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August 4, 2024

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Dems Introduce Bill on Transmission Planning, RTO Transparency

Congressional Democrats have reintroduced legislation that would require FERC to establish interregional and interconnection-wide transmission planning processes and increase RTO transparency requirements.

Sen. Edward Markey (D-Mass.) introduced the bill to the Senate, saying the Connecting Hard-to-reach Areas with Renewably Generated Energy (CHARGE) Act would aid the development of transmission needed to bring clean energy onto the grid. Reps. Alexandria Ocasio-Cortez (D-N.Y.) and Greg Casar (D-Texas) introduced the bill in the House.

“While there has been rapid growth of renewable energy resources and skyrocketing public demand for clean energy, there is not nearly enough capacity in our power lines to bridge the gap between clean power and the cities and towns that need it. The CHARGE Act changes that,” Markey said in a statement announcing the legislation.

Interregional Transmission Planning

The legislation would require FERC to engage in interregional and interconnection-wide transmission planning at least every four years and consider the benefits of a potential project, including reduced energy and ancillary service costs, access to generation in neighboring regions, delivery of renewable energy, and improvements to grid flexibility and reliability. FERC also would be required to consider the potential of grid-enhancing technologies (GETs), such as dynamic line rating and storage-as-transmission.

Developers of interregional projects could submit costs to FERC for recovery, with cost allocation based on the project’s benefits. The bill would seek to avoid cost allocation mechanisms that might discourage energy efficiency, demand response, storage and distributed resources.

The bill also would change the cost allocation for new interconnections to prohibit utilities from requiring generation developers to bear the full — or a disproportionate — cost for network upgrades needed to connect their projects to the grid. Instead, FERC would encourage the creation of cost-sharing models that allocate costs based on the “broad set of benefits and beneficiaries for any network upgrades.”

The legislation would require RTOs to establish independent transmission monitors to oversee planning and operations and look for inefficiencies and practices that may contribute to unreasonable rates for consumers. The monitors also would review project costs, identify where non-wire or interregional project alternatives may be most cost-effective and provide guidance to transmission owners on operations, planning and cost allocation.

FERC would be required to create an Office of Transmission to review projects submitted by utilities in accordance with regional and interregional transmission planning processes. The office also would investigate ways to alleviate interconnection queue backlogs and explore opportunities to improve transmission planning and use GETs.

Ocasio-Cortez and Casar highlighted the importance of new transmission for developing renewable energy and addressing climate change.

“Our patchwork transmission system is blocking billions of dollars in new renewable deployment,” Ocasio-Cortez said. “This same transmission system is also increasingly vulnerable to widespread power outages in nearly every part of the country. The CHARGE Act is the key to updating this transmission network so we can plan for and meet the growing demand for grid resilience and renewable energy across the U.S.”

“As the climate crisis worsens, we must do everything we can to increase grid reliability across the country. That’s why we must pass the CHARGE Act,” Casar said. “Every single family should be able to rely on their utilities.”

Increased RTO Transparency Requirements

The bill would introduce several transparency requirements for RTOs and the commission, including stakeholder meetings being recorded and transcribed, records of votes being public and RTOs being subject to the Freedom of Information Act.

A 30-member advisory committee would be established by FERC to provide recommendations on the governance and oversight of RTOs and their stakeholder processes, with the goals of promoting competition, reliability and affordability in transmission planning. The committee also would consider improvements that could be made to transparency and decision-making in non-RTO regions.

Consumer organizations would be granted full voting and participation rights in stakeholder meetings, and RTOs would be required to provide intervenor compensation for public interest participation in RTO processes.

A handful of the transparency provisions mirror state initiatives relating to RTO governance. A bill introduced in the Maryland House of Delegates this year would have required utilities participating in stakeholder meetings to report their votes to the state each year. (See Maryland Bill Would Require Utilities to Report Votes at PJM.)

Additionally, the West Virginia Public Service Commission in March filed a complaint with FERC seeking access to PJM’s Member Liaison Committee, which is open only to voting members. (See W. Va. PSC Files Complaint over PJM Meeting Policy.)

Under the Markey bill, FERC and utilities would be required to coordinate with EPA and the Energy Information Administration to create a public database with hourly operating data for generators including fuel type, marginal greenhouse gas emissions per megawatt-hour and other attributes updated as close to real time as possible.

The legislation would direct the National Academies of Sciences, Engineering and Medicine to work with EPA, DOE and FERC to draft a public report identifying the effects on consumers of procuring energy competitively outside of utilities in markets administered by RTOs or other independent organizations compared with noncompetitive models. The study would account for factors such as cost savings, improved grid reliability and GHG emissions.

Public Interest and Climate Organizations Endorse Bill

Several climate and consumer advocacy groups endorsed the bill, including the American Council on Renewable Energy (ACORE), Americans for a Clean Energy Grid (ACEG), the Natural Resources Defense Council and Public Citizen.

“Our clean energy transition depends on building new high-capacity transmission lines. We need legislation that will accelerate this development, unlocking new domestic energy resources and making sure the lights stay on during severe weather episodes like the intense heat waves we’ve experienced across America this summer,” said ACEG Executive Director Christina Hayes.

Tyson Slocum, director of Public Citizen’s Energy Program, said the bill’s transparency and transmission monitor requirements would ensure that transmission development proceeds with consumer protections built in.

“Among many other accomplishments, the legislation would impose needed transparency standards, public accountability and governance reform for America’s private RTO grid operators, including subjecting them to the federal Freedom of Information Act; empower the public and energy justice communities with access to resources to participate in FERC and RTO proceedings by requiring FERC’s Office of Public Participation to provide intervenor funding, and; ensure the electric transmission buildout maximizes consumer protections through a new independent transmission monitor,” he said in a statement.

ACORE President Gregory Wetstone said the bill would establish critical provisions around interregional planning and would promote reliability by establishing minimum transfer requirements between transmission planning regions during severe weather.

“This legislation lays the groundwork for the construction of critical interstate transmission lines. The bill also reforms participant funding, a crucial step to help bring more clean energy resources onto the grid, and establishes a sorely needed mandate for a minimum transfer capacity between grid planning regions that will bolster reliability and better enable our electric power system to withstand increasingly frequent extreme weather events,” he said.

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CAISO Board OKs Plan to Admit Subscriber-funded Transmission Lines

CAISO’s Board of Governors on Thursday approved a proposal that will allow transmission projects outside California to join the ISO under a new subscriber-funded model that avoids allocating costs to ISO load-serving entities.

Board members praised the “subscriber participating transmission operator” (PTO) proposal, which is intended to help California tap clean energy resources in other parts of the West to meet its ambitious greenhouse gas reduction goals while reducing financial risks associated with new transmission. Modeling from the California Public Utilities Commission (CPUC) shows the state will need to acquire more than 4,800 MW of new out-of-state wind resources to hit its midcentury targets.

“I’ve been here five years. Other than adopting the day-ahead market, I’m trying to think of something as big, and I can’t, so thank you for this elegant solution,” board Chair Mary Leslie told the CAISO executives who presented the plan during Thursday’s monthly board meeting.

“This continues ISO leadership,” Governor Angelina Galiteva said. “We were leaders with policy-driven transmission, and now this as well, so I hope we’re successful. I’m actually confident that we will be.”

Under the proposal, the developer of a transmission project not selected in CAISO’s transmission planning process will have the ability to solicit generator customers to subscribe to service on a line designed to deliver energy into California. The project could then turn operational authority for the line over to the ISO, joining the balancing authority area as a “subscriber PTO” not eligible to recover their costs under the ISO’s transmission access charge (TAC).

The proposal calls for subscribers to have priority use of the line and be exempt from CAISO transmission and congestion costs, including the TAC. Non-subscribers would be required to pay to use the line at a FERC-approved rate that does not exceed the TAC.

The plan also would require subscribing generators to pay the ISO’s existing PTOs to cover upfront costs for any system upgrades needed to facilitate the new lines’ interconnection into California, but they would be reimbursed for those costs over the following five years. Any future network upgrades associated with future generation interconnection or transmission planning requirements would “be recovered by the subscriber PTO through a cost-of-service rate approved by FERC,” the ISO said.

According to Deb Le Vine, CAISO’s director of infrastructure contracts and management, the ISO will study integration of proposed subscriber lines through its transmission interconnection process. She told the board that the grid operator will “set a higher bar” for including subscriber PTO lines in its 20-year transmission base case than it does for lines chosen through the planning process.

“We don’t want to put it into our base case prematurely, assuming that the line is there, and start making solutions based on the line being there,” Le Vine said.

To be included in the base case, she said, a subscriber PTO must execute a transmission applicant agreement with the ISO; have its subscribing generators complete interconnection agreements; and provide the grid operator with a notice to proceed.

Subscribing generators that go through the transmission planning process would be exempt from the ISO’s separate — and currently lengthy — generator interconnection process.

“Obviously, this is a brand-new service,” Le Vine said. “We’re trying to meet the needs of California, [and] we’re trying to come up with solutions that allow load-serving entities to better determine the best-fit portfolios. And we’re trying to use the existing functionality that the ISO already has in its toolkit, and therefore have minimal changes needed to our systems.”

Le Vine said that in allowing for interconnections to other parts of the West, the model will help improve the performance of the proposed extended day-ahead market in CAISO’s Western Energy Imbalance Market, support resource adequacy and “enhance resilience on the grid.”

‘The Best Wind’

The subscriber PTO model already has one participant waiting in the wings: the proposed TransWest Express transmission project, a 700-mile line designed to carry 3,000 MW of wind energy from Wyoming to Nevada, where it will connect to the CAISO grid.

In March, FERC approved an agreement that would allow TransWest to continue its efforts to become a CAISO PTO under the model, pending the commission’s approval of the ISO’s proposal. Among other things, the agreement allowed TransWest’s subscriber, the Power Company of Wyoming — owner of a 3,000-MW wind farm being constructed in south-central Wyoming — to be studied under the ISO’s generator interconnection queue cluster 15, starting April 1. (See FERC OKs CAISO-TransWest Move Toward PTO Status.)

Speaking during the board meeting Thursday, David Fuller, TransWest director of business development, said, “Not only will the [subscriber] PTO model access new resources, it will access the best wind resources in the continental United States — from Wyoming. … This model allows the LSEs and the ratepayers in California to leverage private investment to bring this resource to California, and probably do it sooner and cheaper than other ways and all without increasing the TAC.”

Neil Millar, CAISO vice president of transmission planning and infrastructure development, also pointed to how the model reduces risk for California by making developers such as TransWest responsible for attracting subscribers and ensuring the financial viability of their projects.

“Without that, the project wouldn’t move forward, and the ISO is basically kept whole because we’re not supporting the cost of the TransWest Express project itself,” Millar said.

CAISO CEO Elliot Mainzer emphasized how the model will assist in the “huge lift” facing California, which will need to bring on about 7,000 MW of new clean resources every year for the next two decades to meet its midcentury GHG targets. He said the procurement orders stemming from the state’s integrated resource plan show the need to acquire “a significant fraction” of the state’s needed resources and transmission from out of state “in terms of reaching total supply and for the diversification benefits in terms of reliability and affordability.”

“The subscriber participating transmission owner model is our effort to work with developers out of state to create additional optionality for the utilities inside California,” Mainzer said.

CAISO expects to file the subscriber PTO proposal with FERC in September and anticipates a decision in November.

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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.