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August 13, 2024

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IRA Gets US Emissions Close to Pledged Levels, Report Finds

The U.S.’ current policies have it on course to cut emissions by 32 to 51% below 2005 levels by 2035, which is an improvement over previous years but still short of its pledges under the international Paris Agreement, the Rhodium Group said in a report released Thursday.

The country is on track to get to 29 to 42% cuts by 2030, while the Paris Agreement calls for cuts of 50 to 52% by that year.

Rhodium Group releases a version of its “Taking Stock” report every year, and this year it has the benefit of a better understanding of how the Inflation Reduction Act is going to be implemented. The law has Rhodium predicting the power sector will see the largest declines in greenhouse gas emissions in its history of tracking emissions.

“The power sector in particular looks quite different in 2035 compared to today, with zero- and low-emitting power plants making up 63 to 87% of all generation that year, up from around 40% in 2022,” the report said. “Electric vehicles also continue their rapid growth, and, taken together, this progress on decarbonization also reduces household energy bills by an average of $2,200 to $2,400 per year in 2035 from 2022 levels.”

Getting there will be challenging, with the country needing to add 32 to 92 GW per year of wind and solar, while its actual annual record is roughly at the very bottom of that range. That level of deployment “faces headwinds in nearly every direction,” with more work to be done on the supply chain, interconnection, transmission, siting and an expanded workforce.

“Without the IRA, cost competitiveness would be one of the primary barriers to clean energy deployment,” Rhodium said.

While new wind and solar had proven to be cost-competitive with new natural gas before the law, they also have to compete with existing fossil fuel generators, which are either partially or entirely depreciated.

“But if cost is less of a barrier, all the other headwinds remain,” Rhodium said. “Until now, relatively less attention has been paid to these other challenges because cost was front and center. That means policy solutions for overcoming these barriers are less developed and have less political momentum.”

Rhodium estimates “economically rational” deployment of renewables, which means some of those other headwinds are not fully taken into account in the report. The group said it planned to tackle them more completely in future research.

Taking into account announced retirements and future economic decision-making by generators, Rhodium expects the trend of coal plant retirements to accelerate in the coming years, averaging 22 to 23 GW from 2023 to 2025, compared to 12 GW over the past five years. The trend slows down in later years because of a much smaller coal fleet.

“Additions of combined cycle and peaker gas plants also accelerate into the 2030s in the mid- and high-emissions cases,” the paper said. “But gas capacity growth is effectively flat through 2030 in the low emissions case and then starts to decline in the early 2030s.”

The paper’s power sector emissions projections include the impact of federal incentives from the IRA such as the extended clean energy tax credits; tax credits for nuclear, carbon capture and storage; current EPA rules such as the Mercury and Air Toxics Standards; and state policies such as renewable portfolio standards and offshore wind mandates.

EPA’s proposed power plant rule to limit greenhouse gases would require a mix of carbon capture retrofits, hydrogen blending, natural gas co-firing, federally enforceable retirement decisions and capacity factor limitations. The agency has yet to take comments on its proposal, which is likely to change before it is finalized. (See EPA Proposes New Emissions Standards for Power Plants.)

“We generally adopt EPA’s proposed phase-in schedule and the stringency of emissions reductions, but we offer a high degree of flexibility for states to create and submit plans for achieving equivalent levels of emissions reductions,” Rhodium said.

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Stakeholders Puzzled by MISO Transmission Service Requirements for Battery Storage

CARMEL, Ind. — MISO stakeholders are trying to figure out what transmission service requirements the grid operator has in place for battery storage that charges from the grid.

Stakeholders have asked MISO to clear up its transmission service requirement process for incoming battery storage that intends to charge from the grid. They said there are inconsistencies and ambiguous language between MISO’s business practice manuals and tariff as to whether battery storage needs to secure yearly, firm point-to-point transmission service for storage, or non-firm service. MISO maintains that storage that charges from the grid is required to obtain long-term, firm, point-to-point service, not the interruptible network service option.

At a July 19 Planning Advisory Committee meeting, WEC Energy Group’s Chris Plante outlined stakeholder concerns that MISO’s interpretation that storage should acquire point-to-point service is overly restrictive compared to FERC requirements and “severely limits the value” of energy storage resources.

FERC’s Order 841 requires that “applicable transmission charges” should apply when a storage resource is charging from the grid to resell energy later.

Several storage developers agreed that MISO’s reading of Order 841 will hurt their bottom lines. Some argued that storage charging behavior is similar to load, and that storage resources already naturally avoid charging during periods of peak demand. Multiple stakeholders said MISO needs storage to help combat deepening capacity shortage risks down the road. (See OMS-MISO RA Survey Signals Potential for 9-GW Shortfall by 2028.)

Plante raised the issue during multiple spring planning meetings. He said he thought MISO’s business practice manuals are light on authority when standalone battery storage connects to the transmission system and intends to charge from the grid.

Plante said MISO’s rules are vague on whether MISO’s non-firm Network Integration Transmission Service could fulfill the requirements of Order 841. He also said it’s unclear as to whether MISO’s interconnection process for storage resources considers its transmission service requirements. Finally, he said MISO is ambiguous as to whether transmission service requirements apply to storage connected to the distribution system.

MISO’s Planning Advisory Committee members agreed to take up the issue for discussion at future meetings.

“If we’re going to be relying on batteries as a large source of our generating fleet in the future, then it will have to charge in areas that are different from what we have today,” MISO’s Andy Witmeier said.

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MISO Aims for Manageable Interconnection Queue

CARMEL, Ind. — MISO is proposing an approximate 73-GW annual limit on project proposals, tripled entry fees, more ironclad land requirements and escalating penalty charges in its quest to oust speculative projects and lighten its gridlocked interconnection queue.

MISO shopped six new rules Wednesday to limit the interconnection requests it will accept and under what circumstances developers can withdraw project proposals. (See MISO Committed to Crackdown on Interconnection Queue Submittals, Departures.) The package of rules includes introducing an escalating, automatic penalty upon withdrawal of project proposals, imposing a 60%-of-peak-annual-load megawatt limit on the total number of new requests per year and enacting a 10% cap of that total size limit on the projects individual developers can submit annually.

“We do not want to slow the energy transition down, but the more projects you have in your queue, the longer it takes to study them,” Director of Resource Utilization Andy Witmeier said at a July 19 Planning Advisory Committee (PAC) meeting.

MISO’s Andy Witmeier | © RTO Insider LLC

Witmeier said MISO considers a queue that adds 73 GW of annual projects more achievable in terms of reliability studies. Last year, MISO received about 171 GW of interconnection applications. As of last month, MISO’s interconnection queue contained 1,412 active generation projects totaling almost 241 GW. Historically, more than 70% of interconnection requests never complete MISO’s queue.

MISO is waiting to file for and receive FERC approval on the proposal before it closes its currently open-ended 2023 queue application window. It hopes to wrap up accepting applications by the end of the year, later than its usual September deadline. Witmeier said if MISO kicks off studies before it has the new restrictions in place, it could be hit with as much as 200 GW in new generator interconnection requests.

“MISO only has an approximate 121-GW peak load. Where are we going to put those additional megawatts? We’ll have to shove them off on our neighbors. We have to set some type of limit so we can get a proper-sized queue and have realistic studies,” he said.

But Witmeier said he had “concerns that FERC isn’t going to go for” MISO’s proposed cap on individual developers because of the potential for discriminatory treatment. MISO proposed an annual cap of 60% of its average 121-GW peak load (73 GW) and that individual developers be limited to 10% of the total, or 7,300 MW. Witmeier said MISO likely will have to create an attestation form for developers where they verify parent companies or subsidiary status to enforce such a cap.

Invenergy’s Sophia Dossin said her company is “deeply concerned” over the proposed megawatt limits, saying it would set the stage for a lottery where the most prepared developers’ projects could be barred from consideration. Others agreed that MISO’s megawatt limits could affect the market forces of renewable energy development.

Witmeier said MISO likely will hike its $4,000/MW first milestone fee to $12,000/MW. The second milestone fee is set to be $1,000/MW or 20% of the cost of identified network upgrades, whichever is greater. The third milestone fee would be at least $1,000/MW or 30% of network upgrades.

“We think the [Inflation Reduction Act] has changed the dynamics of our interconnection queue,” Witmeier said, adding that MISO hasn’t increased the milestone fees it charges developers since 2017.

MISO is proposing to use its larger, second milestone fee as the basis for a new, automatic penalty schedule for interconnection customers who withdraw projects. MISO is proposing to keep 10% of the first milestone payment if projects are removed before the start of the queue’s definitive planning phase, 25% of the payment if projects drop out at the queue’s first decision point, 50% at the second decision point, 75% during the queue’s final phase and 100% at generator interconnection agreements (GIAs) and beyond.

Witmeier said the penalty schedule relies on an expanded definition of withdrawn projects’ harm on lower-queued projects. He said MISO will use the pool of money it collects to spread among other generation projects, some of which were banking on sharing network upgrade costs with the dropouts. He said the move should cut down on the instances of cascading project withdrawals in the queue.

Witmeier also said MISO will require interconnection customers to secure 50% site control from generator site to point of interconnection upon application and 100% site control to the point of interconnection before developers can negotiate GIAs.

“If you don’t have site control at the time of GIA, you are not a viable project,” he said.

Witmeier said the megawatt limit on individual developers might only serve as a “backstop” against an unmanageably large queue because MISO is creating a more exclusive club of projects that line up in the first place through higher fees and stricter land requirements.

MISO retained Charles River Associates to conduct an independent review of the RTO’s recommendations, Witmeier said. He said while the review is still ongoing, the firm has initially deemed the set of rules to be reasonable.

However, Witmeier said if stakeholders are adamantly opposed to one of the new rules, MISO will consider lowering dollar amounts or adjusting requirements.

“We don’t know how each of these levers will impact the queue. There’s no way to know. Interconnection customers aren’t Goldilocks,” Witmeier said in response to stakeholders’ questions on how the queue might look emerging from the changes.

Staff will again discuss the stricter queue entry and exit rules at the Aug. 30 PAC meeting. Also, MISO has said it will consider stakeholders’ ask for a special meeting on the suite of changes. Many said the 45-minute time slot MISO allotted on its July 19 PAC agenda for discussion of the proposal was insufficient. PAC leadership was forced to stop accepting stakeholders’ questions to MISO staff after the discussion exceeded two hours.

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MISO Trims Minnesota Line Route in JTIQ Portfolio

CARMEL, Ind. — MISO announced this week that it has shortened one of the 345-kV lines contained in its $2 billion Joint Targeted Interconnection Queue (JTIQ) portfolio with SPP, which will lower costs.

At a July 19 Planning Advisory Committee meeting, Director of Resource Utilization Andy Witmeier announced that MISO will replace the Brookings County-Lakefield 345-kV project in Minnesota with the shorter Lyons County-Lakefield 345-kV project. He said MISO was making the change because it approved Northern States Power’s proposal to install a second 345-kV circuit between the Brookings County and Lyon County substations in Minnesota for reliability reasons as part of the 2022 MISO Transmission Expansion Plan. That nearby project negates the need for a full-length line.

Witmeier said the “much shorter line, as the crow flies,” represents a significant savings for customers. He said the new line will solve all the same constraints as the original design but with a better benefit-to-cost ratio. MISO has already performed economic and reliability analyses on the shorter route. Transmission owners Xcel Energy and ITC Holdings will still build the line.

Witmeier said the JTIQ portfolio, which was finalized in 2021, is subject to revisions as MISO and SPP perform their annual transmission planning. He also said since the revised line remains wholly in Minnesota, it won’t require a change in permitting jurisdiction.

MISO has yet to reveal how much ratepayers can expect to save on the shorter line. Last month, the RTOs announced that the portfolio’s cost estimate had nearly doubled to $1.9 billion from a little more than $1 billion in 2021 due to the rising cost of materials and labor and more accurate line route estimates. (See JTIQ Portfolio Cost Estimate Nearly Doubles to $1.9B.)

Witmeier said he didn’t think the more economical line would affect the states’ application for the JTIQ portfolio to receive up to a 50% funding match from the Department of Energy’s Grid Resilience and Innovation Partnerships program.

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FERC OKs Incentives for Republic Transmission on MISO’s 1st Competitive LRTP Project

FERC approved LS Power’s request for rate incentives for the first competitive project surfacing from MISO’s long-range transmission plan (LRTP).

On Tuesday, FERC allowed LS Power’s Republic Transmission an abandoned plant incentive if the $77 million Hiple 345-kV line at the Indiana-Michigan border is canceled or abandoned for reasons beyond Republic’s control (ER23-1924). The commission’s approval elicited a rebuke of transmission rate incentives in general from Commissioner Mark Christie.

The Hiple line is the first competitively bid line segment to emerge from MISO’s LRTP and could be taken from Republic through Indiana’s new right of first refusal law, which gives incumbent developers the right to build projects recommended by RTOs. MISO awarded Republic the right to construction in June. (See MISO Picks Republic Transmission for 1st LRTP Competitive Project.)

Republic acknowledged that its status as selected developer could be in jeopardy in its request for the abandoned plant incentive. It said it “faces risks from incumbent utility opposition to competitive transmission” and that “even though the law did not take effect until July 1, 2023, the incumbent transmission owner may litigate and oppose Republic’s construction and ownership of the project in other ways.”

Competitive developer NextEra Energy lost its bid to construct what would have been the first competitive transmission project in MISO South because of Texas’ ROFR law. FERC recently denied NextEra’s request for a stay on MISO’s termination of the project. (See FERC Briefs: Orders Addressing Arguments Raised on Rehearing.) Next Era this week filed a petition for review with the D.C. Circuit Court of Appeals.

Republic also said it faces uncertainty over “significant regulatory and permitting, financial and construction risks,” including the unpredictability of the future fleet transition, which is the onus behind the line. The point of interconnection with Michigan transmission developer METC at the Indiana-Michigan border also is uncertain and will be determined by the route approved by the Michigan Public Service Commission.

FERC said Republic “demonstrated a nexus between its requested incentive and its planned investment.”

“We find that Republic has demonstrated that the Hiple project faces certain regulatory, environmental and siting risks that are beyond Republic’s control and could lead to the Hiple project’s abandonment,” FERC said.

Commissioner Christie said that while he agreed with FERC’s decision, it is time to “revisit the array of incentives offered to transmission developers, including the abandoned plant incentive … as well as the [construction work in progress] incentive and the RTO participation adder.”

Christie said FERC granting rate incentives of late “has become nothing more than a check-the-box exercise,” with no real examination as to whether developers are shouldering substantial challenges and risks.

He said while the construction work in progress incentive “effectively makes consumers the bank” for transmission projects, the abandoned plant incentive forces them to be insurers as well.

“This incentive allows transmission developers to recover from consumers the costs of investments in projects that fail to materialize and thus do not benefit consumers,” Christie wrote. He asked that FERC reevaluate the incentives to “ensure that all the costs and risks associated with transmission construction are not unfairly inflicted on consumers while transmission developers and owners stand to gain all the financial reward.”

Finally, Christie said he supported limiting the RTO participation adder to the “three years following a transmitting utility’s initial membership in an RTO.”

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MISO Creating Means to Gauge Impacts of DER Interconnections

CARMEL, Ind. — MISO says it will add a study to its planning process early next year to identify transmission reliability issues caused by distributed energy resources.

The study will mimic the style of its affected system study process with other RTOs.

MISO said it will create a technical screening process for interconnecting DERs to test for reliability impacts to the bulk electric system. The grid operator said it will begin screening for when it will need to perform studies on interconnecting DERs in October and initiate the first DER affected system study cycle Feb. 22. MISO asked its transmission owners to submit information on the potential for DER injections at their substations by Dec. 1.

Speaking at a July 19 Planning Advisory Committee, MISO’s Patrick Dalton said the RTO and its transmission owners will evaluate the need for a review of DERs when they can inject 5 MW of power at the substation level during system peak load and if they can force a 1% change in line loading. TOs will screen for the 5-MW injection capability, while the RTO will ascertain whether the DERs could influence a 1% line-loading change.

If the DER is shown to impact both reliability criteria, MISO will issue a report that will trigger its existing facilities study and could lead to network upgrades.

“MISO has not identified reasons that a DER affected system study would trigger the need to open new regulatory proceedings or to modify existing state-based interconnection rules,” Dalton said.

The RTO is updating its business practice manuals to incorporate the new study. It said it doesn’t require FERC permission to add the new study process.

ITC Holdings’ Ruth Kloecker said many of MISO’s transmission owners lack a “cohesive format” for communicating with distribution companies on DER reliability.

“I think that’s a big problem for MISO kicking off these studies,” she said. “We won’t have the data that’s necessary to do these studies.”

MISO staff said it’s important to move ahead with any information it can glean.

Meanwhile, MISO is also working on how it will incorporate more DER aggregations into its planning.

Currently, owners of DER aggregations aren’t required to submit modeling information to MISO. The RTO may make modeling submittals mandatory for larger DER aggregations sometime beyond 2023.

MISO reports that members are providing more details on DERs than in the past. For 2022 modeling, MISO recorded 411 MW of DERs at 651 locations, up from 30 MW at just eight locations in 2019.

In April, Planning Modeling Manager Amanda Schiro said DER “volumes are low and scattered throughout the system,” making planning impacts negligible thus far.

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X-energy, Energy Northwest to Develop up to 12 SMR Nukes

X-energy and Energy Northwest will partner on the development of up to 12 of X-energy’s Xe-100 small modular reactors to be located at a site in Central Washington, according to a Wednesday announcement from the two companies.

Under the joint development agreement, the 80-MW SMRs will come online in phases near Energy Northwest’s Columbia Generating Station, a 1,207-MW nuclear reactor 10 miles north of Richland, Wash. The first of the reactors is scheduled for completion by the end of 2030, with additional reactors added after, based on demand, according to Jason Herbert, Energy Northwest’s senior director for external strategy.

The company intends to apply to the Nuclear Regulatory Commission to license 12 reactors even though “right now, based on our utility, interest and offtake, we’re looking at probably … a four- to eight-module plant to start with,” Herbert said in an interview with NetZero Insider. “But we want to license for 12, so that in the future, let’s say, a utility comes to us and says, ‘Hey, we need 160 MW in three years.’ We can add in two more.”

If all 12 were built, the total capacity would be 960 MW, according to the announcement.

Energy Northwest is a Washington state public power joint operating agency, providing electricity to 28 public power utilities in the state. Other generation includes hydroelectric, wind and solar, and storage.

“As the Northwest region of the United States pursues a future clean energy grid, it is clear it will need new sources of dependable, carbon-free power,” said Bob Schuetz, CEO of Energy Northwest. “X-energy’s Xe-100 advanced reactor technology possesses many attributes ideally suited to a carbon-constrained electric system, and this agreement reflects our determination to deliver the technologies to meet growing clean energy needs.”

Under the Clean Energy Transformation Act (SB 5116) signed in 2019, Washington is committed to a carbon-free electric power system by 2045.

For X-energy, the announcement represents a critical step in building a pipeline of projects for the Xe-100, which the company has developed with $1.1 billion in funding from the Infrastructure Investment and Jobs Act as part of the Department of Energy’s Advanced Reactor Demonstration Program.

The program is supporting two advanced reactor demonstrations, the Xe-100 and the Natrium reactor developed by TerraPower, the company started by Microsoft founder Bill Gates.

The Xe-100 is a high-temperature, gas-cooled reactor, which uses small “pebbles” of graphite-covered nuclear fuel and can produce steam for high-heat industrial processes, with temperatures of 750 degrees Celsius, or close to 1,400 degrees Fahrenheit. At 80 MW, the X-energy reactor is designed to be modular so two or more units can be combined for heat or power or both.

As part of the DOE program, the company’s first four Xe-100s will be sited at a Dow Chemical plant on the Texas Gulf Coast, where they will be used to provide the high-temperature process heat the company needs to produce chemicals. The Dow reactors are being built to provide both power and high-temperature process heat, which X-energy will be able to use in Washington, said Ben Reinke, X-energy’s vice president of global business development.

Speaking at an industrial decarbonization event in Washington, D.C., on Wednesday, Reinke said the Energy Northwest reactors are being planned as “most likely [an] all-electric play. However, when you have low-cost electricity, you start to draw a lot of industry to the area. So, I think what we’ll see over time is an ecosystem built around energy units in Central Washington, hopefully decarbonizing not only electricity, but also potentially process heat as well.”

On Time, on Budget

The challenge ahead for X-energy is delivering its projects for both Dow and Energy Northwest on time and on budget — a goal the U.S. nuclear industry has yet to achieve.

The 92 reactors currently online in the U.S. provide 20% of the country’s power and 50% of its carbon-free power, and both the industry and the Biden administration are framing nuclear energy as an essential source of firm, dispatchable, carbon-free power.

But the only new reactors built in the U.S. in the past decade are Southern Co.’s two Vogtle nuclear plants in Georgia, which are now seven years behind schedule, with a cost that has ballooned from $14 billion to more than $30 billion. The first unit, Vogtle 3, was scheduled to come online in June, but encountered yet another delay due to a problem in the hydrogen system used to cool the main electrical generator, according to an Associated Press report.

Reinke said X-energy is trying to plan ahead to avoid delays and cost overruns. For the Dow project, the company is “fully designing our reactor before we break ground on construction, something the nuclear industry has never done before,” he said. “For example, we brought key partners in on the design of components and systems. We’ve gone ahead and made awards early on, earlier than a typical project might, to be able to bring into our final design period in the process these key partners who will ultimately be manufacturing the components and systems to make sure that what we’re designing is something they can manufacture.”

X-energy has also included construction teams in the design process to ensure a workable “construction laydown plan,” Reinke said.

Fuel for the Xe-100 is yet another challenge. Like other advanced reactors, the Xe-100 uses high-assay, low-enriched uranium (HALEU). The U.S. has historically depended on Russia for HALEU, but in the wake of the Russian invasion of Ukraine, it is working on standing up a domestic supply chain.

X-energy expects it will get the fuel it needs for the Dow project from DOE, Reinke said. He pointed to DOE’s HALEU Availability Program, which received $700 million from the Inflation Reduction Act to spur development of a domestic supply chain.

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NERC Committee Takes Action on Standards Projects

NERC’s Standards Committee moved forward on more than half a dozen standards projects during a busy meeting on Wednesday. While the committee usually meets by conference call each month, Wednesday’s gathering was held in person at the headquarters of the Midwest Reliability Organization in St. Paul, Minn.

Push for Formal Comment on SAR

First on the agenda at Wednesday’s meeting was a standard authorization request (SAR) to modify reliability standard MOD-031-3 (demand and energy data), in order to allow planning coordinators to obtain existing and forecasted information on distributed energy resources (DER) from distribution providers and transmission planners. NERC’s System Performance Impact of Distributed Energy Resources Working Group (SPIDERWG) developed the SAR, which was endorsed by the Reliability and Security Technical Committee (RSTC) in June.

NERC staff brought the SAR to the Standards Committee with a proposal to authorize posting it for an initial 30-day informal industry comment period, which raised eyebrows with some members. SPP’s Charles Yeung asked why the proposal was not for a formal comment period, which would require the SAR drafting team to address comments in the final draft SAR.

Latrice Harkness, NERC’s director of standards development, explained that under recent changes to NERC’s Standards Processes Manual, formal comment may not be required for SARs proposed by the RSTC. However, Yeung observed that the SAR actually was proposed by the SPIDERWG, and while that group does report to the RSTC, he asked whether the full RSTC had provided input into the SAR. Chair Amy Casuscelli of Xcel Energy confirmed that it had not.

As a result Yeung moved to modify the proposal to post the SAR for a formal comment period. After the motion was seconded, the committee approved it unanimously.

FERC Winter Weather Project Moves Forward

Next, the committee turned to FERC’s order to update TPL-001-5.1 (transmission system planning performance requirements), which the commission issued at its June meeting. (See FERC Approves More Extreme Weather Rules.)

FERC found that the current reliability standards do “not obligate transmission planners and planning coordinators to consider extreme hot and cold weather in their transmission planning assessments.” The commission gave NERC the choice of either updating TPL-001-5.1 or creating a new standard that contains such a requirement (RM22-10); the SAR submitted by NERC staff did not specify which option the project should choose, but left the decision to the SAR drafting team.

Like the previous SAR, the proposal that NERC staff brought to the meeting would authorize posting the draft SAR for an informal rather than a formal comment period of 45 days. In this case, the change was because the project was ordered by FERC, and NERC’s Rules of Procedure allow such projects to skip the formal comment phase.

Although members discussed changing this proposal to require a formal comment period as well, a NERC staffer noted that “many issues behind the directive were fully litigated in the FERC proceeding, so our hands are tied to some extent.” The staffer also reminded attendees that NERC must submit the new or modified standard by December 2024, and suggested that because “traditionally TPL revision projects have taken some time,” the standard drafting team’s (SDT) time would be better used focusing on the standard rather than replying to industry comments.

After this exchange, the committee voted unanimously to approve the proposal as written.

Other Standards Actions

The remaining items attracted little comment, though in some cases members asked NERC staff to make minor changes to wording for proposals that were going out for public comment. The approved items were proposals to:

    • Add members to the SDT for Project 2021-03 (CIP-002);
    • Accept the SAR for Project 2022-05 (modifications to CIP-008 reporting threshold);
    • Accept the SAR for Project 2022-04 (EMT modeling);
    • Post proposed reliability standards EOP-004-5, PRC-002-5, and PRC-028-1 (found on pages 69, 108, and 156 of the agenda) for 45-day formal comment and ballot periods; and
    • Post proposed revisions to NERC’s definition of Area Control Error Diversity Interchange for a 45-day formal comment and ballot.
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New York Seeks to Define Zero Emissions

New York regulators’ first steps to broaden the path to a zero-emissions future have drawn limited response from stakeholders.

The New York Public Service Commission received only five comments on its May 18 order to begin filling the power generation gaps likely to arise in the transition away from fossil fuels. It is part of Case 15-E-0302, the PSC’s implementation of a large-scale renewable energy program and a clean energy standard.

The issue is potentially contentious, as the order states that favored renewable technologies such as solar and wind may not provide enough power and that more controversial alternatives such as hydrogen, nuclear and biofuel may be needed.

But the issue is increasingly pressing: Less than two months after the PSC order, NYISO reported that the nation’s largest city could face a reliability margin deficit of up to 446 MW as soon as summer 2025 because of a wave of mandated fossil generation retirements and the slow pace of replacement power coming online. (See NYC to Fall 446 MW Short for 2025, NYISO Reports.)

Meanwhile, leaders are pushing to electrify the state to the greatest extent possible as they carry out the landmark Climate Leadership and Community Protection Act of 2019. But many renewable generation projects have been delayed or canceled, and the new generators that do come online are intermittent.

To start the process of addressing this, the PSC in its May 18 order asked stakeholders to address a series of questions, including:

    • how to define “zero emissions”;
    • whether advanced nuclear power, long-duration storage, green hydrogen, renewable natural gas (RNG), carbon capture and sequestration, virtual power plants, distributed energy resources and demand response resources can be considered zero-emissions sources;
    • what other resources should be considered;
    • whether efforts to achieve zero emissions by the 2040 target should focus solely on resource adequacy or include a broader set of technologies that could be integrated into the transmission and distribution systems;
    • whether lifecycle emissions should be considered when characterizing energy resources;
    • how RNG should be considered, given the limited feedstocks in the state; and
    • what re-examination and possible revision to the tiers of the Clean Energy Standard might be needed.

Some of these would seem to be red flags for environmental advocates and others who have pushed for climate mitigation measures in New York. But the only responses were from industry groups pitching their solutions, as well as from four members of the state Senate’s Republican minority pressing their existing agenda of an all-of-the-above approach to the energy transition. This includes splitting atoms and burning various combustible matter, two solutions that are opposed by many in the environmental movement.

Minority Report

Republican Sens. Mario Mattera, Tom O’Mara and Mark Walczyk, all members of the Energy and Telecommunications Committee, and Senate Minority Leader Robert Ortt said the state needs an all-hands-on-deck approach as it decarbonizes, because it will need nearly 100 GW of new generation by 2040.

They pointed out that solar’s capacity factor is only about 14% in New York. Onshore wind is much higher, but still only 20 to 26%.

“Hydrogen, nuclear, renewable natural gas, bioenergy and sewer heat recovery provide more reliable sources of energy than wind and solar, as they would not be intermittent,” they wrote. “To be clear, New York state cannot meet the mandates in the CLCPA by solely focusing on wind and solar energy generation.”

The senators urged the PSC to consider as zero-emissions all types of hydrogen — regardless of how it was generated. Non-green hydrogen generation is another target of environmental advocates.

Making Gas

Berq RNG and Strategic Project Management submitted mostly identical comments with the American Biogas Council, urging the PSC to give greater consideration to the biogas sector as a means of achieving its goals.

They said New York does not use the full statewide potential of its waste-to-energy biogenic resources, such as landfills and manure lagoons.

Industry data show 191 active biogas systems in the state, they said, but indicate there is enough renewable methane available to power more than 500 systems. Buildout of these facilities is also a significant opportunity to divert organic waste from landfills and to reduce emissions of methane, they said.

They urged that “zero emissions” be defined to recognize any molecule and any system for converting it to energy that can deliver a lifecycle carbon emission profile of zero or below.

Water Flow

The Low Impact Hydropower Institute urged that when totaling up lifecycle emissions, a leveled impact assessment be used, taking into account the project lifespan.

For example, it said, building a hydropower facility generates a high upfront emission impact, but its impact may be less when considered over its very long lifespan.

It noted that old and new energy resources alike, including hydropower, have exacerbated environmental justice concerns, but the process laid out by New York will begin to address that. It suggested New York look to Massachusetts, where regulations try to recognize not just renewable energy but also, in the case of hydropower, resources that reinvest in their natural surroundings in an accountable, annual and transparent manner that meets specific outcome requirements.

LIHI offered itself as a resource, saying its criteria have “helped facilitate healthy river flows, vibrant aquatic communities, and accessible recreational opportunities across the state and region.”

Pumped Hydro

Serium Energy Storage, which is pursuing development of closed-loop underground hydroelectric energy storage, pointed out what others have flagged: the need for large amounts of long-duration storage to maintain reliability in New York when the sun is not shining and the wind is not blowing.

Closed-loop pumped hydro is the perfect fit for several reasons, Serium said: It is a proven and mature technology; it has a more-than-100-year history in New York; it is compatible with carbon-reduction and environmental stewardship; and it does not face the limits that batteries do.

Serium said the major drawbacks of surface pumped hydro, including environmental impacts, are not an issue with the underground systems it proposes. The company asked the PSC to add hydroelectric storage to its “zero emissions” list, and to begin procurement soon, given its long timeframe for approval.

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PJM Recounts Emergency Conditions, Actions in Elliott Report

PJM on Monday released a report detailing a litany of emergency actions taken on Dec. 23 and 24 as a severe winter storm sent temperatures plunging across the region and containing new data on generation and market performance.

The RTO’s analysis of the storm, commonly called Elliott, provides 30 recommended changes to forecasting, modeling, accreditation and market rules. It says that PJM was well positioned in the days leading up to the storm, but a series of unforeseen factors — including a sharper than expected drop in temperatures, an unprecedented amount of forced outages and abnormal consumer behavior around the holiday weekend — led to several emergency actions having to be taken to maintain reliability, including two blocks of performance assessment intervals (PAIs) in which generator underperformance led to $1.8 billion in penalties.

A workshop has been scheduled for July 24 to discuss the report.

“As documented in this report, PJM was prepared for the 2022/2023 winter, as well as Winter Storm Elliott, based on the information available, and conducted extensive preparations and communications with members, adjacent systems and the natural gas industry in advance of the storm, in addition to the regular steps PJM takes each year to prepare for winter,” the report said. “Despite numerous refinements to both the capacity market rules and winter preparation requirements that came out of the 2014 polar vortex, Winter Storm Uri in [February] 2021 and other recent examples of increasingly extreme weather patterns, Winter Storm Elliott created a convergence of circumstances that strained the grid.”

Recommendations

Many of the report’s findings have guided PJM’s recommended changes to the capacity market currently being considered under the Critical Issue Fast Path (CIFP) process, including shifting to a seasonal capacity market, an approach to risk modeling that lays more of the reliability focus on the winter and fuel security requirements. The timing of the report’s release has been viewed as critical by many stakeholders participating in CIFP meetings, with voting on proposals scheduled for next month. (See PJM Completes CIFP Presentation; Stakeholders Present Alternatives.)

The recommendations outside the CIFP process include increasing education and training for members around emergency procedures and reporting requirements; evaluating the expected load reduction that a voltage reduction could yield as load composition changes; and exploring ways of increasing synchronized reserve performance through procurement practices, compensation and the amount procured.

The report also includes several recommendations related to the intersection between the electric and natural gas industry, such as aligning when gas generators are scheduled in PJM’s markets and their fuel nomination cycles, as well as improvements to how they report unit-specific parameters to PJM to improve awareness of their availability. Those proposals are under discussion at the Electric-Gas Coordination Senior Task Force.

The report also states that PJM plans next month to open a stakeholder discussion on whether the reserve market design, including prices and performance incentives, aligns with operational needs.

Generator Performance

The forced outage rate for PJM capacity resources throughout the storm was one of the highest PJM has seen in a severe winter weather event, with 24% of resources being offline — exceeding the 22% forced outage rate seen during the polar vortex. Forced outages peaked at 46 GW at 7 a.m. on Dec. 24 and “remained at an unacceptably high level through Dec. 25.”

Many of the outages were not immediately reported, resulting in the RTO’s operators being told the unit would not be able to operate when they attempted to dispatch the generator.

“While generators are required to provide updates on their operating parameters, including operating status, ramp times and fuel availability, in 92% of generator outages, PJM operators had an hour’s notice or less — in most cases, PJM was informed of outages when dispatchers called generators to request them to turn on,” the report stated.

Gas-fired generators made up about 70% of the outages, with gas supply issues being the single largest cause, followed by freezing and problems with plant equipment.

Natural gas well freeze-offs were a major contributor to generators being offline, with production in Ohio halved and down by about 20% in Pennsylvania, with the impact particularly acute for larger gas generators that require a uniform supply of fuel at high pressure. The timing of the storm falling on a holiday weekend also meant that gas trading markets would not be open for a prolonged period, limiting the liquidity of fuel.

“Many gas buyers, especially [local distribution companies] and other customers with more predictable gas usage levels, purchase their gas supplies on Friday for the Saturday, Sunday and Monday gas days. Gas generators in many cases need to buy their gas supply each day of the weekend period based on their awarded or anticipated dispatch. With the majority of gas traded on Friday, the market for gas commodity can become less liquid, resulting in increased supply scarcity and potentially higher intraday gas prices,” the report said.

Several portions of PJM’s and stakeholders’ CIFP proposals are centered around improving gas reliability by revising their accreditation and creating new fuel requirements. On July 10, PJM presented a proposed dual-fuel status for resources that can start and operate on a backup fuel with at least 48 hours of storage. It also discussed creating additional data reporting around whether gas generators have firm fuel or not and potentially reflecting that in their accreditation.

Coal resources made up about 16% of forced outages, largely because of issues with boilers.

Wind resources overperformed during the storm, contributing 13.7% of the bonus megawatts across the two PAIs, despite only making up 1.9% of installed capacity. Nuclear generators also exceeded their commitments, making up 34.5% of the bonus power while representing 17.7% of capacity.

The gas and coal units that did operate performed well throughout the emergency conditions, providing 29.2% and 17.3% of the bonus power.

Synchronized reserve resources also performed poorly throughout the storm. While the first deployment had a response rate of 86.4%, which PJM attributed in part to the short duration of that event, the average was 47.8% across the five deployments, some of which were hours long. PJM noted that deployments are uncommon, especially clustered in a short time frame.

“Five synchronized reserve events over a two-day period is extremely unusual. All five of the events on Dec. 23 and Dec. 24 exceeded 10 minutes in duration, which is again extraordinary. Since the start of 2021, there have been 47 synchronized reserve events, of which only 17 (36%) were more than 10 minutes in duration, and five of these 17 occurred during Winter Storm Elliott,” the report said.

Demand response resources provided significantly less than curtailment service providers (CSPs) anticipated they could provide when called upon. When PJM dispatched 4,336 MW of DR on Dec. 23, providers estimated they could provide the full amount, but PJM’s analysis of customer load data suggests that only 1.1 GW was delivered. When all available DR was dispatched leading up to the Dec. 24 morning peak, CSPs estimated they could deliver 7,400 MW of the 7,522 dispatched, but PJM said that only 2.4 GW was provided.

“The significant difference between the data provided to PJM about load curtailment capability and the actual performance clearly identify an opportunity and need to improve the rules and processes regarding load management capability estimates,” the report said.

PJM Operations

In the days leading up to the storm, the conditions appeared to be within the norms that PJM had experienced in the past: Temperatures weren’t forecast to be abnormal, and historically loads for the days leading up to Christmas had been overforecast. On the day before the storm’s arrival, PJM increased its load forecast for Dec. 23 from 124.6 GW to 127 GW and procured additional capacity and reserves above what was cleared in the day-ahead market. Actual loads came in at 136 GW and were nearly 10 GW above forecast the following day at 131.1 GW.

While providing exports to the Tennessee Valley Authority and other neighbors, some of whom were in emergency conditions, PJM entered its first of four synchronized reserve deployments at 10:14 a.m. in part from numerous generators tripping offline and failing to start, causing the area control error (ACE) to fall. As loads ramped up substantially higher than expected for the Dec. 23 evening peak, many of the generators PJM attempted to dispatch were tripping offline or failing to start, with a rate of 1.8 GW per hour at 2 p.m.

“PJM found that it was unexpectedly and rapidly exhausting its operating and primary reserves because of the unexpected generator outages,” the report said.

By 4 p.m. the ACE had fallen to nearly ‑3 GW, prompting PJM to begin curtailing exports. It also issued a pre-emergency load management reduction action to deploy DR resources and implemented a maximum generation action, directing generators to operate above their economic maximum outputs. This began the first block of PAIs, which would last five and a half hours, or 66 five-minute intervals.

PJM remained in emergency conditions until 11 p.m., but the nighttime load “valley” remained unprecedentedly high, 40 GW over the next highest valley in the past decade, limiting the ability for pumped hydro plants to be refilled. PJM provided some exports to neighbors that were in emergency conditions, and synchronized reserve events were called at 12:05, 2:23 and 4:23 a.m. on Dec. 24.

PJM began curtailing load again at 4 a.m. on Dec. 24 and issued a call for consumers to reduce their electric usage until at least 10 a.m. On top of forced outages, about 6 GW that was scheduled to come online for the morning peak failed to start and PJM re-entered emergency conditions at 4:20 a.m. with DR deployments and a maximum generation action five minutes later. At 4:52 a.m. it issued a voltage-reduction alert.

Approaching the morning peak at 8:30, which capped out at 130 GW of load, PJM was receiving emergency imports from NYISO and TVA, and Duke Carolinas and Duke Energy Progress were shedding load. The report states that forced outages around the morning peak amounted to 41 GW and 200 unit trips. PJM issued a voltage-reduction warning at 7:15 a.m. and remained in emergency conditions until it canceled the maximum generation action and DR deployment at 10 p.m.

At 4:58 a.m., an 850-MW generator tripped offline, causing the ACE to fall below 1,500 MW and prompting the start of a NERC Disturbance Control Standard (DCS) event, which requires that PJM recover ACE to at least ‑630 MW within 15 minutes. PJM called for an additional 500 MW of shared reserves from the Northeast Power Coordinating Council, having received 1 GW shortly before the start of the DCS, and was able to recover the ACE after 15 minutes and 52 seconds.

At the height of the emergency, the report said that if PJM lost emergency imports or another large generator tripped, a voltage-reduction action may have been necessary.

“If another large unit was lost or imports from NYISO into PJM were cut, PJM would have considered initiating a voltage-reduction action, which would have resulted in approximately 1,700 MW of relief. … If necessary, this action would have been followed by a manual load dump warning to communicate load dump allocations to transmission owners,” the report said.

Several complaints to FERC related to non-performance penalties accrued during the storm argue that PJM violated its tariff by continuing to export while implementing emergency procedures. The Elliott report laid out a series of instances in which PJM curtailed non-firm exports as conditions in the RTO worsened, but it stated that cutting all aid to its neighbors wouldn’t have prevented PJM from entering emergency conditions and would have likely worsened emergencies in surrounding regions that were in load shed. (See FERC Sends Elliott Complaints Against PJM to Settlement Judge.)

“Even if the operators had cut all non-firm exports, there would have been a deficit of at least 1,789 MW needed to satisfy PJM load and firm exports. Pre-emergency and emergency actions thus would have been necessary to satisfy capacity needs even if all non-firm exports had been cut,” the report said.