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November 14, 2024

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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.

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NEPOOL to Consider Raising ISO-NE Board Age Limit

NEPOOL stakeholders will consider whether to increase the age limit for members of ISO-NE’s Board of Directors this week, as the grid operator looks to expand the pool of candidates for the job.

The proposal, put forward by NextEra Energy’s Michelle Gardner, will get a vote at the Participants Committee this week.

A provision of the current ISO-NE and NEPOOL rules, in place since the Participants Agreement was adopted in 2004, prohibits anyone over the age of 70 from being elected or re-elected to the board.

Gardner plans to argue that best practices have changed since 2004, according to her presentation. Her proposal would raise the age limit to 75.

Two other RTOs have age limits of 75, and the rest have no limits at all, she says.

“In recent years, the age limit has contributed to difficulty in finding high-quality director candidates to serve on the ISO board,” according to Gardner’s presentation. It’s “challenging for actively employed executives to serve” on the board because of the time commitment it requires. And as many executives are now working full-time jobs into their 60s, “the present age limit shortens their service window.”

ISO-NE’s Code of Conduct also limits the ability of stakeholders to consider candidates who have been recently affiliated with market participants or are invested in companies that interact with ISO-NE. FERC’s interlock rule also comes into play.

ISO-NE spokesperson Matt Kakley said the grid operator supports the change.

“Making this change would bring ISO New England in line with our ISO and RTO peers and corporate best practices,” Kakley wrote in an email to RTO Insider. “Increasing the age limit will allow for a broader pool of candidates while maintaining existing parameters laid out in our Code of Conduct and FERC’s interlock rules.”

The board will meet on Tuesday, the day before the Participants Committee, for its first public meeting as part of a commitment by ISO-NE to the New England states to be more accessible and transparent.

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HECO Pilot to Fund EV Chargers at Commercial Buildings

Hawaiian Electric (HECO) said last week that it is accepting applications for Charge Up Commercial, a three-year pilot program aimed at reducing the upfront costs for the installation of electric vehicle charging station infrastructure.

The $5 million “make-ready” pilot program will provide up to 30 applicants as much as $90,000 each to install the infrastructure necessary for Level 2 EV charging stations. HECO will install and maintain all infrastructure up to the charging station location, while applicants are responsible for buying, installing and maintaining the charging station itself. Applicants must also install a minimum of four and maximum of six charging ports.

The pilot program is available for non-residential locations such as stores, office buildings and fleet facilities, as well as apartments and condominiums, on all the islands except for Kauai.

The charging stations will dovetail with HECO’s commercial EV charging rates, which apply a time-of-use rate to reduce energy costs during the midday hours when there is an abundance of solar energy on the grid.

Charge Up Commercial is also compatible with HECO’s EV Charging Station Rebate program, which offsets some of the cost of installing an EV charging station for commercial and multi-unit dwellings.

In the Charge Up Commercial handbook, HECO CEO Shelee Kimura said part of the pilot program’s value is to provide charging ability to EV owners who live in apartment buildings or condominiums, where it is generally more difficult to charge EVs in than a house. Kimura noted that apartments and condominiums “make up a full 37% of Hawaii’s housing stock.”

HECO will accept additional applications on a rolling basis if there are leftover funds after the first 30 applicants.

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ESSC To-do List: Labor Shortage, Forest Management, Transformers

Duane Highley (US Energy Association) Content.jpgDuane Highley, Tri-State Generation and Transmission Association | U.S. Energy Association

Solving workforce issues, making transformers easier to replace and improving forest management are among the issues dominating the attention of the Electricity Subsector Coordinating Council, Co-chair Duane Highley said Friday.

The ESSC has been discussing how the industry can deploy federal funding from the Inflation Reduction Act and the Infrastructure Investment and Jobs Act “that would basically triple the rate of expansion of our energy transition,” Highley said during a United States Energy Association virtual press briefing on transmission.

“The No. 1 factor that’s limiting us right now is labor availability. There’s just not enough people,” said Highley, CEO of Colorado-based Tri-State Generation and Transmission Association. “And so despite the will — we might have all the money in the world — if we don’t have the people, we’re not going to get it done. And this is a global problem. It’s not even just limited to us.”

Highley said the ESSC’s wildfire working group is completing efforts with the U.S. Forest Service and Bureau of Land Management to create master special-use permits that will simplify the removal of vegetation under transmission lines.

“We’ve had, in the past, to get separate permits for every single forest district, every single company,” he said. “And what we’re on the verge of completing now … is a master special-use permit that’s going to allow [access] to be negotiated once. And then we can get in and do the work we need to do without so many extra hoops to jump through.”

Getting Away from Bespoke Transformers

Maria Robinson (US Energy Association) Content.jpgMaria Robinson, DOE Grid Deployment Office | U.S. Energy Association

Highley and Maria Robinson, director of the U.S. Department of Energy’s Grid Deployment Office, also spoke of efforts to improve the supply of transformers.

Highley said the ESSC, a public-private partnership formed to improve energy resilience after the Sept. 11, 2001, terrorist attacks, has made major strides. “We’re much better today than we were two decades ago,” he said. “One of the things we’re looking at hard right now is the Defense Production Act capabilities that [the Department of Defense] has been given, and it might allow them to engage in helping make transformer supplies better.”

Robinson cited the Solid State Power Substation Technology Roadmap, a research and development effort being led by DOE’s Office of Electricity to reduce the criticality of substation components.

“One of the biggest issues is that transformers … are made to spec. They’re not modular in any way, shape or form,” Robinson said. “And there’s a lot of investment going into research to allow for more modular parts, recognizing that when you’re ordering a very specific design, it could take months or years for that to come in. And from a resilience perspective, we want to make sure that we’re able to rebuild more quickly than that.”

Ukrainian officials said earlier this month that Russia’s strikes on the nation’s infrastructure had destroyed about 30% of its autotransformers.

Asked what lessons the Russian attacks might hold for U.S. resilience efforts, Highley said: “Defense in depth; redundancy. It’s what’s always saved us, no matter what happens, whether it’s weather, cyberattack or physical kinetic attack.”

Florida’s Transmission Stands Tall

Philip Moeller (US Energy Association) Content.jpgPhilip Moeller, Edison Electric Institute | U.S. Energy Association

Also speaking at the briefing was former FERC Commissioner Philip Moeller, now executive vice president of the Edison Electric Institute, who touted the hardening investments made by Florida’s utilities before Hurricane Ian in September.

“In the last hurricane, we didn’t lose any transmission structures in Florida,” Moeller said. “So that tells you that the infrastructure investments — the hardening, the adaptation, the resilience — actually pay dividends.”

Moeller cited studies estimating that power outages in Florida can result in economic losses of $1 billion per day.

“So to the extent you can invest to correct those outages, that’s a pretty good bargain,” he said. “It also points out [the optionality value of] transmission. … As populations change; when congestion occurs; as public policies change; as fuel choices change, transmission is the infrastructure that gives us optionality.”

Robinson said DOE has $10.5 billion in funding to improve grid resilience and innovation through matching grants, “specifically looking at some of that hardening work that needs to happen, both at the transmission and distribution levels.”

Moeller said additional federal funding also will help expand cybersecurity programs to “more of the smaller energy companies and utilities throughout the country, so that we can have a more comprehensive approach toward the cyber threats that are out there.”

More East-west Transmission

Michael Skelly (US Energy Association) Content.jpgMichael Skelly, Grid United | U.S. Energy Association

Highley and Michael Skelly, founder and CEO of transmission developer Grid United, also talked about the need for more interregional transmission to address reliability problems and the solar duck curve.

“We need a national will to build national transmission east [to] west. So much of what we have now is north to south,” Highley said. “The RTOs even tend to be oriented north to south — if you look at CAISO, you look at SPP, if you look at MISO — and that’s why we have duck curve problems. … A duck curve exists because the sun sets on a time zone all at once. And if you could move that east and west, you wouldn’t have a duck curve at all.”

Skelly was asked whether Texas policymakers might consider making ERCOT FERC-jurisdictional by interconnecting with the Eastern and/or Western grids in response to the blackouts following the February 2021 winter storm.

“I would say the chances of Texas joining the rest of the country, electrically speaking, are between zero and none,” Skelly replied. “But I do think that the prospects for DC connections between ERCOT and elsewhere are fairly good.”

ERCOT currently has transfer capacity of only 1,200 MW with “the outside world, as we in Texas, like to call it,” Skelly said. His company is proposing a project that would connect West Texas and El Paso. He also mentioned Pattern Energy’s Southern Spirit project, a 400-mile line between East Texas and Mississippi.

“I think we’ll see more projects like that. And they’re beneficial, because … ERCOT has tremendous amounts of wind and solar. And these lines would allow ERCOT to share that abundance with the rest of the country, and also provide reliability to ERCOT during stressful grid conditions,” Skelly continued.

“I know ERCOT has had kind of a rough go in many respects. But one of the reasons that Texas has so much renewable energy — we lead the country in wind; we will soon lead the country in solar — is precisely because of its independence. You have one jurisdiction that can make decisions around grid expansion [with] fairly low barriers to entry. … So I don’t think things will change in terms of like FERC jurisdiction, but I do think there’s opportunities to connect us through these DC connections, and those will be beneficial all around.”