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September 30, 2024

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Transmission Conference Focuses on Reliability, Interconnection

WASHINGTON — Transmission stakeholders and federal regulators are concerned about extreme weather and clogged generator interconnection queues, but they’re also encouraged by FERC’s many proposed rulemakings to tackle those issues.

“We’ve probably had more headlines this year in MISO related to resource adequacy and the threat of outages than we’ve had in the last five years combined,” Scott Wright, the RTO’s executive director of resource adequacy and resource utilization, said at WIRES’ annual Fall Conference on Thursday. “The risk profile of the grid is changing significantly.”

Variability and uncertainty have always been a part of managing the grid, he said, but both have increased significantly and faster than expected. “So all of our thoughts and plans at MISO had to be reprioritized and changed.”

The two are related in a way: States are seeking to interconnect more renewables to address climate change, which is increasing the frequency of extreme weather events.

Eric Vandenberg 2022-10-27 (RTO Insider LLC) FI.jpgEric Vandenberg, FERC | © RTO Insider LLC

Eric Vandenberg — recently appointed deputy director of FERC’s Office of Electric Reliability, after serving as deputy director of the Office of Energy Policy and Innovation (OEPI) — gave a keynote speech focused on the threat of extreme weather. He stood in for Commissioner Willie Phillips, who could not attend because of a death in family, according to WIRES.

Vandenberg noted that several regions have come to the brink of load shedding just this year, including an early cold snap in MISO and an extended heat wave in California. “Looking forward, ‘extreme’ does not necessarily mean ‘rare,’” he warned.

Since the beginning of the year, FERC has issued several Notices of Proposed Rulemakings on transmission, including one on planning processes and cost allocation (RM21-17), and one addressing interconnection queues (RM22-14). Both came as a result of a wide-ranging Advance NOPR issued last year, the results of which the attendees of last year’s conference were eagerly anticipating. (See Transmission Industry Hoping for Landmark Order(s) out of FERC ANOPR.)

But FERC also issued proposed rules that would update NERC reliability standards and direct transmission providers to report on their policies for assessing their vulnerabilities to extreme weather. (See FERC Approves Extreme Weather Assessment NOPRs.)

Vandenberg said the NOPRs are designed “to raise that floor” of NERC’s standards “for instances of extreme weather” by making utilities address their vulnerabilities.

Meanwhile, “I don’t need to harp on the need for reform here with this audience; I think it’s pretty obvious to everyone that the interconnection queues are generally pretty backlogged,” said Tristan Kessler, an economist in OEPI. He noted the record number of projects submitted to MISO for interconnection just this year. (See MISO: Record 1,000 Interconnection Requests in 2022.) “So I’m excited to be at your fall 2032 panel to talk about interconnection issues as well.”

Amanda Conner, vice president of FERC and RTO strategy and policy at American Electric Power, asked Wright, Kessler and fellow panelist Cynthia Bothwell, an engineer in the Department of Energy’s Wind Energy Technology Office, whether the commission’s proposal goes far enough.

FERC’s proposed rulemaking on queues would create a first-ready, first-served model for interconnection, which has won wide support. But it would also impose stricter requirements on transmission providers in the form of penalties for failing to meet certain deadlines on completing interconnection studies; RTOs and utilities have not been particularly receptive to these.

Wright said “many things in the NOPR are spot-on,” but some “may not help with efficiency or may cause unnecessary work. … Is FERC going far enough? Well, they certainly proposed things related to very definitive penalties [to which] we would say, ‘Don’t go farther.’”

Bothwell answered that FERC “is doing a great job of getting that conversation going, but we know that the system is changing, and to get to this big transformation, it’s going to happen in steps. And we’re going to learn more … and need additional reforms down the road.”

“It’s definitely not the end of the process for us,” Wright said. “A lot of transmission providers have come to us and proposed other changes … and I think the commission is generally supportive of that.”

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PG&E to Offer Nation’s First V2G Export Rate

Pacific Gas and Electric said Wednesday it had received regulatory approval to establish the nation’s first vehicle-to-grid export rates for commercial electric vehicles, including incentives for early adopters in the program’s first year.

“The V2G export rate promotes EV adoption by providing upfront incentives to help commercial customers offset fleet costs and delivers an innovative solution for these vehicles to export power back to support the grid during peak energy demand periods,” the utility said in a news release.

Electric school buses are a main target of the new rate-setting mechanism.

School buses hold larger batteries than standard EVs and can spend peak solar hours parked and plugged into bidirectional chargers. They can discharge energy to the grid when it is needed most, such as the strained conditions that CAISO has encountered on hot summer evenings in the past three years.

“As large vehicles like school buses and commercial fleets continue to electrify, the opportunity grows for these vehicles to serve as crucial, flexible grid resources to support a more reliable, affordable and efficient energy system,” PG&E said in the news release. “Greater volumes of these vehicles on the road come at a critical time, as peak energy demand challenges California’s grid and novel solutions like V2G emerge.”

The rate-setting mechanism was included in an uncontested settlement between PG&E, the CPUC’s Public Advocates Office, EV advocacy organization Vehicle Grid Integration Council (VGIC), and charging company Electrify America. The settlement was the subject of a proposed decision published Sept. 14 and approved by the CPUC Oct. 20 without discussion.

PG&E first proposed the dynamic, real-time hourly pricing rate structure (RTP rate) for commercial EVs in Oct. 2020.

“The design of the rate to be used in the export compensation pilot is straightforward,” the Sept. 14 proposed decision said. “As with the RTP rate underlying the export compensation rate ‘rider,’ only the components of the generation rate are affected. The design of the export compensation pilot rate rider would delete the revenue-neutral adder currently applied to the RTP rate but would keep the marginal energy charge and marginal generation capacity cost elements.”

PG&E agreed to try to make the export compensation pilot available for enrollment by Oct. 1, 2023. It will operate for three years, unless the CPUC extends it.

The pilot project will include up to $250,000 in incentives for customer enrollment during its first year. Participants will be eligible for incentive payments based on the size of their EV equipment and type of vehicle served, with school buses eligible for an incentive adder.

Equipment of 100 kW or less can receive a base incentive of $1,800 plus a $1,350 school bus adder for a total of $3,150. Equipment greater than 100 kW can get a $3,750 base incentive and a $2,810 adder for a total of $6,560.

PG&E estimates the total ratepayer cost of the export compensation pilot will be between $1.42 million and $1.52 million, the decision said.

“The CPUC’s decision is a strong step forward for Californians and in support of the state’s grid, implementing the nation’s first dynamic export rate for EV charging customers,” VGIC Policy Director Ed Burgess said. “As ever-greater numbers of EVs hit the roads, this innovative rate option will allow EV owners to further benefit from their investment in clean transportation.”

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NYISO RNA Raises Concerns over Timing of Peaker Unit Retirements

[EDITOR’S NOTE: A previous version of this story incorrectly stated that the Astoria natural gas plant is retiring in 2023. Several peaker units based in the Astoria neighborhood of Queens, N.Y., are scheduled to retire.]

NYISO’s draft 2022 Reliability Needs Assessment (RNA) found no reliability issues until 2032 but did identify tightening transmission security and resource adequacy margins across New York, staff told the Management Committee on Wednesday.

Those margins mean generators affected by the state’s so-called “peaker rule” may need to remain operational until either the Champlain Hudson Power Express (CHPE) transmission project or other resources are completed.

The rule imposed strict nitrogen oxide emission requirements on state power plants, which will force many old gas-fired plants to deactivate. It goes into effect May 1, 2023; plants must comply with it by that date or be shut down.

Several members of the committee, which voted to recommend the draft RNA for approval by the ISO’s Board of Directors, expressed concern that certain utilities’ transmission projects will not be completed by the deadline.

“It’s Oct. 26. There are growing concerns about what’s going to happen May 1,” said attorney Doreen Saia, of Greenberg Traurig. Saia was particularly concerned about a Consolidated Edison project being built to account for the retirement of peakers in Queens. “It is critical for the NYISO to — in writing, in a presentation — to confirm that you have been advised that the project is on schedule and will be completed by the May 1, 2023, date. It is not good for the market to have the kind of uncertainty that is sitting out there.”

She said that more transparency around the status of Con Ed’s local transmission plans would alleviate many of the concerns and suggested that the ISO conduct a peaker assessment to help stakeholders better forecast resource planning.

Liam Baker, vice president at Eastern Generation, concurred with Saia, saying that as “the largest owner of assets impacted by the peaker rule,” it is “very hard to make plans” without knowing what the future holds.

Zach Smith, NYISO vice president of system and resource planning, responded that the ISO’s short-term assessment of reliability (STAR) reports have included such assessments since the peaker rule compliance plans were filed in 2020, and that the ISO will continue to get the information across to stakeholders as “transparently as possible.”

Kevin Lang, partner at Couch White, asked when NYISO would “notify developers that they need to stay on” so that they have “enough time to take whatever measures” necessary to remain active and avoid any “gap periods.”

Smith responded that the ISO needs to “continue monitoring this on a quarterly basis” and that these decisions would likely be reported in any future STAR reports.

The ISO also emphasized that the CHPE project is important to the state’s future reliability and that if it is delayed, New York City could see its transmission security margins become deficient by 2028. (See “ISO: Champlain Hudson Critical to NY Reliability in Future,” NYISO Operating Committee Briefs: Oct. 13, 2022.)

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CAISO Approves More Interconnection Enhancements

CAISO‘s Board of Governors on Thursday approved the second and more-complex phase of its interconnection enhancements meant to streamline the addition of resources to its grid and shrink its long interconnection queue.

Applications for new interconnections more than tripled to 373 last year as the state aimed to add more renewable and storage resources to meet its 100% clean-energy mandate by 2045 and bolster system reliability.

“The ISO experienced unseen volumes of projects seeking to position themselves to compete in procurement processes,” CAISO Vice President of Infrastructure and Operations Planning Neil Millar wrote in a memo to the board. “Across the country and in California, stakeholders and regulators have initiated discussions on methods to better accommodate increasing pressure on interconnection processes.”

CAISO started meeting with stakeholders last year in a fast-tracked initiative to “improve its Generator Interconnection and Deliverability Allocation Procedures (GIDAP) and make process enhancements as resource interconnection needs evolve.”

“To date, the ISO has processed nearly 2,000 interconnection study requests, providing interconnection customers with the information needed to make decisions on how to proceed with their projects and to compete for a power purchase agreement with California procurement entities,” Millar wrote. “Of that amount, approximately 200 projects [totaling 24 GW] have gone into commercial operation.

“With the significant acceleration in procurement targets, numerous generator retirements, load growth, and state mandates for non-carbon emitting generation, the ISO’s processes must continue to evolve,” he wrote. “The dramatic increase in competition among suppliers has significantly increased the pressure on the GIDAP.”

The initiative’s first phase focused on simpler, near-term enhancements that had broad stakeholder support. The CAISO Board of Governors approved that phase in May, and CAISO received FERC approval of the changes in August. (See FERC OKs CAISO Interconnection Updates.)

Phase 2 dealt with more complex, long-term enhancements. One involved cost allocation for network upgrades to local systems of less than 200 kV. It would cap costs recoverable from local ratepayers at 15%.

“There is ongoing concern that the current practice for generator-interconnection-driven local upgrades could unduly impact local ratepayers who solely bear their costs,” Millar wrote.

Costs for lower-voltage network upgrades in excess of 15% “will be financed by interconnection customers without cash reimbursement, but with merchant transmission congestion revenue rights if created,” the memo said.

Another change established a new network upgrade reimbursement policy when the ISO is an “affected system.”

“In the last decade, there have been no instances where a generator’s interconnection to a neighboring balancing authority area affected the reliability of the ISO grid such that network upgrades were required,” Millar’s memo said. “In interconnection terms, the ISO is almost never an “affected system,” and has only been asked to perform affected system studies a handful of times. Most of these studies were not performed because the project quickly withdrew.

“However, recently the ISO has received a few notices from neighboring areas that a proposed interconnection potentially may affect the ISO and could warrant ISO study,” it said. “Although the probability is very remote that an external interconnection would require network upgrades on the ISO system, Management believes the ISO tariff should have a clear policy on this issue.”

The changes still require FERC approval.

Other enhancements do not require tariff changes or board approval, such as making data more easily accessible and publicly available to help developers determine the best locations to connect new resources and to better understand the status of projects in queue.

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SPP Board Bypasses Stakeholders on PRM Obligation Exemptions

SPP’s Board of Directors has given its state regulators the go-ahead to file a proposed tariff change that would allow load-responsible entities (LREs) to qualify for and receive exemptions from deficiency payments for not meeting their planning reserve margin (PRM) requirements.

Under the RTO’s tariff, the Regional State Committee has the authority to direct staff to file changes with FERC without the board’s approval. SPP’s directors yielded to the RSC on Oct. 25 by authorizing the filing after the committee’s earlier approval of the revision requests (RR 515).

In doing so, the board disappointed stakeholders who had approved a slightly different version of RR515 brought forward by the Supply Adequacy Working Group (SAWG) two weeks earlier. (See “Members Address Resource Adequacy,” SPP Markets and Operations Policy Committee Briefs: Oct. 10-11, 2022.)

Speaking for the stakeholders she represents as the Markets and Operations Policy Committee’s chair, Evergy’s Denise Buffington said she expects the waiver process to fail at FERC.

“Not because of the substance of the process, but because it is likely to be protested by SPP stakeholders,” she told the board last week. “This gives FERC an easy path to deny something that is hard. I believe they’ll do that because, first of all, they don’t like granting waivers. So, if we are not in lockstep about what the waiver looks like and the criteria and all … the easy thing for FERC to do is to say, ‘There is no waiver.’ So essentially, the results of the decision that was made yesterday means that more responsible entities are likely not to have an option of a waiver.”

Several members suggested SPP’s stakeholders should ensure that important issues are vetted appropriately. Board Chair Larry Altenbaumer agreed, saying, “This is a tough issue because it tends to be a bifurcated issue.

“There are certain responsibilities that are vested with the RSC. This is one of them. And I think the RSC has the full authority to determine how they want to reach their decisions,” Altenbaumer said. “Where I sit as a board member, I think we all strive and desire and try to help facilitate reaching consensus and alignment among our stakeholders. My view is that what we are attempting to do here is to try to reengage the stakeholder process to see if we can now come up with something that might be a balanced outcome.

“I think in the final analysis, the board has to act independently,” he added.

The RSC approved a version proposed by its Cost Allocation Working Group and tweaked by the Market Monitoring Unit. It calls for up to a two-year exemption from deficiency payments, whereas the MOPC version allows a three-year exemption. The CAWG proposal also requires LREs to meet two tests to claim the waiver, while MOPC’s only required complying with one of the two.

LREs would qualify for the waiver in both versions by demonstrating they have enough capacity to meet forecasted load for the upcoming season and the prior effective PRM. Under the CAWG version, they must also prove by a certain date each year that sufficient capacity for purchase has not been identified on a virtual bulletin board; they have a contracted obligation to purchase capacity; and they have a pending request for enough interim, surplus or replacement generator interconnection service to provide planning reserves to SPP.

During a closed-door education session for the RSC on Oct. 24 before its regular meeting, the MMU presented its revisions to the CAWG proposal that included extending the deadline for waiver exemptions from March 10 to May 1 and allowing LREs to cure at least a portion of their deficiency, thus reducing the penalty. The RSC accepted both suggestions.

Buffington protested the lack of stakeholder input into the MMU’s recommendations. RSC President Randy Christmann, a member of North Dakota’s Public Service Commission, countered by telling the board that the assertion that the MMU’s changes were never brought to MOPC “almost makes it sound like it was some surprise thing that was brought on the membership yesterday.”

“Well, the fact of the matter is I studied it up in North Dakota and learned about it, and multiple other states did as well, and I’m confident that companies are aware of those postings,” Christmann said.

The board in July approved an increase to the RTO’s planning reserve margin from 12% to 15%, effective next year. MOPC had recommended a “stair-step” increase by adding a percentage point to the PRM over three successive years. (See SPP Board, Regulators Side with Staff over Reserve Margin.)

Stakeholders have said they support an adequate PRM, but that the sudden 25% increase has left them with just a few months to acquire significant enough capacity to meet contractual obligations. Some also complained that not enough excess capacity is available for purchase.

“People have been ghosted. … They’ve been offered capacity, but then it’s pulled back,” Golden Spread Electric Cooperative’s Natasha Henderson, the SAWG’s chair, told the RSC. “It’s pulled back because of the uncertainty that we’re dealing with [over] what’s the right policy.”

Several state regulators expressed concern that the stakeholder process had not reached full consensus. However, they approved the modified CAWG version by a 9-3 margin. Kansas’ Andrew French, Oklahoma’s Dana Murphy and Texas’ Will McAdams all voted against the measure.

“Everything I’ve heard this week is that we have more time to explore this. We’ve had these issues in the past where people want to continue debating … I don’t feel like we’re right there yet,” French said. “My biggest concern is, have we really run this down to the best solution it can be? This will be in the tariff. … It’s going to be the process moving forward.”

Evergy, Golden Spread, Liberty Utilities, Oklahoma Municipal Power Authority, Public Service Company of Oklahoma and Southwestern Public Service were the only representatives of the 22-person Members Committee to vote against authorizing RR515’s filing.

A virtual bulletin board for informational purposes only will be developed so LREs and generation owners can view and post requests to buy or offers to sell power. All information on the board will be confidential, with only the MMU able to review the data.

SPP bases its reserve margin requirement on a probabilistic loss-of-load expectation study during summer months that is 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).

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Effective Transmission Planning Requires Western RTO, Panelists Say

Kathleen Staks, chair of the Colorado Electric Transmission Authority (CETA), thinks the creation of an RTO is “imperative” for Western states to develop the transmission network needed to meet their clean energy and electric reliability goals.

Staks, who also serves as deputy director of Western Freedom, a self-described “grassroots and grasstops” coalition that is advocating for a Western RTO, also believes it’s just a matter of time before one or more organized market takes shape in the region.

Speaking Thursday on a virtual “Transmission Time” panel hosted by Americans for a Clean Energy Grid, Staks noted the “momentum” building in the West from the competing day-ahead markets being prepared by CAISO and SPP.

“I think what you’re hearing now, even from the utilities in public forums, is that we are on the path to an RTO — or several RTOs, which is probably the more likely sort of future state — where we have two different operators covering slightly different footprints in the West. But I think there’s more of an inevitability in the talking points that you hear at this point in time,” she said.

While Staks thinks the proposed day-ahead markets are a “great next step,” she said they can’t deliver the unified transmission planning and operational benefits of a full RTO.

Staks said legislatures in Colorado and Nevada “lit a fire” in 2021 when they each passed bills requiring their state’s utilities to join an RTO by 2030. (See Polis Signs Bipartisan Bill to Support Interstate Tx and Many Next Steps to Follow Passage of Nevada Energy Bill.)

But when panel moderator Kristine Raper, a former Idaho regulator who is now vice president of external affairs at WECC, asked whether other states should follow suit and pass similar laws, Staks demurred, saying additional mandates aren’t yet necessary.

“Almost all of the utilities in the West are participating in these day-ahead market developments, and I think there’s enough other sort of pressure points — and almost even peer pressure, really — to keep things going,” she said.

Fellow panelist Jeremy Turner, director of New Mexico project development at Pattern Energy, said he could see some benefit in states legislating membership in an RTO but thinks a better approach would be for states to direct commissions and utilities to “force the RTO issue a little bit,” without specifying exactly how.

“California has done a good job with the Energy Imbalance Market [as] kind of a half-step to a formal RTO, but in order to fully build out the transmission system and align on all the decarbonization goals and meet those, I think it’s absolutely going take an RTO in the West,” Turner said.

CETA and RETA

That Colorado sees a vital link between a Western RTO and effective regional transmission planning is evidenced by the fact that the 2021 law (SB 72) requiring utilities to join an RTO also established CETA.

According to the law, CETA is an “independent special purpose authority” that can act as a transmission developer of last resort in areas that the state identifies as needing transmission — particularly those promising for the development of the renewables Colorado needs to meet its clean energy targets. In short, CETA will direct the construction of lines in areas where utilities are declining to build, with an emphasis on interregional projects.

“CETA has eminent domain authority and has the ability to build and own transmission projects,” Staks pointed out.

CETA was modeled on New Mexico’s Renewable Energy Transmission Authority (RETA), which was established in 2007 “to plan, develop finance and acquire utility-scale, high-voltage transmission lines and energy storage projects,” RETA Executive Director Fernando Martinez said during the webinar.

RETA’s mission, Martinez explained, is to help New Mexico develop the transmission needed to tap its extensive wind and solar resources, with an eye to serving both in-state needs and exports to neighboring states.

“Our whole [electricity] infrastructure in in New Mexico was set around fossil fuel plants taking the power to population centers, and so our renewable resources were in other parts of the state where very little transmission existed, and we knew that was a landlocked treasure,” Martinez said. “And the only way to access that was by building transmission and energy storage capacity.”

Because RETA’s jurisdiction ends at the New Mexico state line, the agency relies “almost exclusively” on its transmission development partners to advance lines through other states, Martinez said. He cited the example of Pattern Energy’s proposed SunZia project, a 550-mile, 525-kV bidirectional line designed to move wind output from eastern New Mexico to population centers in Arizona.

“So it’s really been up to [Pattern] to work with Arizona and get that project going in that state, and we worry about what’s going on in New Mexico,” he said.

But projects become “a lot more difficult” once they hit the state line, Martinez said.

“The question is, ‘Then what?’ … And that’s one of the primary reasons that we’re looking at a regional transmission organization and really promoting that and trying to socialize that idea, because I think that is the most effective way to build an upgraded flexible grid that’s geographically diverse, that’s meteorologically dissimilar, [and] that has as many interconnections as possible,” he said. “And then couple that with building utility-scale long-duration storage. I think that’s the only way you’re going to get firm capacity.”

Building Relationships

Apart from their shared views on interregional planning, the three panelists also agreed that transmission developers face similar on-the-ground hurdles in developing projects in different states across the West.

“I think the biggest challenge here in the West is getting the permission to build the generation; getting the permission to build the transmission and storage projects,” Martinez said. “And what I mean by that is there’s a lot of laws that must be complied with that a lot of times are run sequentially, rather than concurrently, and so you have a lot of difficulties in the permitting process at the local level, the state level [and] the federal level.”

Martinez ticked off the various agencies and stakeholders that developers might have to deal with to gain permission for an energy project in New Mexico, including local governments; the state’s Public Regulation Commission (for reliability requirements); FERC; the U.S. Bureau of Land Management or Forest Service (for environmental impact statements); tribes; military bases; and private landowners. All told, permitting across various agencies can stretch project timelines to 10 to 20 years, he said, a problem for states attempting to meet climate goals by 2030.

“We need to find a way to streamline that process without cutting any corners whatsoever and — hopefully working with the permitting agencies; we can do that by simply by cutting down sequential permits versus concurrent permitting,” Martinez said.

Martinez expressed gratitude for the efforts of the interagency Federal Permitting Improvement Steering Council, which has been tasked with speeding up federal infrastructure permitting. Pattern’s Turner agreed that the council has been “incredibly helpful” but thinks increased FERC siting authority will be needed to advance transmission projects in the West.

Turner is also encouraged by the creation of state agencies such as RETA and CETA, which have the eminent domain authority that independent developers lack.

But Staks said any transmission authorities set up by Western states must still deal with opposition from landowners and regional stakeholders, she added.

“People don’t want transmission lines in their backyards,” she said. “They don’t want wind projects; they don’t want solar projects. They don’t want oil and gas pipelines; they don’t want anything. They want to be able to sort of maintain their viewshed or their neighborhood or whatever.”

She said community involvement and relationship-building around proposed projects will be important tools for CETA.

Turner said Pattern Energy, which has about 750,000 acres of private and state land under lease for wind projects, has found ranchers to be among the strongest supporters of new energy projects.

“Most of the ranchers that we have properties leased [from] are seeing this as a way to supplement their income and actually continue their way of life,” he said. “And they’re actually the ones that are trying to help advance, in many cases, the transmission development, because they know that is their path forward to continuing that way of life and seeing wind built on their property.”

Ordering the List

Raper asked Staks how CETA might approach working with neighboring states that do not share Colorado’s political views and climate goals.

Those discussions will come down to appealing to economics of a project, Staks said, imagining such a conversation with a more politically conservative state: “It’s your energy resources, Montana. You have the opportunity to sell those to someone else.”

Staks said she takes a similar approach when she stumps for a Western RTO.

“When I have conversations with different people about the benefits of an RTO … the list of priorities [and] the list of benefits [are] the same. You’re just sort of reordering depending on who you’re talking to and where you are,” she said. “When you’re in Colorado and New Mexico, those climate benefits are going to be really, really important to most of the decision-makers that we’re working with. If you’re in Idaho and Montana and Wyoming, you’re going to prioritize economics and reliability.”

“Everybody’s going to get those all of those benefits. I think part of it is the order [in which] you’re making this list,” she said.

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ClearPath: Nation’s Queue Processes Impeding Energy Transition

Conservative clean energy nonprofit ClearPath last week joined the chorus sounding the alarm over the nation’s congested generator interconnection queues, which it said are throwing a wrench in carbon-reduction goals.

In a new report, “All Queued Up and Nowhere to Go: The Massive Interconnection Challenge Facing Net-Zero Electricity Deployment,” the organization found that increasing queue delays are standing in the way of the clean energy transition, and it released a handful of recommendations aimed at the federal level.

The report concluded that federal agencies should enact policies that include coordinating interconnection and transmission planning processes; allowing expedited treatment for projects proposed in existing rights of way; offering grants and scholarships to electrical engineers who focus on interconnection; and providing technical assistance to those who oversee interconnection processes.

ClearPath analyzed interconnection processes used by transmission providers, utilities and grid operators. It found an average queue wait time of 3.7 years and a “massive backlog, making it incredibly difficult to deploy new generation and storage resources.” It said wait times for interconnection between 2000 and 2010 were just 2.1 years in comparison.

“The interconnection queue has become so dysfunctional that some transmission providers are freezing their process to work through the project backlog,” Spencer Nelson, ClearPath’s managing director for research, said in a press release. “Hundreds of gigawatts of new energy projects — predominantly wind, solar, natural gas, and storage — spend an increasingly long time in the interconnection process. This is now the biggest bottleneck for clean energy development.”

The organization said current net-zero models are “unrealistic” given the current congested queues and warned that the retirement of existing capacity is set to “outpace new additions due to interconnection inefficiencies.”

ClearPath said between 2010 and 2016, only 23% of generation projects entering various queues reached commercial operation. It blamed, in part, first-come, first-served study processes that encourage developers to submit more than one interconnection request in the hopes of landing on the cheapest interconnection points. When speculative placeholders withdraw requests, it causes “turmoil,” the report said.

The nonprofit cited Princeton University’s “Rapid Energy Policy Evaluation and Analysis Toolkit,” which shows that the U.S. requires 1,101 GW of additional wind and solar generation, 179 GW of natural gas generation with carbon capture technology, and 6 GW of nuclear generation by 2035 to reach net-zero emissions by 2050. Using those figures combined with the national average 23% rate of commercial success, ClearPath said 7,000 GW of capacity would need to enter queues to meet Princeton’s 1,300 GW of generation additions.

“Failure to address the current interconnection process at scale will limit the ability to reduce emissions affordably and could hurt grid reliability,” Nelson said. “At this point, achieving net-zero emissions in the U.S. by 2050 is impossible without major interconnection improvements.”

ClearPath said the U.S. needs record annual capacity additions, not feasible under current processes, to accomplish a net-zero midcentury mark. It said the nation should have somewhere between 74 and 156 GW of capacity additions per year. Though proposed capacity entering queues has recently grown to 500 GW per year, ClearPath said interconnection rates have dwindled.

The nonprofit wasn’t keen on FERC’s notice of proposed rulemaking for interconnection queue reform. (See RTOs, Utilities Push Back on Interconnection Deadlines, Penalties.)

The report said the NOPR’s proposals are not likely “transformative or flexible enough for the speed and scale of deployment required.”

It said many transmission providers have already tried FERC’s proposed fixes without much improvement, pointing to MISO’s multiple filings over the last decade to streamline its queue process.

ClearPath said the commission should embark on a rulemaking to integrate regional and interregional transmission planning with interconnection processes. It also said the U.S. Department of Energy should fund workforce development that specializes in interconnection and update its National Interest Electric Transmission Corridors (NIETCs) to issue more construction permits and provide technical interconnection assistance to states, utilities and RTOs and ISOs.

Finally, ClearPath recommended FERC, DOE and U.S. department of the Interior strengthen their coordination in permitting generation and transmission. It said the agencies should work together to expedite permitting at interconnection points for large, retiring power plants and for rights of way under the U.S. Department of Transportation. It said the agencies should also “proactively pre-site areas on federal land for clean energy and transmission projects along identified NIETCs.”

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Suitors Line up for AEP’s Unregulated Renewable Assets

American Electric Power (NASDAQ:AEP) executives said Thursday that “the usual suspects” are interested in the company’s unregulated renewable energy assets as the company seeks to become a “pure play” regulated utility.

AEP launched the two-step sale process for the 1.37-GW portfolio in August and has accepted bids for the first phase of the auction process. The company announced the sale in February. (See AEP to Sell Unregulated Renewables Portfolio.)

Akins-Nick-2019-09-10-(RTO-Insider)-FI.jpgAEP CEO Nick Akins | © RTO Insider LLC

“Selling the portfolio will allow AEP to shift focus and rotate capital towards regulated businesses as we continue to transform our generation fleet and enhance transmission infrastructure,” CEO Nick Akins told financial analysts during a Thursday conference call. He said a sale agreement is on pace to be signed during the second quarter next year and to close by midyear.

The Columbus, Ohio-based company reported earnings of $684 million ($1.33/share), as compared with earnings of $796 million ($1.59/share) for the same quarter a year ago. The results exceeded analysts’ expectations of $1.56/share.

Transmission will be key to AEP’s earnings growth plan. The company plans nearly $26 billion in wires investment opportunities over the next five years as it focuses on “improving the reliability and resiliency of the grid and integrating new resources to support the clean energy economy,” CFO Julie Sloat said.

AEP said it is responding to a second subpoena from the U.S. Securities and Exchange Commission related to a corruption probe into the passage of an Ohio nuclear and coal subsidy bill.

“We view it as a continuing part of the process. … We said we would be transparent, and we have been transparent, and we’ll continue to work in a positive fashion with the SEC,” Akins said. “They just need more information, and we’re going to supply it. We’ll continue to work with them to get this thing resolved.”

The first subpoena asked for documents related to the bill’s passage and AEP policies, financial processes and controls. Akins said the company has recognized it needed to make changes in a nonprofit’s governance, “and we made those changes.”

AEP’s share price finished the week at $89.40, up $1.96 after its pre-earnings close.

The analyst call marked Akins’ last after 11 years as AEP’s CEO. He will be replaced by Sloat, who takes over on Jan. 1. (See Akins Steps down as AEP President; Sloat to Become CEO.)

“I’m confident in [Sloat’s] deep knowledge of AEP, as well as the emphasis she places on consistency, quality of earnings and dividends and shareholder and customer value creation that will be instrumental to AEP’s continued success,” Akins said, marking the occasion with his trademark references to rock music.

Quoting Rush’s “Closer to the Heart” and Led Zeppelin’s “Thank You,” the rock musicophile said, respectively, “And the men and women who hold high places must be the ones who start to mold a new reality closer to the heart. … And so today, my world, it smiles.”

NextEra Again Exceeds Expectations

NextEra Energy (NYSE:NEE) said that a 13% increase during the third quarter in adjusted earnings year-over-year, reflecting continued strong performance by its utility and clean-energy subsidiaries, has the company well positioned to achieve its overall objectives for the year.

The Juno Beach, Fla.-based company delivered quarterly earnings of $1.69 billion ($0.86/share), compared to $447 million ($0.23/share) for the same period a year ago. Wall Street had expected earnings of 80 cents/share; NextEra has exceeded expectations for the past two years.

The Inflation Reduction Act’s passage “provides a tremendous opportunity set for us across the board,” CEO John Ketchum told analysts during a conference call Friday. “It creates a lot of immediate money opportunities for us going forward on wind, solar and on battery storage.”

NextEra Energy Resources, the company’s wholesale supplier subsidiary, added 2.3 GW of new renewable resources and storage projects during the quarter.

NextEra said Hurricane Ian’s landfall in September knocked out service to more than 2.1 million Florida Power & Light customers, but that a restoration workforce of about 20,000 workers and FPL’s grid-hardening and smart-grid investments restored service to about two-thirds of those affected customers after the first full day. It was the fastest restoration rate after a major hurricane, officials said.

The company’s share price closed Friday at $79.03, a gain of $3.56 (4.7%) on the day.

Xcel: IRA Will Lower Renewable Costs

Xcel Energy (NASDAQ:XEL) on Thursday reported third-quarter earnings of $649 million ($1.18/share), up from last year’s third quarter net total of $609 million ($1.13/share). The company cited capital investment recovery and other regulatory outcomes for the improvement.

CEO Bob Frenzel said the IRA’s passage will reduce the cost of the Minneapolis-based company’s clean energy transition and improve liquidity through tax credit transferability, besides providing “significant” customer benefits. He said the legislation will lower the cost of the recently approved 460-MW Sherco Solar project by more than 30% and also reduce the expense of the 10 GW of approved renewable resources in its Minnesota and Colorado resource plans.

“It shows the tremendous customer benefits of being an early leader in the clean energy transition,” Frenzel told analysts during Thursday’s call.

The quarter’s performance was short of analysts’ expectations of $1.22/share. However, Xcel’s share price closed the week at $65.37, up $2.80 (4.5%) from its pre-earnings close.

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MISO Members Revisit Possibility of Resilience Obligations

MISO members have reopened the suggestion that the grid operator enact resilience criteria within its footprint, saying it has a role to play in preparing to withstand and recover from high-impact, low-probability events that wreak havoc on the system.

During an Advisory Committee teleconference Wednesday, several members said MISO could address resilience through projects that harden and build redundancy into the system, resource diversity and operational protocols. They said the RTO’s long-range transmission planning will reinforce the system, but it could do more in bolstering interregional links, which have proven invaluable during extreme weather events.

ITC Holding’s Brian Drumm said staff could establish minimum intraregional and interregional transfer levels.

“How do we know we’re resilient now if we don’t have metrics?” the Lignite Energy Council’s Jonathan Fortner asked, advocating for defined measures of adequate transmission capability and available generation.

The Union of Concerned Scientists’ Sam Gomberg said MISO “should be on the forefront” of partnering with national laboratories and agencies to understand evolving risks of climate change. He said the grid operator’s “blind spot” is that it doesn’t proactively analyze and plan for future risks “that the science is telling us are going to become numerous.”

Gomberg said MISO might define when heat waves and winter storms cross an “extreme” threshold. He said “smart, low-cost solutions or behaviors” could lower risks and that MISO, states and load-serving entities have a “huge opportunity” to save lives and lessen disruptive events’ economic devastation.

WEC Energy Group’s Chris Plante said the conversation was reminiscent of one the Advisory Committee held four years ago. He said continued attention on the topic without sets of criteria means that it is difficult to pin down resilience objectives.

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Search for Small SPP-MISO Interregional Projects May be Fruitless

MISO and SPP prepared stakeholders last week for the possibility they may come up empty-handed in their joint hunt for interregional transmission upgrades.

SPP’s Neil Robertson said that the grid operators are still “hopeful” they can identify at least one beneficial targeted market efficiency project (TMEP) in their study. But he also said there’s a “strong possibility” that they won’t find any recommended upgrades.

“I think the likely outcome is we’re not going to have any … candidates come out of this first study, but I don’t want to close the door on this just yet,” Robertson told stakeholders Friday during a MISO-SPP Interregional Planning Stakeholder Advisory Committee (IPSAC).

“The cost of the solutions may far exceed the budget,” Robertson said, adding, “We’re still refining the congestion dollar values.”

MISO and SPP have said they would screen for possible TMEPs when a market-to-market flowgate has amassed $1 million or more in congestion costs over a two-year period. The RTOs catalogued seven permanent flowgates that have racked up between $10 and $43 million worth of congestion. (See MISO, SPP Identify Hotspots for Smaller Interregional Tx Projects; MISO, SPP Hunt for Small Interregional Tx Projects.)

They have proposed that TMEPs cost $20 million or less, must not be greenfield projects, be in service by the third summer peak from their approval, and completely cover their installed capital cost within four years of service through avoided congestion.

The grid operators borrowed many of their standards from MISO’s and PJM’s TMEP criteria.

Stakeholders remained adamant that the grid operators are using a cost cap that’s too restrictive to result in any valuable projects.

American Clean Power Association’s Daniel Hall asked whether the absence of qualifying TMEP projects means that the RTOs might consider “tweaking” the criteria to increase the cost threshold or payback period.

Robertson said staffs plan to hold lessons-learned discussions following the study’s conclusion but probably wouldn’t change criteria “purely in the interest of getting Project A or Project B across the finish line.”

“There is merit in shifting [these] criteria or [those] criteria, but we have to balance all of the considerations,” he said. Staffs are looking for upgrade candidates that “truly give us the return on investment we’re looking for” and are not entertaining a change to the $20 million cost cap at this time, Robertson said.

Several stakeholders said inflation has dated the proposed TMEP cost threshold.

Clean Grid Alliance’s Natalie McIntire argued that “the value of dollars changing” means that the cost maximum is “ripe for reconsideration.”

“You should consider keeping up with inflation,” she told the RTOs’ planners.

American Electric Power’s Brian Johnson agreed and said MISO should “right-size the figure to match market conditions.” He said with the current criteria, a TMEP would have to be “almost across the street” for MISO and SPP to recommend it.

The grid operators said they will announce any project candidates during a Dec. 12 IPSAC meeting.

Robertson also said the RTOs are working out a way for one RTO’s transmission owners to fund an upgrade on the other RTO’s system when it stands to benefit them. Robertson said situations where a TO will overwhelmingly benefit from a project on the other side of the seams are becoming increasingly commonplace.

He said the grid operators could “pass the funding across the fence” should there be cross-border construction under MISO and SPP’s interregional planning process.