end of a six-hour meeting, and I forgot to raise it and the other commissioners did too. I think that was an oversight, but it is already a procedural problem.

The Bottom Line: The City is treating the Grayson Boiler Building as a historic resource in the FEIR. The project must come to the HPC for the demolition clearance AND environmental review under CEQA. The language from the GMC is cited below. The City Attorney argued at the HPC meeting that Grayson would come to the HPC for a demolition permit AFTER Council had approved the project and certified the FEIR. It can’t work that way.

First, because the Code gives the HPC authority for environmental review as part of demolition clearance. It is the HPC that reviews the FEIR and adopts the Statement of Overriding Considerations for demolition of historic resources.

It also can’t work that way because it is impermissible to separate project review authority and environmental review authority under CEQA. In POET, LLC v. State Air Resources Bd. (2013)
218 Cal.App.4th 681, 731, the court held that “CEQA is
violated when the authority to approve or disapprove the project is separated from the responsibility to
complete environmental review.” The City Attorney says the HPC would decide whether or not to approve the demolition clearance application, but the FEIR would already have been certified. That is the type of situation POET prohibits.

Further, in Citizens for the Restoration of L Street v. City of Fresno (5th Dist. 2014) 229 Cal.App.4th 340, the Court held, citing POET, that "A decisionmaking body's responsibilities include more than just approving the project. It also must consider and adopt the environmental review document.”

I know this is a complex case because obviously the environmental impacts at Grayson are more than just to historic resources, but 920 of 983
7 everything I’ve learned about CEQA the last five years tells me the City must not bypass noticed review by the HPC.

CEQA requires that any decision by a non-elected body is appealable to the elected body. So even if the HPC were to vote against demolition and refuse to certify the EIR, GWP could appeal it to Council in exactly the same way as it did with the Planning Commission decision over Scholl Canyon. I do not understand why staff are taking this risk of circumventing HPC review.

Here are the relevant passages from the Code.

15.22.025 Authority.

The director of community development shall review all
demolition clearance applications to: (1) determine if the proposed demolition may have a substantial adverse impact on the environment pursuant to CEQA; (2) determine the required level of environmental review under CEQA and require preparation of any documents necessary to conduct this review; and (3) upon review of all applications and supporting documents, determine the appropriate authority for final review of the demolition clearance application and all other required discretionary applications, as follows:

A. The historic preservation commission shall be the review authority for the demolition clearance application, any required environmental review pursuant to CEQA, and all other
discretionary applications related to design review pursuant to Chapter 15.20 and Section 15.22.050 of this code if the proposal under review is determined by the director of community development to involve a:

1. Designated historic resource;

2. Potential historic resource
AND

15.22.050 Historic preservation commission review of
demolition clearance applications.

The historic preservation commission shall review demolition clearance applications, environmental review documents that may be required pursuant to CEQA, additional information or materials submitted by the applicant as required by the director of community development pursuant to Section 15.22.070(A)(1), (A)(2), and (A)(3), and any information or materials submitted by members of the public prior to rendering a decision to approve or disapprove a demolition clearance application.
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8 A. For a designated historic resource, the historic preservation commission shall not approve a demolition clearance application unless it finds:

1. The subject property is not a historic resource because it does not meet any of the criteria for listing on the Glendale Register pursuant to Section 15.20.050 of this code and that this determination is not due to demolition by neglect or unpermitted work; or

2. It has certified an Environmental Impact Report (EIR) and adopted a Statement of Overriding Considerations in reference to a significant and unavoidable environmental impact on cultural resources stemming from the proposed demolition of a historic resource.

B. For a potential historic resource, the historic preservation commission shall consider all evidence in the record and make findings as to whether or not the subject property is eligible for listing on the Glendale Register, and is therefore a historic resource because the resource meets one or more of the criteria for listing in Section 15.20.050 of this code.

1. If the historic preservation commission finds the property is a historic resource, the commission shall direct the community development department to prepare or cause to be prepared by private consultants under contract with the city, an Environmental Impact Report in accordance with CEQA. Following circulation of the draft EIR for public comment and preparation of the final EIR, the final EIR and all other required discretionary applications shall be reviewed by the historic preservation commission pursuant to Sections 15.20.080 and 15.22.050 of this code. The historic preservation commission shall not approve a demolition clearance application for a property found to be a historic resource unless it adopts a Statement of Overriding Considerations, pursuant to CEQA, in reference to a significant and unavoidable
environmental impact on cultural resources stemming from the proposed demolition of a historic resource.

If the City Attorney says “well, Grayson isn’t designated on the Register, and it’s not potential, because the City recognizes it as historic, so technically we don’t need to take it to the HPC,” that’s not right. Certification of the FEIR is actually what would establish Grayson as a historic resource; at this point it is only potential, which still requires mandatory review by the HPC.

Thanks and best wishes,
Cathy

922 of 983

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FRANCESCA SMITH

February 13, 2022

Mayor Paula Devine and City Council Members
City of Glendale
633 East Broadway
Glendale, CA 91206
Sent via e-mail

RE: City Council Meeting February 15, 2022, Item 8.c
Comments on Final Environmental Impact Report, Grayson Repowering Project

Dear Mayor Devine and Council Persons:

On behalf of Glendale Residents Against Environmental Destruction (GRAED), I reviewed the Final Environmental Impact Report, Grayson Repowering Project (FEIR, January 20, 2022) and still see many significant shortcomings, errors, omissions and discrepancies with the California Environmental Quality Act (CEQA) requirements and the City of Glendale’s own Historic Preservation Ordinance (Ordinance) in the new document. Those problems include the persistent lack of a supplemental or updated Cultural Resources Technical Report that supports the Boiler Building eligibility as a historic resource, coupled with the Lead Agency’s dogged insistence not to intensively re-evaluate the entire property for local and California Register historic district eligibility to understand its significance; the weak, one-sided discussion of the potential future reuse of the Boiler Building; the unfounded dismissal of a mitigation measure formed to avoid future problems (which might have avoided this protracted eligibility debate); the excessively selective and improper cumulative impacts analysis and failure to follow the required sequence for reviews and approvals by the Historic Preservation Commission directed in the Glendale Municipal Code. Please ensure that this letter is entered in the Administrative Record for this project.

It was amusing to read the descriptions of how the Lead Agency elaborately sequestered their actions to reverse the property’s previous determination of National Register eligibility. The Lead Agency stopped short of admitting that The Glendale Historical Society (TGHS) and its members have been certain of the Boiler Building’s historic significance since at least 2017, and provided that information in research and expert professional opinion presented in letters. That should have been noted and almost certainly would have affected the State Historic Preservation’s opinion. The description further glossed over the fact that California Office of Historic Preservation supervisory staff agreed in 2021, based on information provided by TGHS and its members that the Boiler Building was indeed eligible for the California Register. That reviewer plainly said that that the entire property should rightly be re-evaluated as a historic district, following professional historic preservation practice for any properties that are intensely surveyed. California Office of Historic Preservation supervisory staff went so far as to say that the entire property appeared to be eligible for listing in the National Register of Historic Places based on the information previously withheld by city staff. 923 of 983

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Absence of Supplemental or Updated Cultural Resources Technical Report While the Lead Agency has, at long last, conceded that the Grayson Power Plant Boiler Building is a historical resource for the purposes of CEQA, we continue to assert that no updated Cultural Resources Technical Report was prepared to support those findings. It is not out of “a reasonable abundance of caution” that the Lead Agency is considering the Boiler Building historically significant as portrayed on page xvii; it was because the City had no choice. TGHS and its members proved in 2017 that the Boiler Building was and is historically significant.

Without a thorough and impartial “good faith” re-evaluation of the entire property, which would include its direct connection to the Glendale Switch Rack that was constructed roughly concurrently with the Boiler Building, both the identification of historical resources (which has wasted seven years thus far) and the analysis of impacts on the historical resource are inadequate.

The Lead Agency continues to claim there is no historic district on the subject property. We remind you that state guidance on recording historical resources directs Districts may be recognized and documented at the time a survey is conducted, or they may become apparent only after several survey efforts reveal the historical relationships among the individually recorded resources in a given geographic region… Because the recognition of a district hinges on an understanding of its historic context, evaluation is required on the District Record (“Instructions For Recording Historical Resources” 1995).

Previous evaluations prepared by the Lead Agency’s consultants found none of the properties at Grayson Power Plant to be historically significant (“Neither the Boiler Building nor Grayson Power Plant were identified as contributors to a historic district” pages 4.5 and 7.56 in FEIR). In light of the fact that the FEIR recognizes the Boiler Building to be historically significant, it would be entirely logical that the evaluation was updated and the entire property re-evaluated for the potential for a historic district. Without that complete identification of historical resources on the property and its consideration as a potential historic district that was directly connected to the establishment and development of Glendale as an independent city and as a Pre-War power plant, the analysis of impacts has no foundation or which to base its conclusions.

We note that the “Historic Context” in the FEIR (pages 4.9 through 4.22) is described as “an in- depth historic context which covers the history of electricity in California, steam generation in Los Angeles County, Glendale history, and the history and evolution of the power plant.” That Historic Context contains no references or footnotes, so both its legitimacy as well as its reliability are in question. Without the existence of the subject property, Glendale would not have an independent source of electrical power to enable the growth that occurred since 1941.

As previously stated, because the now FEIR is not even partially based on the results of a supplemental or updated Cultural Resources Technical Report that supports the current findings, the conclusions regarding Cultural Resources impacts are not supported. We strongly recommend that the City comply with CEQA as it relates to cultural resources in that the future environmental clearance documents for this and other projects would include preparation of reliable, unbiased, supplemental, updated information. Those should at minimum re-evaluate the entire property for historic significance, including as a potential historic district. Such a technical report would rely on a more balanced approach, including facts, actual references and its conclusions would not be predicated on alterations made to other parts of the property (as the most recent technical report did), and would fully consider the effect the independent 924 of 983

3 of 18
power source had in shaping the development of the City of Glendale as well as its architecture, engineering and novel earthquake-resistant design.

Reuse Analysis by Black &Veatch
The “structural review” alluded to, that was “studied to understand [the Boiler Building’s ]… potential for re-use” is inadequate on every level. Firstly, Black & Veatch has no demonstrated experience in historic preservation projects or in the specialized field of structural engineering for historic buildings (https://www.bv.com/search?search=Historic+preservation). Their single example of a previous project hypothetically connected to historic preservation enabled cell phone towers to be built in historic districts in New York (Landmark Sites Wireless Development Services). That project is far different from analyzing a specialized building’s potential for reuse. To emphasize that point, the explanation that “The Boiler Building was designed to older codes and does not meet current Building & Safety codes for seismic safety and would not be acceptable under today’s building standards” on page 7.52 is embarrassing and highlights their inexperience in any such evaluations. At the very least, the City should have explained to their consultants that the California Historical Building Code (Title 24, Part 8) would apply to any projects at this building, and is successfully used throughout the state on all types of resources. Moreover, there is no mention of the type of use proposed, which could well trigger different requirements. There is no mention of any review of the Boiler Building’s structural plans, which demonstrates further inadequacy, and their mysterious report is not appended to the FEIR.

The assertion “with respect to hazardous materials,” that “Stantec also performed a hazardous materials review of the Boiler Building” with descriptions of Transite siding, “significant quantities of asbestos within the building itself in the form of thermal insulation on the piping and boilers as well as insulation on electrical cabling” (page 7.52). Perhaps Stantec’s hazardous materials experts who likely described “Leadbased paints are also prevalent within the building as well as heavy metal contaminants in the Boiler Building fire brick. Equipment that contains PCBs has also been identified in the building” (ibid) are unaware that the Boiler Building has numerous employees who spend long shifts in it every day. It would be more than surprising to learn that none of those sources had been remediated or encapsulated despite the fact that the Boiler Building is in use. Following the fearsome descriptions of those materials, the conclusion is that “All of these hazardous materials will need to be (and can be) safely mitigated and remediated.” So the alarming litany was a needless exaggeration. Hazardous materials exist in most older buildings, many are used as offices, residences, museums and libraries and most were even built using then-applicable older codes.
“Collaboration” between the Lead Agency and The Glendale Historical Society CEQA ensures full public disclosure of the likely impacts of significant projects and provides part of the system through which community members can participate in a meaningful way in environmental review.

On page 5.57, the document asserts that “The City did consult with TGHS although such consultation with TGHS is not mandatory under CEQA.” We note that “Early Public Consultation” as outlined in 14 CCR Section 15083 directs Prior to completing the draft EIR, the lead agency may also consult directly with any person or organization it believes will be concerned with the environmental effects of the project. Many public agencies have found that early consultation solves many potential problems that would arise in more serious forms later in the review process. 925 of 983

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This early consultation may be called scoping. Scoping will be necessary when preparing an EIR/EIS jointly with a federal agency.
(a) Scoping has been helpful to agencies in identifying the range of actions, alternatives, mitigation measures, and significant effects to be analyzed in depth in an EIR and in eliminating from detailed study issues found not to be important. (b) Scoping has been found to be an effective way to bring together and resolve the concerns of affected federal, state, and local agencies, the proponent of the action, and other interested persons including those who might not be in accord with the action on environmental grounds.
(c) Where scoping is used, it should be combined to the extent possible with consultation under Section 15082.

While Scoping is not mandatory, it is considered a “best practice.” TGHS first requested information on the proposed project and copies of Cultural Resources Technical Reports in December of 2015 (e-mail from Greg Grammer, TGHS to Michele Cross, Stantec). No such information was ever provided.

Those discussions were incorrectly described in the PE-EIR and FEIR as “collaboration” which would have meant that the Lead Agency did not pick or choose what its staff would consider to reduce the considerable on-going Cultural Resources problem evidenced in the proposed project. “ The few paragraphs describing those meetings with representatives of TGHS notably contain no records of when those meetings took place, who attended, what was discussed and what, if anything, was agreed. That information is germane to this project’s decision makers and should have been included in more complete detail in future and/or final environmental clearance documents for this project. In those discussions TGHS provided reasonable Mitigation Measures to the Lead Agency that would have ensured problems of this magnitude relating to City-owned historic resources were not repeated in the future (see Attachment 4 and pages 10- 14 of this letter, Cultural Resources Mitigation Measure B- Historic Resources Survey of City- Owned Properties).

On December 15, 2020 the Glendale City Council discussed an Amendment of Contracts with Stantec Consulting Services, Inc. and Black & Veatch Corporation for Additional Professional Services Pertaining to the Limited Notice to Proceed Phase of the Proposed Grayson Repowering Project Alternatives.1 During that item’s public testimony at least one officer of TGHS and two members provided information in that recorded meeting by telephone to decision makers explaining the elaborate circumvention of the eligibility determination made by High-Speed Rail (HSR) for Grayson Power Plant.

Grayson Power Plant was determined eligible for the National Register of Historic Places in 2019. Although the City of Glendale (Lead Agency) was copied on all technical reports as a by- right consulting party, staff took no action until August 31, 2020 after I let them know of the determination via e-mail. At that point the City prepared a letter to HSR outlining the reasons that Grayson Steam-Electric Power Plant should not be considered a historic resource. The 25- page justification included photographs of structures that are not part of the main Boiler Building and notably omitted a map or diagram that would have clarified the locations of those structures (Attachment 1, pages 3-33). In that letter, the City notably excluded any reference to the evidence presented by TGHS and members of the public, including qualified judgment

1 Item 8c from the Agenda at
https://glendaleca.primegov.com/Portal/Meeting?compiledMeetingDocumentFileId=30739. 926 of 983

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establishing that the main Boiler Building was historically significant at both state and local levels (Attachment 2, pages 4-16).

In Attachment 2, TGHS reminded the Lead Agency that “CEQA strongly encourages early consultation with interested or affected parties, which includes local historic advocacy groups.

No consultation efforts were made with TGHS. We were asked for information early in the process [December 2015] but have not otherwise been consulted on the project” (page 17). No consultation effort with TGHS was made by the Lead Agency until January 2021, at the request of City Council, and in the few months following. Rather than collaboration, where both sides listen to each other, those meetings could better be described as a one-way street, where City staff offered carrots but proffered only sticks in return.

Despite TGHS’s demonstrated interest in the proposed project as described above, the non- profit and its representative were not copied on the Lead Agency’s Attachment 2 letter to HSR requesting the property’s National Register determination be overturned. Based on the unnecessarily secretive process and partial information provided by the City in Attachment 1, and absent any information and professional opinions to the contrary provided by TGHS regarding the subject property’s historic significance, the State Historic Preservation Officer (SHPO) concurred with the opinion provided by the City of Glendale based on alterations to separate Cooling Tower structures (1, 2, 3, 4 and Units 8A-C) that the Boiler Building was not eligible for listing in the National Register. TGHS was not ever apprised of the request for reversal of the property’s determination of eligibility until the City Council Meeting Agenda was posted for the December 15 meeting despite demonstrated interest in letters regarding its historic significance.

Notably as well, in that December 15 City Council Meeting, City Attorney staff member Gillian van Muyden asserted to Council that the concurrence letter from SHPO found that the property was “not historic.” That is untrue, as was pointed out by a member of the public at the meeting (see Attachment 3, pages 1 and 2). Also in that meeting, the adopted City Council motion included the provision that City staff meet with TGHS to address the historic significance of the Boiler Building and mitigation for its demolition, and voted to move forward, excluding consideration of “Alternative 7.”
We note that the Glendale Switch Rack, which dates from the same year as the Boiler Building (1941) and was central to the property’s operation as a power plant should be considered historically significant as well (see Figure 1 on page 4). 927 of 983

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Figure 1: Annotated excerpt of Sanborn Fire Insurance Co. map of Grayson Power Plant in 1950. Note the outline of irregularly configured Boiler Building on the left side with three exhaust stacks which remain and extant Glendale Switch Rack on right. Both are highlighted in red. Source: Sanborn Fire Insurance Co. Maps of Glendale, CA Volume 2, updated to October 1950, sheet 299B.

Figure 1, above, depicts the Boiler Building and the functionally-related, and currently extant Glendale Switch Rack in 1950. Review of aerial photographs from the same time period reveal the same relationship between the Boiler Building and Glendale Switch Rack. If the property had been appropriately, impartially evaluated for historic significance impacts and effects, we believe the Glendale Switch Rack and likely other part of the property would likely have been identified as contributing features of what may likely be a National or California Register- eligible historic district.

We assert that in failing to re-evaluate the property it was not analyzed for its engineering significance either. In the first addition to the Boiler Building, its architect, Daniel A. Elliott, AIA extended the main rectangular form and repeated the original bay configuration to the northwest. The Lead Agency should know that addition notably included “the first hydrogen- cooled turbine generation for outdoor use,” which was made possible by the “prevailing moderate weather.”2 The then-novel use of hydrogen to power the turbines allowed the plant to maintain its original design program of a narrow block-like building which housed generating units served by exterior turbine engines. Hydrogen is more efficient transferring heat than air is because it can absorb heat and can thus transfer it another medium. Challenges include maintaining the pure hydrogen, ensuring the pure gas has no air leaks and safety.

2 Electric Light and Power, Volume 18, 1940: 74.
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According to industry news, hydrogen cooled generators became the industry standard, which makes that early instance of its use in Glendale all the more important. 3 At the time of the installation of the unique exterior turbine, the concept of making personnel work outside was the subject of wide debate among professionals in the field. Factors in its favor included reducing the necessary size of the main plant buildings (like the Boiler Building) and the obvious benefits of natural ventilation. Minor drawbacks were the requirement for a deep “basement” as is present in the turbine deck, the excessive noise generated inside small turbine covers and the exposure of employees to the elements. In the 1940s, an industry publication held a competition to assess the practicality of such outdoor turbines. The fact that exterior turbines are now common and hydrogen cooling remains the most widely used application seems to ultimately close the discussion.4

Figure 2: Daniel A. Elliott’s’ early rendering of Glendale Power Plant, with one turbine above steps and the crane at left. The rendering was published in Electric Light & Power with the caption: “Architect’s sketch of the Glendale (Calif.) plant where the first hydrogen cooled turbine for outdoor operation will be installed.” Source: Electric Light & Power, Volume. 18 July 1940: 72.

The regional Postwar residential boom in Glendale was enabled, in part, by the fact that the City had an independent power plant. 5 The City could not have developed as rapidly or as widely as it did in the years after 1941 without its own power plant. “Discretionary” Historical Resource
We note as well that in the FEIR and PR-EIR text, every mention of the single identified historical resource is diluted by repetition of the modifier “discretionary.” That thinly veiled language mannerism, which is a component of CEQA as it relates to historic resources, was repeated more than 50 times in the FEIR. It is intended to lead non-professionals (which will

3 Spring, Nancy. “Hydrogen Cools Well, But Safety is Crucial” Power Engineering . June 1, 2009 and Covertel Power. “How H2 Is Used to Cool Electric Generators” at https://covertelpower.com.au/products-and-services/electrolysers/how-h2-cools-generators/ accessed on June 24, 2021.
4 Maddock, Bill. M.E. “Is the Outdoor Installation Here to Stay?” Power Plant Engineering. United States: Technical Publishing Company, October 1943.
5 Power Plant Engineering. (United States, Technical Publishing Company, 1944): np. 929 of 983

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include most of the public, the Mayor and City Council members) into believing that the historic significance of the Boiler Building is somehow in doubt, which it is not.

Page xviii in the FEIR ambiguously cites “reasonable abundance of caution“in treating the Boiler Building as a discretionary historical resource under CEQA. That description notably passes over the fact that TGHS and its members provided substantial evidence that the Boiler Building is a historical resource, evidence so compelling that the City felt obliged not to provide it to the SHPO through HSR when asking to reverse the finding of National Register eligibility, despite City Attorney Michael Garcia’s claim twice at the December 15, 2020 Council meeting that the City had contacted the SHPO in order to provide “more complete information” about the historic status of the Boiler Building.

It would have been understandable if the Lead Agency had defined the term “discretionary historical resource” once in the text. It is when the Lead Agency determines that a resource meets the criteria for listing in the California Register of Historical Resources (California Code of Regulations or CCR Section 15064.1.a.3); or the Lead Agency uses its discretion to consider any resource as historic for the purposes of CEQA (CCR Section 15064.1.a.4). The document need only explain that detail once. It can be in a footnote, and should explain that its historic significance was clearly proven based on “substantial evidence [because]… substantial evidence supports the conclusion regardless of any official listing in a historical register” as defined in CEQA.

Alternatives Analysis
According to CEQA, the contents of an EIR must describe a reasonable range of alternatives to a proposed project that could feasibly attain most of the basic project objectives and would avoid or substantially lessen any of the proposed project’s significant effects (CEQA Guidelines Section 15126.6(e)). Grayson Power Plant Boiler Building is a historical resource for the purposes of CEQA as described in the FEIR.

An alternative that would have avoided demolition of the Grayson Power Plant Boiler Building and Glendale Switch Rack would have included but not been limited to considering different locations for the proposed project, a smaller or reduced project, and at the very least, consideration of rehabilitation of the Boiler Building in accordance with the Secretary of the Interior’s Standards for Rehabilitation. None of those were presented.

Alternative 3 “The Alternative Energy Project Alternative” is environmentally superior but is entirely conjectural in the reasons for its dismissal. Its undeveloped description e.g. “some combination of photovoltaic or wind power production with energy storage and transmission lines” in not sufficiently developed to adequately analyze anticipated impacts. The description is completely vague and nearly devoid of clear information.

The conclusion that “the Alternative Energy Project Alternative reduces local potential air quality, cultural resources, energy, greenhouse gas emissions, hydrology and water quality, and noise impacts local to the Grayson Power Plant site” is not sufficiently presented either. The Alternative is described as “it increases off-site impacts to aesthetics [not clearly defined as it is unknown where the solar or wind resources would be], agriculture and forestry resources [unfounded with no identification of locations], biological resources [unfounded with no identification of locations], cultural/tribal cultural resources [which ones, if there is no identification of locations], environmental justice [to whom, with no identification of a location], geology and soils, land use and planning [where is there is no identification of locations], and population and housing impacts [these facilities are normally not built in populated areas] due to the need for increased transmission [unfounded with no identification of locations] as well as 930 of 983

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the large area [the locations of which are not disclosed in the FEIR] needed for a wind farm or solar field.”
Other agencies are building solar (771 in California, according to the California Energy Commission, 2022) and wind farms (there are seven in California) at a rapid pace. How is it that Glendale is somehow hampered by conjectural environmental impacts when others are not? The analysis concludes that the alternative is not viable “This determination is reinforced by the results of the Clean Energy RFP, the 2019 IRP, and the 100% Clean by 2030 study” which demonstrates that an infeasible alternative was brought forth as a CEQA “Trojan horse” or untruthful alternative (PR-DEIR “Alternative Energy Project Alternative – Alternative 3” page xx, see also CEQA Guidelines Section 15126.6(e)). If that alternative would cause more impacts than are disclosed, with promises of future impacts to locations unknown, the argument against Alternative 3 is Reducto ad absurduim, the falsity of the premise is demonstrated by showing that its logical consequence is contradictory.

If, as described in the FEIR, “The City is working with an engineering firm to investigate the feasibility of developing solar facilities on City-owned properties, and has preliminarily determined, subject to further analysis, that of the approximately 150 acres of City-owned property under consideration, approximately 40 acres may have some potential for PV development, however this acreage is far below the 1,310 acres necessary to locally power a PV project,” the TGHS-recommended mitigation measure to prepare a -Historic Resources Survey of City-Owned Properties would have been a valuable tool to understanding the potential impacts of such a project and is not ”punitive” as is alleged without providing any facts or basis for the claim.

The omission of this important component of the alternatives analysis, which would have meaningfully considered a reuse alternative for the historical resource, a different location or a smaller project is significant and problematic under the law. While an EIR need not consider every conceivable alternative to a project, alternatives must include consideration of those that would avoid or substantially lessen the significant environmental effects of the project. The FEIR did not include a rationale for the selection or rejection of the absent reuse alternative or of any clear information on which the Lead Agency relied in not making that a viable alternative under consideration. While City Council may have voted not to analyze an alternative that would have retained the historical resource in December of last year, based on the misinformation about SHPO eligibility determination provided by the City Attorney, such local, and unfortunately not fully informed decisions would not supersede the requirements in CEQA which is a state law, especially now that the FEIR recognizes that the Boiler Building is a historical resource.

The FEIR should have clearly identified alternatives considered but rejected as infeasible during the scoping process and briefly explained the reasons for the exclusions. Alternatives may be eliminated from detailed consideration in an EIR if they fail to meet most of the project objectives, are infeasible, or do not avoid any significant environmental effects; however it is legally required that they be described. See additional information under the Mitigation Measures section in this letter, in the following pages.

We have been told that reuse of the Boiler Building would be impossible numerous times. The “analysis” by Black & Veatch proved only they have no expertise in the subject: the reuse of historic buildings. Stantec’s assertions regarding the potential presence of hazardous materials similarly did not prove that the Boiler Building cannot be reused, but may have shown that Glendale Water & Power is unnecessarily exposing their employees to hazardous materials and 931 of 983

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conditions that could be easily mitigated. Power plant buildings have been successfully reused for a numerous purposes throughout the United States and abroad.6 Reuse of power plant facilities is not impossible, as has been implied in meetings between TGHS volunteers and City staff with their consultants (February 2, 9 and 16, March 4, 2021) as well as in public meetings regarding the proposed project. A fair amount of guidance on the subject of reusing power plants exists, including: “Repurposing Retired Power Plants Into Green Neighborhood Centers” (Smart Cities Dive, Kaid Benfield), “Repurposing Legacy Power Plants: Lessons for the Future” (American Clean Skies Foundation) and “Interpreting The Secretary of the Interior’s Standards for Rehabilitation No. 30: Reusing Special Use Structures” (National Park Service). If reuse of power plants for other purposes were impossible as implied by City staff and the embarrassing “analysis,” then how and why would the described guidance and examples of power plant reuse exist?
The description of alternatives in the FEIR fails to provide the necessary information for stakeholders and decision-makers to understand whether or not the historical resource really could be reused under any of the considered alternatives. Because no such meaningful reuse alternative was considered, and the Lead Agency’s dependence on the opinion of an engineering firm with no demonstrated specialty or understanding of the California Historic Building Code, the alternatives analysis is incomplete and deficient. The FEIR is legally inadequate in its description of existing conditions (without a supplemental technical report), as well as in its analysis of alternatives.

The Lead Agency is using the FEIR as a post hoc rationalization for its predetermination that the majority of the Grayson Power Plant, which may be a collection of unrelated historical resources or more likely is a locally and a California Register historic district, should be demolished wholesale, based on the City Attorney’s uncorrected misstatements about the property’s historic status at the December 15 2020 City Council Meeting. Pre-commitment to a project in advance of an adequate environmental review is a violation of CEQA. The FEIR should instead have considered feasible alternatives that would include new construction in some combination with adaptive reuse of the historical resource or resources.

Mitigation Measures
During that referenced December 15, 2020 City Council Meeting, Councilman Ardashes Khassakhian spoke about the importance of the City completing “all remaining” historic surveys. If the mitigation measure prepared and submitted to the Lead Agency by THGS, which was for a Historic Resources Survey of City-Owned Properties, had been implemented before the Grayson Repowering Project was considered, it is assumed that the subject property would have been identified as a historical resource and could have avoided this years-long dispute with TGHS and its members, and now with GREAD, regarding its significance.

Attachment 4, the April 25, 2021 three-page attachment sent via e-mail by TGHS to the Lead Agency directed: “The environmental document prepared for the Grayson Electric-Steam Power Plant must study and analyze historical resource impacts.”

6 Examples of successful power plant reuse projects include Barksdale Power Station (London, UK), City Hospital; Power Plant (Chicago, IL), Pier 4 Power Plant (Baltimore, MD), RJ Reynolds Tobacco Co. Power Plant (Winston Salem, NC), Seaholm Power Pant (Austin, TX), Sears & Roebuck Power Plant (Chicago, IL), South Street Station (Providence, RI) and the State Department West Heating Plant (Washington, D.C.). Additional power plants have been converted other uses in Portland, OR; Queens, NY, and Beloit, WI. 932 of 983

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It stated:

The alternatives analysis component will be especially critical in this this document. It must evaluate the No Project alternative as well as a “reasonable range” of feasible alternatives that would retain the Grayson Electric-Steam Power Plant as described in CEQA Guidelines Section 15126.6(e)).

There must be an essential nexus (i.e. connection) between the mitigation measure and a legitimate governmental interest… Nollan v. California Coastal Commission, 483 U.S. 825 (1987). The mitigation measure must be "roughly proportional" to the impacts of the project. Dolan v. City of Tigard, 512 U.S. 374 (1994). TGHS… believes that the below- listed mitigation measures would be both connected to the expected loss of the Grayson Electric-Steam Power Plant and are relational to the expected loss of that structure to the community. The addition of signage on San Fernando Road near the current location of the Grayson Electric-Steam Power Plant and the future retention and display of components of equipment from the Grayson Electric-Steam Power Plant shall be added to these mitigation measures.

Mitigation of impacts must lessen or eliminate the physical impact that the project will have on the historical resource. This is often accomplished through redesign of a project to eliminate objectionable or damaging aspects of the project. Relocation of a historical resource may constitute an adverse impact as well. However, in situations where relocation is the only feasible alternative to demolition, relocation may mitigate the impact below a level of significance provided such that the new location is compatible with the original character and use of the historical resource and the resource retains its eligibility for listing in the California Register (14 CCR Section 4852(d)(1)).

C[ultural] R[esources] M[itigation] M[easure] B- Historic Resources Survey of City- Owned Properties
The City shall prepare or cause to be prepared [a] comprehensive Historic Resources Survey of (all) City-Owned Properties (Survey) with improvements constructed before 1990, unless the property has previously been evaluated (with a written record of that evaluation) within the past five years or are expected to be evaluated in the planned East-West Survey. All survey work shall conform to the Secretary of the Interior's Standards for Archaeology and Historic Preservation, which include Standards for Evaluation, Identification, and Registration. The survey shall be prepared in accordance with “National Register Bulletin: Guidelines for Local Surveys: A Basis for Preservation Planning” and the California Office of Historic Preservation’s latest guidance. The Survey shall commence within 90 days of the adoption of the environmental clearance document for the Proposed Grayson Power Plant Repowering Project. The survey shall be completed within one-calendar year, be subject to a draft and final survey review and recommendation by the City’s Historic Preservation Commission and adoption by City Council.

The resulting survey shall include, at minimum:

A Summary, enumerating the total number of surveyed resources and districts with levels of significance.
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A Project Description, that clearly describes the purposes of the survey, sources of funding, its overall parameters, a description and map of the survey area and property types.

A Summary of Previous Identification Efforts that clearly describes any previous survey of identification efforts, local designations, National and California Register listings and determinations of eligibility, California Historic Landmarks and California Points of Historic Interest listings and designations and any other related historic preservation planning efforts. It shall include and describe the contents of a current, records search at the South Central Coastal Information Center at California State University Fullerton and provide the final survey and all known Glendale surveys to the Information Center upon completion, in accordance with the Information Center’s requirement.

A Context Statement prepared in compliance with The Secretary of the Interior's Standards for Preservation Planning, “Standard I. Preservation Planning Establishes Historic Contexts,” “Standard II. Preservation Planning Uses Historic Contexts To Develop Goals and Priorities for the Identification, Evaluation, Registration and Treatment of Historic Properties” and the California Office of Historic Preservation-prepared “Writing Historic Contexts” guidance. The Context Statement shall establish clear registration requirements for eligibility.

A clear Methodology section that describes field work techniques and research methods used to conduct the survey, a description of how historic districts are identified in the survey, references to previous surveys, and methodology for re- survey completed as part of this project. It will clearly describe efforts made to contact and involve members of the community and organizations with particular interests in historic properties.

Recommendations for future preservation activities, including: potential updates and/or amendments to existing National, California and Glendale Register designations, as applicable; designation recommendations for potential local historic districts, as applicable; and potential economic development, heritage tourism, and other preservation planning activities;
Survey results shall enumerate the total number of surveyed resources in appropriate categories, tables listing the property types and architectural styles identified, as well as narrative defining the results, with information regarding the levels of integrity and condition of resources, describes character-defining features, past and current development trends.

Appendix 1: Two-page DPR 523 series forms for each City-owned property unless the property is vacant or a paved parking lot which shall be noted in the survey results tables by Los Angeles County Assessor’s Parcel Identification Numbers and address (where assigned). The DPRs shall be fully completed in accordance with the latest edition of the OHP-prepared “Instructions For Recording Historical Resources.” They shall include whether or not the evaluation is an update, assign California Register Status Codes and describe other listings in the header blocks and include at least one clear digital photograph and a sketch map. If a property is [given a] California Register Status Code 1-6L, it shall include a complete architectural description, construction history, related features and under significance, describe why the resource is 934 of 983

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significant within … the relevant historic context and identify character-defining features.

Appendix 2: A survey map that delineates the survey area with all previously identified properties including local landmarks and historic districts and the results of the City owner-Properties Survey.

The results of the final or adopted survey shall be provided to the [California] Office of Historic Preservation, submitted in the specified formats to the Information Center and the result, including the DPR series 523 forms shall be posted, by property in the City’s Glendale Information Property Portal or its successors and in its entirely on the City’s website until it is updated by a subsequent survey, within no more than 90 days of its substantial completion or adoption.

The thoroughly described, recommended mitigation measure for a Historic Resources Survey of City-Owned Properties was not included in the PR-DEIR, despite following an invitation by City staff to prepare mitigation measures; Councilman Khassakian’s direction to complete the City’s historical resources survey; or the recommended mitigation measure’s direct connection to a legitimate governmental interest (maintaining a complete city survey); its approximate proportionality to the historical resources impacts of the project and the relation to the expected historical resources loss to the community. Based on this project’s years-long difficulty recognizing that the subject property is a historical resource, there is a very clear “nexus” linking the project’s expected impact to need for a Historic Resources Survey of City-Owned Properties.

The assertion on page 7.59 and 7.60 that TGHS was making an “attempt to leverage its desired interest in obtaining a City-wide survey of historical buildings based on demolition of one historic building” is insulting. The need for a city-wide survey of city-owned properties has been clearly demonstrated in this project. No mitigation measure was recommended for a blanket city-wide survey as alleged. In the Responses to Comments in the FEIR the City neglected to admit that Jay Platt falsely claimed in a “collaborative” meeting with TGHS on Grayson on February 9, 2021 that he had in his possession a city-wide historic survey of city owned properties that he performed with a former member of the Historic Preservation Commission which made such a mitigation measure unnecessary. He agreed in that meeting when requested to forward the contents of that survey to me “in a few days.” At least one e- mail reminder was sent to Mr. Platt to remind him that TGHS was expecting a copy of the survey as promised (see below), but the agreed-to copy of the City-wide survey that could have alleviated the need for implementation of a mitigation measure directing the propagation of such a survey was never provided.

Figure 3: Copy of e-
mail to Jay Platt from
Francesca Smith sent
on April 13, 2021 at
12:24 PM requesting
that he send the
survey as agreed. It
was never sent.

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We assert that the proposed Grayson Repowering Project would serve the entire City of Glendale, and therefore the recommended Historic Resources Survey of City-Owned Properties mitigation measure would in fact be “roughly proportional” to its impact (i.e., addresses its fair share of total impact). Future environmental clearance documents for this project shall incorporate the recommended city-wide survey mitigation measure in full.

Identify Existing Conditions and Present to Historic Preservation Commission In addition, the City has made a conscious effort to sidestep compliance with its own Ordinance.

Because the City is treating the Boiler Building as a historic resource in the FEIR, the proposed project must come to HPC for the demolition clearance and environmental review under CEQA.

Language from GMC is cited below. The City Attorney argued at the HPC meeting that Grayson would come to the HPC for a demolition permit after Council had approved the new project and certified the FEIR. That would negate the responsibilities of the HPC. The Ordinance assigns the HPC authority for environmental review as part of demolition clearance.

It is obviously wholly wrong to deprive the HPC and the public of this required review.

This project is impermissibly making an effort to separate project review authority and environmental review authority under CEQA. Litigation has proven that “CEQA is violated when the authority to approve or disapprove the project is separated from the responsibility to complete environmental review” (POET, LLC v. State Air Resources Bd. (2013) 218 Cal.App.4 th
681, 731). The HPC could decide whether or not to approve the demolition clearance application, but as the Lead Agency is proceeding, the FEIR would already have been certified.

This state of affairs clearly violates the letter and intent of this decision.

Furthermore, there is no mention in the FEIR of the requirements in the Glendale Municipal Code which addresses demolition of potential historical resources. The ordinance clearly directs under “Demolition clearance and demolition permit required for demolition of designated historic resources and potential historic resources” (15.20.080):

A. No person shall completely demolish a designated historic resource or a potential historic resource without first obtaining a demolition clearance and demolition permit, pursuant to Chapter 15.22 of this code.

B. In the event any designated historic resource or potential historic resource is completely demolished or partially demolished without demolition clearance and issuance of a demolition permit, the provisions of Section 15.20.090 of this chapter shall apply.

C. In the case of a property listed in the Glendale Register of Historic Resources, upon completion of any environmental review required by CEQA and issuance of a demolition permit, the matter will be referred to the historic preservation commission and city council to commence the process of deleting the demolished property for deletion from the Glendale Register of Historic Resources pursuant to Sections

15.20.055 and 15.20.060 of this chapter. (Ord. 5949 § 10, 2020; Ord. 5784 § 11, 2012; Ord. 5110 § 16, 1996; prior code § 21-04).

No demolition clearance or demolition permit for Grayson Power Plant has been presented to the City of Glendale Historic Preservation Commission (HPC) for consideration.

The Powers and Duties of the HPC are clearly set forth in the Glendale Municipal Code as “the following acts”
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A. To consider and recommend to the city council additions to and deletions from the Glendale Register of Historic Resources;
B. To keep current and publish a register of historic resources; C. To make recommendations to the planning commission, and the city council on amendments to the Historic Preservation Element of the city General Plan; D. To grant or deny applications for permits for demolition, or major alterations of historic resources;
E. To grant or deny appeals from decisions of the director of community development as specified in Section 15.20.040 of this code;
F. To encourage public understanding of and involvement in the unique historical, architectural and environmental heritage of the city through educational and interpretative programs;
G. To explore means for the protection, retention and use of any historic resource, historic district, or potential historic resource or district;
H. To make recommendations to the city council on applications for properties to be included in the Mills Act property tax incentives program which may be subject to historic property contracts as set forth in Section 15.20.070 of this code; I. To encourage private efforts to acquire property and raise funding on behalf of historic preservation; however, the commission is specifically denied the power to acquire any property or interest therein for or on behalf of itself or the city; J. To recommend and encourage the protection, enhancement, appreciation and use of structures of historical, cultural, architectural, community or aesthetic value which have not been designated as historic resources but are deserving of recognition; K. To encourage the cooperation between public and private historic preservation groups; L. To advise city council and city boards and commissions as necessary on historic preservation issues;
M. To make recommendations concerning, and render decisions on, design review applications affecting designated historic resources, resources pending designation as historic resources, potential historic resources, protected interiors, and protected landscape features as defined in Section 15.20.020 of this code, and affecting existing or proposed buildings, structures, or objects in designated and pending historic district overlay zones, as defined in Section 30.25.030(C) of this code and pursuant to Chapter 30.47of this code; N. To perform any other functions that may be designated by resolution or motion of the city council;
O. To make environmental determinations under the California Environmental Quality Act on any discretionary project applications the historic preservation commission considers for approval. (emphasis added, Ord. 5949 § 1, 2020; Ord. 5888 § 4, 2016; Ord. 5803 § 10, 2013; Ord. 5783 § 10, 2012; Ord. 5535 § 4, 2006; Ord. 5425 § 3, 2004; Ord. 5110 § 5, 1996; Ord. 4986 § 1, 1992: prior code § 3-139)
The proposed project was presented in January to the HPC but no public comment was accepted. I know because I tried to call twice during that item and received a City recording.

Unfortunately, and notably, actual review of the proposed project by the HPC has not taken place and has not been mentioned in any of environmental clearance documents for the proposed project, most notably in the FEIR, which should have incorporated any HPC findings or opinions regarding the proposed demolition of the historical resource, which would encourage public understanding of the project, particularly with historic preservation groups, explore possible means for protection, retention and future use of the subject property historic resource.
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If HPC’s role, as stated, is “recommending and encouraging the protection, enhancement, appreciation and use of structures of historical, cultural, architectural, community or aesthetic value which have not been designated as historic resources, encouraging cooperation for this project with historic preservation groups, advising city council and other city boards and commissions” regarding the proposed project, which is a historic preservation issue, and to make recommendations concerning, and render decisions on, design review applications affecting designated historic resources, resources pending designation as historic resources, and potential historic resources, then the proposed project must be presented to the HPC for consideration and recommendation to City Council. Any such hearings to address or coordinate with the HPC after the project FEIR was adopted, would be too late to make any findings or recommendations that would be considered for the proposed project. Without HPC’s express participation, this action and environmental clearance of this project would violate the City’s own established, adopted and recently updated Historic Preservation Ordinance.

By-passing the City commission whose stated role is to make decisions regarding historical resources and to advise city council on such matters is unconscionable. At this late date it will, no doubt, make the environmental review process take longer than expected, but it need not extend it by much to do it properly. An expedited review should not be of greater importance to the Lead Agency than making informed decisions on the proposed project or compliance with applicable state laws and local ordinances.

Cumulative Impacts and Effects
The PR-DEIR also failed to adequately analyze the cumulative impacts and effects of currently proposed future and recent projects with the proposed project. The assertion that “There are no known related projects that are expected to impact other previously identified historic resources which are examples of the municipal power property type in Glendale” is an overly restrictive and incomplete view of the expected cumulative impacts in currently proposed future and recent projects. We note that if the Boiler Building were demolished as proposed, then 25 percent of the City’s historic resources which are examples of the municipal power property type in Glendale would be permanently lost. If only one more were damaged or lost as the result of an emergency (e.g. fire, earthquake or other destruction), the count and hence the percentage would be reduced to only two properties and 50 percent remaining. Would the impact only be cumulatively considerable when none were remaining? We do not follow the logic. The Lead Agency’s understanding of cumulative impacts under CEQA is notably not in keeping with the intent of the legislation.

Historical resources impacts in the City of Glendale are not limited to those caused by the City to city-owned properties, such impacts can be caused by any project proponent and would cumulatively affect the community. We are curious how many properties within that narrow context of the “municipal power property type” have ever been evaluated for historic significance in Glendale? Again, we provide more justification for the dismissed mitigation measure: Historic Resources Survey of City-Owned Properties. We remind the Lead Agency that there is no adopted historic context regarding Glendale’s municipal water and power system. If one were prepared, it should include community participation, as well as references.

For example, the expected CEQA impacts expected to be caused by the current GWP “Western Reservoir & Bel Aire Electric Substation Improvements” to the Bel Aire Electric Substation Pump House were addressed in my PE-DEIR comment letter. If that Spanish Colonial Revival 938 of 983

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style, 1920s Bel Aire Electric Substation Pump House (see Figure 4 below) had been evaluated for historic significance in a city-wide survey as proposed by TGHS, that answer would be known.

Figure 4: Bel Aire
Electric Substation
Pump House,
view north.

Source: Google
maps, January
2021, not for
publication.

Nobody knows whether or not the Bel Aire Electric Substation Pump House is a historical resource. The proposed project includes “slope repair, erosion control measures, site drainage improvements, access road repairs, retaining wall repairs, fence replacement, landscape and irrigation improvements” (page 7.57). The Lead Agency described in the FEIR “Activities potentially affecting the Pump House would involve reconfiguring the stairway to avoid a blower [what stairway? Is it a character defining feature?], flattening of the driveway [e.g grading], and modifying the driveway approach [how?] to allow better vehicle access [why?]” but did not offer any proof of CEQA review for the project. Has the Bel Aire Electric Substation Pump House been intensively evaluated for historic significance? Did it historically have a black metal fence as proposed? Was its setting historically in a grove of trees as currently proposed or was it surrounded by lawn during its period of significance? How was the driveway and slope configured? As demonstrated in this example, implementation of the proposed historic resource survey mitigation measure would serve to guide future projects of that type and should avoid future, potential CEQA violations of this type. Refer to the discussion in the previous pages regarding Mitigation Measures and the preparation of a related context statement.

To bring a finer point to the matter, how would the Lead Agency or the public ever know whether or not a city-owned property was historically significant in the absence of the TGHS- recommended intensive historic resources survey of those properties? The Lead Agency’s justification is both exceedingly inward-looking, restricting the analysis of identified historic resources which are known examples of “the municipal power property” type in Glendale, and moreover is circular. If the City of Glendale does not identify city-owned properties that are historically significant to avoid situations like the proposed project, where TGHS has presented substantial evidence for its historic significance, then only unreasonably limited opportunities to analyze historical resources impacts to those properties will exist. 939 of 983

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Because the PRDEIR and FEIR considered neither a comprehensive list of recent and expected future projects that would affect historical resources, nor the combined impacts of those projects considered with the proposed project, cumulative impacts have not been properly analyzed. An analysis of the severity and extent of those impacts is required by CEQA. It is common for a Lead Agency to conclude that a project would not cause significant cumulative impacts because it is assumed that the project’s incremental effect is not cumulatively considerable, i.e., the impacts of the proposed project would be a drop in the bucket compared to the overall view like the Grayson Repowering project. The requirement for an adequate cumulative impact analysis as it relates to historical resources must be properly prepared to ensure the fullest possible protection of the environment as it relates to historical resources.

We appreciate the opportunity to comment and look forward to working with the lead agency in a more constructive and comprehensive way to avoid future problems with CEQA compliance as it relates to historical resources, including the Grayson Repowering Project.

Very truly yours,
Francesca Smith
Francesca Smith

Attachments:

Attachment 1 Letter from High-Speed Rail Authority to Julianne Polanco, State Historic Preservation Officer regarding “High-Speed Rail Program, Burbank to Los Angeles Project Section – additional information and request for review and concurrence on revised determination of National Register of Historic Places eligibility for Grayson Steam-Electric Generating Station (Grayson Power Plant)” November 3, 2020 (pdf pages 1-2); with letter from Erik Krause, City of Glendale to Mark McLoughlin, High-Speed Rail Authority, August 31, 2020 (pages 3-7) and California DPR 523 dated August 17, 2015 and revised 2017 (pages 8-33).

Attachment 2 Letter from The Glendale Historical Society to Erik Krause “Comments on Proposed Grayson Repowering Project Draft Environmental Impact Statement” November 17, 2017.

Attachment 3 Letter from Julianne Polanco, State Historic Preservation Officer to Brett Rushing regarding ”High-Speed Rail Program, Burbank to Los Angeles Project Section, Additional Information and Request for Review and Concurrence on Revised National Register of Historic Places Determination of Eligibility for Grayson Steam-Electric Generating Station (Grayson Power Plant)” December 2, 2020.

Attachment 4 ”Grayson Electric-Steam Power Plant Mitigation Measures” transmitted by The Glendale Historical Society to the Lead Agency dated April 25, 2021. Note: the date may be incorrect, the document was probably transmitted on March 25, 2021. cc: Aram Adjemian, City Clerk
John Schwab-Simms, Vice President of Advocacy, The Glendale Historical Society Alek Bartrosouf, Chair, City of Glendale Sustainability Commission Chris Cragnotti, Chair, City of Glendale Historic Preservation Commission 940 of 983

DISTINGUISHING OIL & GAS INDUSTRY SPIN

FROM ZERO-EMISSION SOLUTIONS

RECLAIMING HYDROGEN

FOR A RENEWABLE FUTURE
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1 Reclaiming Hydrogen for a Renewable Future
AUGUST 2021
Sasan Saadat, Earthjustice’s Right to Zero campaign
Sara Gersen, Earthjustice’s Right to Zero campaign
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Contents 2
Reclaiming Hydrogen for a Renewable Future

CONTENTS
EXECUTIVE SUMMARY 3
INTRODUCTION 6
I. Today, hydrogen production relies on fossil fuels and threatens our climate and public health 10
II. The fossil fuel industry is campaigning to increase reliance on hydrogen from fossil fuels 12
III. Hydrogen can become a decarbonization tool in the
future if policymakers separate the promising
opportunities from fossil fuel industry hype 13

1. For now, the only established way to make hydrogen
without greenhouse gas emissions is by using
renewable energy to fuel electrolysis. 13

2. Limitatations of green hydrogen 16
Energy inefficiency 16
Costs 17
Pollution from combustion 18
Safe transport and storage 18
Water use 20
Time 20
IV . Identifying the promising applications for green hydrogen 21

1. Least-regrets uses for green hydrogen 21
Displace fossil hydrogen in current uses as an
industrial feedstock 21

2. Sectors to explore with caution 21
Maritime shipping 21
Aviation 23
High-heat industrial processes 23
Long-haul trucks and trains 23
Long-term storage of renewable electricity paired
with fuel cells 23

3. Sectors where hydrogen is not a solution 24
Combusting in fossil gas power plants 24
Gas-burning appliances in homes and commercial
buildings 27
Cars, buses and regional trucks 30
CONCLUSION 32
ENDNOTES 33
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Executive Summary 3
Reclaiming Hydrogen for a Renewable Future
The fossil fuel industry has helped generate enormous interest around hydrogen, making it difficult for policymakers to tell how much they can rely on hydrogen to meet climate goals. Too often, companies that profit from our reliance on fossil fuels invoke the vague promise of “clean,” “renewable,” or “green” hydrogen to derail action today. To avoid this trap, policymakers must scrutinize claims about hydrogen and think critically about where it can be a meaningful part of real climate solutions. To reclaim hydrogen for a renewable future, policymakers should explore opportunities to produce hydrogen from renewable electricity and use it to decarbonize sectors that cannot directly rely on a renewable electric grid.

First, reclaiming hydrogen for a zero-emission future requires a transition away from producing it with polluting technologies. Currently, oil and gas companies produce nearly all of the United States’ annual supply of hydrogen—about 10 million metric tons—from fossil fuels through a process that pollutes neighboring communities with health-harming emissions and the atmosphere with greenhouse gases. Transforming hydrogen from a climate threat to a climate tool requires a transition to green hydrogen.

Green hydrogen is made using 100% renewable electricity to split hydrogen from water molecules. For now, this is the only established way to produce hydrogen without emitting greenhouse gases or other health-harming pollutants. This whitepaper helps policymakers distinguish green hydrogen from hydrogen produced through polluting processes using inputs like fossil fuels and gas from factory farms. Fueling an industrial facility with green hydrogen would mitigate climate pollution, but not other pollution from its industrial processes, and so deployment of green hydrogen can never justify a buildout of facilities that would increase toxic pollution.

Once policymakers understan d what g reen hydrogen
is, they should consider the barrie rs to its widespread deployment. It will always b e more efficient to rely first on the direct use of renewable electricity wherever it is possible to do so, rather th an convert that electricity into hydrogen before using it as an en ergy source. This principle applies to vehicles, househol d appliances, and any other sector that has clean electr ic options for decarbonization.

Moreover, relying on green h ydrogen will require significant investments in storage and transportation infrastructure like dedicated pipelines because it behaves differently than the methane in our existing fossil gas infrastructure. Leakage in this infrastructure could undermine the benefits of green hydrogen because hydrogen is a greenhouse gas that is five times more potent than carbon dioxide. Scaling up the infrastructure to make green hydrogen widely available will take another decade—too long to delay dramatic reductions of climate pollution in the sectors that have other decarbonization options.

EXECUTIVE SUMMARY
It will always be more efficient to rely first
on the direct use of renewable electricity
wherever it is possible to do so, rather than
convert that electricity into hydrogen before
using it as an energy source.
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Executive Summary 4
Reclaiming Hydrogen for a Renewable Future
With these limitations in mind, policymakers can identify the sectors for which green hydrogen may nevertheless be a promising decarbonization tool, where it is worth careful exploration, and where they should instead deploy other technologies that are available today.

Our best option for deploying green hydrogen is to displace the fossil fuel-derived hydrogen already in use today. However, hydrogen is not an excuse to build or expand polluting industrial facilities. After additional study, policymakers may also find that green hydrogen is an appropriate tool for decarbonizing maritime shipping, aviation, industrial processes that require high temperatures, long-distance trucks or trains, and/or a small portion of our electricity supply. Given the limits on the supply of green hydrogen that are likely to persist for another decade, in the near-term, policymakers should reserve it for sectors that do not have other viable decarbonization options.

For the sectors that have zero-emission solutions available today, policymakers should embrace those solutions and reject any suggestion that climate action can wait for green hydrogen. For instance, the gas industry has used false promises around hydrogen to fight commonsense proposals to transition to clean, electric alternatives to burning gas in residential and commercial appliances. However, green hydrogen cannot make a meaningful dent in the climate pollution from these gas-fired appliances and the leaky pipelines that deliver gas to America’s homes and businesses.

Meeting the scale and urgency of the climate crisis will require deployment of renewable resources on an unprecedented scale and a widespread transition to electric models for things like household appliances and cars—uses where electric technologies are readily available and economies of scale will further drive down costs. For instance, in the The gas industry
has used false
promises around
hydrogen to hinder
commonsense
climate action,
such as the shift to
electric appliances
like the induction
stove top pictured
here. Tom Werner /
Getty Images
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Executive Summary 5
Reclaiming Hydrogen for a Renewable Future
transportation sector, battery-electric vehicles are the most promising decarbonization strategy for most on-road vehicles. Stabilizing the climate will require aggressive near-term investments in these vehicles and their fueling infrastructure, regardless of whether green hydrogen may prove to be a cost-effective tool for some heavy-duty long-haul vehicles.

Green hydrogen provides an additional reason to deploy renewable energy resources at an unprecedented pace. Not only are massive investments in renewable resources like wind and solar necessary to decarbonize the electric grid, but economies of scale in renewable electricity generation are key to driving down the cost of green hydrogen.

Despite industry rhetoric to the contrary, green hydrogen is not an excuse to build, expand or continue operations at gas-fired power plants. Even if future innovations may make it possible to retrofit these combustion turbines to operate solely on green hydrogen, the facilities would continue to pollute the air and burden the water supply. Today’s renewable energy and battery technologies can cost-effectively supply 80% of the electricity we need by 2030 and 90% by 2035. Green hydrogen is a potential tool for achieving a fully decarbonized electric grid because it can store renewable energy for long periods and convert it back into electricity with zero-emission fuel cell technologies.

As we continue to electrify everything that can feasibly plug into a clean power grid, we can strategically deploy green hydrogen to displace the fossil-derived hydrogen that industry is using today and to power sectors that are otherwise difficult to electrify. When used as a marketing tool by the fossil fuel industry, hydrogen can be used to hinder necessary climate action. But when reclaimed and deployed as a solution to decarbonize sectors we cannot otherwise electrify, green hydrogen can play an important role in a zero-emission future. 946 of 983
Introduction 6
Reclaiming Hydrogen for a Renewable Future
To chart a course toward a safer climate and more habitable planet, we must rapidly reduce emissions of greenhouse gases across our society. The biggest contributor to greenhouse gas emissions is the burning of fossil fuels. Consequently, the clearest path to reducing emissions is to switch from fossil fuels to renewable, zero-emission energy in our transportation, buildings, and power generation (sectors that are collectively responsible for about 75% of United States’ greenhouse gas emissions). 1 This transition would make
significant strides in eliminating the devastating public health impacts of pollution throughout the life cycle of fossil fuels—pollution that is most severely concentrated in Black, Brown, Indigenous, and poor communities.
2 A just transition will also require careful
policy design and meaningful engagement from frontline communities. Renewable energy, energy efficiency, and electrification are zero-emission solutions that eliminate both greenhouse gases and health-harming air pollution. To meet the scale and urgency of the climate crisis will require deployment of renewable resources on an unprecedented scale— ultimately achieving 100% clean power generation—and a complete transition to efficient, electric models for things like household appliances and cars.

As we electrify everything that can feasibly plug into a clean power grid, “green hydrogen” is a promising tool for transitioning to renewable energy in sectors that lack a viable route to direct electrification. Green hydrogen is hydrogen produced by using 100% renewable electricity to split water molecules.

To understand the potential role of green hydrogen, consider the challenges of cutting climate pollution from one hard-to-electrify sector: maritime shipping. Maritime travel is difficult to decarbonize because battery-powered ocean-going vessels will not be able to handle long-haul voyages across the ocean, at least for the foreseeable future. The hope for green hydrogen is that it may store energy from clean electric resources like wind and solar in a fuel that could be used to propel large, long-haul ships. This vision is at least a decade away from reality, if it overcomes the challenges to cost-effective production and efficient on-vessel storage. Still, it offers a path to displacing the highly polluting bunker fuel currently relied on to move much of the world’s goods across oceans.

Section I describes the status quo in industrial hydrogen production. Despite hydrogen’s potential to become a climate solution in the future, today’s reality is that global hydrogen production—more than 99.8 % of which is not green—is responsible for an enormous amount of climate pollution, more than the entire nation of Germany. 3 Oil and
gas companies produce almost all of the United States’ hydrogen supply from fossil gas, through a pollution-intensive process called steam methane reformation. Communities near oil refineries bear the brunt of this pollution because hydrogen production most often takes place at refineries, which are the main hydrogen consumers.

INTRODUCTION
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Introduction 7
Reclaiming Hydrogen for a Renewable Future
Globally, less than 1 percent of hydrogen is produced through electrolysis and less than

0.02% is green hydrogen (i.e., produced from electrolysis powered purely by renewable electricity).
4 Using hydrogen will not break our dependence on fossil fuels unless we quit relying on fossil fuels to produce hydrogen.

Section II discusses the fossil fuel industry’s recent public relations blitz supporting increased reliance on hydrogen. The fossil fuel industry has created a wave of hype around investments in hydrogen, which often conflates green hydrogen with the polluting hydrogen that the industry produces from fossil gas. One of the industry’s main strategies is to fund trade associations that advocate for policies that would increase hydrogen production from renewables and fossil fuels alike. Companies are also using hydrogen to greenwash new investments in fossil fuels, as they attempt to justify infrastructure projects with the vague and unsupported notion that the fossil fuel infrastructure might one day be repurposed for hydrogen. Policymakers must carefully scrutinize claims about hydrogen becoming a climate solution because the fossil fuel industry is aggressively promoting investments in hydrogen that would benefit their shareholders, but are not wise climate solutions.

Figure 1. Three
Types of Hydrogen
Production
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Introduction 8
Reclaiming Hydrogen for a Renewable Future
Section III discusses the definition of green hydrogen and the challenges to its widespread deployment. To help policymakers avoid unsustainable or costly decisions, this report offers criteria to help decide where it might be appropriate to deploy green hydrogen. Widely deployed green hydrogen is still at least a decade away and will always be less efficient than directly using renewable electricity wherever feasible. Still, green hydrogen could be a good climate solution for specific applications in a sector if:

CRITERIA FOR DEPLOYING GREEN HYDROGEN
1 There are no low-cost decarbonization strategies available; 2 There are no electric technologies being developed that could take advantage of zero-emission electricity directly;
3 The logistics and costs of infrastructure for hydrogen transportation and storage can be contained;
4 Technologies for using hydrogen fuel in the sector are or will be available; and
5 Transitioning to green hydrogen could reduce air pollution. 1 2
3 4
5 Section IV discusses the potential for green hydrogen as a decarbonization tool in different sectors. Based on the considerations presented in Section III, the highest priority and best use for green hydrogen is to displace the massive amounts of fossil- derived hydrogen that are currently being used in industrial processes. For the next few years, volumes of green hydrogen will be small and costs will be high. Policymakers need to direct this precious resource to displace existing, pollution-intensive hydrogen, rather than create new pots of hydrogen demand.

STEAM METHANE REFORMATION
Methane is made up of 1 carbon and 4 hydrogen atoms. To obtain hydrogen, high- temperature steam (water vapor at 700-1000 °C) reacts with the methane under pressure. The reaction of methane (CH
4) and water vapor (H2O) produces hydrogen
gas (H2) and carbon monoxide (CO). A second reaction (pressure swing adsorbtion) is performed with additional steam (H2O) to purify the CO and CH4 mixture, leaving more Hydrogen and carbon dioxide (CO2).

CH4 + H2O (steam) A CO + 3H2
CO + H2O (steam) A CO2 + H2
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Introduction 9
Reclaiming Hydrogen for a Renewable Future
These gas
distribution
lines cannot be
used to deliver
pure hydrogen.

Injecting
appreciable
volumes of
hydrogen in gas
lines to burn in gas
appliances poses
health and safety
risks. Kevin Lucas,
EyeEm / Getty
Images
In the 2030s, green hydrogen’s role could expand to address hard-to-electrify sectors or provide a small portion of our electric power supply by storing surplus renewable energy.

Maritime shipping, aviation, high-heat industrial processes, and long-haul trucking are all potential applications for green hydrogen that policymakers should explore with caution.

In the meantime, the declining cost of renewables and batteries is widening the range of things that can easily be electrified, potentially narrowing the applications for which hydrogen should be considered.

There are some sectors for which hydrogen is a dead end. The chief subject of misleading industry hype is the gas distribution network. The pipeline system that delivers methane to gas-fired appliances in homes and businesses cannot carry a significant amount of hydrogen—researchers estimate that hydrogen can only comprise about 7% of its energy content before hydrogen creates safety hazards. Nonetheless, gas companies tout hydrogen as a means of continuing their business model, while fighting against a climate solution that is available today: a full transition to electric appliances.

The very real risk is that these fossil fuel industry initiatives use the idea of green hydrogen to drive climate investments toward fossil fuel assets while siphoning them away from established, zero-emission solutions. The most urgent, near-term priority for climate action is accelerating deployment of the solutions that are already available and managing the transition from the fossil fuel economy. In addition to these aggressive near-term actions, policymakers can explore the potential for green hydrogen to decarbonize hard-to-electrify sectors. 950 of 983
10 Reclaiming Hydrogen for a Renewable Future
I. TODAY , HYDROGEN PRODUCTION RELIES ON FOSSIL FUELS AND

THREATENS OUR CLIMATE AND PUBLIC HEALTH
The recent hype around hydrogen can mask the fact
that the fossil fuel industry already produces hydrogen on a massive scale, with devastating consequences
for the climate and communities. Gas companies
and oil refineries are responsible for producing nearly all of the United States’ annual supply of hydrogen—
about 10 million metric tons
5—through an energy-
intensive industrial process called steam methane
reformation (SMR) of fossil gas.
6,7 Coal gasification is
also a significant source of hydrogen production in
other parts of the world, accounting for 2% of global
coal demand.
8 Globally, hydrogen production’s toll on
the climate is so great that hydrogen production is
responsible for more greenhouse gas emissions than
the entire country of Germany.
9 In addition to emitting greenhouse gases, SMR emits
pollution that harms public health in neighboring
communities, including nitrogen oxides, fine
particulate matter, carbon monoxide, and volatile
Figure 2. Top 10 Carbon
Dioxide Emitters - 2018 21
organic compounds.10 While SMR plants contribute
to warming the climate globally, their local impacts
are concentrated in the same communities on the
frontlines of oil refineries. Oil refining company Phillips 66 for example, recently entered an agreement with
industrial gas company Linde, to build what will be
the largest hydrogen production unit in the United
States.
11 The SMR project is being constructed in St.

James Parish, Louisiana12—a predominately African-
American community in the heart of a region of the
U.S. Gulf Coast known as “Cancer Alley,” so-named
because the concentration of petrochemical plants and
refineries cause high rates of cancer in local residents. 13 The fossil fuel industry is not just the primary producer of hydrogen—it is also the primary consumer of
hydrogen. Roughly 60% of domestic hydrogen demand
comes from crude oil refineries,
14 where it is used
to lower the sulfur content of diesel.15 Demand for
hydrogen from refineries continues to rise alongside
I

10.06 5.41

2.65 1.71 1.61

0.83 0.75 0.72 0.65 0.62
0 2
4 6
8 10
12 Ch ina
Un ited St ates
In dia Russia Japan
Hydro genGer many
Ir an
South Kor eaSaudi Arabia
2018 CO2 Emissions (GT)
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11 Reclaiming Hydrogen for a Renewable Future
The bulk of hydrogen demand in the United States today is for use in crude oil refineries. The fossil fuel industry is the country’s primary producer and consumer of hydrogen. Thomas Northcut / Getty Images increasing global demand for diesel fuel. Global
hydrogen demand has grown 28% over the last
decade,
16 which means that pollution from producing
hydrogen from fossil fuels is also increasing.17 After the petroleum industry, the second largest consumer of
hydrogen (about 30%) is industrial agribusiness, which
uses hydrogen as a feedstock for chemical fertilizers.
18 The remainder (~10%) is used for other chemical and
industrial processes like methanol production.
19 The fossil fuel industry has multiple incentives for promoting hydrogen. First, the industry’s vision for
hydrogen calls for continued reliance on fossil gas to
produce hydrogen, expanding existing revenue streams.
20 In contrast, a transition to a zero-emission economy means rejecting hydrogen from fossil fuels and only using green hydrogen, which is derived from 100% renewable
electricity. Second, industry sometimes uses rhetoric
about green hydrogen to justify new infrastructure for
fossil gas. Gas utility companies boost their profits when they build more pipelines to deliver fossil gas to homes and businesses, with the monopolies’ captive customers
footing the bill. Some gas companies are fighting to
expand their fossil gas infrastructure by spreading
misleading claims about the potential for hydrogen to
decarbonize their gas. Similarly, companies that profit from building gas-fired power plants are beginning to
rely on the promise that they might one day retrofit these facilities to burn green hydrogen to justify investments in new gas-fired electricity generators.
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12 Reclaiming Hydrogen for a Renewable Future
II. THE FOSSIL FUEL INDUSTRY IS CAMPAIGNING TO INCREASE

RELIANCE ON HYDROGEN FROM FOSSIL FUELS
Policymakers must carefully scrutinize claims about
hydrogen’s role in reducing climate pollution because
much of the hype around hydrogen comes from
the fossil fuel industry, whose foremost interest in
protecting shareholder profits may not align with
sensible climate strategies. As public demand for
climate action continues to rise, hydrogen has taken
on a central role in the oil and gas sector’s long-term planning.22 In March 2021, several oil majors, gas
companies, and fossil fuel-intensive utilities launched the “Clean Hydrogen Future Coalition,” which urged the
Biden administration to increase policy support for a
wide range of hydrogen production methods and uses.23
Oil and gas companies have joined with other industries —primarily chemical and car companies—to form at
least six trade associations to advocate for more
hydrogen production in the United States.24 As a recent article in Nature Climate Change observed, “the gas
industry is turning to hydrogen for a new lease of life.”25 U.S. fossil fuel companies are foll owing a playbook
that oil and gas c ompanies have a lready played in
Europe and Austra lia.26 In the United Kin gdom, a
group called “th e Hydrogen Taskforce,” backed by
BP, Shell, and a slew of gas com panies, launched
to advance the mission of securing hydrogen’s
role in the energy transition through increasing
government inves tment. The Taskforce’s focus is o n
increasing suppo rt for hydrogen i njection into the
gas grid, with go als such as ac hieving 100%
hydrogen for home heating 27 (a goal the UK’s climate
chief properly c alled “unwieldy and impractical”). 28 In the European Unio n, a report by w atchdogs revealed
that the hydrogen lobby there—mai nly comprised of
the gas industry—spent nearly 60 m illion euros
successfully convi ncing the European Commission
to pursue a “Hydrog en Backbone.” Th is vision calls
for blending sma ll amounts of hy drogen in the
existing gas syste m with the aspir ation of eventu ally expanding and repurposing that sy stem.29 The report
also highlights how a major global lobbying group,
the Hydrogen Coun cil, was launched in 2017
by FTI Consulting, a public relations firm exposed
for setting up fake “grassroots groups” in the United
States to oppose climate action.
30 The Australia
Hydrogen Council, which similarly draws most of
its members from the gas industry, as well as the
oil and auto industries, is focused on advancing a
vision of hydrogen-powered transportation, and calls
for “incentives or government policies created to
drive scalability [to] initially be hydrogen technology agnostic.”
31 In California, a coalition of oil, gas,
hydrogen, and auto companies wrote to Governor
Gavin Newsom asking him to invest half of the $1
billion dedicated to zero-emission transportation
toward “hydrogen fuel infrastructure to serve the
light-duty, transit and heavy-duty vehicle markets.”
32 Similarly, the Clean Hydrogen Future Coalition,
which includes large gas trade associations and
companies, as well as oil majors BP and Chevron,
sent a recent letter to President Biden calling for
additional funding and tax incentives for “clean”
hydrogen “from a variety of energy resources” for the
power and transportation sectors.
33 There are common themes that emerge across
these efforts: the largest backers of hydrogen
efforts are oil and gas companies; their marketing
materials lead with the benefits of green hydrogen,
but explicitly advocate for “all-of-the-above”
hydrogen production, which is currently dominated
by fossil fuel-derived hydrogen; and they
primarily focus on the benefits of using hydrogen
for injection in the gas grid or as a vehicle
transportation fuel (where the transition to direct
electrification is already underway).

II
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13 Reclaiming Hydrogen for a Renewable Future
III. HYDROGEN CAN BECOME A DECARBONIZATION TOOL IN THE FUTURE

IF POLICYMAKERS SEPARATE THE PROMISING OPPORTUNITIES FROM

FOSSIL FUEL INDUSTRY HYPE
III
This section provides information to help
policymakers understand the potential for using
green hydrogen to reduce emissions and to identify
instances where industries are making misleading
claims about hydrogen to fight climate solutions
that are available and cost-effective today. First, we
explain what it means for hydrogen to be “green,”
which is a critical concept to understand in light of
the many industry claims of “clean,” “renewable,”
and “green” hydrogen that include highly polluting
production pathways. Next, we explain the challenges
to deploying green hydrogen. Policymakers should
consider these limitations to determine where green
hydrogen could be a useful decarbonization strategy.

1. FOR NOW, THE ONLY ESTABLISHED WAY TO

MAKE HYDROGEN WITHOUT GREENHOUSE

GAS EMISSIONS IS BY USING RENEWABLE
ENERGY TO FUEL ELECTROLYSIS.

The first step in understanding whether a hydrogen
project is a practical climate solution is to ask how the hydrogen is made. As discussed above, the predominant
method for producing hydrogen today is a highly
polluting process called steam methane reformation
of fossil gas. Creating hydrogen that is suitable for a sustainable and equitable energy transition requires
a total transformation in how it is produced. Today,
the only established method of producing hydrogen
without emitting greenhouse gases or other pollution
is using renewable electricity to power electrolysis: a process that splits hydrogen from water molecules.

We use the more specific term “green hydrogen” in
this report to refer to this kind of hydrogen, consistent with the International Energy Agency’s definition of
“green hydrogen”: hydrogen produced “using electricity
generated from renewable energy sources.”
34 While
other nascent production pathways are being explored
for producing hydrogen without pollution,
35 it would be
premature to include other technologies in a definition of green hydrogen before they prove their ability to produce hydrogen without emissions.

To rely on electrolytic hydrogen as a climate strategy, it is essential to use 100% renewable energy to
produce the hydrogen. Because electrolysis is so
energy-intensive, hydrogen made with grid-average
electricity is even more carbon intensive than
hydrogen made from SMR of fossil gas. This is true
even in California, which has a cleaner electric grid
than most of the country.
36 To deliver meaningful
environmental benefits,
green hydrogen
production must be
paired with the build-
out of new renewable
resources and/or use
surplus renewable
energy. If hydrogen
producers were to buy
power from existing
hydropower, solar,
or wind facilities,
the customers who have historically purchased
that renewable energy are liable to shift to grid-
average electricity or contract with a fossil fueled
generator. When power plants burn more fossil fuels
to serve these customers, it defeats the purported
environmental benefits of the “green” hydrogen
producers using renewable energy. This phenomenon
is known as “resource shuffling.”
Policymakers should exercise caution with other forms
of hydrogen that industry touts as “clean,” “renewable,” or even “green.” For instance, the California Air
Resources Board allows California hydrogen producers
to call hydrogen derived from fossil fuels “renewable”
when the companies match their fossil gas with the
“environmental attributes” of biomethane from landfills in Mississippi and dairies in Indiana.
37 These companies
market their hydrogen as “renewable” even though
it is made from fossil gas, using the polluting steam
methane process we describe above. Policies will not
To deliver meaningful
environmental benefits,
green hydrogen
production must be paired
with the build-out of new
renewable resources
and/or use surplus
renewable energy.
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14 Reclaiming Hydrogen for a Renewable Future
catalyze the deployment of innovative technologies
if their definition of “clean,” “renewable,” or “green” hydrogen includes the industry’s business-as-usual
practices paired with biomethane credits.
38 The hydrogen industry’s preferred definition of
“green” hydrogen includes any hydrogen made
from biomethane or biomass,
39 regardless of its
climate and public health harms. For instance,
this definition of “green hydrogen” would include
hydrogen made from crops grown for the specific
purpose of becoming an energy source. Although
biomass conversion is sometimes touted as
an opportunity to harness materials that would
otherwise go to waste, the economic reality is that
the cost-effective and logistically manageable
sources of biomass are not dispersed waste
streams, but energy crops. Data on the climate
impacts of the U.S. EPA ’s Renewable Fuel Standard
shows why it is essential to exclude purpose-grown
energy crops as a feedstock for hydrogen. The
Renewable Fuel Standard provides an incentive
to increase biofuel production even though the
EPA ’s review showed the program had led to
Hydrogen
H2
Renewable
electricity
Electrolyzer
O2
Aviation
Chemical
Manufacturing
Shipping
Storage
H2

EUROPEANS LE ADING THE W AY ON

DEPLOYING THE T ECHNOLOGY TO

PRODUCE GREEN HYDROG EN
In 2020, the European Commission set a
target to deploy 6 GW of renewable hydrogen
electrolyzers by 2024 and 40 GW by 2030.*
Meeting this goal will require a massive scale
up of manufacturing capacity, which the
European Commission predicts could cut the
costs of electrolyzers in half by 2030. Wider
deployment of electrolyzers can reduce the cost
of production by both allowing manufacturers
to achieve economies of scale and by spurring
competition between suppliers. The United
States should also develop a strategy for scaling
up its electrolyzer manufacturing capacity or
risk being left behind.
*Neil Ford, Europe must double green hydrogen projects to hit target
(Aug. 26, 2020), https://www.reutersevents.com/
renewables/wind/europe-must-double-green-hydrogen-
projects-hit-target.

Figure 3. Green hydrogen production and use
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15 Reclaiming Hydrogen for a Renewable Future
0 5
10 15
20 25
Coa l Gasif icati onSMR of Fossil Gas SMR of Fossil Gas + C CS (56 %)
SMR of Fossil Gas
+ C CS (90 %)
100% Renewable
E lect r oly si s
U.S. Average Grid
Electrolysis†
kg CO2/kg H2
Direct Emissions*
Upstream Methane Leakage**
the conversion of up to 8 million acres of land—
nullifying and overwhelming any climate benefit the
program might have had. 40
Timber is another example of a biomass feedstock
that could contribute significant greenhouse gas
emissions. Policymakers must not assume that
biomass from forests is a carbon-neutral source of
energy, especially when there is no guarantee that
logged forests will have a chance to regrow. Even when
trees can regrow, it will take many decades or more
than a century to recapture the carbon that enters the
atmosphere when forests are logged for energy.
41 In addition to the unproven climate benefits of
biomethane- and biomass-based hydrogen, the public
health and environmental harms of many biogenic
feedstocks make it misleading to call this hydrogen
“green.” As the Federal Trade Commission has explained, consumers can interpret claims that a product has a
general environmental benefit to mean that the product
has no negative environmental impact.
42 Consumers’
expectations for the environmental integrity of a
“green” product are directly at odds with the production methods for many biogenic feedstocks, such as
biomethane from cow manure lagoons. Policies that
create a market for biomethane inadvertently increase
pollution from industrial agriculture facilities, whose air and water pollution cause significant harm to
neighboring communities that are disproportionately
low-income and communities of color.
43 Producing hydrogen from fossil fuels with carbon
capture to reduce emissions (what is often referred
to as “blue hydrogen”) is also not compatible with a
zero-emission future. Even after an industrial facility installs expensive carbon capture technologies, it will continue polluting because that equipment is expected
to capture 85% to 95% of a facility’s climate pollution at best.
44 The process of capturing, compressing,
transporting, and storing carbon is energy intensive.45 With a power plant, for example, carbon capture can
consume 30-50% of the plant’s energy output.
46 Even if it were powered by renewable energy, the
environmental benefit of this added energy and cost
can be undermined by leakage of stored carbon.
47 Capturing carbon also does not reduce emissions of
most health-harming air pollutants, such as particulate matter and nitrogen oxide, and some researchers
estimate that it will lead to lifecycle increases of these pollutants in line with the additional fuel needed as a result of efficiency losses and increased energy use.
48 Figure 4: Carbon Intensities
of Hydrogen Production
*Source: Bartlett and Krupnick
2020; IEA 2019
**Source: NRDC 2021
† 2017 Data, does not include
upstream emissions
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16 Reclaiming Hydrogen for a Renewable Future
Moreover, carbon capture does not address the
significant upstream emissions from extracting and
then tr
ansporting gas across a leaky pipeline network.

In the pas
t few years, a growing number of studies
ha
ve revised upward the scale of unaccounted-for
leak
s of methane from gas production, processing,
transmission, and storage.49 Based on an analysis by
the Natural Resources Defense Council, accounting for
current upstream leakage at average rates reported
in
the United States would add another 2.1 kg CO2/
kgH2 to the carbon intensity of blue hydrogen—
roughly
double the onsite emissions for SMR with
90% carbon capture.50 Even the vice president of
Norwegian
oil company Equinor (which is aiming to be
a global leader in blue hydrogen production)
acknowledged that 100% carbon capture from
methane reforming is not physically possible, and
admits that upstream emissions risk “killing the
concept of blue hydrogen.”51
A recent United Nations
report warns that the
world must immediately
slash methane emissions
to stall near-term
warming and avoid
crossing irreversibly
damaging climatic tipping
points while we pursue
rapid decarbonization.

Extending and expanding
reliance on methane-leaking infrastructure ignores
this message.52 Capturing carbon from fossil-fueled
hydrogen production leaves these significant emissions
unabated, yet comes at substantial added cost—so far,
the cost of captured carbon has only been economically
feasible when the carbon is used for enhanced oil
recovery, which instigates further fossil fuel production and the related emissions.53 Consequently, industry
analysts and environmental groups alike warn that this
strategy is likely an unwise and distracting investment.54

2. LIMITATIONS OF GREEN HYDROGEN
Green hydrogen cannot deliver near-term emissions
reductions at scale because of several constraints: the significant amount of renewable energy that is lost
thr
ough conversion into green hydrogen, high costs,
difficulty of storage and transport, and environmental
challenges such as water demand from its production.

In sectors where industry might retrofit equipment
that burns fossil gas to burn hydrogen, there is the
additional risk that a transition to green hydrogen could increase air pollution. These constraints limit both
the supply of green hydrogen and our ability to use it.

Moreover, because dramatic reductions in greenhouse
gas emissions must begin this decade to avert climate
catastrophe, we must immediately decarbonize
sectors that have solutions available today and cannot
wait for the widespread availability of green hydrogen.

Therefore, proposals to use green hydrogen must be
vetted on a case-by-case basis to assess whether and
how they manage these constraints, and whether doing
so is more cost-effective than directly using renewable electricity. Because of its scarcity, competition for
green hydrogen among sectors could drive up the cost.

Conversely, limiting green hydrogen demand to only
essential sectors under scenarios with high renewable
penetration could allow its use at negligible extra cost. 55 In the short term, the only plausible economical option will be using renewable-driven electrolysis systems
for niche applications in hard-to-abate sectors where
infrastructure buildouts can be contained.
56 Energy inefficiency
Using renewable electricity to power electrolysis
results in substantial energy losses—anywhere
between 20 and 40% of the energy is lost.
57 Because
of this inherent inefficiency, green hydrogen will
always be a considerably more expensive fuel than
renewable electricity.
58 Not only is energy lost in the
process of making green hydrogen, but equipment
that uses green hydrogen is often less efficient than
its competitors. A comparison of space heating
technologies in buildings provides a good example
of the efficiency advantages of using renewable
energy directly as electricity instead of converting
it to hydrogen. Hydrogen-based, low-temperature
heating systems consume 500 to 600% more
renewable energy than heat pumps.
59 Heat pumps
can use renewable electricity on the power grid
directly and efficiently. Analysts describe heat pumps
Carbon capture
does not address
the significant
upstream emissions
from extracting and
transporting fossil gas.
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17 Reclaiming Hydrogen for a Renewable Future

INPUT ENERGY ENERGY CONVERSION TRANSMISSION CONVERSION TO HEAT ENERGY EFFICIENCY Renewable
electricity
Electricity grid
Gas gridElectrolyzer
Heat pump
Gas boiler
62%
230-410%
74%
92%
97%
250%-
450%
97%
Heat
pumps
Hydrogen
Figure 5: Comparison of efficiencies for hydrogen and heat pumps in homes Data source: Ed Reed, Hybrid hydrogen heating hopes, Cornwall Insight Ireland (Nov. 29, 2018), https://www.cornwall-insight.com/uploads/CoTW%20 Hydrogen_MH.pdf.
as having efficiencies greater than 100% because
they transfer ambient heat, rather than combusting
fuel to create it. Ultimately, heat pumps deliver warm
air and hot water 3 to 5 times more efficiently than
conventional furnaces and water heaters. As a result
of their superior efficiency, heat pumps are cheaper
to operate than equipment that burns fossil gas or
equipment that burns green hydrogen, and even
provide upfront capital cost savings when replacing
the combination of a gas furnace and air conditioner
(since heat pumps can provide both functions).
60 Because electrolysis is so energy intensive,
achieving substantial volumes of green hydrogen
for any major economic sector would require
enormous amounts of renewable electricity.

Just deploying enough clean energy to eliminate
emissions from the electricity sector by 2035 will
be a titanic effort, requiring a six-fold increase over historic rates of renewable energy deployment, even
if demand for electricity were static.
61 Transitioning
to electric vehicles and ditching gas appliances
for efficient electric technologies will dramatically
increase demand for electricity and the need for new
renewable resources.
62 Meeting the global demand
for green hydrogen that one industry group predicts
in 2050 could require the build out of solar resources
that cover more than 81,250 square miles.
63 This
is a land area larger than the state of Minnesota.

Using green hydrogen in segments that can use
direct electricity would exacerbate the challenge of
deploying sufficient renewable resources by wasting
renewable capacity on energy-intensive electrolysis.
64 Costs
Currently, conventional fossil hydrogen costs
between $1.25/kilogram and $2/kilogram in the
United States,
65 while green hydrogen costs between
$2.50/kilogram and $4.50/kilogram.66 Three sets
of analysts — BloombergNEF, Wood Mackenzie,
and McKinsey — have recently found that green
hydrogen could become cost-competitive by 2030
as economies of scale drive down the cost of
electrolyzers and the price of wind and solar power
continues to fall.
67 The Biden administration has
announced a goal of reducing the cost of green
hydrogen by 80% by 2030, indicating that federal
policy might help achieve price reductions even
greater than what analysts have predicted by the
end of the decade.
68 The biggest influence on the
cost of renewable hydrogen is the cost of the clean
electricity that powers its production. Low-cost green
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18 Reclaiming Hydrogen for a Renewable Future
hydrogen requires abundant, low-cost, renewable
energy.69 Increasing total deployment of renewable
energy is therefore a precondition for economically
producing appreciable amounts of green hydrogen.

It is important for policymakers to consider long-term
cost forecasts for green hydrogen when considering
permits for new gas-fired facilities if developers claim the new fossil fueled infrastructure could be retrofitted to run on green hydrogen. For example, a company
that recently proposed a new gas plant in Newburgh,
NY estimated that hydrogen in 2040 will cost $45/
MMBtu in nominal dollars.
70 In contrast, the most recent
Energy Information Administration 2020 Annual Energy
Outlook projects natural gas to cost well below $4/
MMBtu in 2040 (in 2019$) in its Reference Case.

Fuel costs would be
even greater for blends
of green hydrogen and
zero-carbon methane,
as the production of
“synthetic methane”
involves first making
green hydrogen and
then using the hydrogen
as an input into another
chemical process. Yet,
some industry members
and policymakers have
contemplated using blends of green hydrogen and
synthetic methane in residential and commercial
appliances, which were designed to burn
methane and cannot safely burn pure hydrogen.
71 A report prepared for the California Energy
Commission finds that “[e]ven under optimistic
cost assumptions, the blended cost of hydrogen
and synthetic natural gas is 8 to 17 times more
expensive than the expected price trajectory of
natural gas.”
72 The high costs of these gases make
it difficult for gas-burning appliances to compete
against electric options in a zero-carbon future.

The inefficiency of converting clean electricity into
hydrogen (let alone synthetic methane) before
using its energy will always make it more costly
than plugging directly into the electric grid.

Pollution from combustion
Burning hydrogen creates health-harming pollution.

Proponents of hydrogen will often note that hydrogen
fuel cells only emit water vapor, but many potential
applications for hydrogen involve combustion rather
than fuel cells. Hydrogen combustion’s most significant public health threat is oxides of nitrogen (NOx), a
pollutant that damages heart and respiratory function,
impairs lung growth in children, and leads to higher
rates of emergency room visits and even premature
death.
73 NOx is a precursor to both ambient ozone and
fine particulate matter pollution,74 and also contributes to climate change.75 One group of researchers predicted that burning pure hydrogen would emit more than
six times as much NOx as burning methane, the
main component in fossil gas.
76 NOx emissions could
be reduced through advances in pollution control
technology or by lowering flame temperatures, but
this requires either lower volumes of hydrogen in the
combustor (and consequently, increased reliance
on fossil fuels) or de-rating the engine which results
in efficiency losses and power decreases.
77 Industry
should not be allowed to increase hydrogen combustion
without first demonstrating control technologies
that will avoid increases in NOx emissions. In 2018,
air pollution from fossil fuel combustion was linked
to roughly 355,000 premature deaths in the United
States—pollution that African Americans were exposed
to at a rate 1.54 times that of the overall population. 78 As long as combustion continues, proposals to reduce greenhouse gases by displacing some or all of the fossil fuels with hydrogen will not alleviate the uneven burdens of air pollution, and may even worsen them.

Safe transport and storage
Today, the majority (around 90%) of hydrogen in the
United States is produced at or adjacent to where it is used (either onsite by petroleum refineries that use it themselves, or by nearby gas companies that deliver it
by pipeline).
79 Transporting hydrogen is expensive due to
its low energy density, which means that large amounts
of space are required to hold a relatively modest amount of hydrogen energy. By way of comparison, to have
hydrogen replace the energy supply of fossil gas in the global economy would require building 3 to 4 times more storage and pipeline infrastructure.
80 To have hydrogen replace
the energy supply of
fossil gas in the global
economy would require
building 3 to 4 times
more storage and
pipeline infrastructure.
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19 Reclaiming Hydrogen for a Renewable Future
Safely transporting, storing, and handling hydrogen
can add significant costs. For instance, it only costs
a few dollars per kilogram to produce hydrogen from
fossil gas, which is how most hydrogen is produced
today in California and across the United States. Yet
the average retail price of hydrogen at fueling stations in California is about $16.50 per kilogram—the
equivalent of about $6.40 per gallon of gasoline.
81 Precautions against leaks are also necessary at each stage of handling hydrogen. Containing hydrogen is
more challenging than containing other gases because
hydrogen is the smallest and lightest molecule in
the universe; 50,000 molecules of hydrogen gas can
fit in the width of a human hair.
82 It is also extremely
flammable, making it susceptible to combust even in
small concentrations.
83 Deliberate steps are necessary
to detect leaks because hydrogen is a colorless and
odorless gas.
84 Leakage could diminish the climate
benefits of a transition to green hydrogen because
hydrogen itself is a greenhouse gas that is more than
five times more potent than CO

2.85 The three main ways of transporting hydrogen
are by pipelines, trucks or rail, and ships, each of
which would require massive investments in new
infrastructure to transport hydrogen at scale:
(1) Pipelines: Pipelines are the most cost-
effective means of transport. Hydrogen
pipelines today are very limited; there are
only about 1,600 miles of dedicated hydrogen
pipelines in the United States—mostly
clustered in Southern California and along
the Gulf Coast in Texas and Louisiana near
refineries and chemical plants. Building a
hydrogen pipeline can cost up to 68% more
per mile than a conventional fossil gas
pipeline.
86 It is important not to confuse
hydrogen pipelines with the United
States’ vast network of gas pipelines
that were designed to deliver methane
because these fossil gas pipelines cannot
carry meaningful volumes of hydrogen.

Hydrogen’s size and energy density make
it incompatible with generic pipeline
materials and compressor designs.
87 Hydrogen can cause “embrittlement” in
pipes and its higher flammability and leakage
rates create safety risks.
88 Conventional gas
pipelines do not have systems for detecting
leaks of hydrogen.
89 Thus, the lowest cost
manner of transporting pure hydrogen
would require massive investments in
dedicated pipeline networks.
(2) Trucks and rail: Hydrogen can also be
transported in high-pressure tube trailers on
trucks or rail cars. Compression in tube trailers
is expensive, however, and is only suitable for
small volumes over short distances of 200
miles or less.
90 Unless the trucks used to
CAN WE RETROFIT EXISTING PIPELINES TO CARRY PURE HYDROGEN? The first question to ask if the fossil fuel industry claims it can use existing gas infrastructure to deliver hydrogen is whether they are talking about pipelines that deliver gas to homes and commercial businesses. These “distribution” pipelines cannot be retrofitted to deliver pure hydrogen. The gas-burning appliances in homes and commercial buildings cannot burn hydrogen without an unacceptable risk of explosion. For insights into industry arguments for blending small amounts of hydrogen into distribution pipelines, see Section IV .

In contrast, the “transmission” pipelines that carry fossil gas from production centers to storage facilities and industrial users could conceivably be retrofitted to carry pure hydrogen. This retrofit would require significant costs, including replacing all of the pipeline’s compressors. 960 of 983
20 Reclaiming Hydrogen for a Renewable Future
transport the hydrogen are themselves zero-
emission, then this comes with significant
air pollution and greenhouse gas impacts of
diesel combustion.
(3) Ships: For longer, intercontinental transport,
hydrogen could be liquefied and transported
by ship. Ships could transport relatively large
volumes of liquid hydrogen, but liquefaction
is expensive, and requires energy-intensive
(and costly) chilling of hydrogen (to -252°C).

Alternatively, ships can carry ammonia (they
already do) as an energy carrier (ammonia
is NH
3—meaning it carries three hydrogen
molecules for each molecule of nitrogen). But if
hydrogen is ultimately the desired commodity at
its destination, this requires costly and energy-
intensive re-conversion at the point of use.

The low energy density of hydrogen presents similar
challenges for hydrogen’s storage. Kept in a gaseous
state, hydrogen storage requires large amounts
of space. The cheapest solution is geologic salt
caverns, which could store weeks’ or months’ worth
of hydrogen, but these are geographically limited.
91 Pressurized containers could in theory be built
anywhere, but their footprint and cost would limit
them to small (days’ worth) volumes.
92 To shrink
hydrogen’s footprint, it can be cooled and compressed
to a liquid state, or converted to ammonia, but these
present the same temperature and energy conversion
loss challenges as shipping, mentioned above.
93 All
storage options present risks, which planners should
evaluate on a case-by-case basis.
94 Water use
Electrolysis uses freshwater as a feedstock and is thus a significant source of freshwater demand. Producing
one kilogram of green hydrogen requires between
9 and 11 liters of water as a feedstock.
95 Because
additional water is also required for system cooling,
total water demand can be between 15 and 20 liters
of water for each kilogram of green hydrogen.
96 On a
global basis, the water demand for electrolysis is far
less than the water requirements for extraction and
processing of fossil fuels. Still, climate change will
constrain global freshwater resources in significant
ways—e.g., by increasing evaporation and droughts,
altering precipitation patterns, melting freshwater
stored in glaciers, and contaminating aquifers with
saltwater from rising sea levels.
97 These impacts will
mean water-stress will both expand and intensify.

Regions with the potential to produce low-cost,
abundant green hydrogen may intersect with areas of
water-stress, presenting localized resource challenges.

For example, many of the most-often discussed
“solar-hydrogen superpowers” are in regions with high
insolation like North Africa, the Middle East, and the U.S.

Southwest—all regions with extreme drought risk.
98 Some researchers are exploring ways to use low-grade and saline water for electrolysis, which could open
more opportunities for green hydrogen production in
regions facing water scarcity.
99 Time
Today, less than 1 percent of hydrogen is produced
through electrolysis and less than 0.02% is
entirely produced from renewable electricity
(i.e., green hydrogen).
100 Dramatic reductions in
climate pollution cannot wait until the 2030s,
when we expect to see significant cost declines
and increased availability for green hydrogen.

Maintaining a reasonable chance of limiting
warming to 1.5° C requires more than half of global
emissions reductions to happen before 2030—a
commitment the Biden administration made
in its latest submission of the United States’
Nationally Determined Contributions under the Paris
Agreement.
101 In reality, for wealthy nations like the
United States, which is also the largest historical
emitter of greenhouse gases, even steeper and earlier
reductions must be made, since poorer nations will
require more time and carbon budget to develop.
102 To
reduce emissions as rapidly as possible, mitigation
must take full advantage of solutions that already
exist and can be quickly deployed starting today.

The urgent need for near-term reductions means we
cannot afford to wait for the commercial availability of green hydrogen to decarbonize sectors that already
have decarbonization tools.
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21 Reclaiming Hydrogen for a Renewable Future
IV .IDENTIFYING THE PROMISING APPLICATIONS FOR GREEN HYDROGEN This section explores the potential for various
sectors to use green hydrogen as a cost-effective
decarbonization tool. Below, we have sorted
different applications in terms of their suitability for decarbonization with green hydrogen, using basic
questions that policymakers can apply to any sector
or potential hydrogen project. As a general principle,
policymakers should never delay deployment
of cost-effective decarbonization tools that are
available today based on the hope that green
hydrogen might become available in the future.

1. LEAST-REGRETS USES FOR GREEN

HYDROGEN
Displace fossil hydrogen in current uses as an
industrial feedstock
As discussed in Section I, industry currently
produces so much hydrogen from fossil fuels that
hydrogen production is a significant climate threat.

Green hydrogen could avoid these emissions
without requiring new technologies for hydrogen
use. Industrial clusters that have hydrogen
customers grouped in a small geographic footprint
would allow for supply to be delivered by dedicated
pipeline (the cheapest mode of delivery), and
leverage existing storage infrastructure.

As the energy transition proceeds, demand for
oil refining and chemical fertilizer production
should decrease: sustainable and zero-emission
transportation would reduce reliance on petroleum,
and sustainable practices would reduce reliance
on chemical agriculture inputs. In the next decade,
while oil refining is required to meet increasingly
stringent fuel specification standards, hydrogen
demand may grow in the refining sector, and it would
be a win for both the climate and public health if
these inputs are instead supplied by green, zero-
emission hydrogen. However, the potential for green
hydrogen to displace fossil hydrogen cannot be a
justification for expansion of refineries or chemical
fertilizer plants. It should only be considered as
a clean feedstock for existing, polluting systems
that must rapidly wind down to meet climate and
environmental justice objectives.

2. SECTORS TO EXPLORE WITH CAUTION
Maritime shipping
Global maritime transport accounts for roughly
3% of global greenhouse gas emissions, and is
responsible for roughly 15% of global emissions of
sulfur oxides and nitrogen oxides—pollution that
disproportionately harms public health in port-
adjacent communities.
103
Inland vessels, ferries, and other smaller ships
sailing shorter distances can already be powered
using batteries and operate with zero-emissions.
104
The unexpected pace of technological progress in
batteries has even led companies to begin building
and piloting battery-powered zero-emission tankers
and container vessels.
105 Given challenges to
recharging batteries that need to cross thousands
of miles of ocean, however, reliance on liquid fuels
in international voyages is unavoidable for the
foreseeable future.

Recent reports identify green hydrogen and green
hydrogen-derived ammonia as a promising path to
decarbonizing ships with longer voyages.
106 Green
ammonia (derived from green hydrogen plus nitrogen
in the atmosphere) is viewed as slightly more
promising because it is easier to store and requires
less space than pure green hydrogen for a given energy
content.
107 If used in internal combustion propulsion
systems, ships burning green hydrogen or ammonia
will still emit air pollutants such as NOx (and unburned ammonia—a pollutant that is toxic to both humans and
aquatic life).
108 To reduce air pollution, green ammonia
or hydrogen should be used in fuel cells, a solution that is less established than combustion engines but is
being piloted for some long-voyage vessels.
109
IV
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22 Reclaiming Hydrogen for a Renewable Future
Are there currently
technologies for using
hydrogen in this sector?
Would use of
green hydrogen
require significant
investments
in hydrogen
transportation and
storage?
Are lower-cost
decarbonization
strategies available for
this sector today?
Is green hydrogen likely
to be necessary to
decarbonize this sector?
Air pollution impacts
of transition to green
hydrogen

LE AST-

REGRETS

USES FOR
GREEN

HYDROGEN
Displace fossil hydro-
gen currently used as
an industrial feedstock
Yes Not if green hydrogen
is produced on-site.

No Yes A transition to green
hydrogen would avoid air
pollution from current
hydrogen-production
practices.

EXPLORE
WITH

CAUTION
Maritime shipping No Yes No Yes A transition to green
hydrogen or green
ammonia would reduce
emissions from vessels,
especially if they used
fuel cells.

Aviation No Yes No Yes Potential for emissions
reductions if planes use
green hydrogen in fuel
cells, rather than burning
hydrogen.

Industrial processes
that require heat above
400°C (such as steel
production)
Requires case-specific
analysis
Yes Partially Maybe Depends on what fuel
the green hydrogen
would displace. If a fa-
cility is currently burning
fossil gas, a transition
to green hydrogen com-
bustion will not reduce
(and may increase) NOx
emissions.

Long-term storage of
renewable electricity
paired with fuel cells
Yes, fuel cells that can
deliver stationary power
exist and are in operation
around the world today.

Yes No. Current technologies
enable us to cost-effec-
tively achieve 90% clean
energy on the electric
grid by 2035, but do
not offer solutions for
long-term storage of
renewable energy.

Maybe. It is unclear what
technology will emerge
as the most cost-effec-
tive tool for long-term
storage of renewable
electricity.

Green hydrogen using
fuel cells can eliminate
on-site air pollution.

Long-haul trucks and
trains
Fuel cells are commer-
cially available, but are
still being piloted and
tested for long-haul
trucking in the United
States (>200 miles a day)
and line haul locomotives
(cross country).

Yes Partially Maybe. Battery-electric
and overhead catenary
systems are the two
primary alternatives for
zero-emission long-haul
transportation. Hydrogen
fuel cells may be able to
outcompete the demand
for batteries and high-ca-
pacity charging for long,
heavy-duty hauls, and the
infrastructure costs of
overhead lines.

A transition to green hy-
drogen fuel cells would
avoid health-harming
tailpipe emissions.

REJECT
THE

HYDROGEN
HYPE
Combusting
hydrogen in new,
existing, or expanded
fossil gas power
plants
Current turbines can
handle small amounts of
blended hydrogen, but
running on pure hydrogen
requires yet to be demon-
strated modifications.

Yes N/A. However, unsub-
sidized solar and wind,
even when paired with
batteries, are much
cheaper than gas plants
running on even modest
blends of hydrogen,
which would have
minimal greenhouse gas
reduction benefits.

No, gas plants are best
decarbonized by being
decommissioned.

Hydrogen blends run-
ning in gas turbines are
likely to increase NOx
pollution.

Industrial processes
that require heat below
400°C (e.g., food and
beverage processing,
packaging, textile,
and some chemicals
processing)
No Depends on facility Yes No Burning hydrogen
would cause more air
pollution than electric
alternatives.

Gas-burning appli-
ances in homes and
commercial buildings
Gas-burning applianc-
es can tolerate some
blending of hydrogen into
the gas mixture, but it is
unclear how much.

Yes Yes No Indoor air pollution
would continue and may
worsen.

Cars, buses, and
short- haul trucks
Yes Yes Yes No Like battery-electric
vehicles, fuel cell
vehicles have no tailpipe
pollution.

Figure 6: Evaluating potential applications for green hydrogen 963 of 983
23 Reclaiming Hydrogen for a Renewable Future
These paths are preferred to both biofuels, which a
World Bank report dismisses as “highly unlikely to
be available at sufficient scale and to be sufficiently cost-competitive” and synthetic carbon fuels, which
they conclude “involves multiple energy-intensive
steps which leads to poor energy efficiency. ”
110
Aviation
Aviation emits more than 2% of global CO
2 emissions and is expected to rapidly rise. 111 Like
maritime shipping, the aviation sector may not be
able to rely on widespread electrification to eliminate emissions, given the limitations of batteries and
charging for long-haul routes. Independent experts
have identified using renewable electricity to
produce hydrogen or kerosene (derived from green
hydrogen) as a potential path to decarbonizing
aviation, with some companies already piloting its
potential for short-haul flights under 500 miles.
112
Some startups are investigating the potential for
hydrogen-powered aviation, with some developing
hydrogen “capsules” that would be interchangeable,
and will be piloted in aircrafts powered by fuel cells
capable of regional flights up to 700 miles, with a
goal for actual flights by 2025.
113
High-heat industrial processes
Green hydrogen may play an important role in de-
carbonizing high-temperature industrial processes,
such as steel production, that do not have electric
decarbonization options. Steel production is an
industry for which green hydrogen is an especially
attractive decarbonization strategy because green
hydrogen could provide both high-temperature heat
and replace coking coal in the iron-ore reduction
process. Meanwhile, many industrial processes use
temperatures well within the range of lower-cost
alternatives. Electric heat pumps will probably be the
most cost-effective option for decarbonizing indus-
trial processes that require heat up to 400°C.

Currently, about 40% of gas used for industrial heat is for temperatures less than 100°C—like for food, bev-
erage, and textile processing, packaging, and some
chemicals processing.
114 Even for higher temperature
heating demands, other electricity based options are
commercially established (e.g., electric arc furnaces,
resistance, microwave and plasma heating). Electric
arc furnaces are now used in some steel production
and can reach temperatures up to 3500°C.
115
Long-haul trucks and trains
Hydrogen fuel cells are already in use in the transpor - tation sector, but they are significantly more expen-
sive, and would require significantly more renewable
electricity, than battery-electric vehicles.
116 These
constraints limit their potential to segments of the
surface transportation sector where, like shipping
and aviation, batteries are not soon expected to
achieve necessary energy density or refueling needs
for long, heavy-duty hauls. Locomotives that carry
heavy freight across the country, for example, need
so much energy that an entire rail car of batteries
might be required where catenary or other electrified
rail infrastructure is not feasible ,
117 and some worry
that battery weights could penalize the payload of
long-haul trucks (though jurisdictions like California
and Europe have passed additional zero-emissions
vehicle weight allowances) .
118 While some analyses
show that the current and rapidly advancing state
of battery cost and performance will overcome
these concerns, the need for high energy density
and fast refueling times makes hydrogen fuel cells
a potential solution for these surface transportation
segments.
119 A few truck manufacturers continue to
explore hydrogen fuel cells for long-haul trucks, 120
and hydrogen fuel cells are being used to displace
diesel engines in some locomotives.
121
Long-term storage of renewable electricity paired
with fuel cells
The near-term focus for decarbonizing the electric
grid should be dramatically increasing deployments
of renewable resources and batteries—the mature
technologies that can cost-effectively supply
80% of the United States’ electricity by 2030 and
90% of electricity by 2035.
122 Achieving a zero-
carbon grid will require a variety of energy storage
technologies that can store renewable energy over
different time scales. Green hydrogen’s advantage
is that it could economically store renewable
energy for long periods of time with minimal energy
964 of 983
24 Reclaiming Hydrogen for a Renewable Future
loss.123 It is unclear whether green hydrogen will be
able to compete against other long-term energy
storage technologies, such as compressed air and
electrochemical storage.
124
Fuel cells would be the
appropriate technology
for re-converting green
hydrogen into electricity.

Most importantly, fuel
cells do not present
the substantial air
pollution concerns that
come with combustion
turbines because fuel
cells only emit water
vapor.
125 Further, fuel
cells can operate at
higher efficiencies
(up to 60%) than combustion power plants (about
40%).
126 Fuel cells can be sited in urban settings near
the customers who rely on them because they are
quiet and do not emit air pollution, helping to reduce
expensive investments in the transmission system
and the risk of power outages when transmission
lines fail.
127 Fuel cells are an established and
commercially available technology, unlike burning
pure hydrogen in power plant turbines. And because
fuel cells rely on the same principal processes as
electrolyzers (they are essentially electrolyzers
that work in reverse) they are likely to benefit from
the expected cost declines that will come from
increased investment in green hydrogen.

The main drawback of fuel cells is that they tend
to have smaller energy capacity compared to
combustion turbines and have initially been limited
to meeting smaller energy demands. But this is
changing—fuel cells can provide power for systems
as large as utility power stations, and groups of
modular fuel cell systems have been joined to
create small power plants up to 63 MW in size.
128
While the larger deployments of solar and wind
necessary to generate surplus renewable energy
continue to be scaled, higher capacity fuel cell
technology and costs are likely to improve. In the
meantime, it is important that policymakers and
energy system planners seek ways to prioritize their
deployment in place of alternatives that would rely
on combustion and its corresponding air pollution.

3. SECTORS WHERE HYDROGEN IS NOT A

SOLUTION
In these sectors, there are unique and likely
insurmountable challenges to cost-effectively
deploying green hydrogen, in addition to the cross-
cutting challenges described in Section II. Please
see page 18 for information about the infrastructure
needed to safely transport and store hydrogen and
page 17 for information about the deployments of
wind and solar resources that will be necessary to
drive down the cost of green hydrogen.

Combusting in fossil gas power plants
Several entities have supported proposals for in-
vestments in gas-fired power plants with claims
that their new fossil fuel infrastructure could one
day transition to burning green hydrogen.
129 These
proposals often lack meaningful consideration of the
substantial barriers to retrofit a gas plant to wholly
or even partially run on green hydrogen. The project
proponents’ vague claims about hydrogen are likely a
tactic for dismissing climate and public health con-
cerns about expanded fossil fuel reliance.

There are no commercially available power plant
turbines now that can burn pure hydrogen. Without
this technology, even power plants that have access
to green hydrogen will continue to burn a mixture of
hydrogen and fossil gas. Even burning a gas blend
with 50% green hydrogen and 50% methane would
require industry to overcome significant obstacles.

Hydrogen’s energy density (one-third of fossil gas),
molecular size (the smallest of all molecules), flam-
mability, and flame speed (an order of magnitude fast-
er than fossil gas)
130 all pose challenges to retrofitting
gas plants to run on green hydrogen, which scale with
increasing concentrations of hydrogen in the power
plant’s fuel blend. Beyond the turbine itself, running a gas turbine on pure hydrogen requires different fuel
delivery piping and components; different gas turbine
controls, ventilation systems, and enclosures; and
different selective catalytic reduction systems for
Importantly, fuel cells
do not present the
substantial air pollution
concerns that come with
combustion turbines,
because fuel cells only
emit water vapor.
965 of 983
25 Reclaiming Hydrogen for a Renewable Future
0%
3%
7%
12%
18%
24%
32%
43%
56%
74%
100%
0%
10%
20%
30%
4 0%
5 0%
60%
70%
8 0%
90%
10 0%
0 10 20 30 40 50 60 70 80 90 100
Percent Reduction in CO2
Hydrogen (Volume %)
NOx removal.131 Many of these are also needed for high
blends of hydrogen mixed with traditional gas.132
Even if logistical challenges can be overcome to allow
gas-fired power plants to burn a gas blend with even
30 to 50% green hydrogen, this feat will have a mod-
est effect on greenhouse gas emissions. For example,
a 30% hydrogen blend would only achieve a 12% CO
2 Figure 7: Relationship
between CO2 emissions from
combustion and hydrogen/
methane fuel blends
(volume %)

THE INTERMOUNTAIN POWER

PROJECT
The project with the most advanced plans
for transitioning to green hydrogen is the
Intermountain Power Project in Utah. This
facility has access to underground salt caverns
for storing hydrogen, which do not exist in
most parts of the country, and abundant
renewable generating capacity as well as
existing transmission lines. This intersection of
low-cost storage, delivery, and energy capacity
conditions is likely to be extremely limited
across the United States.
reduction. This is because of hydrogen’s low energy
density, which means that large volumes of hydrogen
deliver less energy than the methane in fossil gas.

The air quality impacts of combustion turbines will not only persist if they transition to hydrogen, but will wors- en absent satisfactory advances in emission control
technology. Indeed, it is unclear if and when industry
will develop turbines that can burn hydrogen without
violating air quality standards. Transitioning to hydro- gen-burning turbines threatens to increase air pollu-
tion because hydrogen burns at a higher temperature
than methane. A study conducted by General Electric
on its combustion turbines found that a 50/50 mix-
ture of hydrogen and fossil gas (by volume) increased
concentrations of NOx in gas exhaust by 35 percent.
133
A recent report by a gas turbine industry association
warned that these higher flame temperatures will
produce more health-harming NOx emissions “if no ad-
ditional measures are undertaken.”
134 The industry as-
sociation recommended that “[s]ome flexibility might
be needed on NOx limits,” noting that complying with
pollution standards will be even more challenging if
governments adopt the stronger NOx limits it foresees
in the future.
135 For these reasons, regulators should
not allow any increases in hydrogen blending without
966 of 983
26 Reclaiming Hydrogen for a Renewable Future

GREENWASHING SPOTLIGHT
Danskammer Energy LLC is proposing to build a new 636 MW fossil gas combined cycle plant in the Town of Newburgh, New York. Under the Climate Leadership and Community Protection Act (“CLCPA”), New York has committed to achieving ambitious greenhouse gas reductions by 2030 and 2050, 70% renewable electricity by 2030, and a zero-emission electricity sector by 2040. Danskammer maintains that its proposed fossil gas plant will comply with state law because the proposed plant could theoretically someday convert to operation on hydrogen or another zero-carbon fuel and has floated the possibility of a hydrogen pilot study post-construction. However, the Company does not explain—and does not appear to know—how operating the proposed plant on hydrogen would actually work, including where the hydrogen might come from and how it would be transported to and stored on-site. When asked for additional details, Danskammer conceded that it is not proposing to operate on green hydrogen as part of the project under review, basic details on the potential hydrogen pilot project are not available at this time, and further approvals would be necessary in connection with any proposal to operate on hydrogen. Unsurprisingly
then, Danskammer does not commit to a hydrogen
transition and does not even plan to develop a scope
for any pilot study until sometime after its proposed
plant is approved to run on fossil gas. Moreover, after reviewing Danskammer’s application for a facility
air permit, the Commissioner of the New York State
Department of Environmental Conservation tweeted
that the application does not justify the project or show compliance with the CLCPA.

Source: Basil Seggos, https://twitter.com/basilseggos/sta- tus/1410334434595946496.
reviewing the adequacy of a facility’s emission controls and establishing an emissions monitoring program.

Regulators should set specific limits on a facility’s NOx emissions during startup periods; gas turbine NOx
emissions often spike before their pollution controls
warm up and a transition to hydrogen could exacerbate
these spikes of uncontrolled emissions. This is a public health concern for residents living near such a facility and especially in non-attainment areas, which may
potentially increase the disparate impact many fence-
line communities already bear in this country. Without
sufficiently improved pollution control technology, an- other alternative would be to lower the flame temper-
ature by “derating” the turbine, which means that the
unit would not operate at its full nameplate capacity.
136
This strategy could increase the risk of power outages
if grid planners had assumed these plants will be able
to perform at capacity when needed.

Water use is another environmental burden that will
persist regardless of whether combustion turbines
transition to green hydrogen. Fossil-fueled power
plants are the nation’s top user of fresh water and
demand tremendous amounts of water for cooling.

As the climate changes, there will be less fresh water
available to cool these power plants—putting their
continued operation at risk.137
Fi
nally, policymakers should not permit the buildout
of new gas-fired power plants un der the assump -
tion that it will be economical to operate these
facilities with green hydroge n. As mentioned above,
a company that recently propos ed a new gas plant
in Newburgh, Ne w York estimated that hydrog en in
2040 will cost $45/MMBtu in nom inal dollars. 138 In
contrast, the most recent Energ y Information Ad -
ministration 2020 Annual Energy Ou tlook projects
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27 Reclaiming Hydrogen for a Renewable Future

BEWARE THE HYPE AROUND HYDROGEN BLENDS
Southern California Gas Company and San Diego Gas & Electric Company brag in press releases about proposing “groundbreaking” research that could allow them to deliver gas with an “industry-leading” 20% hydrogen blend, calling it a “key milestone in our efforts to decarbonize our energy system.”* If these companies find a way to safely deliver a gas mixture that is 20% green hydrogen and 80% fossil gas, their gas will still be a major climate threat. Because of hydrogen’s low energy density, burning a gas blend with 20% green hydrogen will only reduce carbon dioxide emissions by about 7%. This is close to the ceiling for how much hydrogen the gas companies could deliver to homes and businesses before creating an explosion risk in gas-fired residential appliances, which is around 25% hydrogen.** * Southern California Gas Company & San Diego Gas & Electric Company, SoCalGas and SDG&E Announce Groundbreaking Hydro- gen Blending Demonstration Program to Help Reduce Carbon Emissions (Nov. 23, 2020), https://www.prnewswire.com/news-re- leases/socalgas-and-sdge-announce-groundbreaking-hydrogen-blending-demonstration-program-to-help-reduce-carbon-emis - sions-301178982.html.
** Jeff St. John, Green Hydrogen in Natural Gas Pipelines: Decarbonization Solution or Pipe Dream?, Greentech Media (Nov. 30, 2020), https://www.greentechmedia.com/articles/read/green-hydrogen-in-natural-gas-pipelines-decarbonization-solution-or-pipe-dream. natural gas to cost well below $4/MMBtu in 2040 (in
2019$) in its Reference Case .139
Gas-burning appliances in homes and
commercial buildings
Burning fossil fuels to keep us warm in the winter, heat our water, and power other appliances collectively
contributes about 10% of the nation’s greenhouse
gas emissions.
140 Climate policy poses an existential
threat to America’s gas companies because the most
cost-effective way to tackle these emissions is by
transitioning from appliances that burn fuel to electric appliances that run on a decarbonized power grid.
141
In the face of this threat, hydrogen has emerged
as a new tool for the gas industry to sow confusion
and combat measures that would help homes and
businesses transition to electric appliances.

Multiple independent studies show that there is a
weak economic case for deploying green hydrogen
in buildings through the gas distribution grid.
142 The
main reason is the superior efficiency of heat pumps,
which use small amounts of renewable electricity to
move ambient heat to where it is needed. One recent
Pacific Gas & Electric Company-funded study found
that California could save $20 billion by choosing
a high electrification pathway instead of relying
on renewable gases like hydrogen and synthetic
methane in buildings.
143 Heat pumps for space and
water heating are not only the cheapest of all zero-
carbon options—in many instances, their superior
efficiency means they will yield cost savings relative
to conventional gas-based heating systems.
144
There are several reasons why green hydrogen is
a bad fit for addressing the pollution from gas-
burning appliances:
(1) Injecting green hydrogen into the
gas system could require significant
investments into a system that was not
designed for hydrogen. In California, the
regulated gas utilities have proposed a pilot
project to study how much hydrogen they
might safely inject into the gas distribution
system, and under what conditions. The
utilities identified numerous potential safety
and reliability risks they intend to study.

For example, the elastomers and rubbers
that seal many pipeline components can
swell or develop voids after exposure
to pure hydrogen; hydrogen can cause
embrittlement of steel pipes; and the utilities
do not know how much hydrogen they can
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28 Reclaiming Hydrogen for a Renewable Future

BIOMETHANE
Biomethane—sometimes referred to as
“biogas,” “renewable natural gas,” or “RNG”—is
methane generated through the decomposition
or gasification of organic matter. The most
common sources of biomethane are landfills,
animal manure from factory farms, wastewater
treatment plants, forest and agricultural waste
products, or crops grown for the specific
purpose of converting into energy.

While gas utilities—often in partnership with
industrial agribusiness—have promoted
biomethane as a drop-in alternative to fracked
gas, the actual supply of non-fossil gases is
extremely limited. And despite the industry’s
branding of this gas as “renewable,” much of it
comes from sources that are highly polluting,
and can perversely increase greenhouse gas
emissions. The small fraction of biomethane
that is genuinely sustainable to produce
cannot justify anything close to the current gas
distribution system, and is best allocated to
niche, hard-to
-electrify end uses.

For a more detailed look at the industry’s misleading claims about biomethane, see Earthjustice’s report with Sierra Club:

Rhetoric vs. Reality: the Myth of “Renewable Natural Gas” for Building Decarbonization. Sasan Saadat et al., Rhetoric vs. Reality: the Myth of “Renewable Natural Gas” for Building Decarbonization (July 2020), https://earthjustice.org/report/ building-decarbonization.
safely store in the underground formations
that they rely on for gas storage. Because
hydrogen molecules are much smaller than
methane molecules, utilities may also need
to upgrade their infrastructure to prevent
it from leaking into the atmosphere. When
a pipeline carries a blend of hydrogen and
methane, hydrogen can leak at three times
the rate of methane.
145 Regulators should not
let gas utilities force their captive customers
to bear the costs of modifying pipeline
infrastructure to carry hydrogen safely and
with minimal leakage. It is unreasonable
for resources to go toward hardening a gas
system that has no role in a zero-emission
future, rather than reserving resources for
building electrification.
(2) Even after blending in green hydrogen,
the gas system hits a dead end as a
decarbonization tool. Regardless of whether
retrofits could theoretically enable the gas
system to deliver pure hydrogen to homes
and businesses, local gas utilities could not
do so. At most, gas utilities can blend limited
amounts of hydrogen with methane because
appliances that were designed for methane
gas cannot safely burn pure hydrogen.
146
The most optimistic scenarios estimate
that the gas system that serves homes and
most businesses could only handle up to
20% hydrogen by volume—representing
just 7% of the energy in the gas pipeline
system because hydrogen is less energy
dense than methane.
147 In that case, fully
decarbonizing the gas system would require
the gas utilities to procure enough renewable
methane to supply the remaining 93% of
energy need on the system. There is no
feasible way to displace 93% of the country’s
fossil gas demand with non-fossil sources
of methane. Even under the gas industry’s
“high resource potential” scenario, methane
from landfills, animal manure, food waste,
and water treatment facilities could displace
less than 9% of the fossil gas this country
currently uses each year.
148 The same report
identifies various methods of creating
additional methane that could displace up
to 19.5% of America’s gas consumption in
its most aggressive scenario.
149 The gas
industry’s claims about the potential for
supposedly “renewable natural gas” may
be overly optimistic. A report by the Union
of Concerned Scientists found that there is
only enough potential biomethane supply to
displace about 3% of California’s fossil gas
use.
150 Other sources of “renewable natural
gas” are being studied, but are decades
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29Reclaiming Hydrogen for a Renewable Future

GREENWASHING SPOTLIGHT
Across California, local governments have adopted policies that encourage new buildings to use all- electric appliances as a cost-effective strategy to reduce greenhouse gases. The nation’s largest gas utility, Southern California Gas Company (SoCalGas), has repeatedly fought these commonsense measures by urging policymakers to instead consider the possibility that gas companies’ infrastructure could deliver hydrogen and other so-called “renewable” gases. For instance, the company made the following argument in its attempts stop Ventura County from blocking the build-out of fossil gas infrastructure to new homes:*
SoCalGas urges the County to consider other GHG emission-reduction strategies that are scalable and easier to implement, more resilient and more affordable. Specifically, the use of renewable gasses such as hydrogen and renewable natural gas (RNG), are low carbon to negative fuels that can dramatically reduce county greenhouse gas emissions and provide optionality and flexibility for the energy system.

This is self-serving hype from the gas company. Despite its vague claim that green hydrogen is “more affordable” and “easier to implement” than using all-electric appliances in new homes, SoCalGas has never revealed the potential cost of procuring green hydrogen and upgrading its infrastructure to handle hydrogen blends. Promoting the interests of its shareholders, SoCalGas is invoking the future potential of hydrogen to stop policymakers from choosing climate solutions that are cost-effective today. * SoCalGas, Comment letter RE: County of Ventura – Draft 2040 General Plan Update EIR (Feb. 28, 2020) at 12. away from commercialization. 151 Even if a
gas company could buy a blend of zero-
carbon gas, the cost would be exorbitant—
potentially 8 to 17 times the cost of natural
gas.
152 Thus, the current and potential future
supplies of non-fossil gases do not alter
the imperative to quickly and dramatically
reduce gas throughput.
(3) Injecting hydrogen into the gas system
does not eliminate—and may increase—
the indoor air pollution from gas-burning
stoves, furnaces, and other appliances.

Unlike electric appliances, all gas-burning
appliances emit nitrogen oxides, pollution
that contributes to respiratory and heart
diseases.
153 Under the status quo, gas
combustion for heating and cooking results
in significant NOx pollution and other
combustion byproducts that would be
considered illegal if measured outdoors.

Recent studies show that children growing
up in homes with gas stoves have a 42%
increased risk of developing asthma
symptoms.
154 In their joint application to
the California Public Utilities Commission
to research the compatibility of hydrogen
blends with their infrastructure, the California
gas utilities acknowledged that blends of
hydrogen and methane “may yield higher NOx
emissions than natural gas because hydrogen
burns faster than natural gas, which increases
combustion temperatures and reduces
ignition lag. . . . therefore, additional emissions
testing should be completed with natural gas
end-use equipment operating with hydrogen
blends.”
155 Regulators should not allow gas
companies to inject hydrogen into their
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30 Reclaiming Hydrogen for a Renewable Future
H2

WELL -TO-TANK TANK-TO-WHEEL
Renewable
electricity
Battery-electric
vehicle (BEV)
Fuel-cell electric
vehicle (FCEV)
Transportation
and storage
Electric Battery
(high capacity)
E-Engine
Fuel cell and
power generation
Transportation
and storage
Compression and
liquefaction
Electrolysis Electric Battery
(low capacity)
E-Engine
100%
~25-35%
Overall efficiency rate
~70-90%
Overall efficiency rate
ENERGY
Figure 8: Comparing the efficiency of renewable energy in battery and fuel cell vehicles Data source: Volkswagen (2020)
distribution systems unless independent
researchers find that doing so will not further
degrade indoor air quality.

Cars, buses, and re gional trucks
Green hydrogen is not an attractive technology for
decarbonizing most vehicles on the road because
battery-electric vehicle technology provides a
straightforward path for cars, buses, and trucks. In
the market segments where battery-electric and
hydrogen options are available, the battery-electric
options are cheaper to purchase and operate than
their hydrogen competitors, even when the hydrogen
vehicles run on less expensive hydrogen from fossil
fuels.156 By the mid-2020s, researchers expect many
battery-electric vehicles to have an even lower cost
of ownership than vehicles with internal combustion
engines.157 Battery-electric light-duty vehicles will likely reach upfront price parity with combustion engines
between 2022 and 2024, at which point they will
produce operational savings relative to conventional
vehicles at no added cost.158 Though manufacturers of
fuel cell vehicles could reduce upfront purchase prices by scaling up production, the economics of fueling a
battery-electric vehicle with renewable energy have
inherent advantages over fueling a fuel cell vehicle with green hydrogen. Hydrogen cars require more than 2 to
3 times as much renewable energy as battery-electric
cars because so much energy is lost in the process
of compressing and transporting hydrogen and
converting it into electricity in fuel cells.159
Some efficiency improvements are possible.

Nonetheless, a recent study found that to meet
climate goals, “in comparison to electric
vehicles,
hydrogen-based propulsion technologies will reach
market readiness too late.”160
Given the economic advantages of renewable
electricity over green hydroge n as a vehicle fuel,
fuel cell vehicles will likely o nly be viable in the
shrinking market segments that lack battery-
electric options. Even for long-hau l trucking, where
hydrogen was once thought to b e necessary
for decarbonization, battery-elec tric vehicles
are emerging as a cost-effective a nd low-risk
mitigation pathway thanks to rapidly improving
battery technolog y.161 Recent studies find that
these dramatic improvements can ren der long-
haul battery-electric trucks with 500-mile range
both technically feasible and eco nomically
compelling. 162 About 80% of trucks travel l ess than
500 miles, 163 making battery-electric tech nologies
the best option for the vast majorit y of trucks.
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31 Reclaiming Hydrogen for a Renewable Future

GREENWASHING SPOTLIGHT
Toyota is advertising its hydrogen fuel cell car, the Mirai, with the misleading claim that “[t]he more you drive, the more you clean air.” The idea behind this claim is that the car’s air intake has a filter that captures particulate matter and other impurities in the air before sending oxygen to its fuel cell. However, Toyota’s ads ignore the emissions from producing hydrogen, even though almost all of the hydrogen in the United States is produced from fossil fuels through a process that releases significant health-harming pollution. Ultimately, these ads are likely to give consumers the false impression that they can help improve air quality by driving more often.

Source: TOYOTA MIRAI, Air Purification System (last visited July 30, 2021), https://www.youtube.com/watch?v=VX8p0mG7pL Y.

Recognizing the challenges for fuel cell ve hicles,
industry i s rethinking investments in hydrogen.

Scania, one of the world’s largest truck and bus
manufacturers, decided to end its fuel cell vehi cle
program bec ause “three times as much renewable
electricity is needed to power a hydrog en truck
compared to a battery ele ctric tru ck” and
maintenance is more ch allenging for hydro gen
vehicles than their battery-elect ric competitors.164
Volkswagen is also focusing on electric vehicles,
with its chief executive officer declaring that “You
won’t see any hydrogen usage in cars. . . . Not
even in 10 years, because the physics behind it are
so unreasonable.”
165 Likewise, Mercedes-Benz is
ending its hydrogen car program because it could
not scale up sales and production enough to make
hydrogen cars cost-competitive.
166
972 of 983
Conclusion 32
Reclaiming Hydrogen for a Renewable Future
Recently, hydrogen has captured the attention of the press and policymakers, partly because green hydrogen may become a climate solution for sectors that have long seemed out of reach for renewable energy. However, hydrogen hype is also flowing from industry trade associations that represent the oil and gas industry, which produce the vast majority of hydrogen in use today from fossil fuels. For the oil and gas industry and for other incumbents of the fossil energy system—like certain manufacturers of combustion vehicles, turbines, and boilers and companies that profit from building gas pipelines—hydrogen may offer a path to continued relevance and investment under potential climate policies.

While hydrogen can—and likely must—complement traditional renewables and electrification, policymakers should only promote hydrogen that is genuinely compatible with a zero-emission future. Today, more than 99% of the hydrogen that industry produces in the United States is made from fossil fuels through a process that emits massive amounts of health-harming pollution into neighboring communities. Appropriate investments in green hydrogen, which is made from renewable electricity, are no excuse for expanding or continuing hydrogen production that threatens the climate and public health.

Further, policymakers should understand the limits of green hydrogen’s economic potential.

Green hydrogen is not a useful tool for sectors that can decarbonize by transitioning to electric technologies and relying on a renewable power grid. It will always be more cost- effective to use renewable energy directly from the grid than to use green hydrogen; due to the inefficiency of converting renewable energy into hydrogen, powering equipment with green hydrogen requires several times as much renewable energy than doing the same job with clean electricity. Therefore, policymakers should focus on supporting green hydrogen in sectors that lack feasible electric options, such as maritime shipping.

Currently, industry trade associations are advocating for the use of a broad range of hydrogen sources and seeking public support for using hydrogen in sectors that have more cost-effective strategies for transitioning to renewable energy. Policymakers must carefully scrutinize these requests. The window to rapidly transition to a just, zero-emission energy system is narrowing. There is no time to waste with distractions or missteps. To chart a clear course, we must distinguish green hydrogen’s true potential from fossil fuel industry spin, and reclaim it for a renewable future.

CONCLUSION
973 of 983
Endnotes 33
Reclaiming Hydrogen for a Renewable Future
1 U .S. Energy Information Administration (“EIA ”), Energy and the environment explained – Where greenhouse gases come from, https://www.eia.gov/energyexplained/energy-and-the- environment/where-greenhouse-gases-come-from.php (last
updated May 21, 2021).
2 See generally Tim Donaghy & Charlie Jiang, Fossil Fuel Racism – How Phasing Out Oil, Gas, and Coal Can Protect Communities, Greenpeace (Apr. 13, 2021), https://www.
greenpeace.org/usa/wp-content/uploads/2021/04/Fossil-
Fuel-Racism.pdf.
3 In ternational Energy Agency, The Future of Hydrogen, at 17 , 37–38 (June 2019), https://www.iea.org/reports/the-future-of- hydrogen.
4 E manuele T aibi et al., Green Hydrogen Cost Reduction, International Renewable Energy Agency, at 18 (2020), https:// irena.org/-/media/Files/IRENA/Agency/Publication/2020/Dec/ IRENA_Green_hydrogen_cost_2020.pdf.
5 Mark F . Ruth et al., The Technical and Economic Potential of the H2@Scale Concept within the United States, National Renewable Energy Laboratory at 7 (2020) (“NREL 2020,
Technical and Economic Potential of H2@Scale”), https://www. nrel.gov/docs/fy21osti/77610.pdf.
6 U .S. EIA, Hydrogen for refineries is increasingly provided by industrial suppliers (Jan 20, 2016), https://www.eia.gov/ todayinenergy/detail.php?id=24612#:~:text=Refineries%20 use%20hydrogen%20to%20lower%20the%20sulfur%20
content%20of%20diesel%20fuel.&text=Refineries%20
also%20produce%20some%20by,fraction%20of%20their%20
hydrogen%20needs.
7 U .S. EIA, Hydrogen explained, https://www.eia.gov/
energyexplained/hydrogen/production-of-hydrogen.php (last updated Jan. 7 , 2021).
8 In ternational Energy Agency, The Future of Hydrogen, supra note 3, at 17.
9 Id.
10 See Pinping Sun et al., Criteria Air Pollutants and Greenhouse Gas Emissions from Hydrogen Production in U.S. Steam
Methane Reforming Facilities, Env’t Sci. & Tech., Vol. 53 Issue 12, (Apr. 30, 2019), https://www.osti.gov/pages/servlets/ purl/1546962.
11 Oil & Gas Journal, Phillips 66 lets contract for Sweeny refinery hydrogen supply (Nov. 9, 2018), https://www.ogj.com/refining- processing/refining/optimization/article/17296166/phillips-66- lets-contract-for-sweeny-refinery-hydrogen-supply.
12 10 /12 Industry Report, Linde plans $250M hydrogen plant in St.

James Parish (Apr. 9, 2019), https://www.1012industryreport. com/projects/linde-plans-250m-hydrogen-plant-in-st-james- parish/.
13 E milie Karrick Surrusco, Cancer Alley Rises Up, Earthjustice (Feb. 14, 2020), https://earthjustice.org/features/cancer-alley- rises-up.
14 NREL 2 020, Technical and Economic Potential of H2@Scale, supra note 5, at viii T able ES-1.
15 U .S. EIA, U.S. Gulf Coast refinery demand for hydrogen increasingly met by merchant suppliers (Mar. 15, 2019), https:// www.eia.gov/todayinenergy/detail.php?id=38712.
16 W ood Mackenzie, The rise of the hydrogen economy, https:// www.woodmac.com/nslp/hydrogen-guide/ (last visited July 21, 2021).
17 See U.S. EIA, U.S. Gulf Coast refinery demand for hydrogen increasingly met by merchant suppliers (Mar. 15, 2019) (showing that hydrogen demand is increasingly met by industrial gas companies relying on steam-methane reformation), https:// www.eia.gov/todayinenergy/detail.php?id=38712.
18 NREL 2 020, Technical and Economic Potential of H2@Scale, supra note 5, at viii T able ES-1.
19 Id.
20 R ob Watts, Gas lobby group with BP and Shell touts blue hydrogen to lead $23bn UK boost, Recharge (Aug. 14, 2020), https://www.rechargenews.com/transition/gas-lobby-group- with-bp-and-shell-touts-blue-hydrogen-to-lead-23bn-uk-
boost/2-1-858079.
21 Union o f Concerned Scientists, Each Country’s Share of CO2 Emissions, https://www.ucsusa.org/resources/each-countrys- share-co2-emissions (updated Aug. 12, 2020).
22 See, e.g., DNV, Heading for Hydrogen (May 2020), https://www. dnv.com/oilgas/hydrogen/heading-for-hydrogen.html.
23 L etter from Clean Hydrogen Future Coalition to President Joseph R. Biden (Mar. 22, 2021), https://legacy-assets.eenews. net/open_files/assets/2021/03/23/document_ew_02.pdf.
24 In addition t o the Clean Hydrogen Future Coalition, there is Hydrogen Forward, Hydrogen Council, Fuel Cell & Hydrogen Energy Association, Renewable Thermal Collective, and the Green Hydrogen Coalition.
25 Sonja V an Renssen, The hydrogen solution?, Nature Climate Change (published Aug. 27 , 2020), https://www.nature.com/ articles/s41558-020-0891-0.
26 E nergy Networks Australia, Gas Vision 2050, http://www. energynetworks.com.au/projects/gas-vision-2050/ (last
visited July 22, 2021).
27 Hy drogen T askforce, The Hydrogen Taskforce launches at Parliament, https://www.hydrogentaskforce.co.uk/news-
story-1/ (last visited July 22, 2021).
28 E mily Gosden, Switching All Boilers to Hydrogen ‘Is Impractical’, The Times (Dec. 7 , 2020), https://www.thetimes.co.uk/article/

ENDNOTES
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Endnotes 34
Reclaiming Hydrogen for a Renewable Future
switching-all-boilers-to-hydrogen-is-impractical-zw00f3v9l. 29 Corpor ate Europe Observatory, The Hydrogen Hype: Gas Industry Fairy Tale or Climate Horror Story (July 12, 2020), https://corporateeurope.org/sites/default/files/2020-12/ hydrogen-report-web-final_0.pdf.
30 Damian K ahya, Unearthed today: Why oil companies want you to love hydrogen, Unearthed (Aug. 12, 2020), https:// unearthed.greenpeace.org/2020/12/08/unearthed-today-why- oil-companies-want-you-to-love-hydrogen/; see also Hiroko T abuchi, How One Firm Drove Influence Campaigns Nationwide for Big Oil, The New York Times (Nov. 11, 2020), https://www. nytimes.com/2020/11/11/climate/fti-consulting.html.
31 A ustralian Hydrogen Council, AHC policy framework: the three licenses to operate, at Hydrogen Market Activation Policy Principles, https://h2council.com.au/about/policy-and-
regulation (last visited July 22, 2021).
32 L etter from Executive Representatives of Companies
Investing Heavily in the Development of Hydrogen Mobility to Governor Gavin Newsom, at 2 (May 10, 2021), https:// californiahydrogencoalition.org/wp-content/uploads/2021/05/ CEO-Letter-to-GGN-Final.pdf.
33 L etter from Shannon Angielski, President of Clean Hydrogen Future Coalition, to President Joseph R. Biden (Apr. 21, 2021), https://cleanh2.org/wp-content/uploads/CHFC-Letter-to-
Biden-on-AJP-2021-04-21.pdf.
34 In ternational Energy Agency, “Green” hydrogen for use in industrial processes (Nov. 17 , 2020) https://www.iea.org/ articles/decarbonising-industry-with-green-hydrogen. The International Energy Agency’s definition of “green hydrogen” is consistent with the predominant approach among experts in the United States and internationally, such as the European Bank for Reconstruction and Development (“made by using clean electricity from renewable energy technologies to electrolyse water”), international energy companies like Iberdrola (“electrolysis from renewable sources”), and energy consultancies like Wood Mackenzie (“produced from water by renewables-powered electrolysis”).
35 NREL, Hydrogen Production and Delivery, https://www.nrel.gov/ hydrogen/hydrogen-production-delivery.html (last visited July 26, 2021).
36 A ccording to the California Air Resource Board’s Lookup T ables for the Low Carbon Fuel Standard, the carbon intensity of compressed hydrogen produced through steam methane
reformation of North American fossil gas is 118 grams of CO2e/MJ, whereas compressed hydrogen produced in
California from electrolysis using California grid average electricity has a carbon intensity of 164 grams of CO2e/ MJ. California Air Resources Board, LCFS Life Cycle Analysis Models and Documentation, https://ww2.arb.ca.gov/
resources/documents/lcfs-life-cycle-analysis-models-and- documentation (last visited July 26, 2021).
37 John Eichman & Francisco-Flores Espino, California Power- to-Gas and Power-to-Hydrogen Near- Term Business Case
Evaluation, NREL (Dec. 2016) (“NREL 2016, Business Case Evaluation”), at 59 (“Senate Bill 1505 in California requires that 33.3% of hydrogen produced for or dispensed by state- funded fueling stations must be made from eligible renewable resources. At present, the majority of the required renewable hydrogen is produced from SMR and coupled with the purchase of biogas credits.”), https://www.nrel.gov/docs/fy17osti/67384. pdf. For instance, a California Air Resources Board staff report recommended certifying the carbon intensity of a “renewable hydrogen” production pathway based on the procurement of environmental attributes of gas from cow manure in Indiana.

California Air Resources Board, Low Carbon Fuel Standard Tier 2 Pathway Application Staff Summary (Dec. 31, 2020), https://ww2.arb.ca.gov/sites/default/files/ classic/fuels/lcfs/ fuelpathways/ comments/tier2/b0145_summary.pdf.
38 See NREL 2016, Business Case Evaluation, supra note 37 , at 59 (“The cost to produce renewable hydrogen with an electrolyzer is greater than the cost to install an SMR unit and pay the additional fee for renewable biogas credits.”).
39 The Gr een Hydrogen Coalition advocates to define green hydrogen as “hydrogen that is not produced from fossil
fuel feedstock sources.” Green Hydrogen Coalition, Green Hydrogen, https://www.ghcoalition.org/green-hydrogen.
40 U .S. EPA, Biofuels and the Environment: The Second Triennial Report to Congress, at 37 (June 29, 2018), https://cfpub.epa. gov/si/si_public_record_report.cfm? Lab=IO&dirEntryId=341491. 41 Cen ter for Biological Diversity, Forest Biomass Energy is a False Solution, at 4 (June 2020), https://www.biologicaldiversity. org/programs/climate_law_institute/pdfs/Forest-Bioenergy- Briefing-Book.pdf.
42 16 C .F.R. § 260.4(b).
43 Geor gina Gustin, As the Livestock Industry Touts Manure-to- Energy Projects, Environmentalists Cry ‘Greenwashing’, Inside Climate News (Dec. 7 , 2020), https://insideclimatenews.org/ news/07122020/livestock-industry-manure-energy-natural- gas/.
44 In ternational Renewable Energy Agency, Hydrogen: A
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45 S tanford School of Earth, Energy & Environmental Sciences, Optimal CO2 capture and storage to reduce the energy costs of CCS, https://pangea.stanford.edu/optimal-co2-capture-and- storage-reduce-energy-costs-ccs (last visited July 26, 2021). 46 Cr aig Bettenhausen, The Life Or Death Race to Improve Carbon Capture, Chemical & Engineering News (July 18, 2021) https:// cen.acs.org/environment/greenhouse-gases/capture-flue-
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47 A driano Vinca et al., Bearing the Cost of Stored Carbon Leakage, Frontiers in Energy Research (May 15, 2018), https:// www.frontiersin.org/articles/10.3389/fenrg.2018.00040/full. 48 See Mark Z. Jacobson, The Health and Climate Impacts of Carbon Capture and Direct Air Capture, Energy &
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50 Christian T ae, Natural Resources Defense Council (2021) available by request from authors.
51 Leigh Collins, Upstream emissions risk ‘killing the concept of blue hydrogen’, says Equinor vice-president, Recharge (July 15, 2021), https://www.rechargenews.com/energy-transition/ upstream-emissions-risk-killing-the-concept-of-blue-
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52 U.N. Environment Program, Global Methane Assessment:

Benefits and Costs of Mitigating Methane Emissions, (May 6, 2021), https://www.unep.org/resources/report/global- methane-assessment-benefits-and-costs-mitigating-
methane-emissions.
53 David Roberts, Could Squeezing More Oil out of the Ground Help Fight Climate Change?, Vox (Dec. 6, 2019), https://www.vox. com/energy-and-environment/2019/10/2/20838646/climate-
change-carbon-capture-enhanced-oil-recovery-eor.
54 See, e.g. E3G, Hydrogen Factsheet: Supply (Apr. 7 , 2021), https://9tj4025ol53byww26jdkao0x-wpengine.netdna-ssl.
com/wp-content/uploads/E3G_2021_Hydrogen-Factsheet_
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transition/by-2030-blue-hydrogen-will-make-little-economic- sense-versus-green-bnef/2-1-991590.
55 Aurora Energy Research, Hydrogen in the Northwest European Energy System, at 5, https://auroraer.com/resources/Aurora- Hydrogen-in-the-Northwest-European-energy-system.pdf.
56 Shane Ardo et al., Pathways to electrochemical solar-hydrogen technologies, 10 Energy & Env’t Science (June 2018), https:// pubs.rsc.org/no/content/articlelanding/2018/ee/c7ee03639f/ unauth#!divAbstract.
57 Energy Transitions Commission, Making the Hydrogen Economy Possible: Accelerating Clean Hydrogen in an Electrified Economy, at 22 (Apr. 2021), https://energy-transitions.org/wp- content/uploads/2021/04/ETC-Global-Hydrogen-Report.pdf. 58 Jens Perner et al., The Future Cost of Electricity-Based Synthetic Fuels, Frontier Economics Ltd., at 11 (Sept. 19, 2018), https://www.agora-energiewende.de/fileadmin2/
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59 Norman Gerhardt et al., Fraunhofer Institute for Energy Economics, Hydrogen in the Energy System of the Future:

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60 Amber Mahone et al., Residential Building Electrification in California (Apr. 2019), at viii, https://www.ethree.com/ wp-content/uploads/2019/04/E3_Residential_Building_
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61 Leah C. Stokes, Cleaning Up the Electricity System, Democracy Journal https://democracyjournal.org/magazine/56/cleaning- up-the-electricity-system/.
62 Id.
63 Jason Deign, How much renewables expansion is needed for a global green hydrogen economy?, Canary Media (July 13, 2021), https://www.canarymedia.com/articles/how-much-renewable- capacity-would-world-need-for-green-hydrogen/.
64 Nick Ash et al., Renewable electricity requirements to decarbonise transport in Europe with electric vehicles, hydrogen and electrofuels, Ricardo, at iii (Dec. 4, 2020), https://www. transportenvironment.org/sites/te/files/ publications/2020_ Report_RES_to_decarbonise_transport_in_EU.pdf.
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67 Id.; Wood MacKenzie, 2020 Hydrogen Landscape,
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68 U.S. Dep’t of Energy, Remarks as Delivered by Secretary Granholm at President Biden’s Leaders Summit on Climate (Apr. 23, 2021), https://www.energy.gov/articles/remarks-delivered- secretary-granholm-president-bidens-leaders-summit-
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69 See NREL 2020, Technical and Economic Potential of H2@ Scale, supra note 5, at 34, Figure 13.
70 ICF, Supplemental Greenhouse Gas Analysis of the
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71 See, e.g., SoCalGas, California’s Clean Energy Future: Imagine the Possibilities, at 20 (Apr. 2, 2019), https://www.socalgas. com/1443742344191/scg-vision-paper-04032019.pdf.
976 of 983
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74 U.S. EPA, Basic Information about NO2, https://www.epa.gov/ no2-pollution/basic-information-about-no2#Effects (last visited July 22, 2021).
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78 See Donaghy & Jiang, supra note 2, at 25.
79 U.S. Dep’t of Energy, Hydrogen Production and Distribution, https://afdc.energy.gov/fuels/hydrogen_product ion.html (last visited July 22, 2021).
80 BloombergNEF, Hydrogen Economy Outlook, Key Messages, at 3 (Mar. 30, 2020), https://assets.bbhub.io/professional/ sites/24/BNEF-Hydrogen-Economy-Outlook-Key-Messages-
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81 California Energy Commission and California Air Resources Board, Joint Agency Staff Report on Assembly 8: 2019 Annual Assessment of Time and Cost Needed to Attain 100 Hydrogen Refueling Stations in California (Dec. 2019), https://www.energy. ca.gov/sites/default/files/2021-05/CEC-600-2019-039.pdf. 82 See AirLiquide, Hydrogen, At the origin of the Universe, https:// energies.airliquide.com/resources/planet-hydrogen-hydrogen (last visited July 22, 2021).
83 See Erin M. Blanton et al., Investing in the US Natural Gas Pipeline Sys. to Support Net-Zero Targets, Columbia Center on Global Energy Policy, at 39 (Apr. 2021), https://www. energypolicy.columbia.edu/sites/default/files/file-uploads/ GasPipelines_CGEP_Report_042221.pdf.
84 Id.
85 Richard Derwent et al., Global Env’t Impacts of the
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publication/228402009_Global_environm ental_ impacts_of_ the_hydrogen_economy.
86 Julien Dumoulin-Smith et al., US Alternative Energy, Bank of America, at 4 (June 28, 2021).
87 See U.S. Dep’t of Energy, Hydrogen Production and Distribution, supra note 79; see also Christopher Findlay, What’s your purpose? Reusing gas infrastructure for hydrogen transp., Siemens Energy (Sept. 11, 2020) (“If the share of hydrogen exceeds 40 percent, the compressors [on a methane gas
pipeline] will need to be replaced.”), https://www.siemens- energy.com/global/en/news/magazine/2020/repurposing-
natural-gas-infrastructure-for-hydrogen.html.
88 See Blanton, Investing in the US Natural Gas Pipeline Sys. to Support Net-Zero Targets, supra note 83.
89 Id.
90 See U.S. Dep’t of Energy, Hydrogen Production and Distribution, supra note 79.
91 BloombergNEF, Hydrogen Economy Outlook, Key Messages, supra note 80, at 3.
92 Id.
93 Id. at 3–4.
94 See, e.g., Niklas Heinemann et al., Enabling large-scale hydrogen storage in porous media – the scientific challenges, Energy & Environmental Science, vol. 14 at 853-64 (Jan. 2021) (discussing the risks associated with storing hydrogen in geological formations like depleted hydrocarbon reservoirs and saline aquifers), https://pubs.rsc.org/en/content/
articlelanding/2021/EE/D0EE03536J#!divAbstract; Maria
Portarapillo and Almerinda Di Bendetto, Risk Assessment of the Large-Scale Hydrogen Storage in Salt Caverns, Energies (May 15, 2021) (discussing potential risks associated with storage in salt caverns), https://doi.org/10.3390/en14102856.
95 Rain Saullnier et al., Water for the Hydrogen Economy, WaterSMART Solutions Ltd., at 4–5 (Nov. 2020), https:// watersmartsolutions.ca/wp-content/uploads/2020/12/
Water-for-the-Hydrogen-Economy_WaterSMART -Whitepaper_
November-2020.pdf.
96 Energy Transitions Comm’n, Making the Hydrogen Economy Possible: Accelerating Clean Hydrogen in an Electrified Economy, at 61 (Apr. 2021), https://energy-transitions.org/wp- content/uploads/2021/04/ETC-Global-Hydrogen-Report.pdf. 97 See Sarah Fecht, How Climate Change Impacts Our Water, Columbia Climate School (Sept. 23, 2019), https://news.clim ate. c olumbia.edu/2019/09/23/climate-change-impacts-water/. 98 See, e.g., Feroze Abbas et al., Water Resource Considerations for the Hydrogen Economy, K&L Gates (Dec. 17 , 2020) (pointing out that stating that Australia, which has ambitions of becoming a major hydrogen exporter, is “the driest continent on earth (apart from Antarctica)”), https://www.jdsupra.com/ legalnews /water-resource-considerations-for-the-84603/; Orlando Milesi, Betting on Green Hydrogen in Chile, a Road Fraught with Obstacles, Inter Press Service (June 15, 2021) 977 of 983
Endnotes 37
Reclaiming Hydrogen for a Renewable Future
(stating that Chile—which aims to become a hydrogen
superpower, faces “the scarcity of water” as one of its two biggest obstacles), http://www.ipsnews.net/2021/06/betting- green-hydrogen-chile-road-fraught-obstacles/.
99 Wenming Tong, et al, Electrolysis of low-grade and saline surface water, Nature Energy (Feb. 2020), https://www.nature. com/articles/s41560-020-0550-8.
100 Emanuele T abibi et al., Green Hydrogen Cost Reduction, Scaling up Electrolysers to Meet the 1.5°C Climate Goal, International Renewable Energy Agency, at 18 (Dec. 2020), https://irena. org/-/media/Files/IRENA/Agency/ Publication/20 20/Dec/
IRENA_Green_hydrogen_cost_2020.pdf.
101 UN Framework Convention on Climate Change, The United States of America, Nationally Determined Contribution,
Reducing Greenhouse Gases in the United States: A 2030
Emissions Target, at 3 (Apr. 22, 2021), https://www4.unfccc.int/ sites/ndcstaging/PublishedDocuments/United%20State s%20 of %20America%20First/United%20States%20NDC%20
April%2021%202021%20Final.pdf.
102 Id.
103 Dominik Englert & Andrew Losos, Summary for Policy
Makers and Industry: Charting a Course for Decarbonizing Mar. Transp., World Bank, at 2 (2021) (Charting a Course for Decarbonizing Maritime Transport), https://open .worldbank.org/ handle/10986/35436.
104 Infineon, Why ships of the future will run on electricity (last updated July 2021), https://www.infineon.com/cms/en/ discoveries/electrified-ships/.
105 Masumi Suga, Battery-Powered Ships Next Up in Battle to Tackle Emissions, Bloomberg (Aug. 6, 2019), https://www. bloomberg.com/news/articles/2019-08-06/battery-powered- ships-next-up-in-battle-to-tackle-emissions.
106 Dominik Englert et al., Vol. 1: The Potential of Zero-Carbon Bunker Fuels in Developing Countries, World Bank, at iii (2021), https://openknowledge.worldbank.org/handle/10986/35435. 107 Id.
108 Id. at iii–iv.
109 Jonathan Saul & Nina Chestney, First wave of ships explore green hydrogen as route to net zero, Reuters (Oct. 30, 2020), https://www.reuters.com/article/shipping-energy-hydrogen- focus-int/first-wave-of-ships-explore-green-hydrogen-as- route-to-net-zero-idUSKBN27F18U.
110 Dominik Englert et al., Vol. 1: The Potential of Zero-Carbon Bunker Fuels in Developing Countries, World Bank, at iv (2021), https://openknowledge.worldbank.org/handle/10986/35435. 111 Hannah Ritchie, Climate change and flying: what share of global CO2 emissions come from aviation?, Our World in Data (Oct. 22, 2020), https://ourworldindata.org/co2-emissions- from-aviation#:~:text=In%202018% C%20’s%20estimated%20
that,CO2%20emissions%20in%202018.&text=Aviation%20
emissions%20have%20doubled%20since%20the%20
mid%2D1980s.
112 ZeroAvia, Our Mission, https://www.zeroavia.com/ (last visited July 21, 2021).
113 Mark Harris, Universal Hydrogen raises $20.5M Series A to help launch hydrogen aviation, TechCrunch (Apr. 22, 2021), https:// techcrunch.com/2021/04/22/universal-hydrogen-raises-20- 5m-series-a-to-help-launch-hydrogen-aviation/.
114 Stefano Andreola et al., No-regret hydrogen, Charting early steps for H2 infrastructure in Europe, Study, AFRY Management Consulting Limited, at 12 (Feb. 2021), https://static.agora- energiewende.de/fileadmin/Projekte/2021/2021_02_EU_
H2Grid/A-EW_203_No-regret-hydrogen_WEB.pdf.
115 Id. at 13.
116 See, e.g., Stephen Edelstein, Battery-electric or hydrogen fuel cell? VW lays out why one is the winner, Green Car Reports (Apr. 1, 2020), https://www.greencarreports.com/ news/1127660_battery-electric-or-hydrogen-fuel-cell-vw- lays-out-why-one-is-the-winner; Eoin Bannon, E-fuel would be wasted on cars while it’s badly needed to decarbonise planes and ships—study, Transp. & Env’t (Dec. 7 , 2020), https://www. transportenvironment.org/press/e-fuel-would-be-wasted-cars- while-it%E2%80%99s-badly-needed-decarbonise-planes-and- ships-%E2%80%93-study.
117 Federico Zenith et al., Techno-economic analysis of freight railway electrification by overhead line, hydrogen and batteries:

Case studies in Norway and USA (July 2019), https: //journal.s . com /doi/pdf/ .117 /0954409719867495.
118 Transp. & Env’t, Comparison of hydrogen and battery elec. trucks, Methodology and underlying assumptions (June
2020), https://www.transportenvironment.org/sites/te/files/ publications/2020_06_TE_comparison_hydrogen_battery_
electric_trucks_methodology.pdf.
119 Deutsche Bahn, Overview of Zero-Emission Motive Power Options (Oct. 29, 2020), https://ww2.arb.ca.gov/sites/default/ files/2020-10/Day%201%20Ext%201%20DB%20ENG%20
20201021.pdf.
120 Jack Ewing, World’s Largest Long-Haul Truckmaker Sees Hydrogen-Fueled Future, New York Times (May 23, 2021)
(updated July 21, 2021), https://www.nytimes.com/2021/05/23/ business/hydrogen-trucks-semis.html.
121 Rochelle Toplensky, Hydrogen-Powered Trains Have Arrived, Wall Street Journal (May 26, 2021), https://www.wsj.com/ articles/hydrogen-powered-trains-have-arrived-11622025494. 122 Dan Esposito, Studies Converge on Benefits of a Rapid Clean Energy Transition, Energy Innovation, at 2 (July 2021), https:// energyinnovation.org/wp-content/uploads/2021/07 /Studies- Converge-on-Benefits-of-a-Rapid-Clean-Energy- Transition.pdf. 123 NREL 2020, Technical and Economic Potential of H2@Scale, supra note 5, at 4.
124 For example, recent research in New York State shows the potential for aqueous air and electrochemical storage technologies paired with traditional lithium-ion batteries to displace the need for up to 83% of New York’s peaking units. Isabella Ragazzi & Scott Burger, Solving the Clean 978 of 983
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Energy and Climate Justice Puzzle, How multi-day energy storage can cost-effectively replace long-running peakers in New York State, Form Energy, at 2 (July 2020), https:// formenergy.com/wp-content/uploads/2020/08/Form_Energy_
NYGasReplaceWhitePaper_V2.pdf.
125 Congressional Research Service, Hydrogen in Elec.’s Future, at 10 (June 30, 2020), https://crsreports.congress.gov/product/ pdf/R/R46436.
126 Id.
127 Id.
128 Id.
129 See, e.g., Danskammer Energy, LLC, Clean, Reliable Energy for New York (Danskammer Energy LLC’s claims that its upgraded power plant could “transition to zero-emission hydrogen power when the technology is available to transport and store hydrogen”), https://www.danskammerenergy.com/energy-
project/ (last visited July 21, 2021); David Brand, NRG spends $600K on high-powered lobbyists pushing Astoria power plant plan, Queens Daily Eagle (Dec. 23, 2020) (describing NRG’s claims that a power plant would eventually transition to operate on hydrogen), https://queenseagle.com/all/nrg-spends-620k- on-high-powered-lobbyists-to-push-astoria-peaker-plant; N.M.

Pub. Reg. Comm’n Docket No. 19-00349-UT , El Paso Electric Company’s Exceptions to Recommended Decision, at 23, (Nov. 25, 2020) (arguing that a new gas-fired combustion turbine could continue serving customers in New Mexico consistent with the state’s 100% carbon-free electricity standard if it were converted to run on hydrogen).
130 Jeffrey Goldmeer et al., Hydrogen as a Fuel for Gas Turbines, General Electric, at 3–4 (2021), https://www.ge.com/content/ dam/gepower-new/global/en_US/downloads/gas-new-site/
future-of-energy/hydrogen-fuel-for-gas-turbines-gea34979. pdf.
131 Id. at 4.
132 Id.
133 Id. at 5.
134 See Bothien, Hydrogen Gas Turbines: The Path Towards a Zero- Carbon Gas Turbine, supra note 77 .
135 Id.
136 Id.
137 Poulomi Ganguli et al., US Power Production at Risk from Water Stress in a Changing Climate, 7 Sci. Reports 1 (Sept. 2017), https://www.nature.com/articles/s41598-017-12133-9.
138 ICF, Suppl. Greenhouse Gas Analysis of the Danskammer Energy Center, at 11 (Jul. 8, 2020).
139 U.S. EIA, Annual Energy Outlook 2020, at 48 (Jan. 2020), https://www.eia.gov/outlooks/aeo/pdf/AEO2020%20Full%20
Report.pdf.
140 Rocky Mountain Institute, The Impact of Fossil Fuels in Buildings: A Fact Base, at 6 (Dec. 2019), https://rmi.org/ insi ght/ the-impact-of-fossil-fuels-in-buildings/.
141 See, e.g., California Energy Commission, 2019 California Energy Efficiency Action Plan, at 84 (Nov. 2019) (“[T]he most viable and least-cost path to immediate zero-emission residential and commercial buildings” is electrification of gas end uses, “in particular, electrification of space and water heating to high-efficiency, demand-flexible technologies[.]”), https://www. energy.ca.gov/filebrowser/download/1900.
142 The National Renewable Energy Laboratory concluded that gas pipeline injection is the least compelling of four potential applications of hydrogen in California. NREL 2016, Business Case Evaluation, supra note 37 , at 64. BloombergNEF founder Michael Liebreich has constructed a “ladder” that ranks numerous potential applications for clean hydrogen and rated “domestic heating” an F, noting that the idea of blending clean hydrogen into the natural gas grid to reduce carbon emissions is “stupidly inefficient.” Leigh Collins, Liebreich: ‘Oil sector is lobbying for inefficient hydrogen cars because it wants to delay electrification’, Recharge (June 30, 2011), https://www. rechargenews.com/energy-transition/liebreich-oil-sector- is-lobbying-for-inefficient-hydrogen-cars-because-it-wants- to-delay-electrification-/2-1-1033226. A recent European study ranks heat for buildings last in the “merit order” of potential applications. Fraunhofer Institute 2020, supra note 59, at 5–6. The California Energy Commission’s 2018 landmark analysis projected that California would only inject renewable hydrogen into the gas pipeline system in the most expensive decarbonization pathway considered, called No Building Electrification with Power-to-Gas. California Energy Commission, Deep Decarbonization in a High Renewables
Future, at Figure 27 , T ables A-1, and A-2 (June 2018), https:// www.energy.ca.gov/sites/default/files/2021-06/CEC-500-
2018-012.pdf. Agora Energiewende and Guidehouse also
analyzed several potential use cases for green hydrogen and classified using green hydrogen in individual buildings for space heating as a “bad idea” because of the proven and efficient electric alternatives. Matthias Schimmel et al., Making renewable hydrogen cost-competitive: Policy instruments for supporting green H2, Agora Energiewende and Guidehouse
(2021) at 9–10, https://static.agora-energiewende.de/fileadmin/ Projekte/2020/2020_11_EU_H2-Instruments/A-EW_223_H2-
Instruments_WEB.pdf.
143 Gridworks, California’s Gas System in Transition, Equitable, Affordable, Decarbonized and Smaller, at 8 (Sept. 2019) (finding that “[e]ven in an ‘optimistic’ scenario that assumed aggressively lower-cost hydrogen and [synthetic gas] in the future, the high electrification scenario would still cost $6 billion less per year [than the high electrification scenario]”), https:// gridworks.org/wp-content/uploads/2019/09/CA_Gas_System_ in_Transition.pdf.
144 Energy and Environmental Economics, Inc., E3 Quantifies the Consumer and Emissions Impacts of Electrifying California Homes (Apr. 15, 2019), https://www.ethree.com/e3-quantifies- the-consumer-and-emissions-impacts-of-electrifying-
california-homes/.
145 M.W. Melaina et al., Blending Hydrogen into Natural Gas Pipeline Networks: A Review of Key Issues, NREL, at 20 (Mar. 2013), 979 of 983
Endnotes 39
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https://www.nrel.gov/docs/fy13osti/51995.pdf.
146 Jairo Duran, Safety Issues to Consider When Blending Hydrogen with Natural Gas (Feb. 17 , 2021), https://processecology.com/ articles/safety-issues-to-consider-when-blending-hydrogen- with-natural-gas#:~:text=Blending%20hydrogen%20to%20
natural%20gas,slower%20than%202%25%20per%20minute.
147 Iain Staffel et al., The Role of Hydrogen and Fuel Cells in the Global Energy System, 2 Energy & Env’t Sci 463, 479 (Jan. 2019), https://pubs.rsc.org/en/content/articlepdf/2019/ee/ c8ee01157e; see also Jeff St. John, Green Hydrogen in Natural Gas Pipelines: Decarbonization Solution or Pipe Dream?, GreenTech Media (Nov. 30, 2020) (quoting an expert from Wartsila Energy for explaining that hydrogen behaves differently than methane and “burns almost as an explosion. . . . When you go beyond 25 percent hydrogen in the fuel, in most places in the world, you’re no longer able to use the same equipment.

Electronics, for example, must be explosion-proof.”), https:// www.greentechmedia.com/articles/read/ green-hydrogen-
in-natural-gas-pipelines-decarbonization-solution-or-pipe- dream.
148 American Gas Foundation, Renewable Sources of Natural Gas: Supply and Emissions Reduction Assistant, at 11, 14 (Dec. 2019) (showing a potential of 1,425.3 tBtu/year for landfill gas, animal manure, food waste, and water resource recovery
facilities and noting an average U.S. annual consumption of fossil gas of 15,850 tBtu), https://gasfoundation.org/wp- content/uploads/2019/12/AGF-2019-RNG-Study-Full-Report- FINAL -12-18-19.pdf.
149 See id. (estimating a combined potential for 3,087 .4 tBtu/year for producing methane from agricultural residue, forest residue, energy crops, solid waste, and power-to-gas methanation, compared to the U.S. average annual consumption of 15,850 tBtu).
150 Jimmy O’Dea, The Promises and Limits of Biomethane as a Transportation Fuel, Union of Concerned Scientists, at 2, Figure 1 (May 2017), https://www.ucsusa.org/sites/default/ files/attach/2017 /05/ Promises-and-limits-of-Biomethane- factsheet.pdf.
151 California Energy Commission, The Challenge of Retail Gas in California’s Low-Carbon Future, at 6 (Apr. 2020), https://www. energy.ca.gov/sites/default/files/2021-06/CEC-500-2019- 055-F.pdf.
152 Id. at 4.
153 Brady Seals & Andee Krasner, Gas Stoves: Health and Air Quality Impacts and Solutions, Rocky Mountain Institute et al. (2020), https://rmi.org/insight/gas-stoves-pollution-health.
154 Id. at 13.
155 Prepared Direct Test. of Kevin Woo et al. on Behalf of Southern Cal. Gas Co. et al., at 17 , A.20-11-004 (Cal. P .U.C. Nov. 2020), https://www.socalgas.com/sites/default/files/2020-11/H2_ Application-Chapter_4- Technical.pdf.
156 California Air Resources Board, Advanced Clean Trucks, Total Cost of Ownership Discussion Document (Feb. 22,
2019), at 1https://ww2.arb.ca.gov/sites/default/files/2020- 06/190225tco_ADA.pdf.
157 Nick Albanese, Electric Vehicle Outlook 2020, BloombergNEF (June 2020), https://efiling.energy.ca.gov/GetDocument. aspx?tn=233410&DocumentContentId=65926.
158 Id.
159 Volkswagen, Battery or fuel cell, that is the question (Mar. 12, 2020), https://www.volkswagenag.com/en/
news/ stories/2020/03/battery-or-fuel-cell--that-is-the- question.html.
160 Fraunhofer Institute 2020, supra note 59, at 12.
161 Amol Phadke et al., Why Regional and Long-Haul Trucks are Primed for Electrification Now, Lawrence Berkeley Nat’l Lab’y (Mar. 2021), https://eta-publications.lbl.gov/publications/why- regional-and-long-haul-trucks-are.
162 See Id.
163 Soren Amelang, Battery-electric trucks will win race against fuel cells and e-fuels - researcher, Clean Energy Wire (Nov. 25, 2020), https://www.cleanenergywire.org/news/battery- electric-trucks-will-win-race-against-fuel-cells-and-e-fuels- researcher.
164 Maximillian Holland, Scania Ditches Fuel Cell Trucks to Focus on Full Electric, CleanTechnica (Jan. 30, 2021), https:// cleantechnica.com/2021/01/30/scania-ditches-fuel-cell-
trucks-to-focus-on-full-electric/.
165 Joshua S. Hill, VW joins ranks of car makers rejecting hydrogen fuel cells, TheDriven (Mar. 16, 2021), https://thedriven. io/2021/03/16/vw-joins-ranks-of-car-makers-rejecting-
hydrogen-fuel-cells/; see also Volkswagen, Battery or fuel cell, that is the question, supra note 159 (“The conclusion is clear:
in the case of the passenger car, everything speaks in favor of the battery and practically nothing speaks in favor of hydrogen. ‘No sustainable economy can afford to use twice the amount of renewable energy to drive with fuel cell passenger cars rather than battery-powered vehicles,’ says study leader Dietmar Voggenreiter.”).
166 Johnna Crider, Mercedes-Benz is Done Chasing the Hydrogen Fuel Cell Car Dream, CleanTechnica (Apr. 23, 2020), https:// cleantechnica.com/2020/04/23/mercedes-benz-is-done-
chasing-after-hydrogen-fuel-cell-cars/.
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1 Ghazarian, Renia
From: Powers, Christine
Sent: Wednesday, February 16, 2022 9:49 AM
To: Ghazarian, Renia
Cc: Garcia, Michael; van Muyden, Gillian; Godinez, Christine Subject: FW: Feedback for City of Glendale, CA
From
: [email protected] <[email protected]> Sent: Tuesday, February 15, 2022 4:45 PM
To: WebDev <[email protected]>
Subject: Feedback for City of Glendale, CA
CAUTION: This email was delivered from the Internet. Do not click links, open attachments, or reply if you are unsure as to the sender.

You have received this feedback from Michael Herwig < [email protected] > for the following page:
https://www.glendaleca.
gov/government/city-hall/contact-city-officials
I saw the docum
entary on Spectrum News on the proposed new Glendale DWP gas power plant, the comments made, and have some points to make. Please share with the appropriate government and DWP officials. I have an engineering degree, some experience in power generation, do sometimes keep up with current events in energy. I believe this plant would provide an important reliable power source at a relatively low carbon footprint, especially important during the transition to green power. Natural gas has the lowest pounds of carbon dioxide produced per BTU of the carbon based fossil fuels. Coal is about double that number for natural gas.

Many states and countries have found natural gas to be a good reliable and robust energy source with lower pollution and relatively low carbon footprint, a reasonable choice in an attempt to meet all objectives stated above. I am doubtful of the current reliability of the current green energy infrastructure in California. Countries have found the importance of reliable and robust energy with energy shortages, higher prices, and limited ability of green energy to meet demand. Europe has been going through a terrible energy crisis and the report was that their windmills were not that helpful. Texas went through a terrible outage last winter and it was found all of their wind turbines were frozen, although probably would have only met part of the demand. In response, I believe Texas is increasing their electricity production from natural gas. Countries cannot rely on when the wind blows or when the sun shines sufficiently. Hydroelectric has reached its maximum. China has reverted back to re-starting their coal plants. Nuclear power is staging a comeback as governments are taking a renewed interest (U.S., U.K., France, Japan). Nuclear power meets climate control goals in not emitting greenhouse gases while providing reliable power (technically green power). Governments must be really concerned about 982 of 983
2 reliable power, while transitioning to green power, if they are interested again in nuclear power. I hope and expect green energy will improve in the years to come. In the same time demand will increase substantially and that has to be accounted for. I do believe more should be invested in solar power and energy storage. Not mentioned too much is the effort by some companies to produce renewable natural gas from methane emissions from farms and dairies (there may be other sources). One company is capital rich Chevron whose CEO has one of his goals to support ESG. Methane has a much higher greenhouse potential over carbon dioxide, about 56 times more for 1 lb of methane to 1 lb of carbon dioxide. The latter s 2.75 times heavier and more prevalent in the atmosphere, but methane is still a serious threat to global warming. Capturing these fugitive methane emissions is important to help reduce global warming. Using this renewable gas in a power plant further reduces the plant's net global warming footprint. Newer plants should have increased efficiencies from old, so the new plant should also have a reduced carbon footprint.
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Glendale City CouncilFebruary 15, 2022

Glendale City Council
February 15, 2022