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August 4, 2024

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JTIQ Portfolio Cost Estimate Nearly Doubles to $1.9B

MADISON, Wis. — The cost estimate for MISO’s and SPP’s package of 345-kV lines meant to facilitate the interconnection of generation at the seams has nearly doubled, the RTOs have said in the past week.

The portfolio’s costs have climbed from $1.1 billion to $1.9 billion because of the mounting cost of materials and labor and the transmission owners providing more precise routing options.

Aubrey Johnson, MISO’s vice president of system planning, updated the joint targeted interconnection queue’s (JTIQ) cost estimate during the grid operator’s Board Week in Madison, Wis., last week.

The increased amount was included in an application led by the Minnesota Department of Commerce and The Great Plains Institute for Department of Energy funds from the agency’s Grid Resilience and Innovation Partnerships program. If successful, the JTIQ portfolio could receive up to 50% funding match from the federal government. (See DOE Clears JTIQ Projects to Proceed with Funding App.)

MISO said the first cost estimate was theoretical and two years old.

“The 2023 JTIQ application to DOE reflects a higher end, broader scope, cost estimate for matching federal funds, and it is not directly comparable to the 2021 planning-level cost estimates,” MISO spokesperson Brandon Morris said in an emailed statement to RTO Insider. “Since 2021, we have also seen inflationary pressures and supply chain uncertainty.”

“Developers are having heartburn about the cost increases and would like to have some understanding and parameters around the increases,” Clean Grid Alliance’s Beth Soholt said during an Advisory Committee meeting Wednesday.

She urged MISO and its transmission owners to institute “checks and balances,” given the JTIQ’s proposed cost allocation that has generation developers responsible for 90% of costs and load picking up the remaining 10%.

MISO said it will further update stakeholders on the JTIQ’s application for DOE funding at a June 27 combined Planning Advisory Committee and Regional Expansion Criteria Benefits Working Group meeting.

During an SPP Seams Advisory Group meeting June 9, the RTO’s Aaron Shipley said staff is reviewing the cost increases and developing a more detailed breakdown of the rising prices.

“Whereas originally we were working on a conceptual cost estimate basis, as we get closer to it, we find those cost estimates from the TOs themselves,” he said. “Some of that [is] inflation impacts … but also more accurate routing of assessments, materials’ costs, the construction timeline [and] supply chain concerns. Those type of items really drove some of that cost [increase].”

Shipley said had the applicants’ DOE application used the $1 billion estimate, they would have been limited to up to half that amount should the agency award any funds.

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Historic Solar Growth Seen in Southeast

The Southeast’s solar capacity will more than double by 2026, according to the Southern Alliance for Clean Energy’s (SACE) sixth report on solar energy development.

The report released Wednesday forecasts growth to 40 GW of capacity by 2026, more than double the 18.8 GW claimed last year. Available watts/customer (W/C) are expected to increase as well, from 580 last year to 1,217 in 2026. SACE Executive Director Steve Smith described this rise as a “generational transition” in more than one sense.

“You have to be part of the clean energy generation, both in a generational sense where each and every one of us are part of the generation to actually seize this moment and create change,” Smith said. “But then also we’ve got to get more literally physical clean energy generation on the ground.”

This growth, the report says, is due largely to two federal moves: The implementation of the Inflation Reduction Act (IRA); and a two-year moratorium on import duties from Vietnam, Cambodia, Thailand and Malaysia that “helped the U.S. solar industry regain its footing after an extended supply chain disruption.”

Southeast Solar Capacity Forecast by State

Southeast Solar Forecast by State | Southern Alliance for Clean Energy

Within the IRA, production and investment tax credits were returned to their full valuation of 30% and extended out to 2032, which “provided certainty into the market that the market really needs,” said Bryan Jacob, SACE’s solar program director.

The IRA also contains a $9.7 billion grant for rural electric co-ops, which Jacob said may be “the most transformational program for rural America since the Rural Electrification Act itself, back in 1936.”

The steep increase in available solar capacity in the next four years will not be evenly borne by the states in the Southeast, the report showed. Driven by policies such as solar base rate adjustment, said Jacob, Florida will increase its capacity to more than 17 GW by 2026, “almost as much as the entire Southeast region had last year.”

North Carolina, Georgia and South Carolina are also projected to increase their capacity dramatically, with Georgia slated to overtake North Carolina in both total capacity and watts/customer by 2026. Alabama, Tennessee and Mississippi “continue to fall far short of other Southeast states in both installed capacity MW as well as watts per customer (W/C) solar ratio,” the report said.

When asked to elaborate on the latter projection, Smith said he has not seen these states’ utilities “look at solar as a workhorse resource yet,” adding that many utilities are “inappropriately planning for what the future is unfolding to be,” and “making the wrong bets” on fossil fuels.

Sunblockers and Sunrisers

SACE’s report highlights several of these lagging utilities as “Sunblockers” — utilities with more than 500,000 customers with a four-year projected W/C ratio less than the Southeast’s average for last year (580).

Alabama Power and the North Carolina Electric Cooperative remain on this list from last year, at 331 and 197 W/C respectively, with PowerSouth joining them at 169 W/C. While Tennessee Valley Authority and Seminole Electric “remain considerably below the region averages,” at 658 and 600 W/C, the report said, they are not quite Sunblockers technically.

The opposite category also exists: “Sunrisers,” or the seven utilities with the largest projected increase in W/C solar ratio. Walton EMC, projected to increase its ratio by more than 4,000 W/C, retained its large lead. The second-largest increase was 1,564 W/C by the Knoxville Utilities Board. New to the Sunrisers list is Santee Cooper, due both to the utility’s own plan and commissioned solar development. The Sunrisers list is not constrained by customer base size as is the Sunblockers list.

However, these projections are not set in stone, Jacob said, as “the most important contributor to the forecast is integ resource plans (IRPs) that we have access to.” Because of the IRA’s recency, some utilities “haven’t had a resource planning process since August of last year, when the Inflation Reduction Act was signed.”

Georgia Power, for example, will not have a new resource planning process until 2025, while Duke will file its first IRPs aligned with its new Carbon Plan on Aug. 1 and Sept. 1 for South Carolina and North Carolina.

So, while some growth is reflected in the forecast, Jacob said, “We’re gonna see a lot more for kind of the back half of the decade. That being said, the current forecast out to 2026 is already super bullish.”

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MISO Modeling Line Options for 2nd LRTP Portfolio

MADISON, Wis. — MISO says it’s on track this year to map the new transmission lines required for its second long-range transmission plan (LRTP) portfolio.

“We’re facing unprecedented circumstances, new conditions coming at us faster,” Aubrey Johnson, vice president of system planning, said Tuesday during the Board of Directors’ System Planning Committee meeting.

Johnson said resource churn is driving MISO’s need to pull together a second Midwestern LRTP portfolio. He said staff are planning to regularly update 20-year transmission planning futures after a refresh this year revealed dramatic changes since the previous update in 2020 (See MISO: Long-range Tx Needed for 369 GW in Interconnections.)

“The system we’re operating, and the plans our members have are dynamic, and they’re changing day by day,” Johnson said.

The grid operator has finalized the second of the portfolio’s three futures, a mostly decarbonized scenario that anticipates a 2042 energy mix comprised of 51% wind, 22% solar, 8% battery, 8% other resources and 7% nuclear. It also includes a 2% hybrid with renewables paired with storage and a 1% contribution each from coal and natural gas.

MISO hopes that the last 0.3% of the energy mix will come from 29 GW of “flex” resources, yet undefined resources that are expected to be a dependable, on-call source of firm capacity.

The second future projects MISO will operate with 466 GW of nameplate capacity. That is broken down into 160 GW of wind generation, 112 GW of solar, 65 GW of natural gas, 41 GW of other generation, 31 GW of battery storage, 29 GW of “flex” resources, 12 GW of nuclear, 10 GW of storage and 6 GW of coal.

Johnson said though the RTO still expects to operate several gigawatts of gas and coal facilities, their energy contributions will be on a strictly as-needed basis.

“We need to have these resources, but they’re going to be used very infrequently. But when they’re needed, they’re needed,” Johnson stressed.

MISO foresees risks during calm, hot summer days when the wind doesn’t pick up after sunset and during winter daytime load peaks, where there’s a risk of unserved energy before sunrise and after sunset. Johnson referred to those risky periods as the grid operator’s “twilight problem.”

He said staff are anticipating escalating thermal generation retirement requests and are preparing to study them. MISO plans to complete the second LRTP portfolio’s modeling by early fall.  That modeling will inform which projects MISO ultimately recommends.

“We’re getting ready for the sprint, if you will,” Johnson said.

Johnson said it’s getting more challenging to feasibly model a future system that can reliably serve load with the resource mixes on the horizon.

“In reality, we’re probably behind in the way we’ve done some of our economic analysis,” he told board members.

Senior Director of Transmission Planning Laura Rauch said MISO’s resource expansion tool currently used for transmission planning was intended to account for large baseload power sources, not siting a host of scattered wind and solar facilities.

Johnson said the RTO’s forthcoming proposal to tighten rules around when developers can enter and exit the interconnection queue should make clear to planners the future mix they’re planning for. (See MISO Wants Tougher Obligations on Queue Entry and Exit.)

He said MISO is hoping to encourage generation plans that are “targeted toward completion rather than targeting holding a place in the queue.”

The grid operator’s current generator interconnection queue contains 1,379 active projects totaling a little more than 237 GW. Almost all of that is renewable energy or battery storage.

“Future generations are depending on this to get this done and get it done right,” director Mark Johnson said of the expansion planning.

Ciaran Gallagher, with nonprofit Clean Wisconsin, said MISO is neglecting storage resources in its annual transmission and LRTP planning. She said there’s “insufficient” representation of battery storage in modeling and the RTO’s assumptions don’t represent the projects in the queue.

Gallagher said storage and hybrid resources can “bolster the grid with attributes” that MISO is losing through thermal generation retirements. She said more battery storage incorporation must be considered “to plan the optimal grid.”

ROFR Developments May Complicate LRTP Planning

Johnson also addressed right-of-first refusal (ROFR) legislation activity in the MISO footprint.

He said staff are monitoring developments in Illinois and Iowa. A bill in the former that would specifically give Ameren Illinois exclusive rights to build regional MISO lines has passed both houses and is awaiting the governor’s signature (HB 3445). Iowa’s ROFR law has been temporarily overturned, pending a final ruling from a district court. (See Iowa Regulators Ponder MISO Tx Projects After ROFR Ruling.)

Both developments could determine which utilities are allowed to construct some projects in the LRTP portfolios.

“There’s a lot of activity we’re following and working with our legal team to understand the implications,” Johnson told board members.

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California EV Grid Fixes Could Cost $35B Less than Estimated

Upgrading California’s distribution grid to serve millions of electric vehicles could cost far less than the $50 billion that a study published last month indicated, the California Public Utilities Commission’s Public Advocates Office said in a paper announcing its own study.

“The Public Advocates Office is finalizing a study of the costs of upgrading the distribution grids of the three largest investor-owned utilities to meet California’s transportation electrification goals,” the paper said. “Our preliminary results indicate that the total cost of upgrading the distribution grid by 2035 will be approximately $15 billion to $20 billion.”

California law requires that all new vehicles sold in-state be zero-emitting by 2035, but the potential effects on the grid are only now being weighed.

A separate study commissioned by the CPUC and published May 9 found that it could cost as much as $50 billion to upgrade the distribution grids of Pacific Gas and Electric, Southern California Edison, and San Diego Gas & Electric to accommodate high levels of EV charging. (See Study: Calif. Needs $50B in Distribution Work for EVs.)

Energy analytics firm Kevala conducted the study. It emphasized that the findings assumed existing time-of-use rates would remain in place throughout the study period, from 2025 to 2035.

“It did not consider alternatives or future potential mitigation strategies such as alternative time-variant rates or dynamic rates and flexible load management strategies,” the firm said.

Kevala’s study predicted that distribution systems’ peak load would increase by an average of 56% from 2025 to 2035, requiring the utilities to nearly double their current spending on feeder lines, transformer banks and substations.

The Public Advocates Office, also known as Cal Advocates, is an independent consumer watchdog that often disagrees with CPUC staff and commissioners. It said it used assumptions different from Kevala in preparing its preliminary findings.

“The difference between our preliminary cost estimate and Kevala’s higher cost estimate stems from Kevala’s forecast of a larger growth in peak load,” it said. “Our peak load forecast is drawn from, and aligned with, the California Energy Commission’s Integrated Energy Policy Report (IEPR).”

Kevala’s peak load estimate may have resulted from its assumption that many EVs will be charged at 9 p.m., when time-of-use rates fall on weekdays.

In contrast, “the IEPR, which Cal Advocates uses, forecasts that EV charging occurs much more evenly across the day,” the paper said. “As peak load is a key driver of the need to upgrade the distribution grid, Kevala’s higher peak load growth forecast drives Kevala’s higher costs.”

The paper also says that that Kevala forecast the “total energy consumed in charging EVs will be 40% higher on the peak day than in the IEPR or in Cal Advocates’ study. Higher charging energy contributes to the difference in the peak loads and results in higher cost estimates.”

The advocates office said it intends to refine its analysis, engage with stakeholders and complete its study by August.

A second part of Kevala’s Electrification Impacts Study will build on the first part’s findings, including by developing scenarios that reflect state policy goals, state agency targets and the Energy Commission’s demand forecast. The advocates’ finding will be available to Kevala as it performs the second part, the office said.

Cal Advocates said additional studies would be useful for state planners.

“No single study or pair of studies, particularly this early in the electrification process, can definitively answer such a complex question as what the costs of distribution grid upgrades will be,” the office said. “Cal Advocates’ study aids the continuous discourse on electrification costs and benefits rather than establishing a final cost projection.”

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Future of Grid Planning Debated at Infocast Transmission Summit

ARLINGTON, Va. — The electric industry must improve its long-term planning to account for a changing generation mix and new load patterns, experts at Infocast’s Transmission & Interconnection Summit said Tuesday.

While MISO’s long-range transmission planning and California ISO’s 20-year transmission outlook both stand out as exceptions, the industry generally does not think far ahead when it comes to grid planning, Grid Strategies President Rob Gramlich said at the summit. (See MISO Board Approves $10B in Long-range Tx Projects.)

But FERC’s Notice of Proposed Rulemaking requiring the industry to adopt long-range, scenario-based planning has started to change that. (See FERC Issues 1st Proposal out of Transmission Proceeding.)

“I think the push has been helpful in the establishment of a sort of a vision that you should be proactively looking at the anticipated future resource mix and … the load forecast. And both of those things are, of course, uncertain, but the industry has had to deal with that for its entire history,” Gramlich said.

The uncertainty can be addressed by using scenarios to determine the best transmission options to link future supply and demand. While that would be the ideal, most of the country is not doing that even at the regional level, Gramlich said.

“What happens then is all the pressure for the limited capacity goes into the interconnection process,” Gramlich said. “And it’s a self-reinforcing downward spiral of studies and re-studies and queue churn — and all of those things that can be greatly alleviated if we had the infrastructure.”

In SPP’s 2021 interconnection process, most interconnecting resources were saddled with more than $1 million in transmission upgrade costs — often for lines rated at 345 kV and above, said ICF Vice President Himali Parmar.

“That clearly tells you that the system — the planning process — is broken somewhere in SPP,” she added.

Stuart Nachmias, CEO of Con Edison Transmission, agreed that the transmission planning process needs to start looking ahead to a grid dominated by renewables and responsible for the electrification of both transportation, which has already started, and heating, which he said is not far behind.

“There is much more robust planning process that we need. We need to identify the transmission … and distribution that needs to be expanded to meet the future needs,” Nachmias said. “Because the one thing I know for sure is that the day reliability is not what customers expect is the day that everything comes to a standstill. And none of us want that to happen.”

The industry has a spotty record when it comes to planning lines required to meet public policy mandates, but FERC could be doing more under existing rules to make that more common, said Sharon Segner, senior vice president of transmission policy at LS Power.

“There’s whole sections of the PJM operating agreement that are not being enforced right now relating to public policy planning and requirements,” Segner said. “And there’s more than this FERC could be doing under existing law.”

PJM’s Order 1000 compliance rules call for the RTO to perform an annual sensitivity analysis on public policy transmission requirements, which are not being used, she added.

Transmission planning processes were all designed around slow and deliberate change to the power system, but bigger changes are coming now, said Kris Zadlo, chief commercial and technology officer at Grid United.

The “institutional framework” was “set up for something that was relatively static,” Zadlo said. “And now we don’t have a very static system, the system is changing in front of our eyes, and the whole planning process must adapt accordingly.”

An increase in computing power has made planning much quicker. Where it once took hours for a mainframe to process one power flow, modern machines can now go through thousands of scenarios across an interconnection in just hours, Zadlo said. That extra analysis has led to paralysis: Instead of focusing on so many options, transmission planners should pick the best plan and move forward with it, he added.

At the request of New England states, ISO-NE started to plan further into the future with its 2050 study, in which the states helped identify what resources would be developed and how load would grow in response to their policies, said Maine PUC Chair Philip Bartlett II. (See ISO-NE Planners Outline Potential Solutions for 2050 Tx Overloads.)

Bartlett said state officials hope the change will ensure the region can “right-size” investments in larger projects that improve efficiencies. “Because the only way we’re going to get through this transition cost-effectively is if we think thoughtfully, we don’t miss opportunities for lower-cost upgrades, and we avoid some of the expensive costs down the road by making smarter decisions through our planning today.”

While New England has spent plenty on transmission in recent years, the spending has been directed at curing reliability issues, and not nearly enough has gone to help states meet long-term policy goals, he added.

PJM is also spending on transmission now, but its process often favors local projects that lack outside scrutiny, said Greg Poulos, executive director of the Consumer Advocates of the PJM States.

“We pay a lot of money for local transmission, and the local transmission process doesn’t typically allow for any oversight,” Poulos said.

Coordinating policies can be challenging in both RTOs. PJM states have a wide range of policy goals, while in ISO-NE, one state has no climate goals, while many others call for net-zero emissions by midcentury.

But transmission provides other benefits for all states, from improving reliability and resiliency to reducing emissions covered by existing federal laws, Bartlett said. The key to getting needed transmission built regardless of state policy differences is to define those benefits and allocate associated costs in a way that achieves agreement, he said.

By using separate planning processes to meet different goals, RTOs dilute the value of the kind of multipurpose transmission lines that are often praised as most effective, said Matthew Crosby, senior director of policy and strategy at Cypress Creek Renewables.

“There’s a clear need to look at the sequencing of these tests,” Crosby said. “And right now, without someone that’s independent of the transmission owner, or the regional transmission operators, enforcing that and guiding that process — I’m not sure how we disrupt the status quo.”

That role could be filled by an “independent transmission monitor,” an idea FERC floated in its advanced NOPR on transmission but that did not make the cut in its planning NOPR. Reliability often takes precedence because the issues need to be fixed quickly and a multivalue planning process takes longer, but Crosby suggested some of those issues could be dealt with using grid-enhancing technologies while giving planners enough time to come up with more efficient, long-term transmission fixes.

State Perspectives

In states participating in organized markets, grid planning is typically led by the RTO, but that seems to be changing, as FERC and ISO-NE have started to recognize that states should lead when it comes to planning lines for policies, said Vermont Public Utility Commissioner Riley Allen. States in his region are represented by the New England States Committee on Electricity (NESCOE), which gives them a cohesive voice on RTO issues.

NESCOE should be able to come up with a plan to build out the grid regionally to meet its members’ policies, both through the ISO-NE’s 2050 outlook and nearer-term planning, Allen said.

“Something that is relatively robust and amounts to a more postage stamp-type framework is probably preferable over time to kind of a state-by-state approach and addressing some of the challenges associated with that,” Allen said.

Allen sits on the Joint Federal-State Task Force on Electric Transmission with North Carolina Utilities Commissioner Kimberly Duffley, who said the Order 1000 process is working in the Southeast without resulting in capital flight to local projects with less oversight, which she attributed to her agency’s robust IRP process. (See Federal and State Regulators Look into How to Improve Grid Security.)

“If you do this type of top-down approach of transmission planning in non-RTO regions, you really are infringing upon the state’s resource planning that they’re doing where the state is looking at transmission, as well as generation, for solutions to meet the goals in a least-cost manner,” Duffley said.

Her state also has a robust transmission siting process, issuing certificates of public convenience and necessity in a process where the commission’s “public staff,” which represents state residents, can intervene to oppose unneeded projects. Another major difference is that North Carolina utilities can recover 70% of their transmission costs in retail rates, so FERC does not even control most of the funding.

Colorado is considering joining an RTO, but in 2021 it created the Colorado Electric Transmission Authority (CETA) to facilitate development of new transmission, said the agency’s Kathleen Staks.

CETA was established by the same bill directing the state’s utilities to join an RTO by 2030, so it was conceived to consider the broader regional perspective of better connecting the state with the rest of the West, Staks said.

Colorado modeled CETA on New Mexico’s Renewable Energy Transmission Authority, which helped clear the way for approval of Pattern Energy’s Sunzia line, which was designed to bring New Mexican wind output to markets further west, Staks said. (See Sunzia Project Wins Final Approval, Signs Offtakers.)

DOE Sees State Collaboration as Key

While the U.S. Department of Energy has limited authority to designate National Interest Electric Transmission Corridors, it will be increasingly important for it to collaborate with states as it studies the issue of transmission buildout, according to Jeff Dennis, deputy director for transmission at the agency’s Grid Deployment Office.

The nascent offshore wind industry could benefit from such a collaboration. The sector is currently driven by state contracts and dominated by an inefficient radial approach to transmission, where each project runs its own connection to the onshore grid. But that approach won’t scale as more projects get built, Dennis said.

DOE has been working on recommendations to help expand the industry, including getting Atlantic states to collaborate on a networked transmission system and share the costs.

“The obvious example is landing points, right?” Dennis said. “If we continue this radial approach, we’re going to impact lots of communities. We’re going to impact lots of offshore industries outside of energy, like fisheries.”

Offshore wind’s most obvious impacts are along the coast, but the resource will require an expansion of the onshore grid that will impact even inland states such as Vermont, he added.

“We’re not the regulator, of course, so that gives us some opportunities, I think, to provide support to collaboration [and] to try and provide good information that will help the states in those collaborations make decisions collectively,” Dennis said.

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FERC Approves More Extreme Weather Rules

FERC on Thursday approved two new rules intended to strengthen the grid against extreme weather events.

The commission ordered NERC to either update reliability standard TPL-001-5.1 (transmission system planning performance requirements) or create a new rule that would require responsible entities to plan specifically for both extreme heat and cold weather events (RM22-10). Either way, entities will be required to create a corrective action plan to mitigate any occasions where performance requirements for extreme weather have not been met.

FERC also directed transmission providers to submit a one-time report detailing their policies and processes for conducting extreme weather vulnerability assessments and mitigating identified risks (RM22-16, AD21-13).

Based on the staff’s presentation at FERC’s monthly open meeting in Washington, D.C., the commission made only minor alterations from when the rules were first proposed about a year ago. (See FERC Approves Extreme Weather Assessment NOPRs.)

Both rules will take effect 90 days after their publication in the Federal Register, and transmission providers will be required to submit their reports within 120 days of publication. FERC had originally proposed that the reports be due in 90 days. The commission also approved extending the public comment period on the reports to 60 days, from the 30 originally proposed. In doing so, FERC agreed with the Edison Electric Institute and other commenters that the time periods were too short. (See ERO Supports FERC Weather Assessment Proposal.)

According to Alyssa Meyer, an energy industry analyst in FERC’s Office of Energy Policy and Innovation, the final rule also requires transmission providers to include in their reports how they define extreme weather and how RTOs and ISOs account for differences between transmission owner members’ assumptions and results.

“For the first time, reliability standards will require planning for extreme heat and cold weather,” acting FERC Chair Willie Phillips said in a statement. “NERC will develop the standards, and once we approve them, transmission owners and operators will identify the elements of their systems that are vulnerable to extreme heat and cold and develop solutions to address those vulnerabilities.”

Elliott: Different Storm, Same Outages

Before the commission approved the orders, FERC staff presented some preliminary findings of the commission’s joint inquiry with NERC into the December 2022 winter storm, also known as Winter Storm Elliott.

Unplanned generator outages exceeded 70 GW of capacity. The three main causes of the outages, staff said, were mechanical problems, equipment freezing and lack of fuel availability. Natural gas production, processing and shipping was hindered by compressor facility and well outages.

The observations are familiar: They are essentially the same as those in a 2021 technical conference held in the aftermath of a February winter storm (Uri) that nearly led to the collapse of the Texas Interconnection. Thursday’s orders stemmed from that conference.

“We’re seeing the same three causes, so therefore we think that it makes all the sense in the world to continue full steam ahead on implementing prior recommendations” from Uri and other previous severe winter storms, said Heather Polzin, an attorney adviser in FERC’s Office of Enforcement. Those include weatherizing equipment, inspecting facilities before winter and reviewing emergency operations plans.

Phillips said after the presentation, “Let me be clear: I want to join [staff] in encouraging, urging, cajoling all the utilities — every covered entity — to not wait. Implement these recommendations now. Right now. We know, to borrow a phrase, ‘Winter is coming.’”

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NERC, Trade Groups Oppose Call for Quick Fix on CIP Standards

NERC and several electric industry trade groups asked FERC this week to reject a petition to change how assets are classified under the Critical Infrastructure Protection (CIP) standard, saying it duplicates an ongoing initiative (EL23-69).

The Secure-the-Grid Coalition last month asked FERC to order NERC to propose an “enhanced standard” for identifying critical infrastructure using the “most recently updated engineering models used in operations.” The group, which describes itself as “policy, energy and national security experts, legislators and industry insiders who are dedicated to strengthening the resilience” of the grid, said NERC should be required to submit the proposed standard within 90 days.

In its response, NERC noted that it already plans to review reliability standard CIP-014-3 (physical security) in a joint technical conference with FERC on Aug. 10 (RD23-2) and through a separate reliability standards development project. CIP-014 requires transmission owners to identify which of their transmission stations and substations are critical to bulk power system reliability and implement a physical security plan for protecting them. The standard requires similar protection for primary control centers controlling critical assets.

“The petition does not allege any significant new circumstances, nor does it raise factual issues that are not ripe for consideration through the current NERC initiatives addressing the physical security of the BPS. Since appropriate forums for considering the petitioner’s ideas have already been or are in the process of being established, development of a new rulemaking to address similar physical security issues is not necessary at this time,” NERC said.

In a separate filing, the American Public Power Association, Edison Electric Institute, Large Public Power Council, National Rural Electric Cooperative Association and Transmission Access Policy Study Group protested the petition, calling it duplicative, unsupported and procedurally deficient.

The groups said the Secure-the-Grid Coalition failed to make its case that CIP-014 requirements for conducting threat assessments are deficient.

“The petition’s support for this request is the bare assertion that ‘[b]ased on the increasing frequency and sophistication of attacks against electric grid infrastructure, and the growing evidence that there is a persistent intent to conduct such attacks from domestic anarchist and extremist groups and foreign adversaries, a more prudent new metric is now required for these “Risk Assessments.”’”

Citing their comments in docket RD23-2-001, the trade groups said their members “are acutely aware of the physical threats posed to the grid, and of the importance of effective protective measures. Notwithstanding an uptick in physical security events in recent years, however, simply pointing to a number of recent events does not establish the need for the commission to direct changes to the threat assessment requirements of CIP-014.”

The trade associations also said FERC should reject Secure-the-Grid’s petition for failing to follow commission rules requiring petitioners to first ask NERC to initiate a new reliability standard. The groups also said the petition should have been filed as a complaint.

Responding to an increase in reports of physical attacks on substations, FERC in December ordered NERC to evaluate the effectiveness of CIP-014. NERC responded with a report in April concluding that the existing criteria are still appropriate to “focus limited industry resources” on the most critical grid facilities and that expanding the criteria would not identify additional critical substations. (See NERC Says Changes Coming to Physical Security Standards.)

However, NERC agreed to conduct a technical conference with FERC to identify the type of substation configurations that should be studied to determine whether any additional substations should be included in the applicability criteria and to establish data needs for conducting those studies.

NERC also said Requirement R1 of CIP-014 should be refined, acknowledging inconsistencies in how entities perform the risk assessment, with some failing to provide sufficient technical studies or justification for study decisions.

NERC’s report recommended a reliability standards development project to clarify the risk assessment methods for studying instability, uncontrolled separation and cascading.

NERC told FERC this week that the project “will be commencing in the near future.”

“Petitioner has not demonstrated a significant change in circumstances or that there is a sufficient problem to merit a generic solution that would necessitate a rulemaking prior to and without the benefit of the public stakeholder processes,” it said.

In a second FERC filing June 13, Secure-the-Grid said it was acting on behalf of the “American public … whose security interests are grossly underrepresented by NERC.”

The group rejected the position that “the costs are too high to invest in widespread and mandatory physical protection of the electric grid.”

“We think the costs are far too high NOT to invest in this protection, and we believe that the public will be willing to pay more for their electricity to see this protection realized,” it said.

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Panelists Debate PJM Capacity Market at FERC Forum

PJM officials and stakeholders told FERC Thursday they oppose abandoning the RTO’s capacity market but disagree over the degree to which it needs to be changed.

The four FERC commissioners heard from 20 RTO officials, state regulators and other stakeholders during a nearly five-hour “Capacity Market Forum,” which the commission scheduled in response to concerns over the RTO’s ability to maintain resource adequacy as dispatchable coal and gas-fired resources retire and are replaced by renewables (AD23-7).

Chair Willie Phillips at the FERC hearing on PJM Capacity Market

FERC Chair Willie Phillips | FERC

“NERC and PJM and others have warned us, early and often, that current forecasts could lead to a supply gap in certain regions over the next few years caused by early plant retirements and far slower development timelines to bring new resources online,” FERC Chair Willie Phillips said in opening the session.

Commissioner Mark Christie, a former Virginia regulator, questioned whether PJM should consider an alternative to the capacity market.

“The statement that the PJM capacity market is fundamentally sound — it just needs some tweaks — this is now the 19th consecutive year I’ve heard that,” he said. “… As we look out to the future … is the PJM capacity market something we can just keep sticking some bubble gum and some rubber bands [to] keep the thing going?”

Marji Philips, senior vice president of wholesale market policy for LS Power, said the market is “broken” because the introduction of intermittent generation means it no longer comprises “fungible” products.

Consultant James Wilson, who represents state consumer advocates, acknowledged PJM is facing a transition but said the market has “enormous excess capacity” and noted that other regions such as California have integrated far higher proportions of wind and solar power. “The house is not burning,” he said.

Independent Market Monitor Joe Bowring also defended the market but said it needs more than “tweaks,” calling Capacity Performance a “failed experiment.”

During Winter Storm Elliott in December, he said, new combined cycle generators performed worse than old combined cycle plants. “There’s no excuse for that,” he said.

Speakers at the FERC hearing on the PJM Capacity Market

FERC Commissioner Mark Christie (left) listens to Kent Chandler, chair of the Kentucky Public Service Commission | FERC

Kent Chandler, chair of the Kentucky Public Service Commission, said the capacity market is only part of PJM’s challenges.

“Even if you fix the capacity market, even if you fixed [resource] accreditation, you’re still going to have gas-electric coordination issues,” he said.

He cited Philips’ criticism that the Intercontinental Exchange is requiring generators to purchase gas four days in advance before the Independence Day holiday because July 4 falls on a Tuesday.

“You know, I’m happy that the gas market is apparently good to have a very enjoyable long weekend on Fourth of July,” he said. “But if we have system issues, that’s going to be a problem. … People are going to have to go find their old Rolodex and try to get ahold of people.”

Energy Landscape ‘Changing Dramatically’

Speaking during the first of three panels, PJM CEO Manu Asthana said the capacity market has historically achieved its goal of sending the price signals needed to incentivize generation where it’s needed, yielding a grid that’s remained reliable even as NERC reports that large portions of the country are at elevated risk this summer.

“Having said that, the energy landscape is changing, and it’s changing dramatically. Policy choices are resulting in accelerated retirement of the generation we use to manage our grid today, and frankly policy choices are chilling investment in new dispatchable generation,” Asthana said.

Asthana said the capacity market can continue to function alongside renewable incentives, so long as accreditation and risk modeling are done properly to ensure that existing resources are valued correctly.

Asthana was joined on the panel by NERC CEO Jim Robb, former FERC Commissioner Phil Moeller, now executive vice president of the Edison Electric Institute, and Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS).

Robb said NERC has found that reliability risk has been increasing across the country over the past five years, referencing a May report warning of an elevated potential for insufficient reserves in many regions. (See NERC Warns of Summer Reliability Risks Across North America.) Although PJM was not identified as being at risk, he said its identification of 40 to 50 GW of capacity that could be retiring by 2030 means it could soon be on the map.

The traditional one-outage-in-10-years reliability metric is becoming outdated and needs to be replaced with a focus on providing energy in every hour, he said. Grid operators also need to improve planning around how extreme weather is modeled, he said.

“We need to make sure investments that are needed to maintain reliability purposes are compensated for and reflected in the design of the markets. Markets have demonstrated an incredible ability to drive out inefficiency, but they really haven’t demonstrated their ability to reward the reliability investments that are going to become increasingly valuable as an insurance policy against extreme weather events and common condition challenges such as wind droughts and solar droughts,” he said.

In NERC’s post event analysis of the December 2022 winter storm, 2014 polar vortex and other major storms, Robb said natural gas availability has been an issue. He said the gas distribution system performs well at its historical role of keeping pilot lights lit, but it was designed in a time when it was a niche fuel for energy production.

“Right now natural gas is the single largest fuel for power generation, and power generation is the single largest customer of the natural gas industry. Every winter event we’ve analyzed has had the supply of natural gas to power generation and the ability of that system to perform to meet the needs of customers as a common theme. … At some point we’ve got to take this problem on, but it’s a bigger problem than any of us can solve individually,” he said.

Moeller said jurisdictional questions make addressing coordination between the electric and gas industries complex. But if the cause of winter deliverability issues is on the transportation side, rather than gas production, there may be solutions such as how force majeure is declared and transparency when outages occur, he said. He expressed hope that work the North American Energy Standards Board is engaged in will yield solutions the commission can act on.

Poulos cautioned against a focus on retaining existing generation, arguing that PJM should incentivize the entry of reliable resources, rather than picking and choosing resource types.

Commissioner Christie said the capacity market’s “constant state of churn” is undermining investment in new resources.

“The big problem PJM faces is because you’re a big multistate RTO and your problem is not economic … it’s political. PJM has 13 states and D.C., and the policies of those states have diverged tremendously since the first time [the Reliability Pricing Model] was approved,” he said. “Wouldn’t an SPP model be better for reconciling the different state policies and let them figure out what to build and what to buy, as opposed to trying to hold this thing together with all these states diverging?”

Asthana said PJM is set up to accommodate fixed resource requirements and bilateral contracts, while retaining the capacity market for load that’s open to retail choice and maintaining reliability across a large geographic area.

Bowring and Poulos agreed, saying that the capacity market has reduced prices for consumers while preserving reliability while other regions experience elevated risk.

Critical Issue Fast Path Process

On a second panel, representatives of power providers, environmental groups and state consumer advocates debated the solutions the RTO is considering through the critical issue fast path (CIFP) stakeholder process.

Adam Keech, PJM’s vice president of market design and economics, said the core of the RTO’s CIFP proposal includes improving risk modeling by moving away from the assumption that the peak load and reliability risk are aligned. PJM also seeks to improve accreditation to better reflect what capacity resources will be available when needed and to rework performance incentives to align them with the market seller offer cap. At the CIFP meeting on Wednesday, PJM also proposed a shift to a seasonal capacity market to account for the identification of higher risk in the winter.

Glen Thomas, president of the PJM Power Providers (P3) Group, said accreditation is important but needs to be accompanied by changes to allow generators to recover costs, reflect risks in their bids and limit the potential of demand side market power.

Todd Snitchler, CEO of the Electric Power Supply Association, said accreditation of all resources, thermal and intermittent, must be improved.

“If load is going to grow, you’re going to need more, not less [generation]. You’re going to need both and, not either-or. But certainly it suggests that you’re going to need certain performance characteristics that will enable your system to operate reliably,” he said.

Michelle Bloodworth, CEO of coal power industry group America’s Power, agreed, saying that generators likely to retire under pending state and federal policies will take valuable contributions to reliability with them.

“Whether that’s coal or another thermal resource, those attributes are being lost that PJM still needs,” she said.

The Sierra Club’s Casey Roberts said accreditation should account for fuel availability, saying that if gas-fired resources cannot procure fuel on short notice, they may not be as flexible as believed.

Susan Bruce, of the PJM Industrial Customer Coalition, said while many consumers support a seasonal market, there has to be a focus on the drivers of winter risk.

“I think there is interest in a seasonal auction from a customer perspective. However, getting that cost allocation piece right is complex and important, and just replicating what we have for summer to winter I don’t think is the solution, because the reason why we have winter risk is because we have performance issues,” she said.

Commissioner Allison Clements questioned what role the interconnection queue is playing in the pace of new resource development.

Abigail Ross Hopper, CEO of the Solar Energy Industries Association, said queue challenges remain significant. There will likely be a significant period of time when few new resources will be constructed because of the amount of time it takes to get approved for interconnection, she said.

LS Power’s Philips said PJM’s market rules do not reflect the realities of demand response and peaker plants, which tend to be rarely called upon and be price capped when they are dispatched.

“This market is not addressing the reality of who needs the money, and it’s not sending the price signals,” she said.

Chair Phillips questioned whether PJM is considering changes that can address some of the issues behind Winter Storm Elliott, including the sharp drop in temperatures.

Keech said PJM is using a longer weather history lookback to capture cyclical patterns and tying reliability risk and generator performance to weather. It also is looking at options outside the capacity market, including notification to gas units, scheduling and modeling uncertainty in the energy and reserve markets and the costs that are recoverable for reserve commitments, such as fuel procurement.

FERC hearing on PJM Capacity Market

Regulators and public advocates from Ohio, New Jersey, Kentucky, D.C., Maryland and Delaware (left) spoke to FERC during the forum’s third panel. | FERC

A third panel featured state regulators and public advocates, including Kentucky’s Chandler; Ohio Commissioner Dan Conway; New Jersey Commissioner Zenon Christodoulou; D.C. Public Service Commission Chair Emile Thompson; William Fields, deputy people’s counsel for Maryland; and Ruth Ann Price, deputy public advocate for Delaware.

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Iterative Changes to Interconnection Queues Discussed at Transmission Summit

ARLINGTON, Va. — Interconnection requests continue to grow, and grid operators have had to adopt waves of changes to try to keep pace with them over the years, experts said at Infocast’s Transmission & Interconnection Summit on Monday.

Lawrence Berkeley National Laboratory’s Joseph Rand opened up the conference going over the latest national queue figures he helped produce, which show 2,000 GW waiting to connect to the country’s grids. (See LBNL: Interconnection Queues Grew 40% in 2022.)

“Interconnection requests are growing across the country, in really every grid operator region that we analyze,” Rand said.

One exception in 2022 was CAISO, where it had to pause taking on new projects after a massive spike in requests in 2021. The ISO is processing its first batch of interconnection requests since then, and Rand said it is “another massive one,” which will turn that regional trend around.

While the queues signal plenty of interest in building out renewables, which are the dominant sources for new generation everywhere, most of the projects will not get built.

“People might say, ‘Well, maybe the queues are working the way they should: We’re encouraging generators to come online where it makes sense, in terms of the transmission system where there’s capacity on the system, and where it’s kind of most economically viable to do so,’” Rand said. “But on the other hand, I think it’s a little bit concerning to see completion rates as low as 20% and, by capacity, only about 14%.”

FERC has a pending Notice of Proposed Rulemaking on interconnection queues that would update its pro forma rules from a serial, first-come, first-served system to a cluster-approach that favors projects that are ready to go, Rand said. (See FERC Proposes Interconnection Process Overhaul.)

Some of the changes proposed by FERC have been in place in different markets for years, and they have had to continually improve their processes as the queues grew, he said.

MISO went to a cluster process 15 years ago, and it instituted a first-ready, first-served system years ago with an additional seven waves of changes since then, said Grid Strategies Vice President Richard Seide.

“So, one clear takeaway that everyone should understand: Queues are a work in progress,” he added.

Queue reform is a complex topic, so it makes sense that grid operators would take their time and tweak rules over years to see what works, said AES Vice President of Strategic Development Alexina Jackson.

“I really commend the last panel for recognizing that what we’re doing should be iterative,” Jackson said. “Queue reform is challenging.”

While FERC’s proposed revisions — and the changes PJM recently instituted that are largely in line with the NOPR — should speed up the process, Jackson said it was important to move some of the work around queues into the planning process. (See FERC Approves PJM Plan to Speed Interconnection Queue.)

The energy transition is in the queues, as the resources there represent the clean energy mix the grid is moving toward, said RMI Manager Katie Siegner. She agreed with Jackson on FERC’s NOPR and PJM’s revisions.

“All of that is a really promising signal that we’re finally mustering the will and the resources to tackle the interconnection backlog that has become one of the thorniest challenges in the transition to a more carbon-free electricity mix in the U.S.,” she added.

PJM’s move to a cluster approach in studying projects in the queue will help move them forward by cutting the costs of network upgrades, but Siegner argued more would be needed if the RTO were going to meet the demand of state renewable portfolio standards, corporate clean energy contracts and federal policies pushing renewables.

Planning Transmission to Clear the Queues

Beyond connecting individual projects, the grid is forecast to have to double or even triple in size by midcentury to meet decarbonization goals in the power industry, while electrifying others, and that is a huge task, said Michael Colvin, the Environmental Defense Fund’s California energy program manager. That transmission expansion should include trunk lines out to renewable, resource-rich regions to bring them to market.

CAISO released a 20-year transmission plan that looked ahead to see how the grid would need to evolve as the state meets its clean energy and climate targets, said the grid operator’s vice president of infrastructure and operations planning, Neil Millar.

The 20-year plan was voluntary, but planners used some of its suggestions, and the extra information helped give the industry a lot more comfort that everything was moving in the right direction, Millar said.

CAISO went to a cluster approach back in 2010, and it has worked on reforming its queue every couple of years since then, said LS Power Senior Vice President Sandeep Arora. But projects entering the queue today probably won’t be built until the end of the decade.

“There’s only so many real estate opportunities, and every developer is after those same opportunities, right?” Arora said. “So, the cost of doing businesses is going up on the real estate side.”

Real estate is a major issue in developing new resources in the Northeast, especially anything along its coasts, with the high land values and the abundance of historic and cultural sites, said POWER Engineers Senior Project Engineer Ken Fortier. Given those realities, it makes sense to plan transmission corridors that can accommodate future generation to minimize the overall permitting process.

“We want to make sure we’re not going back and having to knock on those same landowners’ doors and say, ‘Hey, we built this line five years ago; I guess we’re going to be building it again,’” Fortier said.

The planning process in New England would have to be updated for such lines to be built, because right now it lags behind other regions, such as New York, in terms of planning for public policy, said NextEra Energy’s Michelle Gardner.

Demand is expected to grow in New England by 40% by 2035 and 72% by 2040 because of electrification, all while about 32,000 MW of renewables remains in the queue, said Eversource Energy Vice President of Transmission Policy Vandan Divatia.

“We can’t look at these in silos; we’ve got to try to co-optimize,” he added.

A major issue is who is going to pay for all the new transmission. Divatia argued that it should not be left to renewable energy developers; expanding the grid has societal benefits, so consumers should help pay, which will speed up the transition to cleaner energy. Eversource is doing that on Cape Cod, where its customers have paid for the equivalent of a 115-kV line, but it is building a 345-kV line with the difference footed by an offshore wind farm.

New England’s grid can handle about 5 GW of offshore wind without major upgrades, and the states have contracted for enough wind that now is the time to start thinking about expanding the grid to accommodate more, Gardner said. That could be handled by the states coming together and working with ISO-NE to figure out what upgrades are needed to make their offshore wind procurements feasible, she added.

The transmission planning side is generally more important than the queue in New England, Gardner said. While some projects have been stuck in the queue for years, they include wind farms in Northern Maine that face huge costs to connect.

“There may be some projects in the queue now that have been here for a long time, but it’s not because the queue is broken,” Gardner said. “It’s because they just can’t get down to the load. But projects in Connecticut or Massachusetts generally have processed appropriately through the ISO study.”

MISO-SPP JTIQ

In parts of MISO and SPP, all of the projects are impacted by other “affected systems,” which the two hope to overcome through the Joint Targeted Interconnection Queue (JTIQ) study, said NextEra Energy’s Matt Pawlowski.

“We have a lot of projects in both regions,” Pawlowski said. “We’ve had a lot of issues with affected systems and the timelines for affected-system studies that don’t align with our commercial time frames or the interconnection studies in each of the regions. So, if you have an SPP project, [you’ve] got to be hindered by the fact that there’s affected systems that don’t necessarily align with the study time frames in SPP and vice versa in MISO.”

Those delays can cause power purchase agreements and generation developments to be canceled, he said.

The JTIQ will lead to major, central lines designed to resolve any affected-system issues in northern MISO and SPP, said Sunflower Electric Power’s Clifford Franklin. In the past, the cost of dealing with affected systems has been so high that individual projects have not been able to bear it.

The plan invests close to $1 billion in major transmission upgrades, and while 90% of the cost is expected to be picked up by generation developers, load could be on the hook for cost overruns. That has led to some opposition, Franklin said.

Planning lines to deal with such issues will give project developers the certainty they need to move forward. “This stability of the rate, the entry fee, is what is hoped will reduce backlogs,” Franklin said.

Speculative Projects?

Projects have often pulled out of queues when faced with the need to fund transmission upgrades that erase any chance for them to profit, but some developers on the panel argued that they have reasons other than hunting for the cheapest grid connection to file “speculative projects.”

NextEra had some of those projects looking for a cheap connection back when the costs of doing so were low, but the nation’s largest renewable developer still has plenty of projects — for different reasons, Pawlowski said.

“Those speculative projects needed to be in there,” Pawlowski said. “And the reason why they needed to be in there is because if it’s going to take me five to six years, or even seven years, to go through the interconnection queue, I cannot provide my customers with projects if that study process is that long.”

If a client asks for a contract for a wind farm, they will not want to wait the six or seven years it would take NextEra to move a development through the queue process and then actually build it, so the firm has projects in the queue that it can sell to clients in years’ less time. The way to get around that is to make the process as quick as possible, Pawlowski said.

The Inflation Reduction Act put interconnections on steroids, and while the queues were busy before the law and its bevy of energy subsidies were passed, it has created a new dynamic, Seide said.

“The fact is, all of this money out there — private equity funds — they want interconnects, right?” Seide said. “So, when that process of dollars at risk would cause people to withdraw. That doesn’t happen today.”

In the past, some developers were scrappy, and raising the deposit amounts to weed out speculative projects from the queues would have worked, but that is no longer the case, he added.

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Clean Path NY Joins Calls for Inflation Adjustment

Clean Path New York on Wednesday asked state regulators to include it in any inflation adjustments approved for Tier 1 renewable energy certificates (RECs), saying generators would otherwise shun the 174-mile transmission project being planned to deliver power to New York City.

CPNY — a project of the New York Power Authority, Invenergy and EnergyRe — filed its petition with the Public Service Commission in response to a June 7 request by the Alliance for Clean Energy New York (15-E-0302).

ACE NY asked the PSC to authorize the New York State Energy Research and Development Authority to add an inflation-adjustment mechanism for projects awarded through NYSERDA’s 2021 renewable energy certificate solicitation. ACE NY said its solar and onshore wind developer members were facing the same inflationary pressures that have caused offshore wind developers to seek to renegotiate their deals. (See OSW Developers Seeking More Money from New York.)

CPNY said it was seeking relief “due to the unforeseen and severe market disruptions that have occurred” since April 2022, when NYSERDA awarded it a contract to deliver 1,300 MW of renewable energy from upstate to Zone J in New York City. (See NYPSC OKs 2 Huge Clean Energy Projects for New York City.)

CPNY’s contract is based on a single strike price that includes production and delivery of emissions-free power, with a portion of the REC payments going to 23 generation projects and the balance used to fund the transmission line.

Fourteen of the 23 projects in CPNY’s generation portfolio hold Tier 1 contracts with NYSERDA, and the other nine are Tier 1-eligible wind and solar projects “that are experiencing exactly the same cost pressures,” CPNY said.

“To the extent that the commission provides an adjustment mechanism that shifts the price of Tier 1 RECs upward, CPNY will need to increase its payments to Tier 1 generators in order to induce their participation in CPNY,” it said. “If CPNY does not provide the same level of net revenues to [its] resources … those resources would be commercially disadvantaged by participating in the CPNY project and therefore motivated to participate only in Tier 1.”

CPNY, which emphasized it is not seeking to change the transmission component of its contract, asked the PSC to rule by Oct. 12. The transmission project, which has an expected in-service date of 2027, is currently undergoing permitting and interconnection analysis.

“If the commission fails to provide concurrent relief to CPNY, or if it fails to act on this request by its Oct. 12, 2023, session, CPNY will be unable to attract capital for the CPNY project or proceed with binding orders for the hundreds of millions of dollars in materials and equipment needed,” it said.