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November 5, 2024

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CAISO, Stakeholders Consider 2 GHG Mechanisms for EDAM

CAISO stakeholders and staff soon could be weighing two options for how the Extended Day-Ahead Market (EDAM) would track and account for greenhouse gases in a way that accommodates the patchwork of different carbon pricing programs across Western states.

Speaking at a March 14 meeting of the ISO’s Greenhouse Gas Coordination Working Group, Doug Howe, GHG policy consultant with the Western Climate Action MOU Group, delved into how the different carbon reduction programs among Western states complicate accounting for GHGs in EDAM. Some states — such as California and Washington — price emissions through cap-and-trade systems while many others seek to limit with “non-priced” GHG programs such as targets for declining emissions for utilities.

“For a standalone utility not in a day-ahead market, compliance would be a relatively straightforward procurement issue,” said Howe, a former member of the Western Energy Imbalance Market’s Governing Body. “In a day-ahead market, compliance would certainly still require the utility to procure the needed resources, but the added complexity is that of imports and exports through the market — specifically, how to account for imports and exports to report on compliance. 

“At a minimum, a thorough tracking and accounting system would be required that provides emissions attribution to all market transfers to avoid over- or undercounting.” 

In contrast to priced programs that place responsibility for compliance on the emitting resource, non-priced programs regulate the load-serving entity and require compliance across a longer time frame, often a year or more. When referring to non-priced programs, Howe excluded renewable portfolio standard programs, which exist in some form in every state in the Western Interconnection except for Wyoming and Idaho.  

Non-priced Challenges

The variety of GHG programs across the Western Interconnection means some states will require utilities to make aggressive emissions reductions as early as 2030 while others face no obligation to reduce.  

One of the main components needed to ensure GHG compliance within EDAM is “control” — or the ability of a market participant subject to a GHG program to have a say in what is imported into and exported out of its area, Howe said. That goes for utilities subject to non-priced programs as well as those operating underpriced programs. 

The variations in average emissions rates among Western states presents a key challenge for designing GHG market mechanisms that satisfy the needs of states with non-priced programs, Howe explained. While the relatively low emissions rates in the Pacific Northwest could help utilities there become compliant with their non-priced GHG mandates, the higher rates in Rocky Mountain and Desert Southwest regions indicate utilities in those regions might struggle to comply with 2030 mandates.

Pointing to patterns already seen in CAISO’s Western Energy Imbalance Market (WEIM), Howe said he expects “GHG competition will emerge” in EDAM, with the priced programs in California and Washington drawing in the lowest-emission resources first.

“This means higher-emitting resources will comprise the bulk of market imports and exports between utilities subject to non-priced GHG programs,” he said. 

“Given how we see the landscape emerging, we took on the exercise of thinking through other options that might allow the utility to garner economic benefits of being in the market without having to self-schedule significant parts of its portfolio, but at the same time have some control of the carbon content of its market imports and exports to ensure compliance,” Howe said.  

Howe presented two mechanisms to address the problem: the emissions constraint method and an import constraint method. 

In the emissions constraint method, a non-priced GHG zone establishes a maximum emissions rate for the dispatch interval and the market optimization chooses which resources’ energy and emissions will be attributed to priced zones.  

“It’s important for me to say that this method does not attribute only resources that can meet the specific emission rate. Rather, it selects resources that, as a pool of resources, can meet the maximum emission rate and energy requirements of the non-priced GHG zone,” Howe said. “A higher-emitting resource could be dispatched, be assigned to the non-priced GHG zone and be offset by a lower-emitting resource.” 

A non-priced GHG zone would operate under a must-offer obligation, meaning it’s obligated to offer a portfolio of generation that meets its load and the maximum emission rate set for the interval. Whenever the emission constraint is enabled, the must-offer obligation must be met.  

This method produces both an energy marginal cost and a GHG marginal cost, with resources attributed to the non-priced zone would be receiving payment from load for both costs, raising what Howe identified as a central policy question: whether the GHG marginal cost should be paid to generators.  

To address that question, Howe presented the second mechanism: the import constraint method.  

“Are there some ways that we can maybe avoid that kind of GHG marginal cost policy question of, ‘Should it be paid or should it not be paid?’ Because it’s a very thorny question,” he said.  

The import constraint method has many similarities to the other method, including allowing the utility to specify the maximum emissions target with a must-offer obligation and not requiring the constraint in every interval. The difference, though, is that external resources would not be attributed to non-priced GHG zones, which “effectively moots” the question of whether attribution should be voluntary. Instead, emissions attributed to non-priced zones would be computed as emissions from internal generation and market imports, minus emissions from exports.  

“In this case, the optimization will choose the internal generation and the amount imported and exported to minimize the total system costs while still meeting the maximum emission rate,” Howe said. “But to do this, we have to establish an imported emissions rate and an exported emissions rate, very much like the residual emissions rate” the Western Power Trading Forum (WPTF) discussed in another presentation.  

Residual Emissions Rate

“We really believe that we should have a long-term goal of developing a better tracking and accounting system for the market to accurately account for energy and to accurately account for emissions,” Clare Breidenich, assistant executive director at WPTF, said in presenting another approach for GHG accounting.  

Central to Breidenich’s proposal was use of residual market supply — energy not committed to market participants or attributed to GHG regulation areas. It determines the residual emission rate, a dispatch-weighted average emission rate of the market supply.  

If the market can ensure that entities are able to claim and procure their own resources to meet load, Breidenich said, then what is left is a relatively small increment of energy, which is the residual market supply.  

“If we can do a better job accounting for that increment of energy, as well as do a better job of accounting for the emission rate of that increment, it’s not clear to us that there really is a need for a dispatch mechanism,” Breidenich said.  

Power producers first need to agree on a set of accounting rules and an emission rate that determines what is in the residual supply, then determine how to match resource claims to dispatched energy and associated emissions and place them into entity accounts for correct attribution. Lastly, a reporting and publication system would be needed for producers and regulators.  

Under this framework, leftover energy in the market would go into the residual supply, and the emissions rate would be the average of the residual mix.  

The benefit of this approach, Breidenich said, is that it ensures all entities subject to GHG regulations can account for energy and emissions without imposing requirements or costs on LSEs and energy users in non-GHG areas.  

Regardless, she said, CAISO staff and stakeholders need to have a unifying assumption for how to treat attribution of energy and emissions throughout the states.  

“I appreciate the point about ensuring that we’re able to capture the generation associated with those non-price-based states that don’t have a clean energy policy in place,” said Anja Gilbert, lead policy developer at CAISO. “This is a recommendation put forth, but the states are going to have to opine in terms of, does this meet their requirements? And so, I’m really seeing this as [a situation in which] there could be multiple approaches just based on what different states choose to adopt.” 

But Mary Wiencke, executive director of Public Generating Pool, questioned whether the accounting framework could be applied consistently across states.  

“Within this framework, there may be areas of users’ choice that we can identify and then work within that framework with states to work toward consistency,” Wiencke said. “I also think there may be areas that just can’t be reconciled between different state policies.”  

Despite unresolved questions, stakeholders concluded on a positive note.  

“I know there’s a lot here, and this does imply a lot of work … but now is the time to start getting the accounting system right,” Breidenich said.  

“I think it’s a step beyond a lot of what we’ve been thinking about in terms of leveraging averages and data to really support some of the transfer attribution that we see through the market,” said Pamela Sporborg, director of transmission and market services at Portland General Electric. “I actually have hope for maybe the first time ever.”

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‘Sprint’ Over, Markets+ Regulators Eye Next Phase

Program management “sprints” within the high-tech sector have little on SPP Markets+ stakeholders’ work developing a market tariff, says Oregon Public Utility Commissioner Letha Tawney. 

High-tech sprints normally last four weeks, the Markets+ State Committee’s (MSC) vice chair said during a March 15 conference call with other Western regulators. 

“What we’ve had here is a 10- or 11-month sprint,” Tawney said. “It’s been really challenging for the SPP staff. Very challenging for them, but also it really asked a lot of the state agencies in a way that we’ve not tried to engage in the West before. We’ve not tried to tackle a whole tariff all at once in this way.”  

Tawney is hopeful the process will get smoother “more like our other engagements with regional organizations in the West, where we can go a little deeper, be a little more methodical.” 

No worries there. With the tariff approved by Markets+ stakeholders and going before SPP’s Board of Directors next week for final consideration before a FERC filing, stakeholders will focus on the more technical work of drafting protocols and rules. 

Reflecting on Tawney’s comments, Gia Anguiano, the Western Interstate Energy Board’s government relations specialist and the MSC’s staff secretary, said the next phase of Markets+ will be anything but a sprint. 

“We’ve been very deep in the tariff development process, but this protocols phase is the next level down. It’s going to be a bit more technical and in the weeds,” she said. 

SPP’s timeline would have that work completed by year’s end, along with expected FERC approval of the tariff early in the fourth quarter. 

The MSC staff will prepare potential comments from the regulators on the FERC filing. The committee plans to begin a conversation on the comments rather than wait for the tariff to be filed. 

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FERC Rejects Tri-State Rates for Failing to Unbundle Ancillary Services

FERC on March 15 rejected Tri-State Generation and Transmission Association’s proposed rates, ruling the cooperative failed to unbundle ancillary services, which has been required for jurisdictional utilities since Order 888 was issued in 1996 (ER23-2171-002). 

Tri-State’s 42 utility members have contracts through 2050 and are spread among Colorado, New Mexico, Wyoming and Nebraska — in both the Eastern and Western interconnections. The co-op uses 5,849 miles of high-voltage transmission lines, mostly in the Western Interconnection, and 4,400 MW of generation. It has been a FERC-jurisdictional utility only since September 2019, and its initial rate filings have been going through commission proceedings since then.

The co-op proposed unbundling generation and transmission but made no proposal to unbundle ancillary services under the formula rate it filed in June. It claimed it could not unbundle ancillary services because it does business in five different balancing authorities and does not control its own.

Except for Schedules 1 (Scheduling and Dispatch) and 2 (Reactive Supply and Voltage Control), Tri-State purchases ancillary services from the balancing areas it operates in and passes those charges through its rates without regard to geographic areas. The co-op said it would be impossible to accurately determine exactly which services purchased from the BAs are used by its specific members. 

“Tri-State asserts that separately stating the prices for just the ancillary services under Schedules 1 and 2 aligns with the spirit of Order No. 888, which Tri-State notes aimed to ensure that utilities provide non-discriminatory service,” FERC said. “Tri-State argues that, for the remaining ancillary services, it does not self-supply all of those services itself and does not sell those ancillary services to third parties.” 

But FERC found that in order to comply with Order 888, Tri-State must state prices separately for its wholesale service components. When it was considering unbundling in the leadup to 888, the commission heard similar complaints about the difficulty of figuring out the costs and beneficiaries of specific ancillary services, but none of those reasons proved compelling, it noted.

Unbundling makes a more equitable distribution of costs possible because customers that take similar amounts of transmission service may require different amounts of some ancillary services, FERC said. Bundling would result in some customers having to subsidize others. 

“We are unpersuaded that Tri-State cannot meet, and should therefore be relieved from, Order No. 888’s requirements,” the commission said. “Although it may be more difficult for Tri-State to track costs for other ancillary services, further efforts could be made to comply with the requirements of Order No. 888 to separately state prices for certain ancillary services.” 

FERC also rejected Tri-State’s proposal for rolled-in rate treatment, which would allow it to recover through the transmission rate all the costs of its non-networked transmission facilities and third-party transmission arrangements used to provide wholesale power service to utility members. But FERC said that the co-op could come back with more support for a rolled-in rate treatment.

“We find that, for the most part, Tri-State’s proposed rolled-in rate treatment appears to be consistent with the cost-causation principle, as the benefits accruing to Tri-State’s utility members appear to be at least roughly commensurate with the costs they bear,” the commission said. 

Some protesters argued that Tri-State’s arguments about its integrated planning process are repackaged versions of its “cooperative model” that it used to argue against unbundling all ancillary services. But FERC said that Tri-State has shown its integrated planning provides benefits to all utility members, which supports its proposed cost allocation. 

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New Jersey Lawmakers Back $250 Annual EV Fee

New Jersey legislators sent a bill to the governor’s desk March 18 that would place a $250-a-year fee on zero-emissions vehicles, brushing aside criticism from environmentalists and car dealers that the fee would hinder electric vehicle sales. 

The Senate voted 24-14 to approve the bill, A4011, which would revise the New Jersey Transportation Trust Fund Authority Act to increase revenue to help support state transportation infrastructure and mass transit expenses. The state Assembly voted 48-28 to support the bill, which includes an increase in the state gas tax and revises the way in which it is levied. 

Gov. Phil Murphy’s (D) office did not immediately respond to an inquiry as to whether the governor would sign the bill. 

Starting July 1, 2024, buyers of zero emissions vehicles would pay $250 a year to $290 a year when a vehicle is registered initially or is renewed. The fee in the first year would be $250, rising $10 a year until it reaches $290 a year in the fourth year, and stops increasing. Buyers would have to pay the fee for four years at once, for an upfront payment of more than $1,000. 

Supporters see the bill as a way to increase investment in state transportation and to secure revenue from EVs and other zero-emission vehicles that otherwise might not contribute because they don’t pay the gas tax. But opponents said the fee — coupled with Gov. Murphy’s plan to make EV buyers pay state sales tax, from which they currently are exempt — would hamper EV sales. (See NJ Bill Would Levy Annual Fee on EV Ownership.) 

“Clearly, the state’s aggressive EV mandates are on a collision course with our fiscal realities,” said James Brian Appleton, president of the New Jersey Coalition of Automotive Retailers. 

“No one disputes the notion that EV drivers must pay their fair share to maintain roads and bridges or that some form or some amount of user fee must be paid,” he said. “Consumers will not react well to this and shrinking EV incentives. And adding more than $1,000 to the upfront purchase price of a new electric car will render the governor’s goal of 100% EV sales in New Jersey unachievable.” 

Doug O’Malley, state director for Environment New Jersey, said the bill — if Murphy signs it — would give the state one of the highest EV fees in the nation. He said the bill, which was introduced March 4, has moved like “greased lightning” through the Legislature. He speculated the sponsors wanted to get it approved before the state budget season begins in earnest in the next few weeks. 

“This is a real setback for EV drivers. This is essentially a $1,000 tax that could well dissuade potential EV drivers from making the switch,” he said, adding it’s an upfront fee that gas vehicle buyers don’t have to pay. 

“It’s the opposite of a pay-as-you-go system,” he said. “No one pays the gas tax upfront for four years.” 

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Counterflow: Hair (and Pants) on Fire

Steve Huntoon | Steve Huntoon

Washington Post headline: “Amid explosive demand, America is running out of power.” 1 

The long article cobbles together charts without context, cites states with relatively high electric demand and quotes from all manner of folks. 

Missing are the entities that actually know whether there is “explosive demand” and whether “America is running out of power.” 

These entities are NERC and the RTOs like PJM that manage generation supply-demand and bulk transmission for most of the country.2 But why ask the experts? 

Explosive Demand?

Regarding “explosive demand,” please look at this NERC graph that shows forecast summer and winter peak demand annual growth rates for the next 10 years.3 The lines show the compound annual growth rate (CAGR) values on the right-hand axis. Do you see the most recent 10-year growth rates of 1.0% summer and 1.2% winter? And do you see how much higher these growth rates were from 1995 to 2014? So yes, demand growth is increasing — but at a relatively small rate in absolute and relative terms. 

10-year summer and winter peak demand growth and rate trends | NERC

Running out of Power?

As for America “running out of power,” here’s another NERC chart showing projected new Tier 1 and 2 generation resources over the next 10 years.4 Around 370 GW by 2033. This is a staggering amount of new generation relative to existing generation resources of 1,300 GW.5

Tier 1 and 2 planned resources projected through 2033 | NERC

Will all of it get built? No. Will the renewable (intermittent) resources have the same reliability value and load factor as dispatchable (firm) resources? No — I’ve written about their limits ad nauseum.6 Are there challenges that need to be worked through to ensure the energy transition does not degrade reliability? Yes. Crisis? No. 

Georgia

Georgia is the poster child for the Post article, where the major utility there, Georgia Power, projects increased demand from various sources.7 But is there a crisis? No. Georgia Power identifies eight measures to address the increased demand, including power purchase agreements with generators in Mississippi and Florida, expanding battery storage, building additional simple-cycle combustion turbines, and expanding distributed energy resource and demand response programs.8 Where’s the fire? 

Distracting from the Real Work at Hand

Articles like the Post’s distract from the real work at hand. Here are a few no-brainers I’ve flagged before:  

(1) Keeping existing nuclear plants open. Thank goodness Diablo Canyon was saved, as I pleaded for eight years ago;9  

(2) banning cryptocurrencies (especially “proof of work” crypto like Bitcoin), which have nothing but negative externalities like emissions, ransomware enabling, money laundering, drug smuggling and human trafficking; 10  

(3) rational onshore wind instead of irrational offshore wind, which costs at least twice as much per MWh;11

(4) rational grid solar instead of irrational rooftop solar, which costs five times as much per MWh;12  

(5) high-voltage interconnections between Texas/ERCOT and the rest of the country;13   

(6) unique emergency ratings for generation interconnection studies (and dispatch);14   

(7) new (but known) technologies for increasing capacity of existing transmission lines;15   

(8) not wasting money on green hydrogen electricity;16 and, dare we keep saying it,  

(9) carbon pricing.17 

The flip side of good public policies is bad public policies, such as premature closure of dispatchable resources (a threat that goes unaddressed in the Post article). Bad public policies can create a crisis that would be otherwise avoidable. But we shouldn’t assume we’ll foolishly create a self-inflicted crisis. 

A Last Word

In my humble opinion, the damage from an article like the Post’s goes beyond distracting us from the real work at hand. It adds to the collective trauma from all the big things we already worry about, like climate change, artificial intelligence, politics and international crises.  

We have plenty to worry about. Enough already.  

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.

1 https://www.washingtonpost.com/business/2024/03/07/ai-data-centers-power/

2 As an example the most recent PJM load (demand) forecast is here, https://pjm.com/-/media/library/reports-notices/load-forecast/2024-load-report.ashx. Load growth attributable to electric vehicles and data centers is accounted for.

3 https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2023.pdf, Figure 25.

4 NERC report, Figure 16.

5 https://www.publicpower.org/system/files/documents/Americas_Electricity_Generating_Capacity_2023_Update.pdf. This is U.S. generation capacity and does not include Canada.

6 https://energy-counsel.com/wp-content/uploads/2022/11/More-Happy-Talk.pdf; http://energy-counsel.com/docs/No-Carb-California.pdf; http://energy-counsel.com/docs/German-La-La-Land.pdf; http://energy-counsel.com/docs/Cue-the-PixieDust.pdf.

7 https://www.georgiapower.com/content/dam/georgia-power/pdfs/company-pdfs/2023-irp-update-main-document.pdf

8 IRP report, pages 2-3.

9 My column on the insanity of closing Diablo Canyon is here, http://energy-counsel.com/docs/Helter-Skelter-September-Fortnightly.pdf. No such luck with saving Indian Point which closure I showed would cost New Yorkers $830 million/year, http://energy-counsel.com/docs/New-Yorks-Surreal-New-Deal.pdf

10 https://energy-counsel.com/docs/The-New-Technoking-and-His-Bitcoin-Crown.pdf; https://energy-counsel.com/wp-content/uploads/2022/04/Stop-the-Insanity.pdf.

11 https://www.energy-counsel.com/docs/we-see-through-a-glass-darkly.pdf, item 3 and sources cited there.

12 Same column, item 4 and sources cited there.

13 https://www.energy-counsel.com/docs/a-modest-proposal.pdf; https://energyathaas.wordpress.com/2022/01/31/the-most-obvious-way-to-avoid-another-texas-blackout.

14 https://energy-counsel.com/docs/waste-not-what-not.pdf; tangible comments in the FERC rulemaking are here, https://elibrary.ferc.gov/eLibrary/filedownload?fileid=15740097.

15 https://www.epri.com/research/products/000000003002023004; https://energy-counsel.com/wp-content/uploads/2022/06/Transmission-and-Technology.pdf (penultimate paragraph).

16 https://energy-counsel.com/wp-content/uploads/2023/12/Hydrogen-Reality.pdf.

17 “‘If we don’t put that price of carbon on the system, I don’t see how anything could work,’ Harvard economist William Hogan said in the last session of the daylong conference.” https://www.rtoinsider.com/articles/29867-epsa-members-renew-call-carbon-price.

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Stakeholder Soapbox: PJM Moves to Wipe Out Energy Efficiency When It’s Needed Most

By Bo Clayton

After nearly two decades of flat load growth, U.S. electricity demand is rising. Fast. The boost in domestic industry related to the growth of data centers and increased economywide electrification is driving operators to revise load forecasts and scramble to flag concerns about future capacity insufficiency.  

They are right to be concerned: This new load is coming onto the aging grid far faster than solutions to handle that demand. New generation takes years to get through the backlogged interconnection queue; new and expanded transmission capacity even longer. We need to be using every tool in our toolbox to help meet these challenges — and energy efficiency is critical to ensuring we can do this effectively and affordably.   

Bo Clayton | Bo Clayton

For at least half a century — since the 1970s U.S. energy crisis — energy efficiency has been America’s cheapest, most reliable source of energy. Even as modern, clean technologies like solar PV, wind energy and battery energy storage have tumbled down their cost curves, megawatts of efficiency remain a winning bet for states and their utilities.  

A recent Lawrence Berkeley National Laboratory study confirms energy efficiency plays a significant role in many states. These energy efficiency programs range from major industrial-scale efforts to reduce consumption to hundreds of millions of residential customers around the country installing products and taking actions that, in aggregate, save a lot of energy and money.   

Rather than identifying ways to promote further efficiency in its footprint, the nation’s largest grid operator — PJM — inexplicably is taking the opposite approach. PJM is pursuing imminent changes that effectively will gut energy efficiency across its region, precisely at a time when those gigawatts of capacity are needed more than ever.   

PJM is seeking to bypass its standard stakeholder process to make a “quick fix” to its rules governing energy efficiency. PJM’s hasty proposal, which will be voted on at its Markets and Reliability Committee meeting March 20, essentially would invalidate a majority of states’ energy-efficiency programs by establishing an arbitrary timeline for when PJM thinks states should update their own energy-efficiency guidelines. (See PJM MIC Briefs: March 6, 2024; and PJM Seeking Expedited Approval of Energy Efficiency Changes.)   

PJM didn’t bother to explain which state programs would be impacted or provide support for its concern about how states are running these programs. This is irresponsible at best and outright disrespectful of state programs and efficiency progress at worst.  

In parallel, it effectively would eliminate the ability to aggregate energy efficiency through big box retailers, removing the primary means of energy efficiency participation in PJM to date. This could significantly hamper consumer adoption of energy efficiency solutions such as LED light bulbs and spray foam insulation.  

Make no mistake: PJM should revisit its rules governing efficiency’s participation in the capacity market. Much has changed in the 17 years since these rules first were adopted.  They are outdated and due for overhaul. But the process to do so must be transparent, inclusive and thoughtful.   

PJM isn’t even planning to allow its regulator — FERC — to have a say on the changes. That leaves it up to the PJM stakeholders to push back. If you are a stakeholder, I urge you to pursue the harder but better approach: Send the issue back to lower committees for thoughtful deliberation including PJM staff, states and others with a stake in the outcome. Anything less flies in the face of PJM’s own commitment to consensus-based issue resolution, to the detriment of consumers and grid reliability. Moreover, PJM will be abdicating its place at the forefront of energy innovation.    

This is not the time for PJM to erase decades of progress on energy efficiency by hastily implementing an ill-conceived rule change with far-reaching ramifications.  

Bo Clayton is the CEO of American Efficient, a developer of energy efficiency resources with 10 years of operating history in PJM.    

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Pathways Initiative Discloses Funders, Reiterates Goals

The West-Wide Governance Pathways Initiative has secured financial commitments from 24 utilities and other electricity sector organizations and expects that list to grow, the group disclosed March 15 as it identified the contributors.  

The disclosure seeks to address concerns raised by some skeptics of the Pathways Initiative about who is backing the effort and whether it is being dominated by specific interests.  

Those concerns stem from the fact that the effort is at the heart of a contest between CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+ day-ahead offering to attract participants.  

Last year, energy officials from five Western states launched the Pathways Initiative to build a governance framework that could oversee a regionwide market that pointedly includes California and builds on CAISO’s Western Energy Imbalance Market (WEIM) and EDAM. 

“The thing I did want to note on this is we have a fairly broad and diverse set of funding parties that have agreed to help us and also that there isn’t any super large amount of money coming from any one entity that’s trying to in any way dominate our funding,” Jim Shetler, general manager of the Balancing Authority of Northern California (BANC), said during a March 15 update call hosted by the initiative’s Launch Committee.  

Shetler is co-chair of the committee’s Priority Admin Work Group, and BANC last August became the second balancing authority to announce its intention to join the EDAM after six-state utility PacifiCorp. (See BANC Moving to Join CAISO’s EDAM.)  

Shetler displayed a spreadsheet listing companies that have pledged donations and their approximate funding. The top-level funders ($20,001-$30,000) include the investor-owned utilities Avista, Pacific Gas and Electric, PacifiCorp, Portland General Electric, Public Service Company of New Mexico, Puget Sound Energy and Southern California Edison.  

Others in that pledge category include BANC, California Community Choice Association (CalCCA), Northern California Power Agency, Oregon-based generation and transmission cooperative PNGC Power, Seattle City Light, and Western Power Trading Forum (on behalf of AES, Calpine, Constellation, Shell and Vistra).  

The next level of funders ($10,001-$20,000) includes NextEra Energy, Northwest Energy Coalition and Western Freedom, which represents companies seeking to buy emissions-free energy. 

The third level of donors ($5,001-$10,000) consists of Apex Clean Energy, EDP Renewables and Turlock (Calif.) Irrigation District, while the fourth level ($1-$5,000) includes Avangrid, Invenergy, Ørsted Wind Power North America, Northwest & Intermountain Power Producers Coalition and Union of Concerned Scientists. 

“Invoices have been sent out, funds are flowing in, so we’re able to pay our bills. We greatly appreciate that,” Shetler said. 

These financial commitments put the Pathways Initiative at about $430,000 of an estimated $570,000 budget needed to fund Phase 1 of the effort through April, with more pledges expected, Shetler said.  

The group also expects to win the $800,000 in U.S. Department of Energy grant funding it applied for in January, Shetler added. The first half of that money likely won’t arrive until June or July, potentially leaving a funding gap in late spring. Still, he said he thinks the initiative can run on its original budget until the end of June. 

‘Quick Wins’

Opening the March 15 update, Launch Committee co-Chair Kathleen Staks, executive director of Western Freedom, emphasized the initiative is focused on its original mission of establishing an “independent entity” to oversee governance of a market building on CAISO’s WEIM and EDAM and containing the largest possible Western footprint. 

Staks’ statements appeared to address a question raised in a thread under a LinkedIn post she published March 11 in which a commenter said that, based on information shared at the committee’s previous update, they assumed Pathways was no longer pursuing creation of a “regional organization” because it would require a change in California law. 

“We have been evaluating how we get there. What are the options for that end state?” Staks said. That “includes everything from interim steps that demonstrate progress and achieve some quick wins for market development in the West, as well as a potential legislative change in California.” 

CalCCA General Counsel Evelyn Kahl, co-chair of the Launch Committee’s Functions and Scope Work Group, elaborated on that “stepwise” approach to governance, which was discussed during the committee’s February update. (See Western RTO Effort Makes Gains on Funding, Legal Analysis.) 

Kahl said her group, which is working with the law firm retained to examine legal issues around transforming CAISO’s governance, has made progress on Step 1 of the process — namely, identifying changes that could be done to make the WEIM/EDAM governance framework more independent of Californian control without triggering legal action. 

She said the “two key features” in Step 1 would be elevating the level of authority for the WEIM Governing Body and introducing a dual filing concept at FERC in cases of disagreements over tariff changes between that body and CAISO. 

Kahl said the work group expects to deliver stakeholders a “straw design” and associated paper by April 10. 

“Step 2 is harder,” Kahl said. “It’s the next incremental step of augmenting market independence, and it’s going to require a lot more in-depth analysis and design. And it’s likely to require a change in law. So given the complexity of Step 2, it’s moved necessarily more slowly and deliberately.” 

Kahl’s group is looking into the creation of a new regional body as a 501(c)(3) organization and in April expects to discuss with stakeholders a “narrowing” of the governance options the Launch Committee laid out in December. (See Western RTO Initiative Outlines Governance Options.) 

“We’d like to emphasize that nothing you’re going to see on April 10 is going to be a final recommendation. What we plan to do is show you our work … and get your feedback on our work before we go further,” Kahl said. 

Mike Florio, a former California Public Utilities Commission member who now works as a consultant, asked if there’d be an effort to amend California law during the 2024 legislative session. 

“We want to make sure that we are having a very thorough stakeholder engagement process and don’t want to cut that short — and we will need to do some engagement with legislators in California” Staks said. “Without committing fully one way or another, I think the likelihood of having legislation ready to present in the 2024 legislative session is probably unlikely.” 

The Launch Committee will hold its next update call April 19. 

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CPS Energy Plans to Retire 859 MW of Gas Resources

CPS Energy has notified ERCOT it plans to “indefinitely suspend operations” at three aging gas-fired units in 2025, further reducing the Texas grid’s thermal capacity. 

The San Antonio municipality filed a notification of the suspension with the Texas grid operator March 13. The three steam turbines at the V.H. Braunig facility have a combined summer seasonal net maximum sustainable rating of 859 MW. 

CPS Energy says the units are nearing the end of their operational lives. The first unit came online in 1966, and the other two followed in 1968 and 1970. Four smaller gas turbines at the site each have a nameplate capacity of 61 MW.  

The municipality has made a concerted effort in recent years to meet the city’s climate goals and maintain reliability with a fuel mix that relies on clean energy, storage and gas resources. Its Board of Trustees approved a generation plan last year that shifts the utility away from coal power by retiring one unit at its J.K. Spruce plant by the end of 2028 and converting another to run on natural gas. 

CPS Energy decommissioned two coal-fired units at its J.T. Deely plant in 2018. 

ERCOT is accepting comments through April 3 as it conducts a study to determine whether the closure will lead to reliability issues. 

The grid operator began the year with 15.5 GW of interconnection requests from gas resources. Most of those are for quick-starting combustion turbine or combined cycle units. 

Texas voters in November approved a proposition that creates the Texas Energy Fund, a $7.2 billion low-interest loan program intended to develop up to 10 GW of natural gas plants. (See 2023 Elections Bring Billions for Texas Gas, Dem Wins in Virginia, NJ.) 

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PJM MRC/MC Preview: March 20, 2024

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings March 20. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. 

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

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

As part of its consent agenda, the MRC will be asked to endorse:

B. proposed revisions to Manual 11: Energy and Ancillary Services Market Operations to conduct more regular reviews of interface pricing points. The changes would add a definition of interface pricing points, which group buses together when calculating LMPs for energy transfers between external areas and establish an annual review of power flow impacts on each interface. (See “Other Committee Business,” PJM MIC Briefs: March 6, 2024.)

Issue Tracking: Interface Pricing Points Review

C. proposed revisions to Manual 12: Balancing Operations identified through the document’s periodic review. The new language would seek to align with real-time market operations detailed in Manual 11 and add detail to hybrid resource market parameters. (See “Periodic Review Manual Revisions Endorsed,” PJM OC Briefs: March 7, 2024.)

D. proposed revisions to Manual 37: Reliability Coordination including administrative changes identified through periodic review and reflecting changes to NERC standards FAC-011 and FAC-014. (See “Periodic Review Manual Revisions Endorsed,” PJM OC Briefs: March 7, 2024.)

Endorsements (9:10-11:35)

  1. Governing Document Clarifying Revisions (9:10-9:30)

PJM’s Michele Greening will present proposed revisions to PJM’s governing documents endorsed by the Governing Documents Enhancements and Clarifications Subcommittee (GDECS) last month. Greening told the committee in February that most of the revisions are clarifications and corrections, though some stakeholders have argued that several changes are more significant than are typically made through the GDECS. (See “Other MRC Business,” PJM MRC/MC Briefs: Feb. 22, 2024.) 

The committee will be asked to endorse the revisions to the tariff, Reliability Assurance Agreement and Operating Agreement. 

  1. Demand Response Window (9:30-9:55)

Bruce Campbell, principal of Campbell Energy Advisors representing demand response providers, will present a quick-fix proposal to extend the availability window for DR resources by two hours during the winter to reflect expanded ability for load to respond in the evening hours and to align with changes made to PJM’s market structure following the Critical Issue Fast Path (CIFP) process. (See “Demand Response Providers Seek Expanded Availability,” PJM MRC/MC Briefs: Feb. 22, 2024.) 

The committee will be asked to approve the proposed issue charge and endorse the proposed solution to key work activity 2 using the quick-fix process outlined in Manual 34, which allows an issue charge and proposed solution to be voted on concurrently. 

  1. Manual 18B: Energy Efficiency Measurement and Verification (9:55-10:45)

The committee will be asked to endorse one of the following proposed packages of revisions to Manual 18B: Energy Efficiency Measurement and Verification.

A. PJM’s Pete Langbein will present the main motion to revise how the RTO measures and verifies the capacity offered by energy efficiency resources. Prior to endorsement from the Market Implementation Committee on March 6, Langbein told stakeholders the manual revisions would clarify which basepoint EE providers should use to measure the energy savings associated with a resource and require that they possess exclusive rights to offer those savings into the capacity market and that they can demonstrate installation of more efficient equipment was completed. (See PJM MIC Briefs: March 6, 2024.)

B. CPower’s Ken Schisler will present an alternative motion offering a proposal seeking to resolve several concerns that EE providers laid out during the March MIC meeting, including the requirement that an EE installation be causally linked to the capacity market and a three-year limit on the eligibility for technical reference manuals be used to compare the energy use of new technologies against.

C. Affirmed Energy’s Luke Fishback will present an alternative motion that seeks to resolve issues with the PJM proposal, which Fishback told the MIC could result in large amounts of EE being unable to offer into future auctions.

Issue Tracking: Evaluation of Energy Efficiency Resources 

  1. Capacity Obligations for Forecasted Large Load Adjustments Issue Charge (10:45-11:10)

Old Dominion Electric Cooperative’s Michael Cocco will present revisions to the issue charge framing an ongoing stakeholder discussion on how capacity obligations arising from forecasted large load adjustments should be assigned to electric distribution companies. The proposal would add language to the in-scope section of the issue charge to include changes to Manual 19 to add details on how load-serving entities forecast large load additions and how those are then incorporated into PJM’s load forecasted. (See “1st Read of Proposal on Capacity Obligations Resulting from Large Load Additions,” PJM MIC Briefs: March 6, 2024.) 

The committee will be asked to approve the amendments to the issue charge on first read. 

Issue Tracking: Capacity Obligations for Forecasted Large Load Adjustments 

  1. Forecast Pool Requirement and Installed Reserve Margin (11:10-11:35)

PJM’s Patricio Rocha Garrido will present revised installed reserve margin (IRM) and forecast pool requirement (FPR) values for the 2025/26 delivery year to reflect changes to the RTO’s risk modeling and generation accreditation processes following FERC approval of market changes in docket ER24-99 resulting from the CIFP process. The recommended IRM is 17.8% — up from the 17.7% IRM the MRC endorsed in October — and the recommended FPR value is 0.9387, down from 1.1170. (See “Recommended Values for 2023 Reserve Requirement Study,” PJM MRC Briefs: Oct. 25, 2023.) 

The committee will be asked to endorse the results upon first read. Same-day endorsement may be sought at the MC. 

Members Committee

Endorsements (2:10-2:25)

  1. Forecast Pool Requirement and Installed Reserve Margin (2:10-2:25)

PJM’s Patricio Rocha Garrido will present the updated FPR and IRM figures for the 2025/26 delivery year discussed at the MRC. The MC may be asked to endorse the results upon first read. 

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NYISO Recounts Mild Winter

The 2023/24 winter season was one of NYISO’s most humdrum winters, characterized by high temperatures, low gas prices and below-average loads, according to a presentation shared with the Operating Committee on March 15. 

Aaron Markham, NYISO vice president of operations, told the OC that “moderate temperatures led to moderate fuel prices for much of the season,” and the few “short-duration cold snaps” were not “super impactful.” 

He added, however, that those cold snaps meant NYISO needed to burn “a fair amount of stored fuel” and saw “some gas system constraints,” but the ISO would “continue to monitor [fuel] replenishment” and study how to ensure fuel could be delivered more effectively for future peak days. 

The season’s coldest period occurred around the Martin Luther King Jr. Day weekend, when load peaked at 22,754 MW on Jan. 17. It was still one of the ISO’s lowest winter peaks over the past 15 years and represents only one of three times during the month when load went above 22,000 MW, which usually occurs an average of 11 times during January. 

During the Jan. 17 peak hour, New York’s load was served by an estimated supply mix of 26% natural gas, 14% oil, 17% hydropower, 20% imports from neighboring regions, 14% nuclear, 8% wind and 1% from other renewables. 

Markham said one of the highlights for the winter season was the generation fleet’s “very good” performance, especially during the season’s peak load hour, when there was only about “150 MW of unavailable capacity from the day-ahead to real-time.” Additionally, intermittent production during peak days, although “still relatively low compared to the total demand,” continued to “see more contribution to meet demand.” 

Markham also delivered the February operations report to the OC, saying the month “continued the trend of mild weather and no real strenuous operating conditions,” with a peak load of 20,981 MW recorded on Feb. 14. 

He also mentioned that NYISO expects to “be able to manage” the April 8 solar eclipse and has asked its solar forecast vendor to ensure the eclipse’s impact on solar production is included in the next forecast delivered to the ISO. (See “NYISO Updates,” NY State Reliability Council Executive Committee Briefs: March 8, 2024.) 

NYISO added 45 MW of behind-the-meter solar since its last monthly operations report. (See “January Operations,” NYISO Operating Committee Briefs: Feb. 15, 2024.) 

Thermal and hydro outages by type over peak hours in January’s winter cold snap | NYISO

Bear Ridge Solar Waiver Denial

FERC on March 14 denied Bear Ridge Solar’s waiver request for remedial relief from certain NYISO interconnection tariff requirements, effectively removing the project from the ISO’s queue (ER22-2085). 

Bear Ridge aimed to develop a 100-MW solar farm in Niagara County and requested an exemption from two of NYISO’s tariff requirements because of “unforeseen events” that were “beyond its control” and led it to “substantial difficultly” in adhering to state siting processes and critical regulatory deadlines. 

As a result of its “failure to comply with the regulatory milestone requirements,” Bear Ridge’s project faced withdrawal from the interconnection queue and risked the loss of a $657,000 cash security deposit necessary to cover its share of the costs for transmission upgrades determined by NYISO to be required for the project’s interconnection. 

Although sympathetic to Bear Ridge’s situation, FERC said that granting the waiver would be “retroactive in nature and is prohibited by the filed-rate doctrine” in the Federal Power Act. 

In a joint concurrence, Chair Willie Phillips and Commissioner Allison Clements said that although they were bound by the filed-rate doctrine, “the outcome here is neither equitable nor commercially reasonable” and is “emblematic of other waiver proceedings in which an applicant did not foresee that it would miss a deadline before it occurred.” 

They acknowledged that FERC’s procedures are rigid and prevent it from granting even a modest milestone extension, which would “avoid sending the project back to the starting gate,” even though Bear Ridge satisfied the regulatory milestone at issue two months after submitting its waiver request unopposed by NYISO.  

The commissioners called on transmission providers to revise their tariffs to permit FERC to waive such deadlines to allow the commission “greater flexibility in addressing sympathetic cases such as this one,” recognizing that the outcome “does not advance the goal of getting new resources online as quickly and reliably as possible” and “causes needless inefficiencies and deprives NYISO’s customers of the benefits that such a project provides.”