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October 9, 2024

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NARUC Weighs SCOTUS Decision’s Impact on Coal

SAN DIEGO — The Supreme Court’s recent decision in West Virginia v. EPA and its potential effects on the nation’s coal-burning power plants occupied a session on EPA’s authority over CO2 emissions at the National Association of Regulatory Utility Commissioners Summer Policy Summit.

NARUC’s Subcommittee on Clean Coal heard from attorney Matthew Leopold, who helped lay the legal groundwork against the EPA in the West Virginia case during a discussion moderated by West Virginia Public Service Commission Chair Charlotte Lane.

The high court’s 6-3 decision on June 30 ruled that EPA lacks authority to compel generation shifting to reduce carbon emissions, saying the agency failed to provide “clear congressional authorization” for the rulemaking. (See Supreme Court Rejects EPA Generation Shifting.)

While environmentalists decried the decision, Lane called it “exciting” given the push to retire coal plants.

“We all need to work together to make sure [EPA] regulations do not cause grid reliability problems, or make electricity less affordable for ratepayers,” she said.

Leopold, a former EPA general counsel during the Trump administration and now a partner at law firm Hunton Andrews Kurth, said the decision checked but did not fundamentally alter EPA’s ability to regulate greenhouse gases from power plants under the Clean Air Act.

Yet the decision could have far-reaching effects on federal agencies’ rulemaking, he said. It invoked the major questions doctrine, a rarely cited legal principle affecting Congress’ delegation of authority to executive agencies, to say the EPA had overstepped its bounds.

Going forward, courts will scrutinize EPA and other agencies’ actions to ensure they have a clear basis in statute and historical precedent, Leopold said.

“If an agency’s getting out of its lane, and it’s trying to do something that hasn’t historically done, it may be under threat,” he said. “And so, the example right now on the Biden administration’s list of big rules … is its [approach] to climate change that a lot of lawyers, including myself, are saying might be vulnerable.”

He cited a proposed rule requiring that public companies disclose business risks related to the climate and greenhouse gas emissions to the Securities and Exchange Commission.

“There, you have similar facts [to West Virginia v. EPA because] … the SEC has not regulated climate change since [the agency began in] the 1930s,” he said. The rule would be a “new transformative approach that [the SEC has] never done before. There’s no express discussion of environmental regulation in their statutory authority. And so, I think, you know, the administration is going to have to look long and hard about how they go about finalizing that rule.”

“More to the point and more practical, is how this decision is going to affect fossil-fired and coal generation,” Leopold said.

The case calls into question whether the EPA can require emissions controls only at the source power plant or whether it can go “outside the fence” to regulate emissions.

Requiring a power plant to switch fuels might be permissible but not “forcing a coal plant to become a gas plant,” Leopold said. The decision raised questions about possible carbon capture rules and whether emissions reductions that are not cost-effective would be permitted, “for instance if a plant is scheduled to close in 5 years,” he said.

For the foreseeable future, the EPA is going to “hit singles and doubles rather than … swinging for the fence,” being careful to base its actions on statutory authority and not push its boundaries beyond what the courts deem permissible under West Virginia v. EPA, Leopold said.

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NARUC Panel Explores ‘Future Proofing’ EV Infrastructure

SAN DIEGO — Utility regulators are confronting myriad challenges in dealing with the growing need for electric vehicle chargers, including a quickening pace of obsolescence, a lack of uniform standards among charging stations, and lingering questions about who should deploy and pay for equipment.

And any meaningful response to those challenges will likely fall to the states, according to Phil Jones, executive director of the Alliance for Transportation Electrification (ATE) and a former member of the Washington Utilities and Transportation Commission.

“It appears to be a decision of the federal government not to do anything on climate and perhaps not even renew the EV tax credits,” Jones said during a July 18 panel on “future proofing” EV charging technology at the National Association of Regulatory Utility Commissioners’ Summer Policy Summit. “The issues are going to be squarely in your laps in the states. That’s my prediction over the next three to four years, at least.” 

Following is some of what we heard during the panel.

Future Proofing Explained

Panel moderator Jamie Barber, director of the energy efficiency and renewable energy unit at the Georgia Public Service Commission, opened the discussion by pointing to a key problem utility commissions face in future proofing utility EV infrastructure investments.

“The regulatory process is often so long that by the time the commission approves a program or plan, the technology may already be out-of-date. So the question is, how should the commission plan for these short-lived assets?” Barber said.

“What does future proofing actually really mean?” said Marie Steele, vice president of electrification and energy services at NV Energy (NYSE:BRK.A). “When I think about it from a utility perspective, it’s very easy for us when we think about how to operate the greatest critical infrastructure that has reliability metrics around it. We focus on standardization; we focus on interoperability; we focus on reliability — also with that center of the customer experience. And grid integration is layered on top of it.”

NV Energy is allowed to own EV charging stations in Nevada, Steele noted, giving customers a choice of who can operate their sites: the utility, third-party providers or the customers themselves.

The utility previously took a “top-down” approach to encouraging development of charging sites by providing incentives. “‘Just do the best you can with moving the market’ was really how we designed our programs,” Steele said.

But with the approval last year of its $100 million Economic Recovery Transportation Electrification Plan, NV Energy is now taking a more “bottom-up” approach to developing charging sites, according to Steele. The plan is expected to produce 1,882 chargers at 120 sites across the state. (See NV Energy Gets Green Light for $100 MW EV Charger Plan.)

Under the new approach, NV Energy starts by developing site profiles with an eye to standardizing the charging network within utility’s entire service territory while determining cost estimates for each site “irrespective of ownership model.”

“So we want to have the standardization there and know what the project is going to cost,” Steele said. “And then when we get to interoperability, which is also still reliability and standardization, we have another long list of requirements for infrastructure that will be incentivized or owned by NV Energy.”

Those include minimum power levels, secure communications protocols and customer payment requirements.

“All of this so as to make sure that we can connect it into the grid, right? So that it benefits not just that individual EV driver or businesses that host EV charging stations. We can also optimize grid integration. That’s to the benefit of everybody,” she said.

‘Anchoring’ with Fleets

“We have a lot of clean energy assets, and one of the core principles we are trying to bring to this industry is the lessons learned from the solar and wind industry and apply those lessons to the scalability of [EV] infrastructure,” said Suresh Jayanthi, a senior director of sales and business development in the mobility solutions division at NextEra Energy Resources (NYSE:NEE).

For NextEra, that includes a technology-agnostic approach to the design and construction of EV charging sites and bringing finance and operations groups together to provide charging energy as a service to customers.

“This similar perspective for infrastructure will be critical as we look at all the variables that we just heard, figuring out the design [and] permit considerations, [and] bringing those into a platform that gives us predictable deliverables in terms of the time it takes to get through the interconnection and all the issues associated with that,” Jayanthi said.

Jayanthi, who currently focuses on developing charging solutions for medium- and heavy-duty vehicle fleets, said it’s important for the power industry to remember that fleet operators want to focus on what they do best, such as delivering packages on time.

“They’re not out to become infrastructure experts. They’re not trying to figure out how to build charging stations and figure out how to manage energy cases. We are trying to remove some of those bottlenecks, so as they look at electrification, their focus is on using the infrastructure as an enabler rather than a bottleneck. And that’s been our focus,” he said.

NextEra believes that its experience in developing fleet charging can provide lessons for a broader charging strategy.

“While consumer vehicle infrastructure is a critical enabler for the broad-based adoption of electric vehicles, fleets can provide a unique anchoring point around which we can look at infrastructure scaling, and it could have a multiplier effect,” Jayanthi said.

‘Right-sizing’ vs. Future Proofing

ATE’s Jones recounted a recent conversation with his daughter, who works as a legislative analyst in Washington’s capital, specializing in broadband policy.

“When I told my daughter I was going to be speaking about future proofing in San Diego … she says, ‘Dad, there’s no such thing as future proofing. How can you proof the future? There’s always going to be uncertainty,’” Jones said.

“I prefer the term ‘right-sizing for the future,’ or something like that. So what you’re trying to do is right-size the conduit, the pipes, the asphalt, concrete, transformers [and] switchgear,” he said. “You’re trying to get the right set of equipment in that first phase that can scale without the risk of stranded assets.”

Jones offered a list of recommendations for state regulators, including:

  • creating a transportation electrification (TE) plan;
  • finding a way to bring stakeholders (such as truckers) into the process so they can describe where their industries are going;
  • encouraging utilities to have a single point of contact on TE issues;
  • developing an interconnection review process for TE projects;
  • offering incentives and rebates, which should be revisited often;
  • encouraging utilities to frequently change their approved product lists to accommodate new companies coming into the EV space; and
  • looking around for best practices from across the country.

And with the longer curve of adoption for EVs, Jones also encouraged commissioners to consider allowing utilities to employ multiyear rate plans to recover costs from EV equipment.

“I know that consumer advocates and [the National Association of State Utility Consumer Advocates] and others may not be fans of this, but in order to bring the right-sizing of this technology and do least-cost planning for the long term, you may need to do that,” Jones said.

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SPP Board, Regulators to Consider Reserve Margin Increase

WESTMINSTER, Colo. — SPP and its members have agreed to boost the RTO’s planning reserve margin to 15% from 12% but remain at odds over the timing of the increase following Markets and Operations Policy Committee discussions that Chair Denise Buffington described as “contentious.”

SPP’s Regional State Committee and Board of Directors will each consider the issue during their virtual quarterly meetings, Monday and Tuesday, respectively.

SPP’s reserve margin requirement, currently 12%, is based on a probabilistic loss-of-load expectation (LOLE) study performed every two years to determine the capacity needed to meet the reliability target of a one-day outage every 10 years (0.1 days/year). LREs unable to meet their obligation can incur financial penalties from the RTO.

“There was concern that moving too quickly will put members in non-compliance from the start,” Buffington told the Strategic Planning Committee the day after MOPC’s July 10-11 meeting. “There were also concerns the [generator interconnection] queue isn’t sufficiently caught up to actually get steel in the ground to meet those obligations.”

The grid operator’s staff wants to raise the planning reserve margin (PRM) to 15%, saying the 2021 study shows the current 12% requirement won’t satisfy the 1-in-10 metric for the 2023 summer season. They also said an increased margin of safety is necessary, as the 31 GW of nameplate wind capacity already present on the system has increased the risk of wind volatility, with more wind projects yet to come. A 15% PRM would incent new generation and reduce the risks and costs associated with extreme weather events, they said.

COO Lanny Nickell told MOPC that SPP doesn’t take lightly its responsibility to manage reliability across its footprint.

“We understand that some LREs expect to struggle to comply with the increased PRM requirement … We understand that taking actions to increase capacity necessary to comply will be costly, likely upwards of a billion dollars in capital investment,” he said.

“However, we also know that experiencing an unwanted interruption of power, especially during extreme heat or extreme cold conditions, is not only extremely frustrating to customers but also very costly, especially when loss of life is involved. A decision to increase the PRM requirement to 15% as soon as possible significantly reduces our risk that we experience another event where load is not able to be served,” Nickell said.

Stair-Step Approach

The Supply Adequacy Working Group (SAWG) is recommending a stair-step approach, with the PRM raised one percentage point over each of the next three years. It said that would give the GI queue time to reduce its backlog, adding certainty to generation forecasts, and allow LREs short of their capacity requirements to close their gaps.

SPP resisted. “As a reliability coordinator, we cannot endorse a 13% planning reserve margin next year when we think the right number is 15%,” Casey Cathey, director of system planning, said. “It’s just too much of a risk to endorse a stair-step approach, given the nature of our generation mix and the uncertainties around us.”

Staff updated MOPC on its efforts to clear the queue’s backlog, sticking to the 2024 completion target they set during April’s meeting. They said they’ve reduced the current queue’s number of active interconnection requests from 481, totaling 90.3 GW, to 466, totaling 87.27 GW as of June, thanks to the new three-phase interconnection study process. (See FERC OKs New SPP Interconnection Process.)

SPP has added more than 25 GW of generation the last five years, most of it from renewable resources.

Usha Turner 2022-07-11 (RTO Insider LLC) FI.jpgUsha Turner, OG&E | © RTO Insider LLC

“We should make certain [our current processes] are reflective of the current changes in our industry,” Oklahoma Gas & Electric’s Usha Turner said. “As we’re looking at 15%, given what we are seeing in the queue and the nature of what’s in the queue, is that enough?

“We’re evolving as we’re seeing things happening,” she said. “We need to better reflect the nature of our generation.”

Stakeholders in various working groups have pointed out the LOLE study does not include 2011 and 2021 weather-related impacts, future forced outage rates, the limited availability of demand response or any safety margin beyond the 1-in-10 reliability metric.

They said a larger, immediate increase in the PRM adds to market uncertainty and could leave LREs unable to cure capacity shortfalls. They also said they are concerned that even if excess capacity exists, it might not be available for purchase.

Nickell said that were the 15% PRM required by 2023, up to a dozen LREs would not be able to meet their obligations. Cathey noted SPP has about 3.6 GW of capacity available for purchase, but Turner responded that in her experience, that capacity is not available.

Midwest Energy’s Bill Dowling, among those favoring the SAWG approach, said instituting the 15% PRM immediately would prevent generators from rethinking retirement plans “that were devised with at least an assumption that the planning reserve margin wasn’t going to make a big jump.

“I don’t think we can expect to get out of this by saying we need 15%,” Dowling said. “We need time.”

Natasha Henderson 2022-07-11 (RTO Insider LLC) FI.jpgSAWG chair Natasha Henderson explains stakeholders’ position during PRM discussion. | © RTO Insider LLC

SAWG chair Natasha Henderson of Golden Spread Electric Cooperative, suggested it would be helpful to gather additional metrics around energy uncertainty. “What do we have now? What did we have a few years ago? What will we have going forward?”

Her recommendation gained support from Nickell.

After rejecting a suggestion to delay the PRM’s consideration until the October MOPC meeting, members voted on several motions before arriving at a consensus. A suggestion to increase the PRM to 13% in 2023 and 15% in 2025 fell short of two-thirds approval at 60%. Endorsing the SAWG’s stair-step increase but incorporating a waiver process should the RSC reject the working group’s recommendation won only 48% approval.

However, a straight motion on the stair-step method passed with 95% approval. Members followed that by endorsing the SAWG’s recommendation for a performance-based accreditation for conventional resources (thermal and hydro), with a one-year delay in the implementation date.

The performance-based accreditation differentiates resources according to their historical reliability but does not change the total capacity required to meet system reliability. It would be the first time SPP has applied this methodology.

MOPC then approved a motion directing staff to create a process for approving waivers from the resource adequacy requirement should LREs not have sufficient time to resolve their deficiency.

As the dust settled, Buffington quipped that MOPC could soon expect a quiz on Robert’s Rules of Order. She was greeted with laughter.

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NextEra Continues to Shine Brightly

NextEra Energy (NYSE:NEE) leadership said Friday that “powerful tailwinds” continue to support strong demand for renewables, repeating a message from last month’s investor conference.

“High power prices and high gas prices … are helping to make renewables the most economic form of generation,” CFO Kirk Crews said during the company’s quarterly conference call with financial analysts.

Crews said NextEra’s renewable developer, NextEra Energy Resources, added slightly more than 2 GW to a backlog that now totals more than 19.6 GW. That included about 1.2 GW of solar projects, the second largest quarter of solar origination in our history.

The Juno Beach, Fla.-based company said it was pleased with the government’s recent decision to waive additional duties for two years on solar panels imported from Malaysia, Thailand, Cambodia and Vietnam. The U.S. Department of Commerce has opened an investigation into claims that panels imported from those countries contain Chinese components subject to tariffs imposed by the Trump administration and continued under President Biden. (See Biden Waives Tariffs on Key Solar Imports for 2 Years.)

Crews said NextEra expects its suppliers will be making ingots and wafers outside of China at the end of those two years. The Commerce Department staff have “publicly stated that panels with wafers made outside of China are not subject to its investigation,” he said.

NextEra reported earnings of $1.38 billion ($0.70/share), compared to last year’s second quarter of $256 million ($0.13/share). Earnings adjusted for one-time gains and costs came in at $1.59 billion ($0.81/share), exceeding Zacks Investment Research’s consensus of 75 cents/share.

During the quarter, NextEra commissioned the 1.2-GW natural gas-fired Dania Beach Clean Energy Center and placed into service the 176-mile North Florida Resiliency Connection transmission line. The line physically connects NextEra’s Florida Power & Light and Gulf Power grids and is projected to yield $1.5 billion in system benefits through consolidated operations.

“Smart capital investments such as these help lower costs and improve reliability for customers, NextEra CEO John Ketchum said.

The company’s share price gained $1.55 on Friday and closed at $80.25.

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Maine Environmental Board Denies Appeals of NECEC Transmission Line Permit

The Maine Board of Environmental Protection last week removed one potential obstacle to the 145-mile New England Clean Energy Connect (NECEC) transmission line, upholding Central Maine Power’s construction permit.

After two days of oral arguments, the board voted Thursday to deny appeals by the Natural Resources Council of Maine (NRCM), NextEra Energy and a group of local entities and individuals to vacate a 2020 Department of Environmental Protection (DEP) order approving CMP’s project application.

The board confirmed DEP’s order approving a permit to construct the project and modified parts of the order related to decommissioning and habitat impact compensation. In addition, the board denied appellants’ request for a new public hearing on CMP’s application.

CMP cannot resume construction, however, unless it prevails in its court challenge of a November 2021 referendum blocking the project.

Compensation, Decommissioning

Prior to hearing oral arguments on the appeals, the board issued a proposed order finding that the department’s order for CMP to conserve 40,000 acres to compensate for the effects of the project on wildlife habitat was sufficient. After hearing petitioners’ arguments, however, the board increased the total compensation to 50,000 acres.

NRMC claimed that the standard compensation ratio used by DEP to calculate the total acreage to be conserved does not reflect the importance of the affected lands. Maine law relies on an 8:1 ratio to replace any lost function from activities that alter wetlands, and DEP applied that standard in the order using an estimated 5,000 acres of baseline affected lands.

“The 8:1 ratio is a typical ratio, but the problem is this is not a typical area — it is a very special part of the state,” said attorney James Kilbreth, representative for NRCM, in testimony Wednesday. “The impacts here are more consequential than in other parts of the state, and the compensation should reflect that higher degree of value.”

In its 2020 appeal of the department’s order approving the project permit, NRCM said that the project is sited in a part of Maine that “supports exception biodiversity,” making the area a “unique and important wildlife habitat.”

The board agreed that the compensation ratio should be higher, and increased it to 10:1, resulting in the new 50,000-acre conservation area.

To address concerns about decommissioning guidelines for the project, the board’s proposed order upheld parts of DEP’s original decommissioning plan, while also addressing what might happen if project construction is completed and not energized or not completed.

Permit Suspended

CMP began construction on the project in January 2021 and halted construction in November when DEP Commissioner Melanie Loyzim issued a suspension order for CMP’s permit to construct. (See NECEC Halts Tx Line Construction, Regulators Suspend Env. Permit.) At that time, CMP had already completed clearing activities on four of the five line segments and begun other infrastructure work.

The board’s proposed order called for CMP to submit a decommissioning plan to DEP for review prior to resuming construction and to begin decommissioning within 18 months of nonrenewal or termination of current power contracts. After hearing oral arguments, the board added a condition to its final order for decommissioning to begin in August 2024 if construction has not resumed by that time.

That 24-month period will allow for an appeal of the board’s decision to play out, if one is filed, board staff said Thursday.

Suspension of CMP’s permit to construct will remain in place unless the Maine Supreme Court decides in favor of CMP in NECEC Transmission LLC, et al. v. Bureau of Parks and Lands, which challenges the legal authority of a referendum on transmission development passed by Maine voters in November. The court heard oral arguments in that case in May.

The referendum authorizes a statutory change requiring legislators to approve high-voltage transmission lines greater than 50 miles that are not necessary for reliability purposes. CMP is asking the court to block retroactive application of that law.

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Westerners Get Tips on Being ‘Little Bitty Cog’ in an RTO World

SAN DIEGO — Officials in Western states looking to join an RTO should know a key thing about organized markets, according to those familiar with them: They will require a lot of time and resources from your regulators and consumer advocates.

“There are times when I think I’m a little bitty cog in a big RTO world, and that the RTO is my full-time job and the other state regulatory stuff is what I end up with when I’m not busy with RTO stuff,” Arkansas Public Service Commission Chair Ted Thomas said Tuesday at the National Association of Regulatory Utility Commissioners (NARUC) Summer Policy Summit.

Thomas was speaking on a panel to provide Western regulators and advocates with insights on how to position themselves to participate in any organized electricity markets that take root in the region.

As a regulator experienced with both SPP and MISO, Thomas said he’s confident in his agency’s ability to help shape market policy.

“What I worry about is someone who’s newer, that doesn’t have the background, and then they show up and they can get [run] over by a big snowball — not even realizing what hit them, and there’s nobody there to help them help themselves,” he said.

Greg Poulos, executive director of the Consumer Advocates of the PJM States, advised Westerners of the benefits of state consumer advocates and utility commissions being aligned on their positions on RTO affairs.

“For me that’s very helpful because I do talk to state commissions, their advisers or staff a lot, and it’s a great working relationship. I’m able to provide some of their opinions in the stakeholder process along with ours, and they have a lot more influence than we do,” Poulos said.

Poulos said RTO/ISO market monitors can be a valuable source of information because electricity customers and their advocates usually have less information than other stakeholders because they don’t directly participate in or regulate the markets.

Although PJM’s territory includes 65 million residential customers, those ratepayers represent just 1.4% of the votes “at the lower levels” of the RTO’s consensus-based stakeholder process, and have little visibility into the transmission planning process, Poulos said.

“There’s public power, there’s industrial customers, but for us as customers — those who pay the bills — we have very little influence,” he said.

Amanda Bradshaw, energy markets adviser with FERC’s Office of Public Participation (OPP), said there are many groups “that are recognizing that RTOs have an increasing impact on everyday people [and] on broader energy policy questions that people care about.

“But they might not necessarily understand or have full information about FERC processes, or about the market underpinnings of those policy goals that they care about,” she said.

Established in 2021, the OPP “is trying to understand how we can reach out to the public and bridge a lot of information gaps,” Bradshaw said. The office also seeks to increase understanding of RTO processes and help public interest groups figure out how get involved in those processes from the beginning.

“How do you actually participate in those processes if you don’t understand how those things work? How do you allocate staff resources to attend those meetings, especially when it’s necessary sometimes to attend in person?” she asked.

“Typical citizens don’t have expertise; they have passion,” Thomas said. “They might have environmental passion. … They might just want the lights to come on [and say], ‘Leave me alone.’ But for that person to have input … you need expertise. But having expertise doesn’t do any good if you don’t have access to the information, and to me, that’s a big part of that problem.”

‘Complex Subject Matter

Panel moderator Kent Chandler, chair of the Kentucky Public Service Commission, asked panelists whether they have enough resources to have a “meaningful impact” on RTO processes. Each answered with a resounding “no.” He followed up with a question about what barriers must be removed to encourage participation by those outside the industry.

“I think you start with inclusiveness: barriers to entry around cost, membership fees, differing eligibility requirements for membership in the RTOs,” said John Moore, director of the Natural Resources Defense Council’s Sustainable FERC Project.

Moore said his organization recently joined SPP for the $6,000 membership fee after FERC eliminated the RTO’s $50,000 deposit fee and $100,000 exit fee for all members. In PJM, he noted, the Sustainable FERC Project cannot become a full member and — along with the states — is barred from attending Liaison Committee meetings with  the Board of Managers. Moore also pointed to the restrictions the press faces in covering NEPOOL, something that “FERC said is okay, more or less.” NEPOOL meetings are closed to the public; although RTO Insider’s ISO-NE correspondent attends meetings as an end-use customer, NEPOOL rules bar quoting from members’ discussions. (See FERC Rejects RTO Insider Bid to Open NEPOOL.)

“Another set of huge issues is around data access and overall understandability of the issues,” he said. “There’s a lot of chicken-and-egg issues going on here. The reason a lot of non-traditional groups and entities don’t show up at the RTOs is that it’s just very complex subject matter.”

Moore said working groups at WECC and other organizations in the West make the region’s electricity data more accessible. “My experience has been lots of times — and somebody in the West can correct me — it’s actually easier to get a lot of the data we need to input in our models than it’s been in the East; and a lot of different standards are applied in different RTOs.”

FERC’s Bradshaw said groups lacking expertise in energy regulation tell the OPP, “‘We’re just having a really difficult time crafting these proceedings that we need to be involved in, and that would be relevant to us,’” Bradshaw said. “I think it’s even difficult when you do have those resources, when you’re able to hire an attorney or contract a law firm to track those things for you.”

“The real resource issue for the states is state staff and state time.” Thomas said.

Balancing Act

Thomas believes the U.S. grid has become more robust since the catastrophic blackout that brought down the Northeast grid in 2003, in part because of new investments and the “balance” that comes with having states certify utility transmission plans after being included in the negotiation process.

“I think one of the most important things that comes out of this is that balance — the balance of states and your roles as commissioners and your ability to maintain that balance,” Poulos said.

But Poulos sees a lack of balance in PJM’s current transmission process. While he lauded the RTO for fostering wholesale competition in power generation, he criticized it for a corresponding lack of competition and transparency in transmission planning.

“We don’t really know what PJM’s role as a planner is in a lot of cases because since 2012, or [FERC] Order 1000, there’s been a lot of push towards competition, but what happened is a transmission owners said we’re gonna push everything away from those types of projects,” he said.

As a result, Poulos said, the majority of the RTO’s transmission projects are “supplemental” ones that waive competition.

Poulos thinks there’s an open question about the roles of PJM, the transmission owners and the states in the “vast majority” of the RTO’s transmission planning.

“One of the deepest frustrations we have is that lack of ability to be involved in that process,” he said.

Moore said there’s now an “implicit connection” between transmission planning and resource adequacy.

“And I think this is something that states and FERC are grappling with, obviously through the [transmission Notice of Proposed Rulemaking] and through the dialogue that has happened with FERC and the state commissions, and the increasing realization with our transforming grid mix that there are going to be more out-of-state resources that have to be relied on to help meet reliability and state resource adequacy needs,” Moore said. (See States Back Interregional Transfer Requirement.)

Poulos wrapped up his comments by advising Western state officials on what they should consider as they contemplate joining an RTO.

“I would say the one thing is, if anything goes wrong in the system in your state, as a commissioner you are the ones who are going to be accountable, so you need to have that ability to have a say in what goes on,” he said.

State officials also need to immediately establish transparency in the RTO and guarantee their representation, preferably with a reserved seat on the board of directors, he said.

Moore said states need to ensure that RTOs make efforts to include different groups in their processes.

“And even if they’re not full-time stakeholders, these groups and communities need to understand what the RTO is doing is actually affecting them, so they can in some way start to influence that process. So don’t forget about equity in this process,” he said.

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Consumer Groups File FERC Complaint Against MISO

An alliance of consumer groups on Friday jointly filed a complaint with FERC against MISO’s practice of respecting state rights-of-first-refusal (ROFR) laws in its regional transmission planning.

The consumer alliance asked the commission to block MISO and other RTOs from applying “anticompetitive” ROFR laws to their regional transmission planning and cost-allocation processes.

The group made the filing as the RTO’s Board of Directors prepares to consider Monday the $10.4-billion, 18-project long-range transmission plan (LRTP) for its Midwestern states. The portfolio is the first of four that MISO is planning to modernize its system.

The group said ROFR laws conflict with FERC’s rules on transmission competition and the commission’s obligation to establish just and reasonable rates.

The alliance includes the Industrial Energy Consumers of America, the Coalition of MISO Transmission Customers, the Wisconsin Industrial Energy Group, Resale Power Group of Iowa, Association of Businesses Advocating Tariff Equity and the Michigan Chemistry Council.

The groups said MISO should not hamstring itself by maintaining tariff provisions that prohibit it from holding a competitive solicitation for regionally cost-allocated projects. It said ROFR laws in that application are unjust and unreasonable.

FERC should prohibit the grid operator from recognizing the laws in the LRTP and order the RTO to hold competitive solicitations for projects located in those states, the consumer alliance said.

MISO estimates $1 billion of the portfolio will ultimately be open to competition. The grid operator said nearly $4 billion worth of the projects are considered upgrades to existing facilities, while another $5.5 billion of projects are in states that have enacted ROFR legislation.

Michigan, Minnesota, Iowa and the Dakotas all have ROFR laws; Wisconsin lawmakers have considered one but haven’t passed it. Additionally, MISO is likely to scrap its only market efficiency project assigned to MISO South after Texas’s ROFR legislation delayed the project’s start by years. (See MISO on Verge of Cancelling Hartburg-Sabine Tx Project.)

The RTO is planning to prepare requests for proposals where ROFR laws don’t prohibit competitive bidding. In those states without the legislation, incumbent transmission developers will need to provide to their regulators a notice of intent to construct.

The consumer alliance insisted that its complaint wasn’t seeking to slow down any reliability projects, but that MISO “delay issuing any notices to construct to projects currently protected by state ROFR laws” in the LRTP’s first cycle.

“Circumstances have substantially changed since 2013-2014 when the commission accepted the MISO tariff provisions … that mandate that MISO apply any state law that includes a ROFR to circumvent transmission competition in MISO,” the alliance said.

The alliance argued it’s now clear that ROFRs are being enacted to circumvent FERC’s competition mandate and “that the burdens of state ROFR requirements do not fall solely on customers within ROFR states, forcing pro-competition states to pay for the parochial policies of incumbent preference states.” They said ROFR laws are premised on the fear that incumbents will be outbid by competitive developers, are “economically inefficient by design” and “needlessly raise costs to consumers.”

“The costs at issue are far from modest, and so the time is ripe for the commission to act,” the alliance argued.

Industrial Energy Consumers of America President Paul Cicio said should $5.5 billion of transmission projects be automatically assigned to incumbent utilities, consumers in MISO Midwest will pay more for regional transmission than if they were bid out.

“We are requesting that the commission act quickly to find MISO’s provisions to be unjust and unreasonable and to require the replacement rate to be based on project costs resulting from competitive solicitation,” Cicio said in a statement.

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Illinois Leaders Blast MISO Inaction on Capacity Crisis

Sponsors of Illinois’ Climate and Equitable Jobs Act (CEJA) condemned “foot dragging” by MISO in getting new renewable energy online to fix its capacity crisis during a press teleconference Thursday.

State lawmakers and a representative for consumer advocate Citizens Utility Board (CUB) said with a climate crisis escalating quicker than scientists predicted and energy prices climbing sharply, MISO should re-evaluate and revamp its interconnection rules to accelerate new renewable capacity interconnections.

They said the grid operator is sitting on 34 renewable projects for the state that are capable of powering 4.5 million homes “while the grid operator blames others, spreads fear.”

The news conference comes as some critics are calling to reopen CEJA’s provisions given the capacity shortages. The legislation requires Illinois to be reliant on 100% renewable energy by 2050.

Ann Williams (IL CleanJobs) Content.jpgIllinois Rep. Ann Williams | Illinois Clean Jobs

Illinois Rep. Ann Williams (D) opened the press conference by referencing Vistra CEO Curtis Morgan’s 2019’s pronouncement that coal was on its way out.

“It was an admission to us and to the state of Illinois that coal could not compete with clean solar and wind energy. Now, gas is following coal into the land of polluting, expensive fuels of the past,” she said.

Williams said Illinois “saw the future” and enacted CEJA.

“But we write the laws. We don’t operate the grid. That’s MISO’s job,” she said.  

Williams said rather than bringing clean energy on the grid as quickly as possible, “MISO is addressing concerns about capacity by trying to shift blame.”

“Fossil fuel interests and entrenched energy lobbies are jumping on the blame game and calling for a return to the days when coal and gas generated Illinois’ electricity, even as fossil fuel prices skyrocket, emissions continue to pollute our communities and our planet is burning,” she said. “Going back to coal and gas is like pouring gas on a fire, in terms of hiking energy prices up and polluting our communities.”

Fossil fuel prices are only becoming more expensive, made worse by Russia’s war in Ukraine, Williams said. She challenged MISO’s “lackluster approach” to bringing new renewable energy online.

“You can’t do what you’ve always done and expect it to solve a problem you’ve never encountered before, but that’s what’s happening. … MISO needs to operate with a sense of real urgency here [and] think outside the box to meet the moment that we are in,” Williams said of the RTO’s system of processing and studying interconnection requests.  

MISO’s 2022-23 Planning Resource Auction (PRA) failed to secure enough capacity in its Midwestern zones, which cleared at a $236.66/MW-day cost of entry for new generation. MISO Midwest now faces the possibility of rolling outages in the 2022-23 planning year, which began June 1. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)

Though the grid operator’s membership approached the auction with more capacity year-over-year, MISO said the resource additions were mostly intermittent and generally less available than retiring thermal generators. It said it will require dispatchable, natural gas generation well into the future.

MISO’s current generator interconnection queue contains 806 projects totaling 126.3 GW of capacity. The queue overwhelmingly is comprised of solar, wind and storage projects or a combination of renewable energy and storage. The RTO historically only interconnects about 20% of projects that enter the queue.

MISO executives have been making the rounds in front of state regulators and lawmakers to drive home the urgency to fix future capacity shortfalls. (See MISO Promises Stakeholder Discussions on Capacity Auction Reform.)

“Rather than do its job, which is to operate the grid and transition our energy needs, MISO is pointing fingers. … MISO, with more than 1,000 employees, can and should move faster to transition Illinois to renewable energy,” Illinois Sen. Cristina Castro (D) said.

Castro said while PJM has made the energy transition a priority, MISO “still stubbornly holds on to a backwards-looking fossil fuel system that is dirty and expensive.” She questioned the grid operator’s delay in reviewing and approving generation projects, saying it led to expensive and “phony” shortage pricing.

“If Ameren customers ever find themselves in the dark, MISO’s inaction is to blame. They are asleep at the wheel, asleep at the switch and dragging their feet,” Castro said.

“It’s time for MISO to let CEJA do its job,” said Jim Chilsen, director of communications for CUB.

Chilsen said he was “challenging MISO to show leadership” and speed up the approval process for capacity additions.

“MISO needs to make the transition away from expensive fossil fuels a bigger priority. This is largely a problem of planning. For years, MISO has known that the transition from dirty energy was coming,” Chilsen said. “MISO has been slow to respond to these developments over the years.”

Chilsen said CUB has seen a 20% increase in ratepayers contacting them over energy affordability concerns.

MISO spokesperson Brandon Morris said the RTO was aware of the virtual press conference and that it planned to review the event in its entirety.

“We look forward to thoughtfully responding to any concerns or questions raised,” Morris said in an emailed statement to RTO Insider.

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MISO, PJM Consider Four Small Interregional Projects

MISO and PJM are considering four interregional transmission project candidates as targeted market efficiency projects (TMEPs).

The grid operators said during a Thursday Interregional Planning Stakeholder Advisory Committee (IPSAC) teleconference that the four congestion-relieving projects were whittled from a list of 23 solution ideas.

They are assessing:

      • a potential project to upgrade ComEd terminal equipment for the Quad Cities to Rock Creek 345-kV flowgate near the Iowa-Illinois border;
      • a conductor and switch replacement on the Mohomet-Champ 138-kV flowgate in central Illinois;
      • bolstering the Powerton-Towerline 138-kV flowgate in central Illinois; and
      • a potential fix for the congested Chicago-Praxair 138-kV flowgate near the Chicago area.

The grid operators plan to complete an evaluation of the upgrades in September. Until then, they continue to review historical congestion and perform no-harm tests, PJM Senior Transmission Engineer Jeff Goldberg said.

MISO and PJM said they were considering conducting a TMEP study in February. (See MISO, PJM Weigh ’22 Interregional Plan.)

The RTOs said they experienced about $519 million in congestion costs on market-to-market flowgates over 2020 and 2021; $328 million of that total has been determined as persistent and is not slated to be fixed with future upgrades.

MISO and PJM have approved three small TMEP portfolios since 2017 and one larger interregional market efficiency project in northwest Indiana in 2020.

TMEP projects must cost less than $20 million, completely cover installed capital cost within four years of service, and be in service by the third summer peak from their approval. The projects are assessed using a shorter time horizon than interregional market efficiency projects.

Earlier this year, some stakeholders asked the RTOs to also consider a more intensive interregional market efficiency project study to analyze expected future congestion instead of waiting until they amass years of expensive historical congestion. Staff officials have said the timeline this year supports the lighter TMEP study because MISO is embroiled in its long-range transmission planning work.

MISO and PJM will hold another IPSAC meeting Aug. 26.

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MISO Stays Course on Sharpening Generation Retirement Studies

MISO is all but certain to enact changes to its study process for retiring generators, stakeholders learned last week.

The RTO also continues to maintain that the changes will not introduce resource adequacy considerations into its retirement-study process.

Staff said during a Planning Subcommittee meeting July 19 that they will relax confidentiality rules around retirement data, adhere more strictly to local reliability requirements, and require more notice from resource owners in making their retirement decisions.

MISO will now impose a one-year notice requirement on retiring generation before it begins retirement studies under Attachment Y of its tariff; conduct retirement studies in on a quarterly basis; share with stakeholders the megawatt value of retirement requests systemwide; and discourage reliance on load shed as a valid mitigation option when voltage and thermal violations are uncovered in its steady state analyses. (See MISO Bolstering Generation Retirement Studies Amid Capacity Shortage.)

MISO has insisted that ensuring local reliability requirements is a last step, not a measure to secure resource adequacy.

The RTO has been firm that the changes will respect state jurisdictions and not extend generators’ operational lives because of resource-adequacy concerns. Its retirement studies currently focus solely on the transmission system’s reliability.

“The Attachment Y process is about local reliability issues associated with a resource retiring,” MISO’s Andy Witmeier said. “Anything related to larger resource-adequacy concerns should be discussed in the Resource Adequacy Subcommittee.”

Witmeier said MISO doesn’t have the authority to keep generation online over resource-adequacy concerns.

Customized Energy Solutions’ David Sapper, representing MISO load-serving entities, said it wasn’t clear how the grid operator would manage simultaneous studies should it encounter a large cluster of retirement requests. Staff said they will still study retirements individually, not in groups.

But Sapper insisted that MISO would still have to make assumptions about other active retirement requests that stand to impact study outcomes. He pointed to downstate Illinois, where several large generators could retire at the same time.

WEC Energy Group’s Chris Plante called for a transition period before the current 26-week notice is doubled. He said some generation owners have planned around the 26-week notice for years.

“I’d rather deal with this in the stakeholder process than at FERC,” Plante said of MISO’s future filing of the proposal.

Plante said generation owners face an “incredibly complicated” decision over whether to retire. An unexpected system support resource (SSR) designation, applied by MISO if it determines there are reliability concerns with plans to retire a generating unit, can throw a wrench into plans he said. Plante referenced the yearslong clash and complex refunding process that followed SSR status for the Presque Isle coal plant in Michigan’s Upper Peninsula. (See $23 Million Owed to Ratepayers in Presque Isle SSR Case.)

“The last thing my company wants to do is go through another hotly-contested FERC proceeding over who pays for an SSR,” Plante said.

Stakeholders last week also voiced frustration that MISO no longer posts unsolicited comments from stakeholders as part of meeting materials. During the week’s transmission-planning meetings, some stakeholders said the RTO had previously compiled stakeholder comments and shared them publicly on its meeting webpages, even when it had not opened a stakeholder comment period.

Coalition of Midwest Transmission Customers attorney Jim Dauphinais and Clean Grid Alliance’s Natalie McIntire called it a change in policy and a step back for transparency.

“I think this is especially important now because MISO makes fewer formal feedback requests,” McIntire said.

“I do think it’s incredibly important that comments, whether informal or formal, are attached to presentation materials. I just don’t see the value of not posting stakeholder comments,” said Andy Kowalczyk of activist group 350 New Orleans.

MISO staff said they would further address the issue during an upcoming Steering Committee meeting.