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November 5, 2024

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Counterflow: Clean Energy Charging

tesla powerwallSteve Huntoon | Steve Huntoon

Just when you might have hoped for a respite from green/clean energy fantasies — like the miracle of Babcock Ranch I wrote about last month[1] — another one comes along.

Apple (NASDAQ:APPL) just rolled out “Clean Energy Charging” in iOS 16.1. (For tech dolts like me, that’s the latest iPhone operating system.)

The Claim

Apple says: “When Clean Energy Charging is enabled [which is the default] and you connect your iPhone to a charger, your iPhone gets a forecast of the carbon emissions in your local energy grid and uses it to charge your iPhone during times of cleaner energy production.”[2]

What’s going on here?

The Basics

To start with the basics, carbon emissions come from electric power plants fueled by fossil fuels (basically natural gas and coal). In order to get clean energy, power generation has to be shifted from fossil fuels to non-fossil fuels.[3] For what Apple claims to work, it has to change the time of charging iPhones from when fossil fuel generation otherwise would be running to when clean generation would run more because of the iPhone charging. This can only happen by changing the dispatch of electric generators “on the margin” (last to be turned on/first to be turned off) because only generators on the margin are affected by an incremental change in demand (in this case from the iPhone charging). With me so far?

To drill down on Apple’s claim, I’ll focus on PJM. An iPhone charges at about 5 watts.[4] There are about 24 million iPhones in PJM,[5] so we’re talking 120,000,000 watts (equal to 120,000 kWs, or 120 MWs, if all these iPhones are charging at the same time). This is a pittance in PJM, but let’s let that slide.

Clean?

Now let’s make an assumption that all the iPhones in PJM are charging at 5 watts at the same time — 120 MWs worth. But 87.8% of the time, the marginal generator in PJM is fossil fuel.[6] How does Apple know when to stop iPhone charging in order to resume charging during the other 12.2% of the time when it’s not fossil fuel generation on the margin?

Apple doesn’t tell its customers how it knows when that would be, and it did not respond to repeated requests to answer that mystery.[7] And even when non-fossil fuels are on the margin during a given hour, it is only for a fraction of that hour.[8] And even if Apple could somehow guess right on a given five-minute period (and on location wherever there is congestion), it may have to hold off charging for hours or days waiting for those minutes to come along — with 24 million irate iPhone users waking up to learn their iPhone didn’t charge last night because Apple was waiting for Godot.

By the way, that 12.2% doesn’t mean there’s a paucity of non-fossil fuel generation in PJM, which actually makes up 38.4% of all generation in PJM.[9] Instead it reflects the fact that non-fossil fuel generators have low variable costs (sometimes even negative because of the production tax credit), so they are dispatched first whenever they actually can generate. And so they usually are not on the margin.

Cleaner?

Now let’s assume Apple is only claiming “cleaner” energy rather than “clean” energy (despite this title for its new function). It might hypothesize that relatively low energy clearing prices are correlated with cleaner fossil-fuel generation. If that were the case, then Apple might use lower expected energy prices (such as from the day-ahead market) as a predictor of cleaner generation on the margin, and shift iPhone charging accordingly (such as from afternoon hours to wee hours). Although this hypothesis is theoretically possible, there are problems.

First, it appears that the marginal fuel has no material correlation with the time of day.[10] In other words, simply shifting iPhone charging from, say, afternoon hours to, say, wee hours wouldn’t necessarily make for cleaner energy.

Second, if the idea is to choose from time to time between natural gas and coal generation based on the lowest day-ahead prices, that in itself appears to be a crapshoot because the fuel costs of natural gas and coal generation tend to be close.[11] So if for a given next day, Apple goes with say the lowest cost hours of 2 to 4 a.m., there isn’t a solid reason to assume natural gas rather than coal will be on the margin.[12]

Third, data from ERCOT suggests no clear relationship between the generator offer price supply curve and generator emissions.[13]

Bottom line: Even if clean/cleaner charging of iPhones were possible, there’s no reason to think Apple is actually doing it.

We could use a little more virtue, and a little less virtue signaling.

Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.

[3] I’m assuming initially that Apple isn’t basing Clean Energy Charging on shifting iPhone charging from one fossil fuel like coal to another fossil fuel like natural gas. This would be misleading (i.e., not “clean”). But I’ll also discuss the prospect of merely “cleaner” generation later.

[5] There are about 65 million people in the PJM footprint, and about 37% of them have an iPhone based on national data (125 million iPhone users in the U.S. relative to 332 million total U.S. population).

[7] Macworld speculated that “Apple is probably partnering to get data from electric grid managers that shows the mix of energy sources powering the grid (for example, see the California ISO supply trend page), or with a third-party source like Watttime that seeks to measure when the electricity you use is powered by cleaner sources.” https://www.macworld.com/article/1065566/ios-16-clean-energy-charging.html.

[8] https://www.monitoringanalytics.com/data/marginal_fuel.shtml, picking any month and observing in the “Percent Marginal” column the fractions of hours for non-fossil fuel generation (principally wind).

[11] https://pjm.com/-/media/committees-groups/committees/oc/2022/20221208/item-15—fuel-supply-overview.ashx, slide 11 (These are in $/MMBtu so do not reflect the lower heat rate/higher efficiency of natural gas generation, but they make the point.)

[12] This observation is consistent with my own spot-checking of hourly generation/load reporting on PJM’s home page, www.pjm.com. Relative shares of coal and natural gas generation didn’t seem much correlated with total load.

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MISO, SPP Fall Short in 5th Try for Interregional Projects

After four joint studies by SPP and MISO last decade failed to turn up an interregional project, the RTOs began another effort in 2020 by searching for transmission projects that could solve congestion issues along their seam.

They have again come up empty.

“We basically have confirmed that we do not have any viable candidate projects this year,” SPP’s Neil Robertson told the RTO’s Seams Advisory Group on Friday, confirming what staffs have been warning stakeholders in recent months. (See Search for Small SPP-MISO Interregional Projects May be Fruitless.)

He declined to go into detail, saying he is saving that discussion for when the RTOs’ staffs present a “full” presentation to stakeholders during a virtual Interregional Planning Stakeholder Advisory Committee meeting Wednesday.

Robertson said no project met the RTOs’ criteria for qualifying as targeted market efficiency projects (TMEPs), a construct MISO and PJM use on their seam.

“We just wanted to go ahead and give that brief preview that we have not identified any good project candidates that we can recommend to the MISO or SPP board for approval,” he said.

The Joint Targeted Interconnection Queue study screened for possible TMEPs when market-to-market flowgates amassed $1 million or more in congestion costs over a two-year period. The RTOs catalogued seven permanent flowgates that met that criteria but failed others. (See MISO, SPP Identify Hotspots for Smaller Interregional Tx Projects and MISO, SPP Hunt for Small Interregional Tx Projects.)

Missouri PSC Grants CCN for NextEra Project

The Missouri Public Service Commission on Friday approved an agreement with parties involved in NextEra Energy Transmission (NEET) Southwest’s effort to secure a certificate of convenience and necessity to build part of an SPP competitive project (EA-2022-0234).

The PSC agreed with staff’s recommendations that the CCN be approved with certain conditions:

  • there’s a need for the transmission service;
  • NEET is qualified and has the financial ability to provide the proposed service;
  • NEET’s proposal is economically feasible; and
  • the service promotes the public interest.

The CCN is for a 9-mile segment of the 94-mile, single-circuit 345-kV transmission line between Associated Electric Cooperative Inc.’s Blackberry substation in Missouri and Every Kansas Central’s Wolf Creek substation in Kansas.

SPP granted the competitive project, its fourth, to NEET Southwest last year. The NextEra Energy (NYSE:NEE) subsidiary estimated the project will cost $85.2 million and be completed in 2025. (See “Expert Panel Awards Competitive Project to NextEra Energy Transmission,” SPP Board of Directors/Members Committee Briefs: Oct. 26, 2021.)

Kansas regulators awarded NEET a CCN for its state’s portion of the project in August. (See Kansas Regulators Approve CCN for Competitive Project.)

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MISO Board Week Briefs: Dec. 6-8, 2022

Market Platform Replacement to Spill over into 2025

ORLANDO, Fla. — MISO Chief Digital Officer Todd Ramey brought “good news and bad news” to Board Week about the ongoing effort to replace the RTO’s market platform.

Ramey said during a Dec. 6 Technology Committee meeting that while MISO can speed up the delivery of two real-time market applications, the overall work will likely stretch into 2025. Staff previously had ambitions to wrap up the project by the end of 2024, though it frequently cautioned that the timeline could run longer.

MISO will push approving factory acceptance testing and a vendor’s delivery of the day-ahead market-clearing engine into January, Ramey said. He said while staff could likely meet the original end-of-the-year target with long nights, overworking employees wasn’t the answer.

However, the grid operator will meet a Dec. 31 deadline to finish testing and begin parallel operations of its new energy management system. Staff will use the EMS to monitor and analyze the bulk electric system and fulfill MISO’s responsibilities to NERC as a reliability coordinator and balancing authority.

The RTO will launch its new day-ahead market next year and continue migrating data to its one-stop model manager.

MISO has said its “vision to retain one system of record for all models” requires members to review and reconcile discrepancies between data in the new model management system and its existing modeling outlets. It said it has been reaching out to members with discrepancies.

MISO Board Week at the Ritz Carlton Orlando (RTO insider LLC) Content.jpgMISO Board Week was held at the Ritz-Carlton’s Orlando Grande Lakes | © RTO Insider LLC

 

The RTO previously said it has some differences in data between lower voltage transmission representation, generation representations with a common connection point, common load representation, and accurate ownership designation of individual equipment.

Ramey said MISO should be able to quickly introduce a reliability assessment commitment tool and a future-looking commitment tool in 2023 and 2024, respectively.

Director Theresa Wise said the developments were “exciting progress.”

MISO will have to hike the project’s budget because of inflationary pressures and the nation’s tight labor market. The grid operator began the market platform project with a $130 million budget and a $30 million contingency; Ramey said it appears staff will use half of the contingency to finish the project.

Wise said the budget increase is “not a source of angst” because budget overruns are commonly impacting industries today.

The Technology Committee covered preventative cybersecurity and disaster recovery in a closed session.

Members Change Advisory Committee’s Leadership

Indiana Utility Regulatory Commissioner Sarah Freeman will chair the Advisory Committee when Manitoba Hydro’s Audrey Penner steps down at the end of the year.

Penner has served as the AC’s chair since 2015. MISO’s stakeholder relations group announced the transition during a committee meeting Wednesday.

Freeman said during a September Organization of MISO States’ meeting that she is interested in “growing the relationship between stakeholder sectors and the MISO Board of Directors.”

For two years, some stakeholders have pressed for less stage-managed interaction and more organic access to the board. (See MISO Members Request More Access to Directors.)

Michigan Public Service Commission Chair Dan Scripps said it makes sense for a member of MISO’s state regulatory sector to lead the AC in balancing “competing interests for the public benefit.” He said regulatory staff or Manitoba Hydro, the only coordinating sector member, seem best suited for the job.

MISO Welcomes 2 New Members

The board approved Missouri Joint Municipal Electric Utility Commission (MJMEUC) and Rainbow Energy Center’s membership applications.

The commission, a municipal joint-action energy agency, joins as a transmission owner. Rainbow Energy recently purchased the 1,150-MW Coal Creek Station in North Dakota from Great River Energy. Coal Creek delivers power to the Minneapolis area, and Rainbow is exploring fitting the plant with carbon-capture equipment.

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Lewis Upsets Boissiere for Seat on La. PSC

Davante Lewis, a progressive advocate for clean energy, unseated three-term incumbent Louisiana Public Service Commissioner Lambert Boissiere III on Saturday in a runoff election for a seat on the five-person commission.

Lewis won 59% of the votes from 738 of the PSC District 3’s 748 precincts, which stretch from Baton Rouge to New Orleans. He had 18% of the vote in last month’s primary, the highest among Boissiere’s four challengers; two of those later endorsed Lewis.

The 30-year-old Lewis is currently director of public affairs for the Louisiana Budget Project, which monitors and reports on public policy and how it affects Louisiana’s low- to moderate-income families. He ran on a platform of reaching 100% renewable electricity by 2035, hardening the grid against increasingly severe hurricanes, cracking down on excessive fees by utilities and instituting a Ratepayers’ Bill of Rights.

As an incumbent, Boissiere was saddled with an environment in which customer bills were rising after last year’s hurricane season left millions without power, some for weeks.

“Tonight, we have begun a new chapter for Louisiana,” Lewis told his supporters Saturday night at a Baton Rouge pub. “Tonight, the people of Louisiana start taking our power back. Tonight, Louisiana has a public service commissioner who’s unafraid to hold Entergy accountable, because I owe this victory to the people of Louisiana and their commitment to a brighter, cleaner and 100% renewable future.”

Lewis was supported by contributions from environmental groups, including a super PAC aligned with the Environmental Defense Fund that raised about $1.1 million after getting involved in the race during the primary. Boissiere, who was first elected to a six-year term on the PSC in 2004, drew support from utilities and lobbyists, Gov. John Bel Edwards (D) and U.S. Rep. Troy Carter (D), whose district encompasses much of the commission’s District 3.

Lewis and Boissiere are both Democrats; Republicans will hold a 3-2 edge on the commission.

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Western RA Program Secures First ‘Binding’ Phase Participants

Nearly a dozen utilities have committed to joining the “binding” iteration of the Western Resource Adequacy Program (WRAP), with more expected to sign on later this month, the program’s operator said last week.

The commitments by 11 participants, most of which are located in the Northwest, signal a show of confidence in the program, which was conceived to ensure that the Western Interconnection has sufficient capacity on hand to meet growing loads in both summer and winter. Concerns about resource adequacy have dogged the West as state greenhouse gas-reduction policies force early retirement of fossil fuel generation alongside an increasing reliance on variable renewable generation.

Administered by the Western Power Pool (WPP), the WRAP is currently operating in a “nonbinding” fashion in which participants are not penalized for falling short of their reserve requirements. Contingent on FERC’s approval of its tariff, the program in 2024 will enter a binding phase that will levy penalties for shortfalls.

“The critical next steps for the WRAP are securing the needed commitments from our participants and FERC approval of the tariff,” WPP CEO Sarah Edmonds said in a release Thursday. “The commitment of these 11 organizations puts us well on our way to accomplishing one of those steps. Addressing resource adequacy must be a regionwide collaboration, and we commend these first partners for their leadership and thank them for setting the tone for what’s to come.”

The utilities and power providers making commitments include Avista Utilities (NYSE:AVA), Calpine Energy Solutions, Chelan County Public Utility District, Clatskanie People’s Utility District, Eugene Water & Electric Board, PacifiCorp (NYSE:BRK.A), Portland General Electric (PGE), Powerex, Puget Sound Energy, Seattle City Light and Tacoma Power.

The 11 are among the 26 entities currently participating in the WRAP’s nonbinding phase, which also includes utilities from Northern California and the Southwest.

In a release PacifiCorp issued Thursday announcing its intention to join both the proposed extended day-ahead market (EDAM) of CAISO’s Western Energy Imbalance Market (WEIM) and the WRAP, the utility said it has “worked extensively” with the WPP and other prospective participants in developing the WRAP, “which is expected to provide regionwide reliability benefits to it participants by pairing regional diversity with common resource adequacy standards.”

“EDAM, WEIM and WRAP will work together to ensure the benefits and certainty needed to meet our customers’ growing demands for a reliable and clean grid,” said Stefan Bird, CEO of Pacific Power, a PacifiCorp subsidiary. “We are extremely excited to work with our partners to move the region forward into greater collaboration and secure even more benefits for customers.”

“Maintaining reliability is critical as we move forward with advancing decarbonization, and the WRAP would allow us to do this in a way that is most beneficial to our customers and manage costs,” PGE CEO Maria Pope said in a statement. “The WRAP will allow us to pool resources and share in the diversity of the region.”

The WPP filed its proposed WRAP tariff with FERC in August, hoping to win approval from the commission by the end of the year. Last month, FERC issued WPP a deficiency letter asking for more information about the program, including details about participation by members without market-based rate authority and WPP’s intention to hire an “independent evaluator to provide an independent assessment of WRAP’s performance.” (See FERC IDs Deficiencies in Western RA Program.)

Edmonds said at the time that the WPP knew such a development was possible and that she was confident the WRAP proposal will “ultimately gain approval.”

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MISO Members Say Speed Necessary to ‘Mind the Gap’

ORLANDO, Fla. — MISO members agreed that the future generation mix is arriving faster than previously thought during a “mind the gap” discussion last week.

The grid operator is particularly concerned about reliably navigating the resource transition’s next five years in what it has termed “mind the gap.” It foresees the potential for capacity deficits through 2027.

Jennifer Curran, senior vice president of planning and operations, told the Advisory Committee Wednesday that demand for sustainability means that the footprint is losing controllable thermal generation and trending toward variable intermittent resources. She said MISO could face severe reliability consequences if it doesn’t “close the gap well” and should not waste time in making decisions.

“I think it is happening a little faster than people thought it would happen,” said Constellation Energy’s John Orr, of the power marketers sector.  

Alliant Energy’s Mitch Myhre, representing transmission-dependent utilities, said the RTO’s viewpoint might be too pessimistic. He said MISO shouldn’t presuppose its access to flexible resources is completely drying up.

“I don’t think we should assume that technology isn’t going to evolve,” he said.

Myhre said staff should begin studying different power flows where resources are closer to their loads.

Michigan Public Service Commission Chair Dan Scripps said MISO doesn’t have a clear picture of how large its supply shortage might be because its resource accreditation is currently in flux.

Scripps suggested the grid operator’s messaging could be more optimistic. He said though MISO is currently on the “wrong side” of the one-day-in-10-years reliability standard, it doesn’t mean that it will be MISO’s fate throughout the transition.

“We need to make sure that we’re instilling a sense of confidence as we go forward and not an air of fear,” Myhre said in agreement.

The Union of Concerned Scientists’ Sam Gomberg said MISO sometimes “circles the wagons around the status quo,” pointing to demand management and its proposed 2030 adoption date to comply with FERC’s order to allow distributed energy resource aggregators into the wholesale energy markets. (See MISO Defends 2030 Completion for DER Market Participation.)

Illinois Commerce Commission Chair Carrie Zalewski said the RTO and state regulators should ensure that barriers are knocked down for DER aggregation and other new technologies.

North Dakota Public Service Commission Chair Julie Fedorchak added that the grid operator can only move as fast as the commercialization of new technology allows. She also warned MISO and members that “hope is not a strategy.”

Michelle Bloodworth, CEO of coal lobbying group America’s Power, asked staff to expedite their work on defining and requiring certain generation attributes. They have already identified six reliability attributes as necessary: availability, the ability to deliver long-duration energy at a high output, rapid start-up times, providing voltage stability, ramp-up capability, and fuel assurance. (See MISO Considers Resource Attributes as Thermal Output Falls.)

Bloodworth said those attributes and accredited capacity are being whittled away through resource retirements.

MISO has committed to reserving a full day and a half for its Resource Adequacy Subcommittee (RASC) meetings in 2023. The subcommittee works on resource adequacy initiatives, including availability-based resource accreditations, overseeing the move to seasonal capacity auctions, transitioning to a sloped demand curve in capacity auctions, and defining necessary resource attributes.

Some members debated whether MISO should spend $20-$30 billion in the second iteration of its long-term transmission portfolios to interconnect new generation. They said consumers have a limit to how much they’re willing to foot the bill for expensive, 50-year infrastructure.

“There will be a limit on what ratepayers are willing to pay, point blank,” said Clean Grid Alliance’s Beth Soholt, with the environmental sector.

Soholt said consumer advocates are getting more involved in putting up resistance to new rate cases, especially as utilities increasingly ask for double-digit hikes.

Multiple stakeholders said MISO should put more emphasis on its electrification load forecasting to ensure it’s not over- or under-building the system as the fleet transition plays out.

Scripps said MISO will undoubtedly shift away from the flat load growth of the last decade that was “exacerbated by the weirdness of [COVID-19].” He said staff should get load forecasting “as right as they can,” but added that the grid operator will never have perfect forecasting.

“You’re never going to get the load number right. You’re going to get it close,” Orr said. He said there’s a price for a one-in-10 standard versus a “one-in-never standard.” He said members should “educate the public on what they’ve bought, as what they want, and tell them the price of that.”

“We’re in a probabilistic business,” Orr said. “Not an absolute business.”

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SPP Board of Directors Briefs: Dec. 6, 2022

Staff Finalizing Mitigation Strategy for PRM-deficient LREs

SPP staff last week said they are finalizing a mitigation strategy for load-responsible entities unable to meet the grid operator’s new 15% planning reserve margin and developing several concepts that would make failure to meet the requirements “less costly or less punitive.”

Lanny Nickell (SPP) Content.jpgSPP COO Lanny Nickell | SPP

COO Lanny Nickell told the Board of Directors during its Dec. 6 meeting that the concepts include reducing the deficiency payment charge, extending the timeline to cure deficiencies and adding mechanisms to assure capacity.

Staff have been working on the mitigation strategy at the board’s direction since July. It became necessary when the board increased the planning reserve margin from 12% to 15%, effective next year, which left some members complaining they wouldn’t have enough time to meet the requirements. (See SPP Board, Regulators Side with Staff over Reserve Margin.)

“We’re not looking to add that to the tariff on a long-term and permanent basis, but it would give some instant and interim relief,” Nickell said.

He said reducing the deficiency payment would reflect excess capacity’s value when a payment is required after a sudden increase in the PRM requirement. Nickell said the mechanism would incent long-term capacity planning and assess deficiency payments based on multiples of the cost of new entry to LREs that have not met the PRM.

The concept doesn’t relieve LREs of their obligation to comply with their resource adequacy requirements. However, it is applicable to deficient LREs for two years after the PRM change.

SPP is also proposing giving LREs more time to assess and cure their resource adequacy positions and better facilitate submissions on a virtual bulletin board to buy or sell power.

A 12-member strike team of directors, regulators and stakeholders has been meeting weekly since October to vet staff’s work. “We appreciate the fact that they were willing to help and willing to advise staff as we developed our further efforts on a mitigation strategy,” Nickell said.

The 22-person Members Committee unanimously approved staff’s concepts, with one abstention, with its advisory vote.

Staff plan to seek approval this week from the Regional State Committee of the mitigation effort’s applicable concepts. The board in October gave the committee, which comprises state regulators, the OK to file a tariff change with FERC that details how LREs can qualify for and receive exemptions from deficiency payments. (See SPP Board Bypasses Stakeholders on PRM Obligation Exemptions.)

SPP plans to file the tariff revision on behalf of the RSC this week. At the same time, it will draft a revision request for the mitigation concepts and bring that to the board and RSC in January.

Myers, Lang to Lead MOPC

The directors spent the bulk of last week’s meeting reviewing stakeholder evaluations of the board and organizational effectiveness, a stakeholder satisfaction survey, and SPP’s key performance metrics.

They also approved the consent agenda, which included several Corporate Governance Committee recommendations for the Markets and Operations Policy Committee’s leadership and other organizational groups.

As is SPP’s practice, Vice Chair Alan Myers, of ITC Great Plains, assumed the chairmanship previously held by Evergy’s Denise Buffington. The CGC recommended Omaha Public Power District’s Joe Lang as the new vice chair; both will begin their two-year terms on Jan. 1.

Buffington will fill a transmission-owning member’s vacancy on the Strategic Planning Committee. The term expires Dec. 31, 2023.

The CGC also put forward several nominations to serve two-year terms as organizational group chairs:

  • John Turner, Western Farmers Electric Cooperative, Modeling Development Working Group.
  • Tess Venetz, Xcel Energy, Settlements User Forum.
  • Calvin Daniels, Western Farmers Electric Cooperative, Economic Studies Working Group.
  • Derek Stafford, Grand River Dam Authority, Operations Training User Forum.
  • Jodi Hall, Evergy, Change User Forum.
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California to Offer $100M in Clean Hydrogen Incentives

As the California Energy Commission prepares to offer $100 million in incentives for clean hydrogen projects in the state, officials are seeking public feedback on the details of the upcoming solicitations.

The Clean Hydrogen Program has three main components, CEC staff said during a workshop on Dec. 1.

In the first piece, the CEC plans to offer $40 million for large-scale, centralized clean hydrogen production. The funds will target projects using existing technologies to produce hydrogen on a large scale — 5 metric tons a day or more — in the near term. Awards will range from $10 million to $20 million.

Another $30 million in funding will be available to projects in which hydrogen is produced and stored at a point-of-use. The CEC is looking for 1 to 5 metric tons of daily hydrogen production. This funding is aimed at earlier stage technologies. The awards would range from $4 million to $7.5 million.

And in a third component, $20 million would be available to hydrogen projects in need of matching funds for federal money, such as from the Infrastructure Investment and Jobs Act. In addition, another $10 million is set aside for technical assistance and administrative support, bringing the program total to $100 million.

As now proposed, funding for large-scale projects would be limited to those producing hydrogen through electrolysis powered by renewable resources. In contrast, the CEC would allow more flexibility in production methods for onsite hydrogen projects.

The solicitations are expected to be released next year, starting with the federal matching funds component. The CEC is accepting comments on design of the solicitations through Dec. 16 at 5 p.m.

Electrolysis Requirement Debated

The electrolysis requirement for large-scale projects was a topic of debate during the workshop.

“[I] don’t understand why the focus was put on electrolysis. That’s not the cost-effective way to produce green hydrogen,” said workshop participant Chris Headrick, founder and executive chairman of Texas-based H2 Energy Group. The company’s technology produces hydrogen through pyrolysis of woody biomass.

The Clean Hydrogen Program was created by this year’s Assembly Bill 209, and CEC staff said program requirements are based on what’s in the bill.

The bill says that hydrogen projects eligible for the program’s incentives must involve hydrogen “derived from water using eligible renewable energy resources,” or be “produced from these eligible renewable energy resources.”

“I don’t see anything in AB 209 that justifies limiting the larger export projects to electrolytic hydrogen only,” said Julia Levin, executive director of the Bioenergy Association of California. “And I would say it’s actually far more urgent to deal with our organic waste to meet the state’s short-lived climate pollutant requirements, the wildfire reduction requirements, etcetera.”

CEC staff noted that the current program requirements are proposals at this point, and the agency will take stakeholder feedback into account before finalizing them.

Another program requirement that raised questions was a proposal to ban petroleum refining as an end use in either the large-scale or onsite projects.

“Why limit the end use of hydrogen?” a workshop participant said in a chat comment. “If it is green and can replace fossil derived hydrogen, it is a step in the right direction.”

Costs, Emissions Considered

The CEC plans to evaluate project proposals based on factors including technological readiness, water usage and reduction in emissions of greenhouse gases and other pollution.

The agency will be looking for cost improvements as compared to the cost of hydrogen from steam reforming of fossil gas. Job benefits and community impacts will also be considered.

CEC staff described the clean hydrogen program as complementary to the Alliance for Renewable Clean Hydrogen Energy Systems, or ARCHES.

ARCHES is California’s public-private consortium aimed at accelerating the development and deployment of green H2 projects and infrastructure. The partnership is seeking a piece of the $8 billion in hydrogen hub funding being offered by the Department of Energy.

ARCHES is seeking proposals for hydrogen projects in California, with a deadline of Dec. 23.

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Rhode Island Updates 2016 Greenhouse Gas Plan

A draft update of Rhode Island’s climate protection plan indicates the state is below the trajectory needed to meet its greenhouse gas reduction targets but lays out steps to achieve them.

The Executive Climate Change Coordinating Council (EC4) is under a Dec. 31 deadline to update the state’s 2016 Greenhouse Gas Emissions Reduction Plan.

The draft update released Monday contains changes based on developments since the original was penned, including last year’s Act on Climate, which converted the state’s emissions-reduction goals to enforceable mandates and set priorities for equity, justice and workforce development.

After delivering the final version of this update, the EC4 will begin to draw up the formal “2025 Climate Strategy,” due Dec. 31, 2025.

Rhode Island’s 2021 Act on Climate requires the state to reduce greenhouse gas emissions by 45% from 1990 levels by 2030 and 80% by 2040, then achieve net zero status by 2050. The state is also trying to reach 100% renewable energy by 2033.

Given changes in methodology, comparing 1990 and 2019 data is not an apples-to-apples exercise, the report states. But using that data, a simulator developed by RMI shows Rhode Island emissions fell 19.5% from 1990 to 2019 and projects emissions would be down only 40.8% in 2030, missing the 45% target by a significant margin.

“This is a very simple, preliminary model that verifies Rhode Island is moving in the right direction but is not quite at the point where we can be confident in our success,” the report states. “More refined modeling and development of specific strategies to increase that confidence will be the crux of the 2025 Strategic Plan.”

Developments in Rhode Island since the original Greenhouse Gas Plan was created in 2016 include:

Priorities going forward include:

  • conversion of the power grid to a two-way conduit between many renewable energy producers and customers, rather than a one-way flow from a few large generators to customers;
  • installation of advanced electric meters capable of by-the-minute measurements and real-time communication;
  • expansion of the number of EVs registered in the state from 6,275 (as of October 2022) to 86,000 by 2030;
  • growing public transit ridership from 53,000 to 87,000 trips per day by 2040;
  • conversion of 15% of all buildings from fossil fuel heat to efficient electric heat by 2030; the authors call this “an aggressive but attainable and necessary target;”
  • strengthening Rhode Island’s Building Energy Code;
  • adoption of a no-net-loss policy for forestland, which absorbs and stores carbon dioxide; the nation’s smallest state has about 361,000 acres now; and
  • the pursuit of districts for geothermal heating and cooling, which can be difficult for individual homeowners to install themselves.

The 2021 Act on Climate did not actually define “emissions” or the “net-zero” balance it seeks to achieve. The EC4 group proposes that emissions be defined as any of the greenhouse gases blamed for global warming now or in the future, and that net-zero be a balance between the amount emitted and the amount absorbed or broken down.

But the authors say that in the 2025 report they plan to continue to stress reduction of emissions over net zeroing. And without improvements in emissions-tracking capabilities, they plan to endorse annual measurements of emissions, rather than seasonal, monthly, daily or even hourly measurements.

Near-term prospects appear strong for federal funding to pay for these initiatives, the authors say, but it will not be enough. State taxpayers will have to foot some of the bill.

Rhode Island’s greenhouse gas emissions in 2019 — the last year available — were estimated to be 1.8% lower than in 2016.

Transportation and thermal uses accounted for the bulk of emissions at 39.7% and 38.8%, respectively, followed by electricity consumption at 18.9%. Agriculture and waste were the source of 2.6%.

Emissions from electrical power consumption and industrial uses decreased between 2016 and 2019, countered by increases in emissions from heating, transportation, agriculture and waste.

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ERCOT Technical Advisory Committee Briefs: Dec. 5, 2022

Real-time Co-optimization Could be Back in 2023

ERCOT plans to resuscitate the development of real-time co-optimization, staff told the Technical Advisory Committee Monday.

The market tool was paused last year because of staffing constraints following the February winter storm. (See “Passport Pushed Back 18 Months,” ERCOT Technical Advisory Committee Briefs: April 28, 2021.)

Dave Maggio, ERCOT director of market design and analytics, said plans to resume RTC’s development in mid-2023 are “on the radar.” Its delivery is dependent on staffing and other requirements that may come out of the market design, he said.

RTC was originally scheduled to go online in 2024. Maggio said assuming a mid-year kickoff next year, it will be delivered in 2026.

Staff has estimated it will cost as much as $55 million to implement the RTC tool, which procures both energy and ancillary services every five minutes. ERCOT’s Independent Market Monitor has called for the grid operator to add the tool for several years.

Maggio will return to TAC’s Jan. 24 meeting with additional details on scheduling and timing.

No Major Changes to AS Methodology

TAC endorsed staff’s annual recommendations for the proposed methodology for computing ancillary service quantities in 2023, which included making no changes to the methodologies used to compute regulation service and responsive reserve service (RRS) requirements for 2023.

Staff is proposing changes in the methodology used to compute minimum non-spinning reserve service requirements in 2023 by shifting from a 6- to 10-hour ahead net load forecast error. Upon its implementation, they are recommending computing ERCOT contingency reserve service requirements as the sum of capacity needed to recover frequency following a large unit trip and capacity needed to support sustained net load ramps.

Staff is also proposing to revise the minimum RRS-primary frequency response limit next year to 1,390 MW, aligning it with an increase to ERCOT’s interconnection frequency response obligation.

The recommendations were added to the TAC’s combination ballot.

Lange Welcomes Return as Chair

South Texas Electric Cooperative’s Clif Lange, who chairs TAC, told members he is open to returning to the leadership position next year, assuming he remains a committee member.

Lange, who was recently promoted as the cooperative’s general manager, said he had been approached by several other members about continuing as chair.

“I wasn’t sure that that was going to be possible,” Lange said, “but after having had some time to reflect and think about it, I’m certainly willing if TAC is willing to have me as chair for next year.”

The Board of Directors will confirm TAC’s representatives during its annual membership meeting Dec. 20.

TAC Endorses 10 Revision Requests

The committee endorsed a system change request (SCR821) that would address operational issues by allowing transmission and distribution service providers to set the voltage set point target information provided to distribution generation or energy storage resources.

The measure passed unopposed but with abstentions from CenterPoint Energy, Oncor Electric Delivery and Texas-New Mexico Power, members of the investor-owned utility segment.

The combination ballot passed with one abstention. It included five nodal protocol revision requests (NPRRs), two revisions to the Nodal Operating Guide (NOGRRs), and single changes to other binding documents (OBDRR) and the Resource Registration Glossary (RRGRR) that, if approved by the board, would:

    • NPRR1128: set an ancillary service offer floor $0.01/MW lower for fast frequency response (FFR) than for other RRS categories to allow FFR procurement up to the current limit, without proration with other RRS categories.
    • NPRR1132: specify that during local cold weather conditions, each qualified scheduling entity (QSE) must update its generation resources and energy storage resources current operating plan, real-time telemetry, and outage and derate reporting to reflect any limitations. It also requires each resource entity to provide resource-specific cold weather minimum temperature limits, hot weather maximum temperature limits, and alternate fuel capability information in its submitted resource registration data and update this information as necessary.
    • NPRR1138: require each resource entity to ensure the reactive capability curve for any intermittent renewable resource accurately reflects its reactive capability when it is not providing real power or is operating at lower levels of real power output.
    • NPRR1152: remove the protocol requirements to submit emergency operations plans (EOPs), weatherization plans, and declarations of summer/winter weather preparedness; revises procedures for submitting declarations of natural gas pipeline coordination with natural gas generation resources; revises the list of items considered protected information to remove references to weatherization plans and add protections for information relating to weatherization activities; and revises the list of ERCOT critical energy infrastructure information to clarify language concerning EOPs and add protections for information relating to weatherization activities.
    • NPRR1154: update language to allow for a qualified alternate resource to be considered in calculating the availability reduction factor for the firm fuel supply service (FFSS) resource and provides a new settlement billing determinant providing the FFSS award amount per QSE per FFSS resource by hour.
    • NOGRR226: add provisions for transmission operator “anti-stall” automatic firm load shedding at 59.5 Hz to mitigate the risk of a total system-wide blackout.
    • NOGRR243: modify the Nodal Operating Guide’s load-shed table to include separate load-shed obligations for the winter and summer seasons that align with Senate Bill 3 directives.
    • OBDRR043: align the operating reserve demand curve’s methodology with NPRR1148’s revisions, approved in August, in calculating the real-time reserve price adder.
    • RRGRR032: add data required to be shared with ERCOT as the reliability coordinator, balancing authority and transmission operator in considering cold weather limitations in its operational planning analysis, real-time monitoring, real-time assessments, and other analysis functions. The ISO also requires this information for hot weather limitations and making this a requirement for distributed generation resources and distributed energy storage resources.