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November 18, 2024

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FERC Accepts ISO-NE Order 2222 Compliance Filing

FERC last week accepted ISO-NE’s third compliance filing for Order 2222, ruling that the RTO’s proposal does not pose prohibitive barriers to market participation for distributed energy resource aggregations (DERAs) (ER22-983-004).

The commission directed ISO-NE to make an additional filing within 90 days to address outstanding issues related to its metering proposal.

At the beginning of March, the commission accepted and rejected parts of ISO-NE’s first 2222 filing, prompting a series of compliance filings from the RTO. (See FERC Gives ISO-NE Homework on Order 2222.) The second and fourth filings that followed went uncontested and were accepted by FERC in late October (ER22-983-003 and ER22-983-005).

The third filing focused on metering rules, market participation models, small utility opt-in requirements and coordination among the RTO, aggregators and utilities.

The filing was challenged in May by Advanced Energy United, PowerOptions and the Solar Energy Industries Association. The groups argued that the metering requirements in ISO-NE’s proposal are prohibitive to DERAs.

“ISO-NE has failed to make any adjustments to facilitate participation by DERs located behind a customer meter, leaving in place a barrier recognized by the commission in its compliance order, and has failed to justify the metering and telemetry provisions that underlie this barrier as directed by the commission,” the groups wrote. “The impacts of ISO-NE’s failure to incorporate behind-the-meter DERs into wholesale markets will only grow as penetration increases.”

For metering DERs, ISO-NE provided three options: retail delivery point metering, submetering with reconstitution and parallel metering.

The organizations said submetering with reconstitution and parallel metering are not viable options for most DERs, and metering resources at the point of interconnection would prevent those behind the meter from responding to price signals during times of peak demand. The organizations said this would “limit ISO-NE’s visibility into their availability, fail to optimize demand flexibility and undermine competition.”

ISO-NE wrote in its compliance that these configurations “minimize overall costs, are consistent with the metering requirements of all non-demand response resources and loads in New England, and ensure a just and reasonable allocation of wholesale power costs.”

FERC sided with ISO-NE, writing that its proposed options are necessary to prevent double counting.

“No party has identified less burdensome alternative metering configuration options that would also address the need to avoid double counting and inequitable cost shifting,” FERC wrote. “However, we encourage ISO-NE to continue to work with its stakeholders to consider additional metering options in the future, including for DERAs to utilize alternative submetering configurations.”

FERC gave ISO-NE 90 days to submit an additional filing that identifies the DERA as the entity responsible for submitting meter data and specifying a deadline for submitting data.

Also at issue was ISO-NE’s rule changes to incorporate DERAs into its participation models used in the RTO’s energy and ancillary services markets. ISO-NE’s initial filing modified aspects of the RTO’s five existing models, while adding two models specific to DERAs.

In March, FERC ruled that ISO-NE “failed to demonstrate that its proposed energy and ancillary services market participation models for [DERAs] accommodate the physical and operational characteristics of behind-the-meter [DERs], because behind-the-meter DERs participating under those participation models may be unable to provide all services that they are technically capable of providing through aggregation.”

The commission’s ruling in March, along with the protest comments, specifically took issue with ISO-NE’s existing Binary Storage Facility and Continuous Storage Facility participation models. In its ruling last week, FERC accepted ISO-NE’s clarifications and revisions, agreeing that the requirements of the models apply to all resources looking to participate.

In a statement to RTO Insider, an ISO-NE spokesperson said the RTO is pleased with the ruling, adding that the changes will “ensure distributed energy resource aggregations are metered accurately and the services they provide are not double counted.”

Sam Ressin of Advanced Energy United said the organization is disappointed with the ruling and “concerned that ISO-NE’s proposal, once implemented, will result in barriers to participation that will prevent most behind-the-meter DERs from contributing to the reliability and affordability of New England’s electric grid.”

In a concurring statement, Commissioner Allison Clements expressed her disappointment with ISO-NE for its decision not to use the filing to enable the full range of DR benefits from DERs.

“In essence, ISO New England chose to do the minimum required by law,” she wrote, noting that the RTO was clearly permitted by FERC to establish alternative DR metering options. “Rather than examining the full suite of options that may facilitate participation of DERs in its markets, ISO New England focused its further compliance filing solely on non-demand response resources.”

Clements added that all supply and demand resources should be considered as options to improve reliability in the region, saying it is “lamentable that ISO New England has failed to examine this path for facilitating more robust resource participation.”

Commissioner Mark Christie dissented with the order, citing the comments he issued in his previous dissent on FERC’s response to ISO-NE’s Order 2222 rehearing request. Christie had said Order 2222 created “nothing short of an incomprehensible quagmire bearing a substantial price tag.” (See FERC Responds to ISO-NE Rehearing Request on Order 2222.)

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Parties Preview FERC Review of EPA Power Plant Rule

FERC will host a discussion Thursday on the potential impacts of EPA’s proposed rule for power plant emissions as part of its annual technical conference on grid reliability, and parties have laid out the arguments they want addressed at the forum. (See EPA Power Plant Proposal Gets Mixed Reception in Comments.) 

The think tank Energy Innovation Policy & Technology released a report and hosted a webinar arguing that EPA’s proposal can be met while maintaining reliability. 

The rule would require fossil fuel-fired power plants to install emissions-mitigation technologies depending on when they plan to retire and how often they run. Coal plants that want to keep operating beyond 2040 need to install carbon capture and storage (CCS) technology that eliminates 90% of their emissions, Harvard University Environmental & Energy Law Program Executive Director Carrie Jenks said on the webinar. 

Baseload natural gas plants would either need CCS or blended hydrogen, though the rule would require less investment for plants that run on an intermediate basis or as peakers, Jenks said. 

The rule would effectively retire uncontrolled coal plants and largely leave a system with natural gas and storage balancing higher levels of renewables, which is already largely the case in California, New England and the U.K., said GridLab Executive Director Ric O’Connell. 

“Adding clean resources and using the gas fleet as a balancing resource is a pretty well-known playbook,” O’Connell said. 

Sens. John Barrasso (R-Wyo.) and Shelley Moore Capito (R-W.Va.) — the ranking members of the Energy & Natural Resources and Environment & Public Works committees, respectively — wrote FERC a letter urging it do more than the tech conference. The senators, whose committees oversee FERC and EPA, had urged the commission to hold the tech conference this summer. (See GOP Senators Call for FERC Conferences on EPA Power Plant Rule.) 

“Unless the EPA withdraws or significantly revises its proposed Clean Power Plan 2.0, the EPA will unnecessarily and significantly increase risks to electric reliability,” the senators said. “It will also increase dramatically the costs of generating electric power and make electricity less affordable for American families.” 

If FERC does not bring to bear its expertise and fact-based analysis “to dissuade the EPA” from continuing with the rule, it would be partially responsible for the resulting blackouts, they added. The senators urged FERC to gather comments and submit that record to EPA before the rule is finalized. 

While the rule does have requirements on how long uncontrolled natural gas plants can run if they operate more than 50% of the time, as long as EPA allows averaging, that should not be an issue, Jenks said during the webinar. 

Power plants can run at their full capacity during emergencies, such as Winter Storm Uri in February 2021 or the 2014 polar vortex, and then make up the difference in the rest of the year, she said. 

Another worry that opponents have brought up is the lack of “essential reliability services” such as frequency response, regulation reserves, operating reserves and voltage regulation that are provided for free because of the way traditional power plants work, said O’Connell. Grids do not need all their power plants to provide such services, with O’Connell saying a grid like MISO with about 200 GW of supply needs an “order of magnitude less” than that. 

“It turns out that clean resources, especially batteries with grid-forming inverters, can absolutely provide essential reliability services,” O’Connell said. “In fact, batteries have been providing regulation services in PJM for a long time now, closing in on a decade.” 

California is already rapidly decarbonizing its generation fleet, and CAISO is looking ahead to meet the state’s goals of eliminating emissions from electricity by 2045, said Cristy Sanada, regulatory affairs senior manager for the ISO. 

“The state policies have driven kind of where California is right now,” Sanada said. “California was very early to move on RPS standards and battery mandates. And, you know, we’ve already surpassed a lot of those early kind of RPS targets that were set out.” 

California’s own policies are driving the grid there to change more than a pending EPA proposal, but O’Connell noted that more is at play than just policy when it comes to the energy transition. 

“Let’s look at a state like Texas that doesn’t have any kind of clean energy goals at all, right?” O’Connell said. “Last year, wind energy exceeded both nuclear and coal and provided 25% of Texas’ electricity. Solar came on really strong this year. We saw a huge amount of solar being installed – it’s likely going to be 10% of the state’s electricity next year, if not more. And so, this is happening in states and locations that aren’t necessarily policy-driven like California. It’s really economically driven.” 

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MISO Stakeholders Split on Sloped Demand Curve Proposal

Stakeholders appear divided over MISO’s proposal to use a downward sloping demand curve in its capacity auction, with criticism aimed mostly at a provision to allow utilities to opt out of the auction for three years at a time.  

MISO at the end of September filed for FERC permission to replace its vertical demand curve used in its capacity auction with a sloped demand curve that assigns value to excess capacity (ER23-2977). (See MISO South Support for Sloped Demand Curve Wanes on Opt-out Provision.) Stakeholders’ comments on MISO’s filing rolled in last week.  

Consumers Energy filed in support of the sloped demand curve and said it should take care of the auction clearing capacity prices at either very close to $0/MW-day or near the cost of new entry, and drive “proper” grid investments.  

The Michigan-based utility said MISO’s “current model struggles to provide adequate price signals and investment incentives and fails to promote efficient resource planning or accurately reflect the reliability value of incremental capacity.”  

The Kentucky Public Service Commission also supported the sloping demand curve, saying it would allow excess capacity “to be assigned value commensurate with its reliability contribution along the downward slope of the curve.” 

The Electric Power Supply Association called the new curve “a key element in the ISO’s efforts to address the region’s resource adequacy challenges and support reliable operations.” Calpine also chimed in, saying the curve will yield more accurate capacity prices.  

However, the Sierra Club, Natural Resources Defense Council and the Sustainable FERC Project said while they agreed with most aspects of MISO’s plan to implement the sloped demand curve, they took issue with MISO’s plan to impose an “X% adder” on load-serving entities that opt out of the auction altogether. The adder will require those LSEs to secure more capacity than strictly necessary to meet MISO’s one-day-in-10-years system reliability standard. The adder will be based on how much excess capacity is procured through the auction using the sloped demand curve in previous years. 

The trio said the adder introduces “an artificial financial disincentive against LSEs utilizing the opt-out mechanism, undermining the suite of choices available to LSEs, and it will impose significant artificial costs on ratepayers.”  

In a joint protest, the Public Utility Commission of Texas and the Arkansas Public Service Commission likewise said MISO’s opt-out provision will penalize LSEs. Entergy and Cleco joined in criticism of the opt-out provision and advocated for allowing LSEs to partially opt out of the capacity auction with a portion of their load.  

The Louisiana Public Service Commission said MISO’s requirement that LSEs procure beyond the 1-in-10 standard if they wish to opt out of the auction “all but guarantees” LSEs will choose to participate in MISO’s auctions. The commission said the demand curve won’t incent new capacity, just “shift dollars around among existing capacity, while requiring LSEs” to acquire more capacity than necessary to meet loss-of-load expectation standards.  

Other stakeholders struck a harsher tone against the whole of MISO’s proposal.  

The Mississippi Public Service Commission said MISO’s narrative that a downward sloping demand curve is necessary for reliability is untrue. It said the price signal that the sloped demand curve is designed to evoke is unnecessary because most MISO utilities are vertically integrated and can roll the costs of generation needed to meet resource adequacy targets into their rate bases.  

“The premise — that ‘incremental capacity’ above that needed to satisfy the one day in 10 years loss-of-load expectation standard — is pure ex cathedra hokum,” the commission told FERC. “Energy from installed capacity, not capacity that clears an auction, is what serves load and provides reliability. Efforts in MISO that establish appropriate energy pricing, including scarcity pricing, market monitoring that prevents physical and economic withholding, and the desire to profit from existing generation investment will motivate generators to produce electricity, irrespective of whether those generators cleared in the Planning Reserve Auction.”  

American Municipal Power, Missouri Joint Municipal Electric Utility Commission, Southern Minnesota Municipal Power Agency and WPPI Energy asked FERC to completely reject MISO’s proposal, saying they doubted the changes are necessary.  

“MISO has not justified that these dramatic changes to its resource adequacy construct are warranted. Nor has MISO acknowledged or justified largely eliminating critical auction clearing price mitigation that protects against excessive prices, or explained how its various revisions can be implemented in a coherent, just and reasonable manner,” the utilities said. 

They said they didn’t see how FERC could allow MISO to clear its auction beyond the current limit of 1.75 times the cost of new entry for generation. They also said MISO’s opt-out provision is murky and its proposed opt-out deficiency charge for LSEs that fail to come up with the adder amount of capacity is “unduly punitive.”  

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Eversource Closer to Exiting OSW Venture with Ørsted

Eversource Energy reported Monday that it is moving closer to the sale of its share of an offshore wind joint venture and has substantially completed negotiations with a potential buyer. 

New England’s largest utility has been looking to exit offshore wind development for more than a year, but the process has moved slowly as financial and supply chain challenges altered the economics of its partnership with Ørsted, the world’s largest offshore wind developer. 

Earlier this year, Eversource reported a $401 million impairment on its offshore wind business, which came to $331 million after taxes. (See Eversource Takes Hit on Sale of Offshore Wind Assets.) 

In September, Ørsted bought out Eversource’s interest in the uncommitted wind lease area the two jointly held. Eversource is now trying to finalize the sale of its interest in the Revolution, South Fork and Sunrise projects to an as-yet undisclosed buyer. 

In a Nov. 6 conference call with financial analysts, Eversource CEO Joe Nolan said the main remaining hurdle is for the potential buyer and Ørsted to finalize their joint venture agreement and other documents. 

Nolan could not estimate how long that would take but said Ørsted and the buyer are familiar with one another, having engaged in other transactions. 

“We expect this process to wrap up shortly,” he said. 

Eversource’s stock, which has been trading near 52-week lows, closed 3.16% higher Monday. 

Eversource’s 10-Q filing for the third quarter indicates the company’s total equity investment balance in its offshore wind business had reached $2.58 billion as of Sept. 30. 

South Fork is under construction and is expected to start generating power later this year. The partners have decided to begin construction of Revolution next year. 

Ørsted has said it would like to continue with Sunrise, but the best path to do so would be through rebidding the project with more lucrative terms. 

Nolan shared the same message Monday: “Together, [Eversource and Ørsted] will work towards developing a bid that will reflect the attractive nature of this project. We feel confident that Sunrise Wind will deliver clean and reliable energy to New York and support economic development in the region, much earlier than many other projects. We will continue to evaluate ways to maximize project economics and to ensure project schedules remain on track. We have begun limited onshore construction for Sunrise Wind.” 

Given the fluid nature of that project, CFO John Moreira said Eversource could see a scenario under which it sells its share of South Fork and Revolution first, then follows up with sale of its interest in Sunrise. 

In its financial report, Eversource said it earned $339.7 million for the third quarter, down from $349.4 million in the same period of 2022. For the first nine months of 2023, earnings totaled $846.2 million, down from $1.08 billion in 2022. 

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Energy Bar Assoc. Panelists Urge Midwest to Get a Jump on DER Aggregations

Midwestern parties need to act with more urgency to open wholesale markets to DER aggregation, panelists said during the annual meeting of the Midwest chapter of the Energy Bar Association.

Joann Stevenson Worthington, senior manager of regulatory affairs at Voltus, said DER contributions aren’t as new as some may think. She said FERC Order 2222 was “acknowledging that it was happening and really trying to put some structure around it.”

“The regulations are behind and continue to be behind what’s happening on the ground,” Stevenson Worthington said during the Nov. 6 meeting.

She also said FERC “seems inclined not to give people a lot of time to get their ducks in a row” on compliance.

FERC last month rejected MISO’s proposed 2030 go-live date to bring DER aggregations into its markets. The commission told the grid operator to pick a closer date and explore the possibility of aggregations spanning multiple pricing nodes. (See FERC: MISO’s 2030 Finish Date on Order 2222 Compliance not Soon Enough.)

So far, Stevenson Worthington said she’s observed “piecemeal” responses from states on aggregator participation, driven largely by their regulated utilities approaching them about cost recovery and tariffs. She said she’s concerned that state commissions and RTOs won’t reach the level of cooperation required to successfully implement Order 2222.

Stevenson Worthington said Order 2222 issues need to be “grappled with in the shorter term instead of the longer term” and that it behooves states to work out rule sets now. She said she felt “horrible” telling states that because she knows they’re working with limited funds and resources and often focused on “putting out other fires.” However, she said states and grid operators continuing to work in their own “siloed” processes isn’t practical.

“I think this will require a greater deal of coordination than at current,” she said. She added that full DER aggregator implementation in the wholesale markets will pay off through lower prices for customers.

Ameren Illinois Senior Manager of Regulatory Compliance Peter Millburg said states, utilities, aggregators and grid operators need to arrive at a process that works for everyone — and quickly.

“It’s here. Aggregation is already here, and it’s at scale. … We already purchase capacity from it,” Millburg said. “Right now, it’s a really manual process, and that needs to change.”

Millburg called for a “dynamic, real-time” solution. He said utilities and grid operators need to move from simply making sure load is served to understanding how to maximize dispatch of the system. He also said asking utilities to hand over data and let a third-party aggregator handle every aspect of the process is a “nonstarter” due to cybersecurity concerns.

Millburg said despite vendors’ claims, fully functioning distributed energy resource management systems don’t exist yet, though they should.

Millburg advised everyone to “remove fear.” He said he understands aggregation participation is a new concept, and reliable service is paramount, but that the two aren’t mutually exclusive.

“These are known products; these are existing products. … Keep in mind that it’s not just generation; it’s also demand,” he said.

Steve Davies, IURC’s senior assistant general counsel, said IURC has been holding public meetings on Order 2222 and gathering opinions for nearly a year.

Davies said Indiana might start a docket on the rule or institute its own state rulemaking on allowing DER aggregator participation.

He urged other states to get started as early as possible collecting suggestions and thinking about what rule changes they will need.

“We’ve been doing this for almost a year now … and I feel like I’m just starting to get my head around this,” Davies said.

MISO said it will seek an extension with FERC to hold up to six months’ worth of additional discussions with stakeholders before proposing a new Order 2222 implementation date and deciding whether it can handle multinodal aggregations.

MISO said it will handle FERC’s other, less intensive asks in a filing within 60 days.

MISO’s plan to devote more time to Order 2222 coincides with it extending its DER Task Force through 2024. The RTO originally considered sunsetting the task force this year.

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Vistra Teases ‘Re-segmenting’ Businesses in 2024

Vistra said Nov, 7 that its acquisition of Energy Harbor will accelerate the company’s transformation and lead to a “re-segmentation” of its businesses when the deal closes.

CEO Jim Burke told financial analysts during the company’s quarterly earnings call that Vistra’s “transformative acquisition” of Energy Harbor will support the Irving, Texas-based company’s clean-energy transition, one of its four strategic objectives. He said management expects to disclose the specifics of the combined company’s long-range plan in the first half of next year.

“In the meantime, we continue to opportunistically invest in renewables and energy storage growth,” Burke said.

Ohio-based Energy Harbor and its three nuclear plants — Davis-Besse, Beaver Valley and Perry — will add more than 4 GW of nuclear generation to Vistra’s existing Comanche Peak plant and its 2.4 GW of capacity.

The $6.3 billion transaction, announced in March, has run into a delay at FERC over market power concerns. The commission has said it will rule on Vistra’s application by April 11. The Nuclear Regulatory Commission in September approved the transfer of the plants’ operating licenses to Vistra. (See FERC Delays Ruling on Vistra Purchase of Energy Harbor.)

Vistra has committed to selling more than 1,000 MW of gas-powered generating plants to alleviate the market power concerns and says it made substantial concessions to comply with a Justice Department request in August.

“We have responded to requests from FERC, and that process is progressing,” Burke said. “We believe that will eliminate any potential remaining concerns around market competition. We continue to target a closing before the end of the year.”

The company will also begin construction on its three largest combined solar-and-storage projects next spring as part of the Illinois Coal-to-Solar and Energy Storage Initiative.

Vistra reported $1.61 billion in ongoing operations adjusted EBITDA, compared to $1.04 billion during the same period a year ago. The record-breaking Texas summer boosted its ERCOT fleet’s output to 2.5 TWh during the third quarter, its highest quarterly performance by 10%.

The company uses adjusted EBITDA as a performance measure because, it says, outside analysis of its business is improved by visibility into both net income prepared in accordance with GAAP and adjusted EBITDA.

Vistra’s share price closed at $34.77 Thursday, down 56 cents on the day.

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Obstacles to Decarbonizing Key New York Housing Sector Flagged

Decarbonizing New York state’s million-plus midsize apartments will be difficult under current regulatory and financial structures, a report by the Federal Reserve Bank of New York found last month.

Decarbonization is critical for the state’s emissions-reduction goals, but it is expensive and cumbersome for those businesspeople who are generally short of the money and expertise to carry it out. Moreover, the return on investment — slowing damage to the planet — is societal rather than individual. When the benefits of taking action do not accrue to the decision-maker, the report’s authors point out, there is no impetus to decide to take action.

“Window of Opportunity: New York’s Small Multifamily Buildings, Expiring Equipment and Clean Energy Goals” was published in late October as part of the New York Fed’s Community Development initiative. It looked at a specific segment of the state’s 8.6 million housing units: those in five- to 50-unit buildings.

More than 1.45 million housing units are in this category. Those units are aging; almost 70% of their occupants are low- or middle-income; 1.3 million are heated with fossil fuel equipment that is nearing the end of its service life; and many are owned by small-scale landlords.

The conflict is readily apparent: A perfect target for decarbonization is owned by people who lack the resources and knowledge to carry out the work and inhabited by people who cannot afford to pay for it.

The Problems

New York already has one of the lowest per-capita levels of greenhouse gas emissions of any state, among the fewest vehicles per capita and a dominant industry — finance — that does not spew emissions.

So as state leaders pursue the goals and mandates of the Climate Leadership and Community Protection Act, and New York City leaders implement Local Law 97, a primary goal is decarbonizing buildings, the largest single source of emissions in the state.

But actually decarbonizing all those buildings is a tall order. New York’s population growth has been stagnant or negative in recent years, so the effort must focus heavily on retrofitting its existing, aging housing stock: 80% of the buildings that will exist in 2050 have already been built, the authors predict.

The report is based on a series of interviews and a roundtable discussion with 28 stakeholders in the housing and finance sectors. They flagged numerous problems facing decarbonization of the five- to 50-unit sector of New York’s housing stock:

    • Absent any legal mandates, the decision to electrify ultimately is up to the building owner. Owners of smaller properties often run the operation themselves, without benefit of support teams. They are less likely than large-property owners to know about electrification or have the means to pursue financing for it.
    • Owners have far more pressing concerns, such as basic maintenance, and lack bandwidth to undertake a sweeping new initiative.
    • Owners often cannot self-fund a deep retrofit, which can cost more than $100,000 per unit. Financing is dicey, because electrification may actually increase operating costs. The owner cannot raise the rent on a regulated unit, and if the local market is struggling, the owner may not be able to raise rent on an unregulated unit either.
    • Many five- to 50-unit properties already are financed to maximum leverage, making it hard to secure new debt; also, senior lenders worry about lien priority when new mid-process debt is issued.
    • Government incentives and financing for electrification are not optimized for five- to 50-unit properties; the process to apply for such funding is arduous; and the administrative costs are prohibitive.
    • Owners of nonregulated units fear their property will become regulated if they accept funding.
    • Owners of regulated units fear their property will go through a lengthy and potentially costly rent restructuring when utility bills rise post-electrification.
    • Contractors qualified to do the work are in short supply. Small contractors often consider the five- to 50-unit projects too large to undertake, and large contractors consider the projects too small.
    • Risk allocation is lopsided: Owners have no recourse if, as first-movers, they invest in equipment that becomes technologically obsolete or becomes noncompliant with superseding state regulations soon after installation.
    • Predevelopment processes can be lengthy, expensive and cumbersome, potentially including gathering and analyzing historical data, conducting an energy audit and modeling energy savings projections.
    • There is no standardized solution — every project is essentially done from scratch.
    • There is no one-stop shop where small property owners operating on a thin margin with minimal resources can go for assistance with the many aspects of decarbonizing their buildings.

Suggested Remedies

Many of the problems cited in the report boil down to high cost and complex regulations, stubborn issues common to many endeavors in New York.

The report offers no ready list of solutions, but it does flag potential improvements, including increased funding, streamlined incentive programs, more proofs of concept, easily accessible technical assistance and a better-structured retrofit market.

Stakeholders offered some other suggestions:

    • Combining incentives offered through different agencies would help facilitate a project, but that is often impossible because the agencies do not coordinate with each other, or because the funding streams cannot be combined.
    • A new tax credit, abatement and/or exemption would be impactful, helping ease the financial weight of the work.
    • Utility cost breaks or monetized emission reductions would provide something that lenders could underwrite to.
    • Pairing public health care dollars with energy efficiency funding would monetize the health co-benefits of electrification.
    • Creating a form of secondary debt for electrification would sidestep the difficult prospect of financing such projects through the primary debt on the property.
    • On-bill financing for electrification or efficiency upgrades would be helpful, extending the repayment period and eliminating the need for upfront capital without competing with other debt.
    • A single entity or consortium could seek a single bid for multiple properties and ease the deficit of expertise that many of the owners of those properties have.
    • Larger financial institutions could meet their net-zero commitments by reducing the cost of capital.

The report was emphatic on this last point: “Stakeholders strongly emphasized that no matter how many incentives are offered, subsidies are provided or other funding levers are pulled, until the largest financial institutions begin putting their weight behind electrification, mass scale cannot be achieved.”

Along with their concerns and criticism, the stakeholders provided some positive reviews. They unanimously praised the state’s Climate Friendly Homes Fund, for example. The $250 million state initiative is intended to retrofit at least 10,000 units of multifamily housing in economically disadvantaged communities, and in so doing create a template for wider-scale work, establish best practices, demonstrate the feasibility of electrification and spread awareness of the need to electrify.

Another effort is the Clean Heat for All Challenge, designed to install low-cost, low-power heat-pump technology in New York City Housing Authority buildings. The cost of rewiring the authority’s 2,000-plus buildings for higher-voltage solutions would be staggering.

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MISO Welcomes Former Ford Exec to Board

The MISO Board of Directors next year will boast a former Ford Motor Co. executive after a vote of the RTO’s membership. 

Jeff Lemmer, former vice president and CIO at Ford, will begin a three-year term beginning Jan. 1, 2024. (See “Members to Vote on Whether to Place Former Ford Exec on Board,” MISO Board of Directors Briefs: Sept. 14, 2023.) 

Lemmer retired from Ford in 2020. While with the automaker, he managed an annual $2 billion budget and oversaw IT services for its global operations.  

Current Director Jody Davids will leave the board at the end of the year; she decided against seeking re-election after rounding out her first term.  

MISO members did re-elect Directors Robert Lurie and Theresa Wise to their second and third terms, respectively. Board members are limited to serving three, three-year terms. 

“Directors Lurie and Wise have proven to be instrumental in our continued success, and Director Lemmer brings a new perspective that will aid in our work to solve complex grid challenges,” MISO CEO John Bear said in a press release. “Our board represents a diverse group of leaders within and adjacent to the electric power industry, which provides us with a broad cross-section of experience.” 

MISO’s Nominating Committee — comprising two members and three directors — advanced Lemmer and the two incumbents for consideration in September after conducting interviews. Voting isn’t based on a choice between candidates but whether a nominated candidate can secure a majority of votes in support from the MISO membership in a monthlong electronic poll. 

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New Jersey Moves to Embrace Geothermal Heat Pumps

After years of largely overlooking geothermal, New Jersey has launched an effort proponents hope will better integrate the energy source into the state’s renewables portfolio.

The state Board of Public Utilities (BPU) on Sept. 14 began setting up a pilot project to help develop geothermal energy projects, boost consumer education and outreach about the technology and prepare a workforce ready to build such projects.

Under a board-approved Memorandum of Understanding, the BPU will work with the New Jersey Department of Environmental protection (DEP) to develop the pilot with the New Jersey Corporation for Advanced Technology (NJCAT), which helps verify technology and develop and grow energy and environmental technology-based businesses.

Proponents say the geothermal agreement could stimulate interest in the energy source, which has remained on the back burner even as the state in recent years has developed solar power aggressively and put together a program to harness wind through turbines to be located off the New Jersey shore.

In the past two decades, state help for geothermal projects has ranged from incentives of thousands of dollars that could cover most of a project cost to just a few hundred dollars that barely covered the cost of the paperwork, said Jim Thomas, owner of Thomas Geothermal Engineering of Tabernacle, N.J.

“Fifteen or 20 years ago, there was some hope that geothermal would be big,” Thomas said. But lately, “New Jersey has not had any record with geothermal,” he said, expressing optimism the latest initiative could reverse the pattern.

“It’s a huge task,” he said. “I’m glad that the state is finally reaching out for people like us to maybe help them do this. So it could turn out to be a watershed moment.”

Tapping Underground Temperatures

The renewed focus on geothermal energy comes amid a vigorous push by New Jersey to cut building emissions, the state’s second largest emissions source, mainly by shifting heat and hot water systems away from fossil fuel energy to electricity. In one initiative, the BPU in June released a $50-million-a-year, three-year plan to cut building carbon emissions by prioritizing a shift from delivered fossil fuels to electric heat pumps. (See NJ BPU Outlines $150M Building Decarbonization Plan.)

Geothermal heat pumps, also known as ground source heat pumps, harness the stable temperature of the ground soil deep below the surface — usually between 50 and 59 degrees Fahrenheit — to cool a building when the temperature of the air outside is high and warm it when the air temperature is low.

Some projects rely on a closed “loop” system, with a pipe that connects to a heat collector or system of underground pipes, tapping the ground temperature to warm or cool the fluid, depending on what’s needed. The heat or coolness is then extracted and used to heat or cool air or water, which is distributed around a building to alter its temperature. Other projects use an open-loop system, drawing water from a water source — such as ground water — and pumping it through the piping system and into the building before returning it to the source.

NJCAT suggests New Jersey focus only on closed loop rather than open-loop geothermal heat pump systems, in order to protect groundwater.

Interest in the technology is growing in other states, too, especially New York. Speakers at the packed NY-GEO Conference in May said the interest in geothermal has been helped by federal and local government promotion of the technology and the availability of tax credits in the recently enacted Inflation Reduction Act (IRA). (See Geothermal Heat Pump Industry Flush with Potential.)

The state on Sept. 21 enacted a law that would make it easier to pursue geothermal projects by loosening the regulations that govern closed-loop boreholes. (See NY Seeks to Unlock Geothermal Potential for Buildings.)

Short Term Pain, Long Term Gain

In New Jersey, despite the relatively modest recent support for geothermal projects, there are 3,400 geothermal heat pump systems in operation, 1,400 of which use a closed loop and 1,900 of which use the open loop system, according to the DEP.

The first major geothermal project in the state was at Stockton University in South Jersey, Thomas said. The now-30-year-old project heats and cools the campus with a system of 400 heat exchange wells containing plastic pipes drilled to a depth of 425 feet and connected. Water flows through pipes and the heat or cold — depending on the time of year — is extracted and piped into the buildings.

The most prominent project using geothermal techniques underway in the state is at Princeton University, which is developing a “geo-exchange” it calls a “thermal piggy bank” and describes as one of the largest in the world. The project, which consists of two systems that heat and cool campus buildings, is key to the college’s goal of reaching zero emissions by 2046 and is designed to store energy created in seasonal patterns rather than discarding it.

The project uses similar technique to a geothermal system, but rather than simply extracting heat from the ground and not returning it, as a geothermal system does, the geo-exchange stores heat energy in the ground and takes it out later.

“During summers, we take heat out of buildings and store it in the ground using geo-exchange bores to slightly warm the rock below campus,” according to a recent explanation by the college facilities department. “During winters, we use the same geo-exchange bores and warmed rock as a heat source for our buildings.”

Cost, Space Challenges

Ravi Patraju, associate executive director for NJCAT, said the organization believes geothermal heat pump systems can help the state reach its goal of cutting carbon emissions to 80% of their 2006 levels by 2050.

“We realized that with the current methods of heating and cooling residential and commercial buildings, that would not be achieved at all,” he said.

The state has in the past focused more on air-source heat pumps, which use the outdoor ambient temperature for heating and cooling, he said. Installers say a geothermal heat pump for a 2,000-square-foot home can cost between $15,000 and $38,000, double the price of a conventional HVAC system.

But air-source heat pumps are less efficient for heating and cooling, especially when the outdoor air reaches very low temperatures in the winter and very high temperatures in the summer, Patraju said. Air-source pumps use much more energy than geothermal heat pumps and so would pressure the state’s energy grid more, he added.

Geothermal heat pump systems, “if designed and installed properly, not only will it solve the space heating and cooling (problem), but also … pretty much give you the domestic hot water that you need,” he said.

The challenge, however, is getting a widespread buy-in for heating systems that are cost-efficient in the long run but require a greater upfront investment than a fossil fuel heating system, Thomas said.

“The difficulty becomes basically, you need to put pipe in the ground to exchange heat, which has meant you need to get a driller, and that’s a whole big deal,” he said. “It could easily add $15,000 to the cost of installation. … You could pick up a gas furnace for as little as $1,500.”

New Jersey in the past offered incentives of up to 80% of a project, which has been dramatically reduced, and even when projects were financially viable, the state lacked a support network of tradesmen, particularly drillers, to do the work, he said.

Another challenging issue, Thomas said, is the large amount of space needed to get drilling equipment into a house and where to put in bore holes. One solution under discussion, which would become more viable the more geothermal energy is embraced, is to have a shared loop, called a thermal energy network, he said.

“So you would not own the loop,” he said. “The loop would be owned by the utility, they would bill you monthly like they would for gas or electric, based on the amount of BTUs that you transfer.”

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PJM OC Briefs: Nov. 2, 2023

Stakeholders Endorse Winter Weekly Reserve Target

VALLEY FORGE, Pa. — The PJM Operating Committee on Nov. 2 endorsed the RTO’s recommended winter weekly reserve target (WWRT) for the upcoming season. 

The figure is used to coordinate outages over the winter to mitigate load and forced outage uncertainty. (See “PJM Presents Recommended Winter Weekly Reserve Target Values,” PJM OC Briefs: Oct. 5, 2023.) 

PJM’s Patricio Rocha Garrido said the study recommended values of 28% for December, 30% for January and 25% for February. All three months would have higher targets than last year’s study, which had 21% for December, 27% for January and 23% for February. 

The higher values are because of changes to the modeling of forced outages over the winter and the inclusion of data from December 2022’s Winter Storm Elliott and the 2014 polar vortex. PJM historically had not included the polar vortex data because of a belief it would not reflect conditions the grid was likely to experience again, but it revised that practice following Elliott. 

The WWRT is one of three components of the annual Reserve Requirement Study. The other two, the installed reserve margin and forecast pool requirement, were endorsed by the Markets and Reliability Committee during its Oct. 25 meeting. 

PJM Presents Operations Assessment Task Force 2023 Report

PJM’s Thinzar Aung presented the results of the Operations Assessment Task Force’s 2023 winter study, which found the RTO would have a reserve margin of about 17 GW under the conditions normally studied but would be short nearly 5 GW if the specific conditions during the December 2022 winter storm were to occur again. 

No reliability issues were found for the base case under the preliminary 50/50 peak load analysis, although some re-dispatching and switching would be required because of local thermal or voltage violations. 

A total of 181.1 GW of capacity is expected to be available in the study, with a 90/10 diversified peak load of 141.4 GW. 

The single largest gas/electric contingency would reduce available generation by 4.8 GW, the study found. Paired with 16.7 GW of generation outages assumed in the analysis, 5 GW of exports and 7.2 GW of demand response, that leaves a 16.8-GW reserve margin. 

The low wind and solar scenario would reduce generation by 4 GW, leaving a 17.6-GW margin. 

The Elliott scenario increases the generation outages to 46 GW, reduces demand response to 2.4 GW and assumes a net interchange of 2.8 GW in imports. In such a scenario, PJM would be short 4.8 GW of generation. 

PJM’s Chris Pilong said the Elliott scenario was designed to replicate the worst conditions seen during the storm. (See PJM Recounts Emergency Conditions, Actions in Elliott Report.) 

“It underscores the need to be prepared and, from a generation perspective, do everything we can to chip away at that 46,000 MW of outages,” he said. 

Quick-fix Manual Changes to Transmission Facility Cut-in Process Approved

Stakeholders endorsed a quick-fix proposal to allow PJM to delay energization of a line with a cut-in ticket if the transmission owner has not submitted evidence that all required critical tasks have been completed and the data verified by the RTO. The quick-fix process allows an issue charge and proposed manual changes to be voted on side-by-side. 

If the required data have not been received and verified by PJM by 11 a.m. on the day prior to the requested energization date, and extending the outage would not pose reliability concerns, the RTO will delay the in-service date by one day, which can be continued if the data continue to remain unavailable. PJM’s Dean Manno said it takes staff about one day to verify the data. 

Manno said critical tasks include submitting parameters such as ratings, impedance, telemetry for tie-lines and monitored priority. 

The changes are expected to be brought to the MRC for an endorsement vote Nov. 15. 

Generation Winterization Requirements Endorsed

The committee endorsed revisions to Manual 14D: Generator Operational Requirements, which include a requirement for resources to prepare for winter conditions and expanded the winterization checklist. 

Part of the manual’s periodic review, the revisions also include several administrative and clarifying changes. 

The checklist now prompts generation owners to assess safety hazards posed by snow and ice accumulation on wind and solar facilities, inspect commodities and resources that may be used in severe winter weather, and consider adding a “freeze protection operator” staff member to inspect critical equipment. 

PJM’s Vince Stefanowicz said generators can substitute PJM’s checklist for a comparable list of their own. 

Clarifying Revisions to Manual 10 Endorsed

The committee endorsed revisions to Manual 10 that would clarify that generators entering outages or their availability into eDART should report their full nameplate capability unless physically derated. 

Stefanowicz said physical derates are permanent changes to a resource that reduce its maximum output, such as components being taken offline that reduce output without the expectation of replacing them.